CAPITAL: WASHINGTON, DC
MONETARY UNIT: DOLLAR
REFINING CAPACITY: 16,538,540 B/D
OIL PRODUCTION: 5,823,000 B/D
OIL RESERVES: 21.7 BILLION BBL
GAS RESERVES: 167.4 TCF

Strong oil prices helped the upstream US petroleum industry in 2000, but downstream problems persisted.

Ronald Gold, of the Petroleum Industry Research Foundation Inc. (Pirinc), New York City, noted that in 1998 through early 1999, the industry suffered from extremely depressed prices. The ensuing financial problems encouraged cutbacks in investment and employment, as well as an unprecedented level of industry mergers.

Gold said that in 2000 the stresses were different, as tight world oil supplies and low inventories of oil—and in the US, low natural gas storage as well—combined in the face of strong demand to produce sharply higher prices.

"Higher prices for crude oil and natural gas, as well as higher product margins, produced substantial gains in upstream and downstream profitability, but the improvement downstream may not be enough."

Gold said gasoline margins in 2000, especially in the spring and early summer, were significantly higher than in the prior 2 years, although at yearend they were in line with earlier levels.

The gains for distillate were even stronger because of its role as a key substitute for natural gas for interruptible and spot gas customers.

With natural gas storage levels at extremely low levels and with spot gas prices soaring, these customers were being pushed into the distillate market. The low level of distillate inventories, especially in the US Northeast, was also helping to sustain high prices and margins.

Gold said that, while the average refinery utilization rate in 2000 rate was 91%, it was not exceptional. The average was the same as in 1999 and below the 95% average rates for 1997-98.

Gold said refiners still faced the problems and risks of "boutique" fuels.

"Indeed, there are new challenges to downstream companies that could aggravate risks—in particular, the new regulations for ultralow-sulfur diesel and the coming phaseout of methyl tertiary butyl ether.

"Unless carefully-and flexibly-managed, the result could be new US supply shortfalls and new limits on the industry's ability to shop world markets to overcome them."

Strong gains

Energy company stocks achieved a median return of 48% in 2000, and a fourth of the issues doubled in price, according to John S. Herold Inc., Norwalk, Conn.

The analyst said that all but one of the 15 energy stock groups it tracked outperformed the Dow Jones Industrial Average in a year when technology stocks were devastated and the broad market suffered its first decline in a decade.

Art Smith, Herold's chairman and CEO, said, "The price recovery that began in 1999 has enabled many companies to adopt more-aggressive exploration and capital spending strategies, particularly aimed at finding and developing US natural gas reserves.

"The market has recognized the value this represents, rewarding-by providing capital for-successful players in these sectors. We expect this recognition to continue in 2001."

The Herold report tracked 307 publicly traded energy issues in every sector of the international oil and gas industry.

It said US exploration and production companies were the biggest winners in 2000's capital markets.

"Fueled by soaring natural gas prices, midsized domestic E&Ps recorded a whopping 118% median gain, followed by the large domestic E&Ps with 94% and small domestic E&Ps with 79%."

It said that, for the first time in 3 years, Canadian E&P stocks trailed their US counterparts and fueled a mergers and acquisitions market in Canada. E&P stocks elsewhere had a median return of 22%.

"Among the large integrated oil companies, prosperity was again confined to North America. The overseas integrated oils, due to especially weak performance by South American and Eastern European firms, posted an overall 16% decline, the only Herold peer group in negative numbers. Highlighting the unusual 2000 theme that 'smaller is better,' the large integrated oils as a whole posted only a 10.1% median gain."

Among the energy sectors, Herold said the pipeline group increased 70%, oil service firms 50%, and drilling firms 49%. The refining and marketing sector rebounded to a 32% gain in 2000 from a 17% decline in 1999.

Reserves climb

The Energy Information Administration said robust commodity prices for oil and natural gas during 1999 bolstered growth in proven US oil and gas reserves.

Proven crude reserves grew 3.5% in 1999 after declining 6.7% in 1998. EIA said that more than 137% of 1999's oil production was replaced by reserve additions, total discoveries net of revisions and adjustments. But EIA said the increase wasn't simply the result of increased drilling, successful exploration, and improved technology.

