Glen Canyon Dam Releases – Economic Considerations

David Marcus

February 28, 2009

I. Introduction 

Glen Canyon Dam, located directly upstream of Grand Canyon National Park, 

controls the flow of the Colorado River through the Grand Canyon. Releases from the 

dam currently fluctuate hourly, daily, monthly, and annually in response to both 

hydrology and changing electricity demand and prices. However, under a “Seasonally 

Adjusted Steady Flow” (SASF) alternative, as described in the March 1995 Final 

Environmental Impact Statement (FEIS) for operation of Glen Canyon Dam, monthly 

volumes would change and daily fluctuations would largely cease.

Section II of this report analyzes how changing the release pattern would affect 

the economic value of power generated at the Glen Canyon Dam powerplant, and how 

those changes would in turn affect the cost of electricity to consumers throughout the 6-

state area where Glen Canyon Dam generation is sold. Section III of this report 

summarizes the results from Section II, and concludes that the total dollar cost of 

changing dam operations would be small, and the impacts on individual customers would 

be very small indeed.

II. Analysis

A. Basis for economic costs associated with different release alternatives

The Western Area Power Administration (WAPA) markets the electricity 

generated at Glen Canyon Dam, and other smaller facilities in the Colorado River Storage 

Project (CRSP) system of reservoirs. CRSP generation is sold at cost to Federal agencies, 

electricity generating cooperatives, and publicly-owned electric utilities within a six-state 

area consisting of the states of Arizona, Colorado, Nevada, New Mexico, Utah, and 
Wyoming. Differences between the hourly CRSP generation and WAPA contracts are 

made up by WAPA sales and purchases into the larger wholesale market. Thus, any 

changes in Glen Canyon Dam operation will lead to changes in WAPA’s market sales 

and/or purchases. The economic cost of changing from one pattern of Glen Canyon 

generation to another can thus be estimated as equal to the market value of the changes in 

generation in each hour, summed over all hours with changed generation. I have analyzed 

the costs associated with changing from current Glen Canyon Dam generation patterns to 

SASF, based on both recent historical data and on near-term future generation 

projections. 

At the most general level, the economic costs associated with different release 

alternatives are due to timing effects. Changing from one release alternative to another 

does not change the total annual releases from Glen Canyon Dam, and does not cause any 

significant change in the total annual kilowatthours (kwh) generated at the dam.1 The 

economic differences come from shifting water releases from months when electricity is 

more valuable to months when it is less valuable (or vice versa), and from shifting water 

releases from hours of the day when electricity is more valuable to different hours when 

it is less valuable. In general, changing from the current release alternative to seasonally 

adjusted steady flows will decrease the value of Glen Canyon Dam generation due to 

more night-time water releases and less daytime water releases. But it will increase the 

value of Glen Canyon Dam generation due to more summertime water releases and less 

wintertime water releases. The net effect, as discussed and quantified below, is a very 

slight decrease in the value of annual Glen Canyon Dam generation, which results in a 

very slight increase in costs to Glen Canyon Dam generation purchasers. The average

 1

 There can be very minor differences in annual kwh generation between release 

alternatives due to different reservoir elevations during the course of a year under 

different release alternatives.
overall cost of Glen Canyon Dam generation to purchasers would remain well below its 

market value.

B. Analysis of costs associated with changing to seasonally adjusted steady flows 

(SASF) – modeling assumptions

To model impacts that would have occurred if SASF had been in effect during the 

most recent water year (i.e., WY2008; from October 2007 through September 2008), I 

used actual monthly releases from Glen Canyon Dam during the October 2007 through 

September 2008 period, actual prices for on-peak and off-peak electricity delivered at the 

Palo Verde trading point during the same period (taking into account Sundays and 

holidays as they affected which hours were on-peak and which were off-peak), actual onpeak and off-peak minimum release requirements, and actual daily fluctuation limits 

during that same period. I used actual Glen Canyon dam conversion efficiency data (for 

the amount of electricity produced per acre-foot of water released) for the period 

September 2007 – August 2008, the most recent 12-month period for which I had data.

I assumed that releases would not be affected by WAPA customer loads, or constrained 

by ramp rate limitations.

To model SASF, I used the monthly release amounts shown in the 3/95 FEIS for 

Glen Canyon Dam operations at p. 32, with one small modification. I made a minor 

reduction of 50 cfs in the September release rate to make the total annual releases come 

out to the annual release rate of 8.23 million acre-feet described in the FEIS for low water 

years.

