Grand Coulee Dam and the Columbia Basin Project usa final Report: November 2000

Figure 3.2.1  Predicted vs. Actual Hydropower Capacity, Grand Coulee Dam 
0
1000
2000
3000
4000
5000
6000
7000
8000
19411943194519471949195119531955195719591961196319651967196919711973197519771979198119831985198719891991199319951997
Year
Rated Capacity (MW)
Predicted Capacity
Actual Capacity
  
Sources: USBR, undated(c); Sprankle 1999a; Sprankle 1999b 
 

Grand Coulee Dam and Columbia Basin Project 
 
         34 
 
This is a working paper prepared for the World Commission on Dams as part of its information gathering activities. The views, conclusions, and 
recommendations contained in the working paper are not to be taken to represent the views of the Commission 
 
Figure 3.2.2 Predicted vs. Actual Hydropower Generation, Grand Coulee Dam 
 
Sources: USBR, 1932: 95, 143; USBR (GCPO), 1999. 
 
3.2.4  Grand Coulee Dam in the Context of the Federal Hydropower System 
 
The power functions served by GCD are most productively analysed in the context of the larger network 
of hydroelectric projects in the Columbia River Basin. In distributing electric power to users, BPA does 
not distinguish the electricity generated by GCD from electricity generated by other dams that feed into 
the BPA network. In other words, BPA transmits and sells power, not GCD power. 
 
Of the more than 250 hydroelectric projects in the Columbia River Basin, 14 are considered to be key 
US projects.
30
 A synopsis of these projects, which are part of the FCRPS, is provided in Table 3.2.1 
Project locations are indicated in Figure 3.2.3.  
 
 
 
 
 
 
 
 
 
-
5,000.00
10,000.00
15,000.00
20,000.00
25,000.00
30,000.00
1941 1943 1945 1947 1949 1951 1953 1955 1957 1959 1961 1963 1965 1967 1969 1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997
Year
Gross Generation (millions of KWH)
Predicted (millions of KWH)
Actual (millions of KWH)

Grand Coulee Dam and Columbia Basin Project 
 
         35 
 
This is a working paper prepared for the World Commission on Dams as part of its information gathering activities. The views, conclusions, and 
recommendations contained in the working paper are not to be taken to represent the views of the Commission 
 
Table 3.2.4  Major Federal Dams in the Columbia River Basin
 
Name 
Date In Service 
Location 
Storage 
Capacity 
(MAF) 
Generating 
Capacity (MW) 
Bonneville 
Jun 1938 
Columbia River, 
OR/WA 
ROR
a
 1 
050 
Grand Coulee 
Sep 1941 
Columbia River, 
WA 
5.19 6 
494 
Hungry Horse 
Oct 1952 Flathead 
River, 
MN 
3.16 428 
McNary 
Nov 1953 
Columbia River, 
OR/WA 
ROR 980 
Albeni Falls 
Apr 1955 
Pend Oreille River, 
ID 
1.16 42 
Chief Joseph 
Aug 1955 
Columbia River, 
WA 
ROR 2 
069 
The Dalles 
May 1957 
Columbia River, 
OR/WA 
ROR 1 
780 
Ice Harbor 
Dec 1961 
 
Snake River, WA 
ROR 
603 
John Day 
Jul 1968 
Columbia River, 
OR/WA 
ROR 2 
160 
Lower 
Monumental 
May 1969 
Snake River, WA 
ROR 
810 
Little Goose 
May 1970 
Snake River, WA 
ROR 
810 
Dworshak 
Mar 1973 
Clearwater River, 
ID 
2.02 400 
Lower Granite 
Apr 1973 
Snake River, WA 
ROR 
810 
Libby 
Aug 1975 
Kootenai River, 
MN 
4.98 525 
a 
ROR = “run-of-the-river” dam
 
 
As shown in Table 3.2.4, GCD is the second oldest of the 14 projects, and it has the largest storage 
capacity and the largest generating capacity. Except for GCD and Hungry Horse Dam (both of which are 
operated by Reclamation), all the projects listed are operated by the Corps. Four of the projects — the 
ones on the Snake River — are currently being considered for possible decommissioning as a means to 
restore salmon populations within the basin. Interestingly, several of the projects listed were identified in 
the Butler Report.
31
 
