The Northwest Power and Conservation Council’s Fifth Northwest Power Plan responds to an energy crisis that developed over a period of about five years, largely unnoticed, and then burst upon the Northwest in the fall and winter of 2000 and the spring of 2001. The Council dissects the crisis — its causes and impacts — in the power plan and then makes a number of policy recommendations for how to avoid a repeat of the crisis in the future.
The Council analyzed the energy crisis and responded to it in the Fifth Northwest Power Plan. The following discussion is condensed from the power plan and from other Council documents and analyses that addressed the causes and impacts of the crisis.
The Western electricity crisis has been referred to as the “perfect storm” — the result of the confluence of a number of adverse trends and events. It had its roots in several years of under-investment in generating and conservation resources. It was triggered by the onset of poor hydropower conditions in the late spring of 2000 leading to the second-lowest Columbia River runoff since 1929. The crisis was made much worse by a deeply flawed electricity market design in California and opportunism by some of the participants in that market. And many believe it was prolonged by the reluctance of the Federal Energy Regulatory Commission to impose West-wide price caps.
The near-record low runoff in 2001 resulted in almost 4,000 average megawatts less hydroelectric energy available than in an average year, and even less compared to the relatively wet years of 1995-1999. The reduced hydropower generation affected not only the Northwest, but also California and the Southwest. Net exports from the Northwest Power Pool area for the May through September period were about 2,700 average megawatts less in 2000 and 2001 than in the preceding three years. However, these conditions and the California market problems likely would not have triggered the crisis had it not been for the extremely tight power supply in the Northwest and the West leading into 2000. The gap between power supply and power demand widened steadily through the 1990s and reached 4,000 average megawatts — nearly enough power for four cities the size of Seattle — by 2000.
During most of the late 1990s, construction of new power plants in the Northwest and, for that matter, the rest of the West, effectively was at a standstill. Wholesale electricity prices were low and were expected to stay low, thus sending an economic signal to power plant developers that it was not the right time to build — it seemed unlikely that a new power plant could compete with market-priced electricity. Similarly, utility investment in energy conservation during that period was less than half the cost-effective levels identified by the Council.
Concerned by the growing deficits, the Council undertook a study of regional power supply adequacy. That study, released in early 2000, estimated that the probability of being unable to fully serve Northwest load (the “loss of load” probability) would climb to 24 percent by 2003 even when accounting for the ability to import power from the Southwest in the winter and to draft reservoirs behind hydropower dams beyond normal limits in emergencies. The analysis also indicated that 3,000 megawatts of new power supply would be necessary to bring the loss-of-load probability down to the industry-accepted criterion of 5 percent. However, the report failed to emphasize that the probable leading indicator of the scarcity was volatility in power prices. Surging prices in the winter and spring of 2000 and 2001 would make that clear.
Neither the Council’s study nor any of the other indicators of the increasingly inadequate power supply prompted a rush to build new power plants or invest in energy efficiency. Some new plants were under development. However, they were not enough, soon enough, to avert the crisis. Why did the Northwest and the rest of the West allow loads and resources to get so far out of balance?
Causes of the crisis
One explanation is the infatuation with the competitive wholesale power market that was prevalent in the late 1990s. Why should a load-serving entity build new resources or enter into long-term contracts when the invisible hand of the competitive market would take care of long-term supply? A long period of low spot market prices seemed to validate this view. However, it should have been clear that the market was not taking care of supply
Demand for electricity continued to grow, but very few new power plants were being built. Wholesale prices in the years immediately preceding the summer of 2000 were generally below what it would take for a new generator to fully recover its costs, in part because of greater-than-average hydropower production during that period. Few independent power producers were willing to undertake the risk of building a plant without having a significant portion of a plant’s capability committed to long-term contracts. This was particularly so in the Northwest, where good hydropower conditions can depress market prices for extended periods.
Fear of retail competition also kept utilities from making commitments to new resources. During the mid-to-late 1990s, there was a great deal of discussion about retail competition. Some states, such as Montana and, on a more limited basis, Oregon, opened their retail markets to competition. Others were considering it, and there was speculation that Congress might impose retail competition. In the face of these developments, utilities were concerned that if they were forced to open their service territories to competition, they might lose customers to competitors and their investments in new resources would be “stranded” — that is, the utility would not be able to fully recover costs of new resources or long-term contracts.
The growing deficits should have been seen as a sign that a reasonable level of investment in new resources would not become stranded. Nonetheless, concerns about retail competition and stranded costs undoubtedly played some part in slowing resource development.
Another contributing factor was uncertainty with regard to the role the Bonneville Power Administration would play in serving future Northwest loads. Most utility and direct-service contracts with Bonneville were to expire in October 2001. Decisions about the signing of new contracts for subsequent service did not begin until 2000. This meant that both Bonneville and its customers were uncertain about whom would have the responsibility for acquiring new resources until the electricity crisis was practically upon us. In the end, Bonneville found itself in the position of having to acquire 3,300 megawatts in a relatively short time during a period of extremely high prices. Had there not been the uncertainty, Bonneville or the utilities may have taken steps to acquire resources earlier that would have lessened the impacts of 2000-2001.
