The treacherous journey toward a more efficient and transparent Northwest power market may be nearing its conclusion.
Steve Wright stands at the helm of an agency with a seemingly impossible task. As CEO and administrator of the Bonneville Power Administration (BPA), Wright must serve a broad spectrum of interests, from aluminum smelters to sockeye salmon. And no matter what he or anyone does, it's impossible to make them all happy at the same time.
In 2000 and 2001, when power shortages caused brownouts and price spikes on the West Coast, several load-serving utilities and big industrial customers showed up at BPA's door, looking for power. These customers previously had negotiated out of their BPA contracts so they could obtain cheaper supplies on the wholesale market. Now they were seeking shelter under the federal dams of the Columbia River system.
BPA took them back, pursuant to law, tradition, and regulatory edict.1 But the sudden influx of demand outstripped BPA's generating resources by more than 30 percent. The agency was forced to take drastic measures. It bought down its commitment to some industrial customers, and it contracted for more than 3,000 MW of additional purchased power.
Those contracts were signed in October 2001-virtually the worst possible time to buy power in the Western wholesale market. But BPA's administrator had little choice.
"There's a limited amount that you can do in that situation," Wright says. "You're dealt a set of cards and you can move them around, but you have limited options to change the fundamental setup."
Wright refers to his obligations under the Northwest Power Act of 1980. The act directs the BPA administrator to "acquire any electric power required by ... any customer or group of customers to enable them … to serve firm load."
So BPA met the demand, but at a huge cost. Moreover, following its usual procedure, BPA "melded" the high-cost purchased power with its own low-cost hydroelectric and nuclear capacity, to distribute costs among all its customers. But the contracted power was so expensive that it resulted in a 46 percent rate increase across the board. BPA's other customers were furious.
"No one wants to repeat the experience of the last three years," says Patrick Reiten, president and CEO of PNGC Power, a Portland, Ore.-based consortium of generation and transmission cooperatives. "The region has come to a solid consensus that Bonneville should not be serving loads in excess of the resources that it has. And to the extent it must, the cost should be picked up bilaterally by the entities that want those resources."
Such an elementary proposal seems eminently reasonable, but in fact it has added fuel to a raging inferno of controversy in the Pacific Northwest. The conflagration centers on disagreements over how BPA operates; who gets dibs on Bonneville's power capacity; and, ultimately, the operating structure of the entire Northwestern power grid. Such momentous issues, furthermore, are being considered within the context of persistent drought conditions, endangered fish populations, and a massive budget shortfall.
Given such challenges, few would envy Administrator Wright's position. Yet Wright has reason to hope that finally the region's fortunes might be turning around.
First, the BPA managed to squeeze an additional $700 million of borrowing capacity out of the U.S. Congress for fiscal year 2003, allowing it to build badly needed transmission capacity, including the region's first new 500 kV-line in decades. "Infrastructure is destiny," Wright says. "The way you avoid price volatility and reliability problems is by building adequate infrastructure."
Second, more than 2,000 MW of new generating capacity has entered service in the Northwest since 2001, taking some of the pressure off BPA's resources.
Finally, in the past year the region's major stakeholders have taken important strides toward a functioning regional transmission organization (RTO). At the same time, consensus is building to create a new role for the BPA that would facilitate private investment in wholesale power supplies, while ensuring that BPA's customers continue to benefit from federal hydro assets. Such efforts are laying the foundation for a more stable and efficient Northwest power market-or at least one hopes they are. The current process-the third wave in an ongoing series dating from 1996-does show signs of greater promise.
"I'm reasonably optimistic that solutions will be found for an effective Grid West [the new name for RTO West], and for BPA to participate in it," says Harvard Spigal, a partner with Preston Gates & Ellis, and previously BPA's senior vice president and general counsel. "In time, the problems that people have had in the past will be worked through."
But, having seen it all before, Spigal adds, "How you get there, and the degree of consensus necessary, is less clear."
Troubled Waters
Depending on whom you ask, the source of the Northwest region's recent power-system problems can be traced back to 1999, 1980, 1937, or even earlier.
