1. Hydro Power
The Columbia River is a great natural resource for the Pacific Northwest, providing transportation, recreation, water for irrigation, power generation and protection against flooding.
It also contains one of the world’s largest salmon populations.
Over the years, however, the number of salmon and steelhead has decreased due to changes in the environment.
The region is aggressively trying to restore salmon and steelhead populations.
The NW Power Planning Council, the National Marine Fisheries Service in conjunction with federal agencies and the Indian tribes and states have all developed comprehensive recovery plans.
This course presents an explanation of the planning and operation of the multiple-use dams of the Columbia River.
The first part of this presentation discusses what the hydroelectric system is, how its operation has changed over the past 20 years and how much it has cost. The second part is devoted to a discussion of how the operation of the hydro system is planned for and the computer models that are used to analyze the system.

2. The Pacific Northwest Power Supply2

3. PNW Firm Generating Resources3

4. The Hydroelectric System4

5. 5 The Columbia River is the fourth largest river in North America.
The system drains 219,000 square miles in seven western states and 39,500 square miles in Canada.
The Columbia River originates at Columbia Lake on the west slope of British Columbia’s Rocky Mountain Range.
The Columbia River is 1,214 miles long.
About 25 percent of the river flow comes from Canada.
Federal agencies have built 30 major dams on the river and its tributaries.
Many non-federal dams have also been built as well.
In total, over 200 dams have been built on the Columbia River system.
About 80 dams are large enough to be included in the simulation models to be discussed later in this session. 5

6. Comparison of Storage Volume to Variations in Runoff
The additional energy, above and beyond the firm generating capability, comes from the hydroelectric system.
Let’s begin with a short description of that system.
The total useable storage capability of the Columbia River reservoir system (including Canadian projects) is only 30% of the average annual runoff volume in the Columbia River (42 Maf/134 Maf).
The U.S. portion of the storage is approximately half of the total (15% of the average annual runoff).
Because of the small amount of storage capability, the Northwest can do little to reshape the natural river flows. 6

7. Variability in PNW Hydro Generation7

8. Monthly Shape of River Flow and PNW Electricity Demand
Let’s now look at the hydroelectric system in more detail.
It is not only important to know how much energy the system can produce on an annual basis but also how much it can produce on a monthly basis.
This overhead illustrates the monthly shape of electricity demand which peaks in the winter and is lowest in the spring.
Also illustrated on this graph is the monthly shape of hydroelectric generation, if no reservoir storage were available.
Hydroelectric generation peaks in the spring months when the snowpack melts and river flow is highest.
By building dams with storage capability, river flows (and generation) can be shifted to other months to better fit the shape of demand.
For power purposes, water is stored during the spring runoff for later release in fall and winter months when demand is higher.
This action reduces river flows in the spring and increases flows in the fall and winter months. 8

9. Typical Reservoir Operation
This particular graph reflects the rule curves for Libby Dam for water year 1945.
Libby has a fixed December flood control elevation of 2,411 feet for all years and all water conditions.
In a very wet year, the flood control curve (red line) would dip below the December limit of 2,411 to nearly empty by April.
The yellow dashed line represents the actual energy regulation. It differs from the refill curve because it contains some of the fish constraints.
One constraint attempts to have Libby as full as possible by the end of June so that more water will be available for summer flow augmentation.
A second constraint allows Libby to be drafted as much as 20 feet down from full by the end of August to help achieve river flow targets in the summer. 9

10. Natural and Regulated River Flows
A good amount of the spring runoff can be captured in dams for later use in fall and winter months.
This overhead illustrates how the operation of dams has changed river flows to better match the need for power.
Typically, dams are at their lowest elevations just before the spring runoff season.
As the snow melts and flows increase, some of the water is captured with the intent to fill dams by the end of summer.
In the fall, water is released from storage, as needed, to help meet firm demands.
This effectively shifts spring flows to fall and winter months.
If we had more storage capability, river flows could be shifted even more to match the shape of electricity demand. 10