 
As indicated in Table, nine of the 14 major federal projects are characterised as run of the river (ROR) 
projects. In contrast to storage projects, which impound water seasonally, annually, and for multiple 
years, ROR dams use available inflow and a limited amount of short-term storage (daily or weekly 
pondage) to generate electricity. In simple terms, runoff from snowmelt is stored during the spring and 
summer until it is needed to generate power (typically, when the regional demand is highest in the fall 
and winter). Space is made available in storage reservoirs in the fall, winter, and early spring to hold 
runoff, and thereby prevent flooding (US DOE et al, 1994: 13). 

Grand Coulee Dam and Columbia Basin Project 
 
         36 
 
This is a working paper prepared for the World Commission on Dams as part of its information gathering activities. The views, conclusions, and 
recommendations contained in the working paper are not to be taken to represent the views of the Commission 
 
Figure 3.2.3  Map of Key Federal Columbia River Power System Dams 
 
 
 

Grand Coulee Dam and Columbia Basin Project 
 
         37 
 
This is a working paper prepared for the World Commission on Dams as part of its information gathering activities. The views, conclusions, and 
recommendations contained in the working paper are not to be taken to represent the views of the Commission 
 
3.2.5  Power Demand and Characteristics of Power Users 
 
Hydropower is the principal energy source used in the US Northwest,
32
 and the FCRPS supplies more 
than half of this region’s hydroelectric demand.
33
 Power is delivered to customers by a network of 
transmission lines extending to Canada in the North, California in the South, and Montana, Utah, and 
Wyoming in the East. BPA’s transmission grid carries the vast majority of this power, which extends 
over 15 000 circuit miles (24 000km), accounting for 25% of the region’s transmission capacity. 
 
Power produced at federal hydroelectric projects in the Columbia River Basin is sold to several types of 
customers through a variety of power sales agreements. Customers include public utility districts 
(PUDs), municipalities, rural co-operatives, federal agencies, and direct service industries (DSIs). 
 
As a matter of law, PUDs, municipalities, and rural co-operatives are given first preference for power 
produced from federally owned Columbia River Basin hydroelectric projects.
34
 BPA has long-term firm 
power sales contracts with over 120 publicly owned utilities. Firm power, defined as energy that can be 
generated given the region’s worst historical water conditions, is provided on a guaranteed basis. 
 
Publicly owned utilities are located throughout the US Northwest and provide power to individual homes 
in both urban and rural areas. Major metropolitan areas include Seattle, Tacoma, Yakima, and Spokane 
in Washington; and Portland, Salem, and Eugene in Oregon. Examples of some PUDs served by BPA 
include those in Grant County, Chelan County, and Douglas County. Some of the municipal utilities 
include Seattle City Light, Tacoma City Light, and the Eugene Water & Electric Board. BPA also sells 
some firm power to other federal agencies, including the Department of Defense and Department of the 
Interior. 
 
Additionally, firm power is sold to some of the region’s largest industries, which are called DSIs. In 
addition to obtaining a share of firm power, DSIs have first call on BPA’s nonfirm power. Nonfirm 
power (ie, energy available when water conditions are better than the worst historical pattern) is 
generally sold on an interruptible, or non-guaranteed, basis. As of 1996, BPA had 18 DSI customers. 
The majority of these customers are aluminium companies (smelters), such as ALCOA; the other DSIs 
represent other industrial sectors, such as chemicals and mining.  
 
The rate schedules for DSIs are complex and have changed over time. In the past, portions of the rate 
schedule have involved power that was interruptible. The rationale for interruptible power was as 
follows: at times, the Corps and Reclamation would draw down reservoir levels below normal to serve 
the nonfirm load in fall and winter months. However, if the probability of reservoir refill is too low in 
the spring, BPA would restrict its sales to DSIs in the spring, thus permitting water to stay in the 
reservoirs. This interruption in power delivered to DSIs was conducted to protect service to publicly 
owned utilities and other firm power customers. 
 