"The 1999 rebound in crude oil reserves was fundamentally driven by price increases, just as the declines of 1998 had been driven by oil prices which were too low to develop and produce much of the US resource base," EIA noted in its report.

The average wellhead price of US-produced crude in January 1999 started rising from the inflation-adjusted 53-year low of $8.03/bbl recorded in December 1998. The average price reached $22.55/ bbl in December 1999.

Crude oil discoveries, half of which were made in the Gulf of Mexico federal offshore, totaled 725 million bbl during 1999, closing in on the 10-year average. Almost all new-field discoveries, 321 million bbl, were in the Gulf of Mexico and Alaska. Other discoveries were field extensions and new reservoir discoveries in old fields.

Natural gas discoveries in the gulf declined from 1998 to 1999, but the region remained the major source of new finds of domestic gas. US gas discoveries fell to 10.8 tcf during 1999.

Texas, which experienced large gas reserve increases in 1999, was the second major gas source for the US. It also reclaimed its position as the US state with the largest crude oil reserves, after it experienced the largest increase in proven oil reserves for 1999.

US dry natural gas reserves rose for the fifth time over the prior 6 years, up 2% in 1999 after falling 2% during 1998. Gas reserve additions for 1999 replaced 118% of domestic gas production.

Reserve additions for 1999 of 11,486 bcf were twice as much as in 1998 and were 70% higher than the previous 10-year average. Gas prices increased only 7% in 1999 to $2.08/Mcf.

Capacity turnback

As the number of US interstate natural gas pipeline companies continued to dwindle through mergers and acquisitions, the survivors faced the critical issue of capacity turnback.

That is the reduction or return of capacity to the pipeline company at the expiration of a firm-transportation contract. Firm contracts—typically carrying tariffs higher than those for interruptible service—ensure the right to transport gas through a pipeline without disruption. Any contracts for unwanted capacity, in turn, must be remarketed to other prospective shippers or risk undermining the pipeline system's profitability.

The issue of capacity turnback is one that some pipelines had been dealing with for a few years, while others were still anticipating its arrival. And in light of a rapidly maturing gas industry in the US—especially since the Federal Energy Regulatory Commission (FERC) issued Order 636, which unbundled transportation and storage services from gas sales—pipeline companies were tailoring methods to coping with their own capacity turnback dilemmas.

EIA said capacity turnback was an issue for a number of US interstate pipeline systems, especially in the US Midwest, Northeast, and West. It estimated 18 trillion btu/day of firm transportation capacity would be turned back to pipeline companies as shippers' contracts expired. Basing its estimate on data from 64 pipelines, EIA said the capacity that would be turned back represented nearly 20% of the 97 trillion btu/day of firm capacity held on July 1, 1999.

Remarketing the capacity was the main challenge that pipelines faced. "Some portion of the capacity that is turned back to pipeline companies would likely be picked up by other customers," said EIA, "depending on future growth in demand for natural gas, infrastructure growth, location, and price for the capacity, and other market changes."

However, even if all of the capacity were remarketed successfully, EIA said, pipelines could still experience revenue loss due to the need to offer discounts on remarketed capacity. "This potential lost revenue could become a concern to both the pipelines and to remaining holders of transportation contracts, whose rates might go up," said EIA.

Energy policy

President George W. Bush's administration was planning to propose an energy strategy in 2001.

Bush named Vice-Pres. Richard Cheney to head a cabinet task force to draft an energy policy that would reduce oil imports.

Bush said, "It's becoming very clear to the country that demand is outstripping supply, that there are more users of electricity and natural gas than there are new units being found, and we've got to do something about that."

He said the task force would address issues such as high energy prices, reliance on foreign oil imports, and development of pipelines and power-generating capacity."

The policy was likely to be consistent with the energy goals Bush outlined during his 2000 presidential campaign.