11. Balance between Resources and Demand11

12. Historic Load/Resource Balance (Based on Critical Hydro)
During the 1980s, the region experienced a surplus of firm generating capability. Little resource development was done. Efforts went into managing the surplus.
By about 1990, the surplus was gone and talk of deregulation became more prominent. Also, several species of salmon were listed under the ESA, which prompted a more constrained hydro operation and a reduction in overall hydro generation.
Even though the load/resource balance was continuing to decrease, no one was particularly alarmed. The region was counting on being able to “share” resources with the southwest, since their peak demand season is late summer and the Northwest’s peak season is winter.
With the onset of deregulation, utilities and IPPs were reluctant to build new resources because of the financial risk.
By the late 1990s it became evident that if something were not done soon that the Northwest’s electricity system would not longer be adequate. 12

13. What’s Happened Since 2000? (Incremental Changes)13

14. Forecast L/R Balance (all load forecasts, critical hydro)14

15. Changes to the Hydroelectric Operation for Fish and Wildlife15

16. Types of Changes
Flow Augmentation – Hold back winter water for later release during spring and summer migration season to shorten travel time
Bypass Spill – Route some flows around turbines to increase passage survival 16

17. Milestones in Fish Recovery
Council’s Water Budget and Spill
Council’s Strategy for Salmon
Council’s Revised F&W Program
NMFS Biological Opinion
NMFS Biological Opinion
2003 – Council’s Revised F&W Program
2004 – NMFS Amended BiOp
In 1984 the Council produced its Fish and Wildlife program that included actions to aid anadromous and resident fish and wildlife.
It was hoped that these actions would reverse the downward trend in populations of several weak anadromous stocks.
By 1990, it became clear that these actions alone would not be enough.
In that year, then senator Hatfield (Oregon) kicked off what has become known as the “salmon summit” which placed more emphasis on the problem. The Council responded by revising its program in 1992.
In spite of the additional focus on dwindling populations, several species were petitioned to be listed as threatened or endangered.
The Council again revised its program in 1994, adding more actions to aid anadromous and resident fish and wildlife.
In 1995, the National Marine Fisheries Service, using its jurisdiction under the Endangered Species Act, developed a biological opinion regarding the listed species. This biological opinion had elements that directly affected the operation of the hydroelectric system.
The biological opinion was revised in 1998 and will be revised again this year.
The Council is also in the process of revising its fish and wildlife program. 17

18. Summary of Changes (affecting mainstem passage)
Increased volume for flow augmentation
Longer flow augmentation period
Increased bypass spill levels
Longer period for bypass spill
In general, the changes made to the operation of the hydroelectric system to aid fish and wildlife are summarized in the slide above.
More stored water has been made available to help increase river flows and to control temperature.
More of the river flow is being diverted around the turbines to increase smolt survival.
And many other actions are being implemented to make the river system a more healthy environment for fish and wildlife. 18

19. Flow Augmentation Period
Among other actions in the Council’s 1984 fish and wildlife program, a little under 5 million acre-feet of water was to be reserved to increase river flows in May at both McNary (Columbia) and Lower Granite (Snake) dams.
As both the Council and NMFS continued to revise their respective plans to aid fish, the period of time over which flows would be augmented has grown to nearly 5 months, from April through August.
Also, the period of time when some percentage of river flow is diverted past the turbines (bypass spill) has also increased. 19

20. Max Flow Augmentation Volumes
Since 1984, the volume of water reserved for flow augmentation or for temperature control has increased from about four and a half million acre-feet (maf) to about 12.5 maf.
This total includes one maf from Canadian storage and 427,000 acre-feet from Upper Snake River dams.
The total volume reserved for fish operations is over half of the total storage capability of all the US reservoirs (12.5 maf/21 maf). 20

21. Changes in River Flows (since 1980)
The shift in river flows, from spring to winter for power needs, is believed to be harmful to salmon because it slows down the river during the migration period.
Slowing down the river results in a longer travel time for smolts to get to the ocean.
Longer travel time means more exposure to temperature, predators and other harmful factors.
The premise behind the recovery plan is that by increasing the velocity of the river, and thereby decreasing smolt travel time, survival will increase.
Since 1980, river flows have been partially restored to a more natural shape (the solid green line in the overhead).
In addition, some of the flows in the spring and summer are routed around the turbines (spilled) to increase survival past the dams.
This change in river operations is not without cost.
By withholding more water in reservoirs in fall and winter, cheap hydroelectric energy is reduced during these months, occasionally forcing utilities to forego sales or to purchase from out-of-region sellers. 21

