In the National Energy Policy Act of 1992, Congress initiated a steady transition for the nation’s electricity industry from state regulation of power sales to deregulation and competition for energy supplies. State utilities commissions continued to regulate distribution of electricity and the prices paid by consumers, but utilities suddenly were free to buy and sell wholesale electricity competitively across state lines.

Energy deregulation was not a good fit with the Northwest power system. That’s because the supply of electricity and most of the region’s high-voltage transmission is controlled by the federal Bonneville Power Administration, and federal agencies are not designed to compete against private businesses. Given the vast supply and low price of hydropower in the Northwest, and given that the supply of hydropower can vary widely with the water supply, the region’s electricity prices can swing widely, as well, as hydropower floods the electricity market and drives prices down overall or disappears from the market and drives prices up.

This is, at root, a fuel problem, and it is a planning problem for electric utilities, too. Elsewhere in the nation, where there is less hydropower, planning future power supplies is simpler because fuel for power plants, such as natural gas and coal, can be purchased for future delivery at set prices and schedules. But in the Northwest, where hydropower accounts for more than two-thirds of the power supply, the matter is infinitely more complicated. No one can say how when or how much it will rain. While water can be stored behind dams for future hydropower use, only one-third of the annual runoff of the Columbia River can be stored.

For power planners, this means a lot of guesswork. As demand for power steadily increases over time, decisions have to be made about building new power plants to augment the hydropower supply. But when is the best time to build? Before deregulation, a utility could request permission to build a new power plant and recover the cost from its customers. After deregulation, which freed utilities and their commercial and industrial customers to buy power from whomever they choose, financing power plants became more problematic. What if, for example, the price of power from a new plant was not competitive in the wholesale marketplace? In short, that power would not be sold.

Thus through the early and mid-1990s, with demand for electricity growing at between 1 and 2 percent per year on the West Coast, power plant developers watched the gap between supply and demand steadily widen as they waited for the right price signal from the wholesale market — the signal that the supply was low enough to justify building new plants. Propped up by usually abundant hydropower, the West Coast power supply was a disaster waiting to happen.

In September 1999, the first warning of future electricity shortages could be discerned from the 1998 Loads and Resources Study issued by the Bonneville Power Administration. The report, nicknamed the White Book, is an annual summary of the year’s electricity supplies and demand for power, 1998 in this case. Importantly, The White Book also includes predictions about demand (loads) and resources (supply) for the coming winter and the following 10 years.

The 1998 White Book suggested that under the critical-water condition, which is the lowest recorded level of river flow in the Columbia, measured at The Dalles Dam, Bonneville would have an energy deficit of 503 average megawatts through 2006. That’s enough electricity for about 287,000 homes. The White Book attributed the shortage to river flow requirements in the 1995 and 1998 biological opinions on Snake and Columbia dam operations issued by the National Marine Fisheries Service. Those opinions, which include hydrosystem operating recommendations for protection of Endangered Species Act-listed salmon and steelhead, “further changed the focus of hydrosystem operation for fish passage to monthly flow-based targets from storage-based targets,” according to the White Book. As a result, there were limits on “the ability of the hydrosystem to shift and shape flows in any one month to meet firm system energy needs.”

“Critical water” is the planning floor for the Federal Columbia River Power System. Put another way, the 1998 White Book suggested that under the worst water conditions, and given the flow-based requirements in the biological opinions, Bonneville would have a 503 average-megawatt shortage that would have to be made up to keep the electricity flowing in the Northwest.

That in itself was not cause for alarm, as Bonneville has contracts with its customers to regularly supply more electricity than the federal system is able to generate. To supply the extra power, Bonneville can alter dam operations, adjust its sales to its largest customers or import power from the Southwest. “Flexibility in the system and in existing power contracts, along with augmenting the system through power purchases will fill in the gaps,” a Bonneville spokesman said at the time.

But flexibility alone would not be enough to overcome the looming problem, as the deficit actually was larger than Bonneville’s 503 average-megawatt prediction. That is because many of Bonneville’s customers also buy power on the wholesale market to meet the full demand of their customers. Bonneville considers the market purchases of its customers, which total about 900 average megawatts, a regional deficit on top of its own.

The White Book predicted that if the region experienced “critical water” conditions or extremes of weather, the deficits could climb to 2,631 average megawatts in 2000, 3,202 average-megawatts by 2006 and 3,626 average-megawatts by 2009. The Bonneville spokesman said the predicted deficits provided “an early warning system to the region” to begin thinking about how to meet future demand for power.