The keystone measure would allow exploration on the coastal plain of the Arctic National Wildlife Refuge east of Prudhoe Bay oil field in Alaska. Federal revenues from ANWR would be used to fund several other energy initiatives, such as alternative fuels programs.

In addition to opening ANWR, Bush's administration would reexamine whether natural gas-prone areas of federal lands should be opened for exploration. That would not include drilling off the California and Florida coasts.

Bush also said the nation needed to ease regulatory roadblocks to the construction of refining capacity and to require federal agencies to develop a comprehensive policy for approving pipelines.

He proposed a North American energy alliance with Canada and Mexico and diplomatic initiatives directed at oil-producing nations of the Persian Gulf.

Meanwhile, Pirinc said the Bush administration and Congress should not focus an energy strategy on reducing oil imports.

"Under any realistic energy scenario, it is inevitable and unavoidable that the US would continue to meet a substantial share, currently over 50%, of its oil requirements through imports," Pirinc said.

"Import dependence per se should not be viewed as undesirable. Availability of imports, even at current prices, keeps energy costs to the US economy far lower than they would be otherwise. Moreover, major oil producers, including key Organization of Petroleum Exporting Country producers, view the US market, the largest in the world, as critical for their own economies and have acted to deepen their ties to it."

Pirinc said import dependence should not be confused with vulnerability to disruption in world oil supplies. It noted that as long as the US participates in the world oil market, a supply disruption anywhere would affect the US through its effects on worldwide oil prices.

Distillate reserve

Former President Bill Clinton during 2000 ordered the Department of Energy to establish a 2 million bbl northeastern US home heating oil reserve, which it did in November.

DOE built the reserve by trading Strategic Petroleum Reserve (SPR) crude oil for home heating oil. Bidders supplied the distillate, transportation, and interim storage facilities. They were chosen on the basis of the best exchange they offered for the SPR crude.

The American Petroleum Institute observed that creation of the home heating oil reserve was a reaction to distillate market shortages in early 2000 that were caused by severe weather that interrupted deliveries.

"Having a regional reserve does not help when the weather conditions are so severe that home heating oil cannot be moved into each individual Northeast market."

In 2000 the US Senate passed a bill reauthorizing the Energy Policy and Conservation Act, the law under which the SPR is operated.

The bill also set a trigger mechanism for use of the Northeast distillate reserve and included a provision stipulating that only firms that distribute or sell distillate can acquire products from the reserve.

DOE set a rapid procedure for selling the heating oil stored in private tankage in New Haven, Conn., and Woodbridge, NJ.

The sale process would begin when the President declared that a severe fuel supply problem justified use of the reserve. Within 2 days, DOE would notify preregistered bidders, who would submit offers by noon the next day via the internet. Winning bids would be announced later that day.

The minimum bid size would be 50,000 bbl. No one firm would be awarded more than half of the distillate at either location. High bidders could take delivery in less than 10 days by ship, barge, truck, or pipeline.

SPR release

Late in 2000, Clinton ordered the release of 30 million bbl from the 571 million bbl SPR in order to make more crude available so refiners could build distillate stocks for the winter of 2000-01. Companies taking the crude had to replace it with a higher volume of crude during 2001.

Former Energy Sec. Bill Richardson explained the National Weather Service had forecast a cold winter, heating oil inventories were down 65% in New England, and the September 2000 crude stocks were the lowest since 1976.

Meanwhile, DOE completed a 7-year, $328-million refurbishment to extend the SPR's life by 25 years. In 1993, DOE began to upgrade the four SPR sites, two in Louisiana and two in Texas.

Richardson said, "We have upgraded pumps, streamlined oil-handling equipment, and automated many of the control systems. The SPR is now ready to continue as this country's first line of defense against oil disruptions for at least the next quarter-century."

The SPR was established in 1975 following the Arab oil embargo of 1973-74. Built as a complex of deep oil-storage caverns along the US Gulf Coast, it had an initial design life of 20 years.

Its major sites were Bryan Mound near Freeport, Tex.; Big Hill near Winnie, Tex.; West Hackberry in Cameron Parish, La.; and Bayou Choctaw in Iberville Parish, La. The SPR had a capacity of 700 million bbl.

