Producers, consumers
paint new power picture

Effects of last year’s crisis still being felt

Whatcom County has been taking power for granted ever since cheap hydro became available in the late 1930s. When we flip a switch, we expect the lights to come on. One result of last summer’s power crunch has been to shake us out of that complacency. There is general agreement that while companies like Enron took advantage of the situation, they did not create it. Trouble has been brewing for some time and increased generating capacity is only part of the answer.

In order to understand the situation in Whatcom County, it is vital to realize that we do not stand alone. Power problems and solutions happen on a regional basis and the situation is far more complex than is generally portrayed in the media.

Doug Thomas is president and CEO of Bellingham Cold Storage (BCS), a major consumer of power. Last year’s volatile power markets forced him to become an expert on the issue.

“Electrons take the path of least resistance,” Thomas explained. “They go where the demand is, regardless of where they were generated.”

This is why increased generating capacity in Whatcom County may have little effect on local power consumers. Even if the 660 megawatt SE2 facility in Sumas wins approval, there is no way under the present system to guarantee that the power will end up here in Whatcom County. What it will do is increase the overall supply on the regional grid. When that output is compared to the overall demand, however, it’s a pretty small drop in the bucket.

California is the 600-pound gorilla in the western power zoo. When California’s demand peaks in the summer months, much of the power comes from Washington, Oregon, Idaho and British Columbia. The northwest grid ships power south through the California-Oregon intertie.

California’s generating capacity falls far short of meeting the state’s demand. Part of this is due to a deregulation scheme that backfired and part is due to policies intended to protect the state’s environment. California, in other words, wants the power but not the pollution that comes with it.

Most of the time, the massive hydroelectric capacity in the other states on the western grid is sufficient to meet the demand. Over time, however, the percentage of power supplied by hydro has slipped from 65 percent in the 70s to a far lower figure. Last year, a combination of circumstances produced what power experts refer to as “the perfect storm.” New generating facilities were not coming on line because the economic incentives were not sufficient to make it profitable. The northwest endured a record-setting drought that reduced the usual runoff into the Columbia and Snake Rivers to a comparative trickle. Hydroelectric producers were restricted by regulations designed to protect dwindling salmon populations. California suffered an unusually hot summer. At times, the demand exceeded the supply, resulting in the infamous “rolling brownouts.”

Regulatory and economic factors aside, power producers can’t base their planning on “the perfect storm.” As Thomas put it, “You don’t build the church for Easter.”

This situation also produced the wild fluctuations in power prices, at least some of which were exacerbated by market manipulation.

“The jury is still out,” said Thomas, “on whether that manipulation was criminal or just unethical.”

Many major power consumers that were served by utilities like Puget Sound Energy (PSE) opted to buy their power on the spot market. For years, that saved them money. When the supply literally dried up, the resulting price increases nearly ran many of them out of business. Some tried to return to the private utilities, but the capacity to serve them was no longer there.

Officials at Bellingham’s Georgia-Pacific West, Inc. (G-P), saw power costs go from seven percent to 40 percent of operating expenses. The resulting losses played a significant part in the decision to close the chemical plant. That closure reduced the facility’s power demands by more than 75 percent and G-P installed a gas turbine with the capacity to supply most of the plant’s needs.

G-P had been locked into purchasing power from Puget Sound Energy at a rate tied to the Mid-Columbia index. This was the same index that reflected the California market at record highs. G-P has now negotiated a settlement with PSE that allows them to purchase power on the open market. The contract with their current provider runs through this year and G-P officials are working on extending it or seeking other providers.

Abundant and cheap energy resulting from the northwest hydro projects lured many power-hungry industries to locate here. Foremost among these is the aluminum industry.

Where an average residence might draw 30 kilowatts and a business like Bellingham Cold Storage might draw 10 megawatts, an aluminum plant will draw as much as 480 megawatts. Picture your home as a garden hose, BCS as a fire hose, and Intalco as a water main. 450 megawatts is about half of what the entire city of Seattle draws.