At the Northwest Power and Conservation Council, computer modeling of the regional power system also showed impending deficits. Bonneville requested the Council to analyze of future power loads and resources.

Dick Watson, the Council’s director of power planning at the time, said the region’s utilities did not appear to have plans to build any new power plants. He said deregulation and competition in the wholesale electricity business was creating uncertainty about whether and when to make the large investments that power plants require. The concern was that power from new plants might be more expensive than the market rate when the plants were completed. Or, it might not. Thus, the decision to invest hundreds of millions of dollars in new power plants is enormously risky, particularly at a time when power prices are low or average, as they were in 1999. “Right now,” Watson said at the time, “expecting utilities to stand up and make an investment [in new plants] is not real likely.”

Federal law prohibits Bonneville from owning power plants, although it can purchase the output of new plants if someone else builds them. Thus the responsibility is on utilities or independent power producers to build new power plants, and in late 1999 no one was moving to fill the impending electricity gap. Watson noted that developers were ready to build at least 12 new plants totaling more than 4,000 megawatts in the Northwest but only one, near Klamath Falls, Oregon, was under construction. As for the rest, Watson said, “all they need is a market to do it.” In fact, the market would turn soon, and dramatically.

In March 2000, the Council issued its analysis showing a 24-percent probability of winter power deficits by the winter of 2002-2003 if new resources — both generation and conservation — were not built in the Northwest.

Energy crisis

Two months later, in May, the rain stopped and the heat started. In most of the Columbia River Basin, the mountain snowpack, which was a little below normal, melted and ran off early. That’s not unusual, but by the end of the summer, rainfall remained below normal, the weather remained warm and the region’s electricity supply, dominated by hydropower, was being pinched.

It was the beginning of a power crisis that would wallop the West Coast, from the summer of 2000 through the spring of 2001 and from California to British Columbia, with power shortages and high power prices — 10 times the normal wholesale price, and higher. From an average of about $25 per megawatt-hour earlier in the year, wholesale prices by June were more than 20 times higher. On June 28th, 2000, for example, average prices for wholesale power during the heavy load hours of early morning and early evening hovered around $700 per megawatt-hour. On December 13, the wholesale price on the mid-Columbia trading hub would spike briefly to over $1,300 per megawatt hour.

As a percentage of all the region’s electricity customers, only a small number are directly exposed to spot-market prices. But they are an important few — large industries and most of the region’s electric utilities. Utilities generally do not pass market costs directly to their customers, but they do raise rates to collect the additional revenue to pay for the higher-priced power over time. Most of the region’s utilities ultimately raised their rates in response to high market prices.

The Northwest had an energy crisis and, to many people, it seemed to develop quickly and for no apparent reason. But there were multiple causes.

Through the 1990s, construction of new power generation and conservation resources failed to keep up with steadily rising demand, largely because supply and demand for electricity determined prices for wholesale electricity transactions, which were deregulated under the National Energy Policy Act of 1992. With power plants costing hundreds of millions of dollars apiece, investors are nervous about committing money to a plant that might not produce power economically when it is completed.

The steadily widening gap between electricity supply and demand was a West Coast phenomena, not one limited to the Northwest. In fact, the imbalance between supply and demand was greatest in California, where the state had deregulated its wholesale power market in 1995. The results were disastrous as utilities fought for increasingly scarce power in an increasingly expensive market where only short-term sales were allowed. Ultimately, the state’s two largest utilities, Southern California Edison and Pacific Power & Light Company, declared bankruptcy.

There were other problems, as well, that became evident in the summer of 2000. High temperatures drove up demand for power throughout the West. Some of the largest power plants in the West experienced unplanned outages, contributing to the electricity shortage. The price of natural gas, the fuel for many West Coast power plants, rose sharply. Risk mitigation practices, such as buying wholesale electricity under long-term contracts at fixed prices, were not widely used as many utilities and large industries continued to buy power through short-term contracts, anticipating that prices would drop sooner than later. In fact, wholesale prices did not fall back to normal levels until June of 2001.