22. Change in Hydro Generation (Relative to an operation with no fish constraints)
Here we add the change in hydro generation to the price chart in the previous slide.
The monthly cost (or benefit) is then, just the loss (or gain) of energy (MW-hours) times the price ($/MW-hours).
The region should expect an average cost in all months from September through March.
As river flows are increased from April through August, the region will see revenue gains, especially in July and August when prices are the highest.
Overall, the total regional annual energy cost is about $153 million. 22

23. Annual Cost of Fish and Wildlife Hydro Operations23

24. 2006 Forecast Market Price for Electricity
This slide graphically depicts the forecast of west-coast wholesale market prices for electricity.
This forecast was developed with the AURORA model.
For the west coast, prices are highest during July and August when southwest demand is greatest.
A winter peak in prices is also visible but is not as significant as the summer peak.
Prices are lowest in May when there is ample supply of hydro generation and demands in both the northwest and southwest are low.
The average price across all months of the year is about $27/MW-hour. 24

25. Evaluating the Cost for 2006 (Energy Loss and Market Price)
Here we add the change in hydro generation to the price chart in the previous slide.
The monthly cost (or benefit) is then, just the loss (or gain) of energy (MW-hours) times the price ($/MW-hours).
The region should expect an average cost in all months from September through March.
As river flows are increased from April through August, the region will see revenue gains, especially in July and August when prices are the highest.
Overall, the total regional annual energy cost is about $153 million. 25

26. Average Monthly Regional Energy Cost
While the net annual energy cost is about $153 million, monthly costs (and benefits) can vary substantially. Costs range from a low of about $10 million in November to a high of about $50 million in December.
The total cost over the fall and winter months is about $218 million.
Benefits in the spring and summer range from a little under $10 million in April to over $30 million in July.
The total benefit (revenue gains) over the spring and summer months is about $65 million.
The net annual cost is then $218 million minus $65 million or about $153 million.
The costs portrayed in this slide are average values based on the change to hydro generation averaged over a 50-year historical water record. Variation in year to year costs will be presented later. 26

27. Dealing with Uncertainties

28. Historical Runoff at The Dalles
This slide illustrates the variability in the amount of water that flows in the Columbia River from year to year.
An average year would appear on this chart as a bar with zero height.
In the driest year (1977) the runoff was almost 50 percent lower than the average.
In the wettest year (1974) the runoff was nearly 50 percent greater than the average.
It is difficult to tell from this slide whether or not a pattern exists, although there are clearly dry periods and wet periods.
2005 Forecast 69% of Average 28

29. Recent Runoff Volumes (January-July Volume at The Dalles)29

30. Variation in Cost due to Water Conditions (2006)
The next series of overheads demonstrate the uncertainty and variability in the estimate of power system cost due to water conditions.
Yearly costs range from a low of about $100 million to a high of about $260 million (with an average of about $153 million).
There does not appear to be a very good correlation between cost and runoff volume, although the costs for wet years (far right hand portion of the graph) all tend to be below the average value.
Intuitively, one might think that cost should decrease as runoff volume increases. This relationship, however, does not hold true because of other factors, two of which are described below:
Because spill requirements are prescribed as a percentage of flow, the higher the runoff and flow, the higher the spill and foregone sales and this contributes to greater cost in wet years.
Another factor affecting cost is the timing of the runoff. Warm temperatures in March and April can initiate an early runoff prior to the migration season. And, conversely, a cold spring might delay the runoff until May or June. 30

31. Cost Probability Curve (2006)
This overhead displays the probability that recovery costs in a particular year will be at or above a certain magnitude.
The curve indicates that there is only about a 10 percent chance that the cost in any given year will be less than $100 million (bottom right part of the curve). Similarly there is about a 10 percent chance that costs will be greater than $200 million (top left part of the curve).
There is about a 50 percent chance that the cost will be $153 million or greater. 31

32. Fish and Wildlife Cost Components

33. Bypass Spill and Flow Costs
This overhead displays the probability that recovery costs in a particular year will be at or above a certain magnitude.
The curve indicates that there is only about a 10 percent chance that the cost in any given year will be less than $100 million (bottom right part of the curve). Similarly there is about a 10 percent chance that costs will be greater than $200 million (top left part of the curve).
There is about a 50 percent chance that the cost will be $153 million or greater. 33

34. BiOp Flow Costs (Generally, as runoff increases, cost goes down)34

35. Bypass Spill Costs (A non-linear function of runoff)35

36. Anatomy of Bypass Spill Costs36