C. Analysis of costs associated with changing to SASF – methodology

For SASF, the methodology was very straightforward. I performed the SASF 

valuation for the period October 2007 to September 2008. I calculated the number of onpeak hours and off-peak hours in each month, based on National Electric Reliability 
Council (NERC) definitions that are widely used in electricity marketing. I used that data 

to calculate monthly on-peak and off-peak water releases from Glen Canyon Dam. I 

converted the water releases to electricity generation using monthly conversion efficiency 

factors. Glen Canyon Dam conversion efficiency varies primarily due to reservoir 

elevation – the higher the water level in the reservoir, the more electricity can be 

generated from a given amount of water. WAPA data show a 7 percent variation between 

September 2007 and August 2008 in conversion efficiency. 

I obtained monthly average on-peak and off-peak wholesale electricity prices 

based on daily prices reported by the trade publication Megawatt Daily for the Palo 

Verde trading hub. Palo Verde is a large trading location in Arizona, and is the closest 

location to Glen Canyon Dam at which a substantial amount of wholesale electricity 

trading takes place and is reported in the trade press.

Once I had monthly on-peak and off-peak prices and generation amounts, I 

simply multiplied them together to obtain the market value of Glen Canyon generation 

for each period, and summed the 24 periods (12 months, with both on-peak and off-peak 

periods in each month) to obtain an annual value. Note that the total market value of Glen 

Canyon Dam generation is not the amount wholesale customers actually pay for Glen 

Canyon Dam generation. This is because most CRSP generation is sold by WAPA under 

long-term contracts at cost-based prices that are well below today’s market prices. 

However, WAPA makes up the differences between contractual deliveries and CRSP 

generation through market operations, and passes those costs through to its customers. 

Changing Glen Canyon Dam operations will not change long-term contracts. Thus, any 

changes in generation patterns will cause offsetting changes in WAPA market purchases 

(or sales), meaning that the market value of Glen Canyon Dam generation is an 

appropriate measure to use to determine the value of changes in Glen Canyon Dam 

generation.
For the existing modified low fluctuating flow (“MLFF”) operating policy, the 

analysis was more complex. I calculated the maximum average on-peak release rate for 

each month based on the total releases for that month, the number of on-peak hours in the 

month, the daily limit on changes in release rates, and the applicable minimum release 

rates for off-peak hours. This calculation assumed that WAPA will always attempt to 

maximize its on-peak generation and minimize its off-peak generation. In March 2008, I 

counted only releases used to generate power, and not the additional 93 thousand acrefeet that were released as part of a Beach Habitat Building Flow (BHBF) and bypassed 

the power-generating turbines.

After calculating on-peak and off-peak releases for each month, I used the same 

conversion efficiencies and prices as for the SASF analysis, and calculated the market 

value of Glen Canyon Dam generation for the on-peak and off-peak periods of each 

month. I did this calculation for actual release volumes in October 2007 through 

September 2008. The actual releases in the October 2007 – September 2008 year were 

about 7.95 percent higher than that the 8.23 Maf used for the SASF analysis, resulting in 

more electricity generation for that time period (under MLFF) than in the same time 

period under SASF. 

After calculating the market value of Glen Canyon Dam generation under both 

current (MLFF) or proposed (SASF) operating rules, I then calculated the changes in (a) 

water releases, (b) electricity generation, and (c) the market value of generation, for both 

on-peak and off-peak time periods for each month. This calculation was done by 

subtracting the MLFF results from the corresponding SASF results.

For the historical period of October 2007 through September 2008, the analysis 

described above compared a SASF operating regime with 8.23 million acre-feet of 

releases to actual operations in which almost 8.9 million acre-feet of water were released 

(about 7.95% higher than 8.23 maf) through the Glen Canyon Dam powerhouse. Such a 

comparison is clearly incomplete, because SASF was not intended to change the annual 
release amounts from Glen Canyon Dam.2

 However, the FEIS does not specify how 

annual releases under SASF of more than 8.23 million acre-feet would be distributed 

across the different months. Thus, I used three separate methods to estimate the true 

impact of shifting to SASF under October 2007 through September 2008 conditions. In 

each case I assumed that releases under SASF would have been 7.95 percent greater than 

modeled up to that point, so as to match the actual releases in October 2007 through 

September 2008. Then I assumed that the value per kwh generated by the additional 

releases would have been either (1) equal to the average value per kwh of all other 

releases over the entire period, or (2) equal to the average value per kwh of all other offpeak releases over the entire period, or (3) equal to the value per kwh of off-peak releases 

during the lowest-market-value month of the entire period (i.e., September 2008). The 

third of these methods produces what I consider to be a lower bound for the value of the 

incremental electricity resulting from releases of 8.9 maf of water rather than 8.23 maf.