In the late 1880s, commercial salmon fishers depleted many fish populations in the region's rivers. Those ecosystems had not recovered by the time dam-building began in the Columbia River system.2
In the 1930s, Congress created the Bonneville Dam Project to boost the Northwest economy and harness water resources for agriculture and power generation. In 1937, the first BPA administrator was endowed with broad powers to manage hydro-dam operations. On this foundation, the agency would become a dominating force in the Northwest region. BPA now owns 75 percent of the transmission lines and generates more than 40 percent of the power in its jurisdiction.
Fast-forward to 1980. Congress passed the Northwest Power Act to allocate the finite power resources of the Columbia River system among the many groups of customers clamoring for its output. The act prioritized the loads of public utilities (primarily cooperatives) and residential and small-farm customers of investor-owned utilities (IOUs). It also mandated that BPA pursue conservation, renewable energy, and fish and wildlife habitat mitigation.
In 1992, the Energy Policy Act began the process of restructuring the U.S. power grid, and in 1996 FERC Order No. 888 opened the door further to wholesale power wheeling. This set the stage for the departure of Bonneville's prodigal sons-certain load-serving utilities and large industrial consumers (termed direct-service industries [DSIs]).
"Some customers started to drop off Bonneville, to find power in the deregulated market," says Jim Kempton, Idaho member and power committee chairman for the Northwest Power & Conservation Council (NWPCC, formerly the Northwest Power Planning Council).
During this time, some stakeholders in the region began arguing that in a deregulated power market, Bonneville's structure created some fundamental problems. Namely, its dominating position, by virtue of the massive transmission system and generating assets that it controlled, would make it difficult for wholesale competitors to make inroads in the region.
"Institutionally, the transmission business line has been a handmaiden to the power business line," says Robert D. Kahn, executive director of the Northwest Independent Power Producers Coalition (NIPPC) in Mercer Island, Wash. "We as generators are transmission customers of BPA, and regularly we are treated as second-class citizens."
Bonneville voluntarily agreed to functionally unbundle itself, creating separate business lines for power generation and transmission. A group of state governors and other stakeholders in the region, however, saw issues that unbundling alone could not address. So they collaborated to develop a set of recommendations for BPA's future-the Comprehensive Review of the Northwest Energy System.3
"BPA's vertical footprint was so huge that the region was incompatible with the concept of a deregulated electric industry," Kempton says. "The 1996 review was an attempt by the region to accommodate the real world as the U.S. Congress had defined it." Key features of the proposal included the recommendation that BPA sell its output through long-term (20-year) contracts, reducing uncertainty and creating a more distinct allocation of the resource. Additionally the review concluded that Bonneville should minimize its acquisition of power supplies from outside its existing asset base, to limit its exposure to wholesale market risks and more appropriately allocate incremental costs (i.e., to the utilities or DSIs that would request the power).
This proposal failed to yield a consensus, but it staked out the territory for debate that would resume in later proceedings.
RTO Redux
When the Federal Energy Regulatory Commission (FERC) issued Order No. 2000 in 1999, the region's transmission operators began collaborating to develop a proposal for the RTO West organization. Then two things happened: the Western energy crisis hit, and FERC proposed a rulemaking on standard market design (SMD).
FERC's SMD proposal worried various stakeholders because of the prescriptive nature of the market it envisioned. "It created substantial alarm among many of the interested parties," says Bud Krogh, a partner with Krogh & Leonard in Seattle, and coordinator of the region's RTO-development process. "The perception was that FERC wasn't going to be responsive to the unique aspects of the system in the Northwest. That one act led to tremendous opposition from a number of regional parties, and we fundamentally lost the base of support in the Northwest region to continue going forward on those specific proposals."
Stakeholders felt that the SMD was a mismatch to the region's heavy reliance on hydropower-a resource that responds primarily to environmental and operational factors rather than the economic needs of the market.
"A lot of issues arise from uncertainties in the generating capacity of the system," Kempton says. "In a hydro system, you have some advantage in the reserve capacity, but you compromise other parts of the program." In other words, a hydro plant can reduce spill or draw down the reservoir to produce more power on demand, but doing so will affect fish migration and reservoir levels.