SPR also operated the St. James terminal on the Mississippi River, 45 miles southeast of Baton Rouge, La., which serves Bayou Choctaw and other facilities at Weeks Island, La.

DOE said upgrading the four storage sites would lower SPR operating costs $12-15 million/year, primarily because less equipment and fewer people would be needed to maintain and operate the site.

"Engineers were able to reduce the number of pumps needed to move crude oil by almost 40%, eliminating 60 large, high-horsepower pumping units. More than 900 of the reserve's 1,800 valves were also eliminated. Many other components have been standardized and automated, making maintenance and inventory control more efficient and lower-cost."

Dumping case

Also in 2000, the Commerce Department appealed a federal court's order that it reconsider a case alleging four nations "dumped" crude on the US market in 1998-99.

The Court of International Trade, New York City, ruled Commerce must reconsider the petition of Save Domestic Oil, which the department rejected in August 1999 on the grounds that it had insufficient industry support.

SDO, representing independent oil producers, had claimed that Saudi Arabia, Venezuela, Mexico, and Iraq had sold crude at unfairly low prices in late 1998 and early 1999.

The four nations provided more than half of US oil imports during that period. US oil prices plunged to about $10/bbl, driving some small producers out of business.

The Energy Department and larger producers opposed the SDO petition. They argued low prices were caused by the forces of supply and demand in international markets and not unfair pricing by a handful of oil-producing countries.

The court ruling required Commerce to determine the extent of oil industry support for the SDO petition. If it determined SDO had standing, then it would determine if the oil industry was injured by the imports. The next step would be for Commerce to determine if the imports were subsidized; if so, it could impose countervaling duties to raise the price of the oil to market levels.

The latter action was improbable, since oil prices by 2000 had more than doubled since SDO brought the action.

Royalty rule

After four revisions and 4 years, the Minerals Management Service (MMS) issued a final rule in 2000 revising the procedures that producers use to calculate the cash royalties they owe the government on production from federal lands.

The rule affected 230,000 b/d of federal royalty oil, less 50,000 b/d being sold through royalty in-kind and small-refiner programs. MMS said, overall, federal leases produced 1.7 million b/d in 2000.

The Independent Petroleum Association of America subsequently sued to overturn the regulation. In particular, it challenged a provision stating lessees had a duty to market royalty oil without reimbursement from the government for their expenses.

MMS said the rule, which eliminated most uses of posted prices to determine royalty values, would increase federal royalty revenues by $67.3 million/year. It said the net effect on the oil industry would be $63.5 million, because producers would save $3.8 million/year from not having to file administrative appeals.

MMS said producers were unlikely to pass their additional royalty costs on to consumers, but if they did, they would amount to less than 0.1¢/bbl of refined product.

The agency said the 10 major integrated oil companies would pay 88% of the additional revenues, large independent producers with refining capacity would pay 8%, and small producers would pay the rest.

MMS said the rule would allow it to accept royalty oil values determined by prices set in arm's-length contracts with buyers.

MMS agreed to language affirming that its auditors would not second-guess producers' marketing decisions in arm's-length sales.

For sales that were not arm's-length, MMS would determine values using market-based spot pricing-with adjustments for transportation and quality differentials. Different valuation methods would be used for different areas of the country, particularly the Rocky Mountains.

In California and Alaska, the value would be tied to Alaskan North Slope crude, with adjustments.

In the Rocky Mountains, MMS would allow values to be set by tendering, arm's-length, or spot pricing methods, where applicable.

In the rest of the US, prices would be determined by the spot price at market centers, adjusted for location and quality differentials.

The rule allowed producers the costs of transportation, allowed for depreciation on pipelines, set criteria for determining company affiliation, and bound MMS to its value determinations.

The rule did not allow marketing costs as a deduction from royalties.

MMS said it was "a well-established principle of oil and gas law that lessees have the duty to market production for the mutual benefit of the lessee and the lessor, with no deduction for costs of marketing."

Order 636 upgrade

In 2000 FERC adjusted its regulatory framework governing the interstate gas market and transportation grid.