That’s why it made economic sense for the Bonneville Power Administration (BPA) to pay the workers at Alcoa Intalco Works in Ferndale, take the plant offline, and market the power elsewhere. It’s also one of the reasons why Intalco and other aluminum producers remain on shaky ground. If the price of aluminum on the world market remains low, more shutdowns, temporary and permanent, may be in store.

Jack Speer is northwest energy director for the Alcoa Corporation. He notes that the days when BPA could serve the aluminum industry without breaking a sweat are gone.

“Bonneville is now allocating 600 megawatts for all the aluminum plants in the state,” Speer said. “If Intalco is allocated 100 megawatts from Bonneville, it has to buy 380 megawatts at higher market rates and may not be able to compete on the world market.

The average rate for aluminum plants worldwide is $19 per megawatt hour (MWH). Under our present contract, we are paying $32 per MWH just for the power we get from BPA.”

Alcoa’s contract with BPA expires in 2006 and the industry is already trying to figure out how to insure power supplies for the future. Alcoa is participating along with other industries, utilities and BPA in the Northwest Power Planning Council. Long-term solutions have yet to be found, but at least they’re talking.

“The only reasons Intalco can compete right now,” said Speer, “are because the plant is largely depreciated, has a lower debt load, and is highly efficient. BPA is still paying Intalco not to use power, but that will end next year.”

While Intalco’s future remains uncertain, it is still better off than the Alcoa facility at Troutdale in Oregon. That facility is being dismantled because it can’t produce aluminum at a price that will make it competitive on world markets.

Alcoa is also experimenting with a new smelting process that would require substantially less power. The new process would also be a boon to the environment. Current smelting processes emit large amounts of carbon dioxide; the new process would emit only oxygen.

When the lights go off at home, it’s usually a minor annoyance. If the power goes off at Bellingham Cold Storage, it’s a major disaster. Power represents 34 percent of the company’s operating costs and prior to last year’s crisis, the bill ran about $2 million a year. When market prices peaked last summer, BCS paid as much as $1.1 million in a single month. That was when Doug Thomas’ learning curve also peaked.

He credits the Talbot family, which owns the facility, with giving him the flexibility to address the problem. Thomas purchased a one-month “hedge” from IDACORP Energy Services, which capped prices for the month of June, and another hedge in July. IDACORP lost money in the short term, but gained a big customer in the long term. BCS now has a multi-year deal with the Idaho company.

There’s another hedge sitting next to the BCS facility on Bellingham’s waterfront: a natural gas fired generator capable of supplying the facility’s needs in an emergency. If prices spike again, it may make economic sense to fire it up.

Large industrial consumers of power are known as DSIs, or direct service industries, meaning they often purchase their power directly from producers rather than local utilities or public utility districts. After last year’s brouhaha, many of them are seeking to stabilize their energy sources.

BP Cherry Point Refinery has proposed building a 750 megawatt natural gas fired plant on its property west of Ferndale. The company has asked EFSEC, the state Energy Facility Site Evaluation Committee, to make a potential site study for the project. The cogeneration plant would also produce steam for the refinery, enabling BP to eliminate some of its older boilers and reduce overall emissions.

The BP plant has a number of advantages over some of the other facilities proposed in the state. Most of the proposed facilities would be fired by natural gas. The transmission system for that commodity is nearly taxed to its limits right now and new pipelines have been rejected on a regular basis. BP, however, has its own pipeline bringing in gas from Canada to the refinery.

There is an intertie to the Bonneville Power grid at the eastern edge of BP’s property, which would preclude the necessity for new transmission lines. Those lines are problematic at best and a major factor in why the power can’t always get where it’s needed.

The geography of the Cherry Point area is much less susceptible to trapping pollutants than the Fraser Valley. That factor was a major stumbling block for the proponents of the SE2 facility. BP’s noise modeling indicates that there would be no perceptible increase.