During the period from 1981 to 1996, “full requirements service” was provided to DSIs with a four-
quartile arrangement. Under this scheme, DSIs received a variety of different sources of power including 
the following: surplus firm energy, non-firm energy, and firm power. Under the quartile arrangement, 
power to the first and second quartile of the total DSI load was interruptible and could be dropped under 
certain circumstances.
 35
 However, because of a series of interruptions that occurred in the early 1990s, 
and the fact that the price of BPA power was higher than other power markets, the DSIs threatened to 
end their full-requirements power sales contracts with BPA. Though none of the DSIs terminated power 
sales arrangements with BPA, the four-quartile service arrangement was abandoned in 1995. Beginning 
that year, DSIs were able to make long-term purchases from other suppliers. For the period between 
1997 and 2001, DSIs have contracts to purchase approximately 2000 average megawatts of firm 
requirements power from BPA; they purchase their remaining power needs from the open market. 
 
Nonfirm power that is not used by DSIs is sold to other private customers, such as Portland General 
Electric, Pacific Power & Light, Puget Sound Power & Light, Washington Water Power, and Montana 

Grand Coulee Dam and Columbia Basin Project 
 
         38 
 
This is a working paper prepared for the World Commission on Dams as part of its information gathering activities. The views, conclusions, and 
recommendations contained in the working paper are not to be taken to represent the views of the Commission 
 
Power. Hydroelectric projects in the US Northwest have also provided peaking (high demand) power to 
other major metropolitan areas such as Los Angeles during hot summer days.  
 
Industries that consume large quantities of electricity are becoming a smaller part of the US Northwest 
economy as service industries continue to grow. As a result, the traditional dependence of the region’s 
manufacturing and heavy industry on inexpensive electricity has declined somewhat. However, regional 
population is expected to increase substantially during the next decade, and thus the local population will 
depend increasingly upon the hydroelectric power base. 
 
3.2.6  Economic Benefits of Hydropower Production 
 
As noted earlier, development of the Columbia River Basin has been critical to the economic 
development of the US Northwest. The gross national product (GNP) of the Northwest grew to more 
than $300 billion in 1992. After adjusting for inflation, the personal income of citizens in the US 
Northwest doubled from 1929 to 1949, doubled again from 1949 to 1969, and doubled again by 1989. 
 
Since GCD is a storage facility with a large amount of power generation capability that can be brought 
on line quickly, it is used primarily as a peaking facility by BPA. GCD’s typical load ranges from a low 
of 200 to 300MW to a high of 5 000 to 5 800MW. GCD and other hydroelectric projects in the 
Northwest also provide peaking power to other major metropolitan areas, such as Los Angeles, during 
hot summer days.
36
 
 
Revenue attributable to GCD from power sales in 1993 exceeded $412 million (BPA, 1993). This 
revenue not only pays for project costs attributed to power, it also pays for a large portion of federal 
irrigation investment in CBP. Over time, the contribution of GCD to FCRPS revenues has varied, 
depending on how many projects were contributing to the system. For example, from 1950 to 1953, 
GCD accounted for about three quarters of all FCRPS revenues (BPA, 1955). As more projects came on 
line, the contribution of GCD decreased, but it still remained the centrepiece of hydropower generation, 
accounting for 20% to 33%of total FCRPS kilowatt-hours from the late 1950s to the present.
37
 On a 
cumulative basis, by 1993, GCD had generated over 710 million-kilowatt hours and comprised 
approximately 15% of total power generated by FCRPS (BPA, 1993). Cumulatively, this equates to over 
$2.9 billion dollars in nominal dollars. Power generation at GCD far exceeds that of other FCRPS 
projects. For example, GCD power generation exceeds power generation at Chief Joseph Dam, the next 
highest generating project, by 45% (BPA, 1993). 
 