D. Analysis of costs associated with changing to SASF – results

Implementing SASF instead of MLFF in WY 2008 would have increased 

WAPA’s market operations costs, and thus increased the cost of CRSP deliveries to retail 

customers, by $1.04 to $8.85 million. Table 1 compares MLFF (actual operations) in 

water year 2008 to what would have occurred if SASF had been in effect during the same 

period. If the annual release above 8.23 Maf is valued at annual average prices, then the 

value of Glen Canyon Dam electricity produced under SASF would have been $1.04 

million less than the value of electricity produced under MLFF. In the worst case, if the 

annual release above 8.23 Maf is valued at the lowest monthly off-peak prices of the 

year, then implementing SASF would have increased costs to retail customers by $8.85 

million. 

 2

 The FEIS on Glen Canyon Dam operations shows average annual releases under MLFF 

and SASF would differ by less than 0.1 percent.
E. Analysis of costs associated with changing to SASF – caveats

The analysis described above assumes that WAPA would maximize the value of 

Glen Canyon Dam electricity generation by shifting water releases as much as possible 

into on-peak time periods and out of off-peak time periods. To the extent WAPA does not 

do so, the analysis overstates the value of electricity generation under MLFF. There are at 

least two reasons why my analysis does indeed overstate the value of current generation, 

with no corresponding overstatement of the value of generation under SASF. First, 

WAPA is constrained by ramp rate limitations under MLFF. Thus, while daily increases 

of up to 5000 cfs are allowed in all months, hourly increases of 5000 cfs are not allowed. 

My modeling, by ignoring ramp rate constraints, overstates WAPA’s ability to maximize 

on-peak generation, and thus overstates the value of generation under MLFF. Under 

SASF, ramp rate constraints are not binding and do not affect the results. Second, WAPA 

schedules releases from Glen Canyon Dam taking into account its customer loads, rather 

than simply maximizing the value of Glen Canyon Dam generation and making up all 

mismatches between WAPA generation and WAPA loads with market purchases and 

sales. Thus, under MLFF operating criteria, some on-peak hours Glen Canyon Dam 

generation could have been higher than it actually was, and in some off-peak hours Glen 

Canyon Dam generation could have been lower than it actually was. By not modeling onpeak hours when WAPA responds to its customers’ load by reducing generation below 

allowable upper limits (or off-peak hours when it increases generation above allowable 

lower limits), I have overstated the value of generation under MLFF. Under SASF, 

customer loads do not affect Glen Canyon Dam generation and thus do not affect the 

results.I assumed that SASF would not include beach-building flows, or habitat 

maintenance releases in excess of the capacity of the Glen Canyon Dam turbines. During

the March 2008 beach-building experiment, releases in excess of 26,000 cfs did not pass 

through the Glen Canyon Dam powerplant, and did not generate any electricity. A total of 
93 Kaf of water was released without generating electricity. Under SASF, such bypass 

flows reduce generation during both on-peak and off-peak periods. Under MLFF, it is 

possible that a disproportionate amount of the reduction in power generation will be 

shifted to off-peak periods, and thus the net cost of beach-building flows will be lower 

under MLFF than under SASF. I have not quantified this potential effect of changing to 

SASF.

I used actual on-peak and off-peak energy prices from October 2007 through 

September 2008 in my analysis. The 2007-08 time period was characterized by a boom 

and bust in world oil prices, which was paralleled by similar trends in U.S. natural gas 

prices. In the western U.S., the marginal source of electricity generation is often (though 

not always, especially in low load periods) natural gas, and thus electricity prices tend to 

track natural gas prices. In the historical data, average monthly Palo Verde off-peak 

electricity prices rose from a low of $40/Mwh in November 2007 to a peak of $71/Mwh 

in April 2008, dropped to $57/Mwh in May 2008, rose back to $69/Mwh in July 2008, 

and then fell to a low of $39/Mwh in September 2008. Average monthly Palo Verde onpeak prices rose from $50/Mwh in November 2007 to a high of $100/Mwh in July of 

2008 (with a one-month dip in May 2008), then fell to $55/Mwh in September 2008. To 

the extent future prices do not mimic the pattern of prices in 2007-08, the net costs of 

changing to SASF will differ.

