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.
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.
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.
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.
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.
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.
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
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
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.
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.
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.
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
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.
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
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.
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.
Two months later, in May, the rain stopped and the heat
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.
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.
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.
Northwest had an energy crisis and, to many people, it seemed to develop
quickly and for no apparent reason. But there were multiple causes.
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.
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
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.
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
an October 2000 report explaining the energy crisis, the Power and Conservation
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.”
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.”
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.
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.
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.