By late 2000, California authorities were declaring electricity emergencies on an almost daily, and sometimes hourly, basis. In the Northwest, the region’s utilities and Bonneville watched with alarm as the power supply flirted with crisis levels, never quite reaching them. Voluntary energy conservation shaved several hundred megawatts from the region’s demand for power. Large industrial customers negotiated agreements with utilities and the Bonneville Power Administration to reduce their usage during peak periods of demand. Bonneville was able to squeeze more power from the Federal Columbia River Power System, partly through an innovative exchange with California utilities in which Bonneville sold hydropower south overnight and then turned down the dams and imported power from the Southwest during the day. Desperate for affordable energy, the Southwestern utilities, primarily in California, agreed to send two megawatts of electricity north during the day for every megawatt of power Bonneville sent south overnight. This helped Bonneville maintain adequate reservoir levels.

In an October 2000 report explaining the energy crisis, the Power and Conservation Council commented:

For the past several years, the economies of the West have been growing. This translates into growing electricity demand. Between 1995 and 1999, Western Systems Coordinating Council peak loads increased by nearly 12,000 megawatts, or by about 10 percent. Energy use during the same four years increased by about 65,000 gigawatt-hours, or about 2.3 percent annually. The increases would have been even more if 1999 hadn’t been a relatively mild weather year.

“Generating capacity available during peak load months did not increase to keep pace with peak load growth. While peak loads increased by 12,000 megawatts from 1995 to 1999, generating capacity only increased by 4,600 megawatts. … we also believe that efforts to improve the efficiency of electricity use, i.e. conservation, have fallen off considerably in recent years. This is largely the result of the uncertainty caused by the restructuring of the electricity industry.”

Although it wasn’t clear at the time of the Council’s report, later investigation by state and federal authorities suggested that manipulation of wholesale electricity supplies by energy traders in Oregon and California also contributed to the crisis by creating short-term electricity shortages and transmission line congestion that boosted prices . Utilities were reluctant to invest in new generating plants or conservation for fear of stranding those investments in the future if customers left for other suppliers or if the market price of power dropped below the cost of power from new plants or the cost of the conservation investment. Additionally, the Council reported, the pattern of Columbia River runoff in 2000 “was somewhat unusual,” and this affected hydropower generation. Through April, the runoff pattern was normal, but beginning in May the runoff flattened at a level below the 61-year average and stayed low through June. As a result, the May-June weekly hydropower generation average was down 6,000-7,000 megawatt-weeks compared to the same period in 1999. According to the Council:

“The pattern of runoff  fooled a number of participants in the market. The forecast was for a more or less average year. The runoff in February and march supported that forecast. It may be that decisions were made to make forward sales for June and beyond or, for those buying, to go short on the expectation of roughly average water and relatively abundant hydropower. Similarly, decisions to perform scheduled maintenance on thermal plants during the June timeframe when high volumes of runoff were expected also were made. The subsequent runoff pattern confounded those decisions and significantly reduced the amount of hydropower both to meet regional loads and for export. It also seems likely that the relatively good water conditions in 1999 obscured the tightening of supplies.”

In 2000 and 2001, precipitation would remain below normal, as would Columbia River runoff. In 2001, the runoff would be the second-lowest on record, reducing hydropower generating capacity by more than 4,000 megawatts. To hold more water in storage reservoirs for near-term hydropower generation, Bonneville declared a power emergency and virtually eliminated water spills at Snake and Columbia river dams in late May and June 2001. The Corps of Engineers barged as many juvenile fish downriver as it could collect, and migration conditions for the fish left in the river were poor. In 2001, utilities passed along high market prices to their customers in the form of rate increases, mostly in double digits. The region’s economy took a downturn. Industrial demand for power dropped by about 20 percent, led by shutdowns in the aluminum industry.

But new power plants and conservation were being rushed to completion. Between 2000 and the end of 2002, the region added about 2,600 megawatts of natural gas-fired generation, 450 megawatts of wind generation and 200 megawatts of new energy conservation. Another 1,000 megawatts, mostly in gas-fired plants, was added by the end of 2003.

These additions combined with a return to more normal hydropower conditions brought market prices back to normal levels, but the rate increases remained in place to pay off the debt utilities incurred during the energy crisis. The Power and Conservation Council reported in 2004 that the power supply should remain adequate through at least 2010 if demand grows at the predicted rate of about 1.3 percent per year. But after that, the market again could force the region into a crisis of supply and demand. This time, however, the region’s utilities and Bonneville should be better prepared to take actions that will both reduce demand and add supply in increments as demand requires.