Changing to SASF involves both eliminating intra-month shifting of generation 

into on-peak periods (because SASF has steady flows within each month) and also 

shifting of generation between months. The general pattern is that SASF defers some 

releases from the October-February period into the March-June period, and accelerates 

some releases from the July-September period into June. This pattern will result in higher 

reservoir levels under SASF from October through May, and lower reservoir levels in 

July-September. The net effect should be a slight benefit from switching to SASF due to 

higher average conversion efficiency of releases into electricity, an effect which I have 
not quantified. On the other hand, if electricity prices are higher later in the summer 

(August-September) than in the spring and early summer (April-June), which was not the 

case in 2008, then switching to SASF would be more expensive than my analysis shows.

I have used conversion efficiencies from September-October 2007 in calculating 

September 2008 generation (in Table 1), due to a lack of more recent data. These 

efficiencies are almost certainly slightly wrong, but affect both the SASF and MLFF 

analyses. It is not clear which direction the bottom line results would shift in with more 

accurate data. It is also not clear whether long-term average conversion efficiencies will 

be higher or lower than those I have used, since that depends on whether the long-term 

average elevation of Lake Powell is higher or lower than the average level in 2007-08.

I have modeled only one historical year. That year had releases for power 

generation of 8.885 Maf. 8.23 Maf is the minimum required release from Glen Canyon 

Dam, and it is the most frequently released amount (the mode, in statistical jargon), but it 

is not the mean release. Long-term average releases from Glen Canyon dam are projected 

to be around 8.56 Maf (3/95 FEIS, p. 179). My analysis does not capture the full range of 

potential hydrological regimes. 

F. Analysis of costs associated with changing to SASF – retail customer impacts

The analysis described above, and presented in Table 1, shows decreases in the 

value of Glen Canyon Dam generation due to switching to SASF which range from $1.04 

million per year to $8.85 million per year. I have performed a further analysis to show 

what those costs would mean for the average retail customer of the utilities served by 

WAPA. As explained in the “Operation of Glen Canyon Dam” FEIS (at p. 304), Glen 

Canyon Dam electricity is sold to utilities within a “six-State region” (Arizona, Colorado, 

Nevada, New Mexico, Utah, and Wyoming), who in turn resell to their retail customers. 

But utilities buying from WAPA serve only about 30 percent of those customers (FEIS, 
p. 304). Thus, the estimated $1 million to $9 million annual cost of changing to SASF 

would be borne by those retail customers.

Glen Canyon Dam supplies only part of the electricity sold by WAPA (albeit a 

large part). WAPA supplies only part of the electricity purchased by WAPA customers. 

Electricity purchases are only part of the costs paid by retail electric utility customers 

(transmission costs, distribution costs, metering costs, and billing costs are examples of 

other costs included in electric bills). Thus, to evaluate the impact of changing to SASF 

on retail customers requires a review of the total electricity quantities purchased and 

prices paid by retail customers.

I have used the most recently available data (from 2006) to calculate that 33.8 

percent of the electricity usage in the six-state area is by retail customers of publiclyowned utilities and cooperatives, and by federal agencies—the categories of groups that

buy all or a part of their electricity from WAPA.3 The remaining 66.2% of usage is by 

retail customers of for-profit utilities and direct use customers. The customers who used 

that 33.8 percent of 2006 6-state electricity sales paid a total of just under $5.5 billion to 

do so, at an average rate of $73.71 per megawatthour, or Mwh (1 Mwh equals 1000 

kilowatthours, or 1000 kwh) of electricity. The average annual household usage in 2006 

was 10.2 Mwh for the year, with average usage varying by state from a low of 7.1 Mwh 

per year in New Mexico to a high of 12.4 Mwh per year in Arizona.

I have calculated how the impacts of changing to SASF (between a $1.04 and an

$8.9 million cost increase) would affect the average residential household in the 6-state 

area, based on the above figures. Assuming cost changes were spread evenly to all retail 

customers in proportion to their energy use, 66.2% of retail customers (those who do not 

receive power from WAPA) would see no impact. The other 33.8% would face rate 

 3

 Consistent with the 2006 data, the 1995 FEIS estimated that 30% of power users in the 

6-state area bought their power from non-profit entities (i.e., Federal agencies, 

cooperatives, and publicly-owned utilities).
increases ranging from 0.02 percent to 0.16 percent, or from $0.01/Mwh to +$0.12/Mwh 

(depending on how much of their power is derived from WAPA). The impact on the 

average residential household’s monthly bill (of affected customers) would range from 1 

cent per month to +12 cents/month in Arizona, the state with the highest residential 

electricity consumption, and would be lower in the five other states. Averaged across all 

6 states, changing to SASF might cost the affected one-third of residential customers an 

average of a penny a month, or it might cost them as much as just over a dime per month.