Hydropower in the Columbia River Basin has provided inexpensive electricity to both individuals and 
businesses in the region. Columbia River Basin hydropower averages $10 per MWh to generate 
(FWEEa, 1999). Hydropower generation costs at GCD are even lower, at $1.35 per MWh (USBR, 
1996). Average generation costs at nuclear, coal, and natural gas powerplants average $60, $45, and $25 
per MWh, respectively (FWEEa, 1999). Inexpensive hydroelectric power generated by GCD and other 
FCRPS projects in the basin has attracted many energy-intensive industries to the area such as 
aluminium, food processing, aerospace, defence, mining, and others. This has produced numerous jobs 
and increased the economic output of the US Northwest tremendously since the 1930s.  
 
3.2.7  Unexpected Benefits of Hydropower Production 
 
3.2.7.1  Ancillary Service and Dynamic Benefits
38
 
 
A number of benefits of GCD relate to technical features of the process of generating and transmitting 
electricity commonly referred to by specialists as “ancillary services and dynamic benefits”. These 
services and benefits were not mentioned in either the 1932 Reclamation or Butler reports; in that sense 
they were unanticipated. The nature of ancillary services and dynamic benefits is described in general 
terms below and in more complete terms in the Annex titled “A More Detailed Examination of 
Hydropower”. 

Grand Coulee Dam and Columbia Basin Project 
 
         39 
 
This is a working paper prepared for the World Commission on Dams as part of its information gathering activities. The views, conclusions, and 
recommendations contained in the working paper are not to be taken to represent the views of the Commission 
 
 
Power generators that are used to ramp up and down as the load changes from hour to hour are said to be 
capable of “load following”. In addition to the need to meet changing power demand, generators must 
also provide dynamic benefits, such as frequency control and responses to minute-to-minute changes in 
load.
39
  
 
Power systems must also have generating capacity available to meet contingency conditions, such as the 
sudden outage of a large generator or the loss of a transmission line that is importing power into a 
control area.
40
 This type of contingency is provided for by designating an amount of capacity called 
“spinning reserve” (ie, the amount of generation that can be called on in a few seconds that can make up 
for the sudden forced outage of a large generator or a heavily loaded transmission line). Since reserve 
capacity must be available in a few seconds, the most responsive generators in a control area are used to 
provide it.  
 
Another dynamic capability has to do with voltage support. In a power system, voltages must be kept at 
constant levels so that consumer appliances will operate correctly. The tolerance for voltage variation is 
generally within a band of plus or minus 5% of the nominal level. Voltage regulation is accomplished by 
controlling the supply of reactive power in the transmission and distribution system. “Reactive power” is 
the power that is required to create the electric and magnetic fields in transformers, transmission lines, 
generators and load devices. Generators and other power system facilities provide reactive power and 
voltage regulation. 
 
 
BPA has identified the following ancillary services from generation capacity under its control, including 
GCD: 
 
• 
Regulation/load following — According to the Federal Energy Regulatory Commission (FERC), 
load following is “the continuous balancing of resources with load under the control of the 
transmission provide . . . accomplished by increasing or decreasing the output of online generation . . 
. to match moment-to-moment load changes. 
• 
Voltage support (or control) — FERC defines “reactive power/voltage control” as “the reactive 
power support necessary to maintain transmission voltages within limits that are generally accepted 
in the region and consistently adhered to by the transmission provider”.  
• 
Spinning reserve — Spinning reserve is the unloaded (uncommitted) capacity of a generator that is 
in operation and providing output to the power system at any time. It is an amount of generation that 
is available to provide additional energy as an immediate response to sudden drops in system 
frequency.
41
  
• 
Non-spinning reserve — Non-spinning reserve is generating capacity that can be brought into 
service within ten minutes of a call for it.  
• 
Energy Imbalance — FERC defines this as “the difference [that] occurs between the hourly 
scheduled amount and the hourly metered [actual delivered] amount associated with a transaction”. 
• 
Generation Dropping — generator dropping is a procedure that is occasionally used as a system 
stabilising technique. It can be required following the trip out of the high voltage direct current 
transmission line that exports power from the Pacific Northwest to Los Angeles. 
• 
Station Service — station service is power that is needed to operate substations.
42
 