Finally, it seems clear that electricity planning in the 1990s, including that of the Council, failed to fully appreciate and factor into decisions the risks facing the industry. In particular, these included the risks associated with reliance on a potentially volatile wholesale market and risks associated with gas-fired generation that depends on the also volatile natural gas market. If planning had done a better job of reflecting the risks and potential impacts, might load-serving entities have taken action to mitigate those risks? In February 2000 the Council released a report that put a spotlight on the region’s worsening resource condition. However, by then it was too late to elicit much of a response from the region.
Response to the crisis
Ultimately, Northwest utilities, independent developers, businesses, governments and citizens responded to the electricity crisis with ingenuity and effectiveness. There were three primary responses: new generation, both small-scale and larger conventional generation; load reduction
By December 2001, almost 1,300 megawatts of new permanent generation had entered service, approximately 1,100 megawatts of which was gas-fired combustion turbines. Another almost 3,800 megawatts was under construction, almost 2,900 megawatts were permitted, and over 10,000 megawatts were in the permitting process. The great majority were gas-fired plants, and most of those were combined-cycle units. However, there were several hundred megawatts of wind power developed as well. The developers were primarily Independent Power Producers (IPPs). This pattern was seen throughout the West.
By 2003, approximately 4,000 megawatts of new capacity had come on line in the Northwest since January of 2000. An additional 1,400 megawatts was partially complete, although construction had been suspended. With the exception of approximately 970 megawatts of wind (by the summer of 2006), the great majority of the generation was gas-fired. While the amount of new generation is impressive, most of it effectively “missed the party.” By the time the generation became operational, prices had fallen and along with them, the profits anticipated by the developers.
As a result, there are hundreds of megawatts of under-utilized new generating capacity in the region, most developed and owned by independent power producers. The good news is that the capital risk associated with this capacity is borne by the investors rather than by electricity consumers.
In response to increasing wholesale power prices, demand for electricity in the region began falling in late 2000. By 2002, loads were 2,800 average megawatts below loads in 2000 on an average annual basis, a drop of 13 percent. This load reduction was accomplished through two means: efficiency (energy conservation) and, primarily, demand response
While the efficiency response was impressive, demand response made up the great majority of the load reduction. Demand response means a reduction in electricity use unrelated to the efficiency of the facility, equipment or process. It can be accomplished through a reduction or cessation in the electricity-using activity (for example, making sure unnecessary lights are turned off, only running one shift in a factory or shutting down entirely) or by switching to a different source of electricity (installing self-generation) or a different energy source altogether (e.g., switching to direct use of natural gas). All three methods were employed in 2000-2001.
Demand response was accomplished through a number of different inducements. These included appeals to the public-spiritedness of consumers by public figures, price signals, and utility “buyback” offers — offers by utilities to pay for reduced consumption. The governors of the Northwest states raised the visibility of the severity of the electricity situation and made public appeals for cutbacks. Some industrial customers exposed to market prices responded in a variety of ways to the sharp increases in wholesale prices, including fuel switching, self-generation, cutbacks and shutdowns, albeit at some significant economic expense. Sixty-three percent of the load reductions came about through various forms of buybacks, over 90 percent of which came from the aluminum industry. In the residential sector, programs like “20-20” and its variants offered ratepayers a percentage reduction in their bill for reducing their consumption by the same percentage relative to the same period in the previous year. None of these load reductions came cheap, but they were cheaper than the alternative of paying the market price for the electricity.
As impressive as the load reductions were, they came too late to avoid several months of extremely high wholesale prices. Load reduction did not really begin taking effect in a significant way until more than seven months after the onset of wholesale prices that were several hundred percent higher than normal. Had there been a more rapid response of loads to wholesale prices, it might have partially mitigated the high wholesale prices that the region was experiencing. Similarly, had investment in conservation continued at cost-effective levels throughout the 1990s there would have been at least a couple hundred megawatts fewer loads exposed to the high prices.
The third leg of the response to the electricity crisis was changes to the operation of the hydroelectric system that increased generation. The most significant change was reduction in bypass spill at the John Day, The Dalles, and Bonneville projects. Bypass spill (running water over a dam’s spillways instead of through the turbines) is intended to reduce injury and mortality of out-migrating juvenile salmon and steelhead. However, from a power supply standpoint, spill is energy lost. Most of the spill reduction took place in 2001. In total, reducing spill called for in NOAA Fisheries’ 2000 Biological Opinion (BiOp) added an additional 4,500 megawatt-months to the region’s energy supply, much of that coming in late spring and early summer when power prices were still at extremely high levels. It also allowed storing additional water in Canadian reservoirs in case poor water conditions continued into the winter of 2001-2002.
The use of spill reduction also highlighted the conflict between fish and power. Some viewed it as an example of the power system being willing to violate fish operations instead of making the needed investments in an adequate power supply. Others viewed it as a reasonable and prudent step given the high cost and poorly demonstrated biological effectiveness of spill. The debate continues today.