FERC said the rule, under consideration for 2 years, would improve the efficiency of the gas transportation market.

The rapid development of competitive markets following the agency's Order 636 had dated its regulations, said FERC.

The final rule removed price ceilings for short-term, secondary market capacity releases. FERC would reevaluate that action Sept. 30, 2002.

The rule allowed pipelines to propose peak and off-peak rates to coordinate rate regulation with the seasonal demands of the market and allocate revenue responsibility between short-term and long-term markets.

FERC would allow pipelines to use term-differentiated rate structures in contracts.

It revised regulations regarding scheduling procedures, capacity segmentation, pipeline penalties, and the right of first refusal. And it revamped the information that pipelines must report to FERC, with the goal of obtaining "more-transparent" pricing data.

FERC was considering other issues, such as negotiated terms and conditions of service, rate design changes, discount adjustment and rate reviews, capacity auctions, and more market-based rates.

The commission ordered its staff to develop gas market-monitoring capability and to discuss emerging market issues with gas industry groups.

Diesel sulfur rule

The Bush administration declined in early 2001 to attempt to reverse the Environmental Protection Agency's low-sulfur diesel rule, finalized in the last weeks of the Clinton administration.

Refiners had urged it to revisit or rewrite the proposal. The National Petrochemical and Refiners Association sued to overturn it.

The plan required refiners to slash highway diesel sulfur levels to 15 ppm by June 2006 from 500 ppm in 2001.

EPA said the rule would cost industry $4.2 billion/year but would produce more than $70 billion/year in benefits by reducing health costs associated with the public's exposure to smog and soot.

The industry estimate of the rule's cost was far higher: about $8 billion in up front capital investment and a 12¢/gal increase at the pump to consumers.

Environmental and public health groups applauded the initiative, saying EPA's plan would save lives and dramatically reduce respiratory illnesses associated with diesel exhaust. Oil industry officials said while refiners were willing to lower sulfur standards, the low levels were not cost-effective and could cause supply shortages.

In a concession to refiners, EPA Administrator Christine Todd Whitman said she would ask an independent advisory board to examine how the rule could affect diesel supplies. The board would also study technology trends.

Bossier play

The hottest onshore exploration and development activity in the US during 2000 was the Bossier play in the East Texas basin.

Rig counts doubled to 100 rotaries in Texas Railroad Commission Dists. 5 and 6, covering the counties from Sabine and Bowie along the Louisiana line to the Fort Worth area and Bosque County on the west.

At one time Anadarko Petroleum Corp., Houston, had 27 rigs drilling for the Jurassic Bossier sands in East Texas and six drilling a similar type play in Jackson Parish, La.

Seven wildcats Anadarko drilled in 2000 in Freestone and Robertson counties encountered commercial gas in Bossier.

After drilling 142 Bossier development wells in 2000, Anadarko planned 186 development wells and 36 exploratory wells in the play during 2001. It spudded its 300th well in the play in early 2001.

Other operators in the Bossier play included Cross Timbers Oil Co., Fort Worth; Pioneer Natural Resources Co. and Matador Operating Co. of Dallas; El Paso Production Co. and Marathon Oil Co. of Houston; and Ivanhoe Energy Inc., Calgary.

More than 500 wells were expected to be producing gas from Bossier by yearend 2001, Anadarko said.

Anadarko budgeted $535 million for the Bossier play in 2001. The previous year it boosted its lease position 150% to 250,000 acres in East Texas and North Louisiana.

The company noted that Bossier wells have long reserve lives and hyperbolic decline rates: They average 3 MMcfd, decline rapidly to slightly less than 1 MMcfd, and produce for many years.

Anadarko's best Bossier well of 2000, A3 Blair in Dew field, Freestone County, flowed 50 MMcfd with 4,600 psi casing pressure. Another standout, A1 Thigpen, also at Dew, flowed 15.7 MMcfd with 3,400 psi casing pressure. TD was 13,500 ft.

Coalbed methane

The Powder River basin of northern Wyoming and southern Montana saw a high level of coalbed methane drilling in 2000.