 
GCD is operated together with the downstream Chief Joseph reregulating dam.
43
 Because GCD has a 
large water storage reservoir and large amount of installed generation, it is operated by BPA as a peaking 
facility. When GCD discharges during peak load periods, water is held in the Chief Joseph reservoir and 
released at a later time in a controlled way so that downstream water flow requirements are satisfied. 
Because Chief Joseph Dam can re-regulate the water discharge from GCD, it is possible for GCD to 
provide dynamic functions and ancillary benefits as part of its day-to-day operations. GCD provides all 
ancillary services required by BPA, including load following, frequency regulation, spinning reserve, 
non-spinning reserve, and voltage support.
44
  
 

Grand Coulee Dam and Columbia Basin Project 
 
         40 
 
This is a working paper prepared for the World Commission on Dams as part of its information gathering activities. The views, conclusions, and 
recommendations contained in the working paper are not to be taken to represent the views of the Commission 
 
The hydroelectric generators at GCD are well suited to provide dynamic services because they are robust 
and because they have short response times. Hydroelectric generators with minimum response times (in 
terms of megawatts per minute) are ideal for frequency regulation and automatic generation control. In 
comparison to generators operating with nuclear and fossil fuels, hydroelectric generators have the 
fastest response times. Hydroelectric generators are also ideal for spinning reserve service because they 
can deliver sustained output for an extended period of time. For example, GCD is reported to have 
delivered 2 000MW of reserve in response to a recent system disturbance (Flynn 1999).  
 
The BPA control area had an estimated peak demand in 1999 of 10 167MW. GCD maintains 2.5% of 
capacity for spinning reserve and 2.5% for non-spinning reserve. GCD has an installed capacity of 6 
809MW. GCD maintains from 240 to 280MW of generating capacity for reserve frequency regulation. It 
is estimated that the BPA control area average requirement for regulating reserve is 250MW.
45
 
 
3.2.7.2  Atmospheric pollutants Avoided by Not Using Fossil Fuel Powerplants 
 
Emissions of atmospheric pollutants avoided is another unanticipated benefit of power generated by 
GCD.
46
 By generating electricity using hydropower, the combustion of fossil fuels, such as coal, is 
avoided. Although it is clear that these benefits of GCD are real, there is no widely accepted procedure 
for calculating the monetary value of those benefits. Moreover, even attempting to generate numerical 
values of tons of atmospheric pollutants avoided requires that many assumptions be made. This is 
demonstrated in the Annex titled “Atmospheric Pollutants Avoided,” which employs a calculation 
procedure developed by the WCD Secretariat to calculate a range of plausible values of benefits.  
 
In developing a range of possible outcomes, we assumed that the power facility that would have been an 
alternative to GCD would have been a coal-fired steam electric powerplant. We then created five 
different scenarios, each of which is built on a set of assumptions related to several technical parameters, 
such as powerplant efficiency, the heating value of coal, and the type of boiler employed. Additional 
assumptions concern the quantity of power that would have been generated by the coal-fired powerplants 
that would have been built in the absence of GCD. This set of assumptions is required because the 
availability of enormous quantities of low-cost power made possible by GCD significantly influenced 
the demand for power in the US Northwest. 
 
The WCD methodology includes a range for the monetary value of carbon dioxide emissions avoided 
from a low of $2 per ton to a high of $25 per ton. Applying this range and using the five scenarios 
corresponding to alternative sets of assumptions related to heating value of fuel, powerplant efficiency, 
power generated, and so forth, the corresponding range of values of carbon dioxide emissions avoided in 
1998 varies from a low of about $14 million to a high of $541 million.
 47
 Again, using the five scenarios 
and the calculation procedures detailed by the WCD Secretariat, the range of values, in terms of tons of 
pollutants avoided in 1998, are as follows: sulfur dioxide, 5 66 to 17 400; oxides of nitrogen, 239 to 23 
700; particulate matter less than 10 microns, 13 to 433. In each instance, the range of possible values is 
substantially greater than a factor of 10. Under the circumstances, we have reservations about any 
attempt to quantify the benefits of atmospheric pollutants avoided by building GCD instead of coal-fired 
powerplants.