"You are pulling water out of the system, and it will have to be replaced later," Kempton says. "The integrated network is very complex, and it can't meet the same standards you can meet in a system with mostly thermal plants."
A second problem with the SMD was the dominance in the Northwest by entities not regulated under FERC's jurisdiction, including BPA and numerous cooperatives, municipals, and other public power utilities. As a result, FERC would have limited ability to ensure that the bulk of the market's participants were complying with its market behavior standards.
"We agreed to be in voluntary compliance with Order No. 2000," Wright says. "We've shown that we are doing everything possible to get the most out of the existing system, and that investments are being made in a cost-effective way. We have managed to deal with the issues that have arisen, but there always will be a concern about whether Bonneville will choose at some future date to operate transmission systems for its own benefit."
FERC provided RTO West with flexibility on a number of issues; for example, the commission accepted the RTO's proposed eight-year transition period, and its alternative plans for handling congestion management, in the context of the region's hydro-intensive system. Nevertheless, consensus for RTO West had deteriorated as various stakeholders became disenchanted with the process, and the effort stalled.
Then FERC published its wholesale-market white paper in April 2003, signaling that the commission was open to significant regional flexibility. This revitalized the effort, and allowed the stakeholders-embodied in the regional representatives group (RRG)-to regroup and begin their efforts again. But this time, the process would start with a clean slate.
"If we were going to be successful, we realized we were going to have to start by looking at the problems and opportunities facing the region, and develop broad regional consensus on the process and the solutions," says John Carr, a vice president with Pacificorp in Portland, Ore. "We went back to re-engage the region and reached out more directly to the state commissions and governors' offices."
The result was the Grid West proposal, which now is being developed as a homegrown RTO, rather than one based on a model handed down by federal regulators.
"Grid West came out of a bottom-up approach, from the grist of the regional problems that we were experiencing," Carr says. "Where RTO West was a full package with consolidated control areas, financial transmission rights, etc., Grid West is a staged approach that has a well-defined beginning state and a process for moving further. It's a much more evolutionary approach."
The Grid West structure is still in development, but in general, the first stage provides for an independent operating structure and sets forth principles that are intended to facilitate region-wide grid planning and an arm's-length approach to valuing and allocating resources on the system.
"Grid West will have a broad, regional approach to planning transmission additions," Carr says. "It will be able to identify who are the beneficiaries of the new transmission infrastructure in a way that can be used to determine who should pay for it. In the big picture, this is the biggest benefit that it brings."
BPA's New Groove
As efforts toward the Grid West RTO have proceeded, so have initiatives to modernize and restructure BPA's operational structure. Although these two separate efforts are interdependent and interrelated in many ways, they both require major changes at BPA.
"These two proposals force the agency to stare the future in the face," says Kahn of NIPPC. "How BPA chooses to react remains to be seen."
The Northwest Power Planning Council published a set of preliminary recommendations in 2002 for BPA's future role, based on stakeholder discussions regarding the agency's operating conditions. The process was put on hiatus for much of 2002, as BPA faced a financial crisis precipitated largely by the agency's costly power contract arrangements from the previous two years. Efforts resumed in 2003, and in early 2004 the NWPCC produced a series of recommendations intended to provide input to BPA and other organizations considering the agency's future role.
The recommendations4 are timely, considering the status of the BPA's current customer contracts, some of which are set to expire in 2007, and the rest in 2011. Already many of BPA's major customers-including the region's investor-owned utilities-have renegotiated their contracts through 2006. But agreements still must be negotiated for subsequent years.
"It takes literally years to make changes, so starting now is imperative to focus on the period starting in 2007, and to get prepared for the post-2011 period," says Scott Brattebo, director of regulation for Pacificorp. "Bonneville will have new rates in place, so we already are beginning to start working on new ideas for how it should restructure rates."
Adding to the urgency, BPA's generation inventory is projected to be exhausted in about 2008 or 2009, and the agency's customers need to know what the procedure will be for securing new power supplies.
"In the past Bonneville inventories were adequate to meet the demands of preferred customers, but that's not so going forward," Brattebo says. "There is a general consensus among BPA's customers that they don't want Bonneville to continue investing in new required resources to meet load growth. The responsibility to seek non-federal resources to meet their load should pass to the utilities."