It is tempting to believe that the factors that led to and prolonged the Western electricity crisis are no longer of concern. Have we learned our lesson? Certainly the possibility of additional jurisdictions moving to retail competition is much diminished if not eliminated. There is also a renewed enthusiasm on the part of many utilities and their regulators for the vertically integrated utility where the utility owns generation and is less reliant on “the market.” Similarly, many utilities now have experience with demand management programs that could, if maintained, serve them in good stead should another crisis begin to emerge.
In many respects these are positive developments that represent a retreat from excesses of the late 1990s. However, we believe it would be a mistake to think it could not happen again. Market prices will fall again, and the “wrong” economic signal again will be sent to power plant developers as demand for power increases. The lessons learned during the energy crisis must be built into the structure of our electricity system if we hope to avoid another crisis — or at least soften its impact.
It is likely we will continue to see a mix of vertically integrated utilities, a federal power-marketing agency, local distribution utilities and competitive wholesale suppliers in the regional power system for the foreseeable future. This mix will have elements of federal, state and local regulation and competition. This mix results in uncertainty regarding roles and responsibilities and lacks some of the elements necessary for it to function effectively.
The challenge for the Council and the region is to determine what will make such a system function effectively in the future.
In the Fifth Power Plan, completed in December 2004, the Council forecasts demand for electricity 20 years into the future, as required by the Northwest Power Act. The most-likely forecast, according to the plan, is that demand will grow from 20,080 average megawatts in 2000 to 25,423 average megawatts by 2025, an increase of 1 percent per year.
Here is a synopsis of the plan’s recommendations for meeting this demand:
Conservation — improved energy efficiency — costs less than new generating plants and provides a hedge against market, fuel, and environmental risks. The Council recommends that the Northwest increase and sustain its efforts to secure cost-effective conservation immediately. The targets in the power plan are ambitious but achievable: 700 average megawatts between 2005 and 2009; and 2,500 average megawatts over the 20-year planning period.
Demand response — agreements between utilities and customers to reduce demand for electricity during periods of high prices and limited supply — helps stabilize prices and prevent outages. The Council recommends developing 500 megawatts of demand response between 2005 and 2009 and larger amounts thereafter.
The power plan anticipated more than 1,100 megawatts of new wind power between 2005 and 2014, based on what was known at the time about state incentives for wind power and utilities’ integrated-resource plans. However, wind power development has proceed at a much faster pace. Between January 2005 and late 2006, more than 970 megawatts of wind power were completed or were under construction in the Northwest, and construction of another 660 megawatts or more was expected by 2008. Wind project developers have requested integration services and facilities to add more than 3,000 additional megawatts of wind power in the region over the next several years.
This rapid development seems to be spurred by many factors and assumptions, including: 1) that federal tax credits for wind power plants will continue; 2) that controls on greenhouse gas emissions from power plants will be enacted in the future, encouraging wind power; 3) that construction costs for wind plants will continue to decrease; 4) that wind power, an intermittent resource, can be integrated into the existing power system at reasonable costs; and 5) that large areas of land with access to high-voltage transmission will be available at moderate costs.
Prepare for new power plants:
As a risk-management strategy, the power plan defines a schedule for siting and permitting new power plants in anticipation of construction. With siting and permitting completed, actual construction can begin quickly when conditions are best. If the projects are not needed, the expended costs are relatively small. The schedule includes up to 5,000 megawatts of wind power to be developed through the end of the 20-year planning period, 425 megawatts of high-efficiency coal-fired generation (begin construction by January 2012) and, late in the planning period, additional natural gas-fired generation.
The power plan identifies four policy issues that are critical to the future of the region’s power supply:
The Council recommends that Bonneville sell electricity from the existing Federal Columbia River Power System to eligible customers at cost. Customers that request more power should be required to pay the additional cost. The Council recommended that Bonneville implement this change through new long-term contracts to be offered by 2007. The Council also believes that Bonneville must continue its commitment to support conservation, renewable energy and fish and wildlife mitigation.
Adequate transmission is critical to any of the new generating resources identified in the plan. The move toward deregulation and expansion of wholesale electricity markets, along with changes in technology, altered the character of the traditional transmission system. Questions of how to plan for, build, pay for and effectively manage the region’s transmission system are becoming critically important. The Council supports and is an active participant in regional efforts to resolve these problems.
An adequate power system has a high probability of being able to maintain service when the region experiences a poor water year, unexpected growth in demand for power or the failure of some new resources to perform as planned. The power plan evaluates alternative regional adequacy standards and their interaction with the western United States power system. The Council is committed to working with regional utilities and regulators to develop a standard that will assure an adequate power supply while being fair and equitable to all parties.
The Council’s Northwest Power Plan and Columbia River Basin Fish and Wildlife Program coordinate planning for future power supplies and for fish and wildlife affected by hydroelectric dams. The Council committed in the power plan to improve coordination of power and fish and wildlife issues with other entities in the region.