The Wyoming State Geological Survey said 25 tcf of coalbed methane may be recoverable from the basin, up from previous estimates of 9-12 tcf.

The increased activity launched a flurry of pipeline construction and acquisitions.

Anadarko Petroleum planned to spend more than $131 million in 2001 on gas and coalbed methane prospects. It planned to drill more than 20 exploration wells and 130 development wells in Wyoming, Colorado, and Utah, and planned to participate in more than 275 wells operated by other companies.

In Wyoming, Anadarko had interests in seven coalbed methane plays. It planned to drill 35 wells in the Powder River basin in 2001.

One of the leading Wyoming coalbed methane operators, Pennaco Energy, Inc., was acquired by Marathon Oil for $500 million.

Pennaco, Denver, produced only coalbed methane gas from the Powder River basin. It was one of the largest leaseholders with more than 400,000 net acres and net production of over 50 MMcfd. Net proven reserves were 200 bcf.

Bighorn Gas Gathering LLC, Tulsa, signed agreements with Prima Oil & Gas Co., a subsidiary of Denver-based Prima Energy Corp., to provide gathering services for Prima's coalbed methane production on 10,000 acres.

Bighorn would extend its system west of Gillette, Wyo., to provide gathering services for Prima's 4,000-acre Kingsbury/Throne prospect in Campbell County, where Prima had drilled more than 30 wells and had 70 potential well locations.

Bighorn also would serve 6,000 acres of property leased by Prima in Campbell County. Prima had drilled 110 coalbed methane wells in the county's Stones Throw prospect area and expected to begin production by late 2001.

Wyoming Interstate Co. Ltd. (WIC) planned to loop its southeastern Wyoming Medicine Bow Lateral, increasing capacity out of the Powder River basin by 675,000 dekatherms/day (Mdth/d).

WIC said producers had committed to firm contracts to transport 556 Mdth/d on the expanded system.

The existing lateral was a 24-in. line that extended from the southern end of the Power River basin near Douglas to WIC's main line southwest of Cheyenne. The proposed $160 million lateral loop project would parallel this line with a 36-in. pipeline and add 7,170 hp of compression. Completion was expected in late 2001.

Northern Border Partners LP, Omaha, Neb., bought Enron North America Corp.'s (ENA) gas-gathering facilities in the Powder River and Wind River basins for $200 million.

Included in the purchase were Enron Midstream Services LLC, which held an ownership interest in Bighorn Gas Gathering LLC, and the ENA subsidiaries that held ownership interests in Fort Union Gas Gathering LLC and Lost Creek Gathering LLC.

Fort Union had an existing 106-mile gas gathering system in the Powder River basin. Lost Creek owned a 123-mile gas-gathering system in the Wind River basin. Bighorn had a 92-mile gas-gathering system in the Powder River basin, which was being expanded by 56 miles.

Trenton gas play

Plays for gas in Ordovician zones in central West Virginia drew attention in the Appalachian basin.

Columbia Natural Resources Inc., Charleston, W.Va., touched off the play in 1999 with a Trenton discovery in Roane County that had bottomhole pressures of 6,600 psia and indicated flow capabilities of around 50 MMcfd. CNR had similar results at a second well.

CNR's success prompted the company and other operators to stake 20 exploratory tests to Ordovician or deeper formations in southeastern Roane County, 20-30 miles northeast of Charleston.

CNR completed an 8-in. pipeline in late 1999 to transport gas from its Cottontree field in Roane County. The field area was part of a cluster of drilled and permitted wells 2-5 miles west of Amma, W.Va. Other clusters were 5-6 miles west of Minnora, 3-4 miles east of Looneyville, and 4-5 miles west of Looneyville.

Permits for all of the wells were 10,000 ft or deeper. One independent, Ardent Resources Inc., Bethel Park, Pa., planned a 15,000-ft test to Cambrian in Calhoun County northeast of the play.

Lease prices exceeded $300/acre in some areas. Before the exploration play, less than two dozen wells had penetrated Ordovician zones in the state.