Customers that would call upon BPA to acquire new power supplies to meet their load growth would be expected to bear the incremental cost of those new power supplies. In other words, the days of melding purchased power with federal power to serve preferred customers and DSIs will come to an end, and BPA's preferred customers would no longer need to worry about the potential effects of high-cost incremental power.
At the same time, load-serving customers are seeking greater confidence that BPA's contracted prices will remain stable over the long term. Thus, the NWPCC recommendations call for BPA to offer 20-year power sales contracts.
"Everyone recognizes that things will happen that will require changes in the rate structure," Kempton says. "But in those cases they want a mechanism for examining their options within the process of a 20-year contract."
Bonneville acknowledges the need for changes in its operations and has announced plans for a policy process in the summer of 2004 to define its future role and address medium-term contract issues.
"We are trying to create clarity about the obligation to serve," Wright says. "We want to be clear about the use of the existing system, who will get how much, and about who will have the obligation to serve load."
By addressing both the agency's role and the regional market structure, stakeholders are ensuring a more stable future in the Northwest. Additionally, they are laying the groundwork for a market that will attract badly needed infrastructure investment. The challenge now is to sustain the momentum that the regional representatives have developed and reach an end state that satisfies everyone's needs.
"Have we created the institutional structures to make sure that steady investment will happen over time?" Wright asks. "No, we haven't. That's why we are interested in creating Grid West and bringing clarity on our obligation to serve."
If the agency and the region can accomplish these tasks, then the Northwest will be well prepared to meet 21st century power demands. And BPA's multiple masters will become slightly easier to please.
Endnotes
- Then-DOE Secretary Bill Richardson brokered a deal wherein the aluminum mills would curtail operations and resell up to 1,000 MW of power that BPA would acquire in the wholesale market. The deal effectively subsidized aluminum industry jobs, arguably at the expense of BPA customers. See Redman, Eric, "The Aluminum Lobby: Impact of the Direct Service Industries on Electric Consumers of the Northwest," , Spring 2002, Willamette Public Policy Research Center.
- Lackey, Robert T. 2001. "Salmon and the Endangered Species Act: Troublesome Questions." . (19(2): 6-9); (http://www.epa.gov/wed/pages/staff/lackey/pubs/trouble.pdf).
- , Northwest Power Planning Council, Dec. 12, 1996 (CR96-26); (http://www.nwcouncil.org/library/1996/cr96-26.htm).
- , Northwest Power & Conservation Council, May 2004 (NWPCC 2004-05); http://www.nwcouncil.org/library/2004/2004-5.pdf.
Water Worries
Environmental factors are playing a larger role in the Pacific Northwest energy drama, with some interesting ramifications for the region's power supply future.
Recently the spotlight turned to global warming and climate change effects. The latest climate model, released in February 2004 by the U.S. Department of Energy's Pacific Northwest National Laboratory (PNL), indicates that in the best-case scenario, snowpack will shrink by up to 70 percent in the coastal mountains during the next 50 years. This would have widespread regional effects, possibly including reduced hydropower production in the spring and summer months.
During the Western electricity crisis, low-water conditions contributed to power shortfalls in California and price spikes throughout the region. Such conditions also put increased pressure on river ecology.
In the context of growing environmental concerns, policy-makers and utility planners are focusing on windpower and conservation opportunities to meet a greater share of future power demand. Renewable portfolio standards and other initiatives directly encourage investments in renewables and conservation, and efforts to establish the Grid West RTO might yield transmission investments that could bring power generated in such windy states as Wyoming, Montana, and Idaho across the mountains to serve loads on the West Coast.
On a purely economic basis, however, windpower alone will not support much new transmission infrastructure in the foreseeable future. The investment required to traverse the mountains requires a more lucrative opportunity-for example, the coal fields of Wyoming, Montana, and Idaho.
"In effect, the windpower industry is partnering with the coal industry," says a source who asked not to be identified. "Those states have windy places and coal reserves, as well as a crying need for economic development and an enhanced tax base. With the next generation of the transmission system, we will pick up wind along with coal."
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