Project manager Mark Moore believes that about 350 jobs would be created during the construction phase and 30 permanent jobs once the plant is in operation.

If the proper arrangements can be worked out, the proposed BP plant could sell power to the adjacent Intalco Works, thus eliminating a major drain on the regional grid. Intalco is currently buying its power from a supplier other than Bonneville, which they would prefer not to disclose for competitive reasons.

“Our project does not depend on selling power to Intalco or Phillips 66,” said Moore. “It depends more on what BPA plans to do.”

Does approval of SE2 mean that the BP project faces an uphill battle? Not likely. The current demand is such that the success of both facilities will only make a dent in it.

The problem goes beyond generating capacity. Building new power plants doesn’t help much if the transmission system is inadequate. Almost everyone agrees that it is. BPA controls 75 percent of the transmission capacity in the northwest and they admit it’s not enough.

“There are problems moving power both north to south and east to west,” said Stuart Clarke, senior account executive with BPA. “FERC (Federal Energy Regulatory Commission) needs to reestablish the rules for selling transmission rights.”

FERC has asked utilities to design and fund the formation of regional transmission organizations (RTOs). BPA and the private utilities would turn over the operation of their transmission lines, substations and other equipment to the RTO so that the system would be controlled by one entity.

In 1996, FERC ordered the utilities to open up their transmission lines to all power generators. This increased the use of the transmission system without guaranteeing adequate investment in infrastructure.

Transmission systems are not only expensive to build and maintain, but are controversial because they often cross environmentally sensitive areas. In trying to keep costs low for customers, BPA made little investment in the system during the 1990s. That investment must be made if the electricity is to get where it is needed and it needs to be made whether or not the RTOs become a reality.

RTOs are a hotly debated topic among industry leaders. Some believe that a well-run RTO will reduce the cost of electricity to consumers. Others insist that the RTO is an expensive and unnecessary bureaucracy, which consumers will pay for through higher transmission rates.

If an RTO West is formed, it will not legally be able to own transmission lines. Instead, it would function as a watchdog insuring that utilities are building and maintaining their systems. The level of authority given to the RTO is still uncertain.

No one questions the need for significant investment in the transmission system and it is possible that ratepayers will see an increase as a result. There are no answers yet as to how the proposed RTO would affect this amount.

There are those who believe that a more distributed system would solve both supply and transmission problems. However, this tends to result in a trade off: fewer lines, but higher prices since the economies of scale do not come into play.

Salmon, which play a huge role in the culture of the Pacific Northwest, are also part of the equation.

“Salmon are key to the health of the environment,” said Clarke. “If salmon can’t survive, we face a significantly changed environment.”

The Regional Power Act of 1980 charged BPA with mitigating damage to the anadromous fish. Some water now must be used to support salmon instead of generating power. This ends up costing about $560 million a year, all of which is passed on to ratepayers. There is a continuing dialogue about whether salmon can be protected more efficiently.

Public and private utilities have put forth a proposal to restructure the northwest hydrosystem through new 20-year contracts. These would allot federal power through “slices” or percentages of the system’s capacity. The plan is making salmon protection advocates nervous because they believe it pays very little attention to legally mandated salmon recovery goals.

“We’re not saying ‘Hell no, we won’t go,’” said Shawn Cantrell, northwest regional director for Friends of the Earth. “We’re simply saying that the proposal on the table is alarmingly thin on details.”

A coalition of fishing and conservation businesses called Save Our Wild Salmon (SOS) has suggested a set of five principles be adopted to insure adequate species protection. Among those principles, SOS urges that the final plan be so structured that it will meet current and future legal obligations of salmon recovery and remove economic and operational incentives to violate those requirements.

Obviously, there are no quick fixes or easy solutions. What has changed is the motivation on the part of all concerned to take action. The one thing all the diverse interests seem to agree on is that we can’t afford a repeat of last summer’s debacle.