Averaging the cost of a change in Glen Canyon Dam operations over all users in 

the six-state area (including customers who do not acquire power from WAPA), the 

average impact of changing to SASF for all residential customers in the 6-state area 

would be an increase of between 0.4 cents and 3.4 cents per month. The computations

described in the preceding paragraphs are shown in Table 2. 

An alternative approach to estimating the impact on residential customers if SASF 

had been in place during water year 2008 is consistent with the previous calculations. It 

shows that the CRSP provided about 6.9 percent of the electricity sold by municipal 

utilities, Federal agencies, and electric cooperatives in the 6-state region, and that a 

typical residential customer of a utility obtaining 6.9 percent of its electricity supplies 

from the CRSP would have had 3-6 cent per month increase in their monthly bill due to 

SASF, depending on which state they lived in. These numbers are consistent with the 

middle set of SASF costs calculated in Table 1 and their impacts as shown in Table 2. 

The calculations are presented in Table 3.

Table 3 goes beyond the data in Table 2 to also show the impact on residential 

customers of utilities obtaining 15, 50, or 100 percent of their electricity supplies from 

the CRSP. While the monthly bill increases go up as the percentage of reliance on CRSP 

increases, the total monthly bill goes down. This happens because CRSP generation, 

which consists primarily of generation from Glen Canyon Dam, is sold at prices below 

prevailing spot market prices. Thus, the customers who would theoretically face the 
greatest costs from a switch to SASF are also the customers obtaining the greatest benefit 

from below-market CRSP prices, and the benefit of below-market CRSP prices far 

outweighs any CRSP price increase attributable to a switch to SASF.

III. Summary of conclusions 

Changing Glen Canyon Dam operations from MLFF to SASF would defer water 

releases from the fall and winter forward into the spring. It would accelerate water 

releases from mid and late summer into June. It would shift some releases during each 

month from on-peak hours to off-peak hours. Shifting releases would change the timing 

and value of electricity generation. Increased off-peak generation would decrease the 

value of Glen Canyon Dam generation. Shifting generation between months could either 

increase or decrease the value of generation, depending on the month. Based on historical 

data from the most recent water year, and based on actual prices during that year, shifting 

to SASF in water year 2008 would have decreased the value of Glen Canyon Dam 

generation, and thereby increased costs to end users, by between $1.0 and $8.9 million. 

Changes in the value of Glen Canyon Dam generation would result in changes in average 

residential electric bills in the 6-state area served by Glen Canyon Dam of zero for twothirds of the customers in the 6 states. For the other third of the customers, the average 

residential household electric bill would have increased by between 1 cent per month and 

10 cents per month. In Arizona, where residential customers use more electricity per 

capita than in the other five states, the average residential bill impact would have ranged 

from 1 cent per month to 12 cents per month.
From: David Marcus <dmarcus2@sbcglobal.net>

Date: December 10, 2009 11:59:16 AM PST

To: Mary Orton <mary@maryorton.com>

Cc: Nikolai Lash <nlash@grandcanyontrust.org>

Subject: Re: "Glen Canyon Dam Releases - Economic Considerations"

See the attachment for the tables. Note that for Table 1, there are underlying 

workpapers that are not included. When users open the spreadsheet, they will need to 

click the "don't update" button to avoid problems. For Table 3, the print area is set to 

cells A1.L61, to exclude a duplicate set of input data in column Q (hidden for 

presentation purposes) and allow the results to print on one page in portrait mode. 

Tables 1 and 2 are formatted to fit in one page in landscape mode. For the paper itself, 

there is already a copy of the paper (but not the tables) on the GCT website at 

http://www.grandcanyontrust.org/documents/gc_damEconomics.pdf. The only 

difference between what is on the website and what I handed out on December 2 is that 

I added page numbering to my handout. 

Please call with any questions, 

David 

510/528-0728 
Market values

MLFF MLFF Mwh/af MLFF Off-peak priceOn-peak price Composite Off-peak $ On-peak $ Total $

off-peak Kaf on-peak Kaf (9/07-8/08) Total Kaf Off-peak gwh On-peak gwh ($/Mwh) ($/Mwh) price ($/Mwh) ($1000s) ($1000s) ($1000s)

October 180 422 0.41335801 602 74.5 174.3 $44.59 $59.24 $54.85 $3,324 $10,325 $13,649November 196 407 0.41828059 603 82.2 170.0 $40.31 $50.33 $47.07 $3,313 $8,559 $11,872December 295 508 0.41974884 803 123.8 213.3 $49.99 $58.33 $55.27 $6,187 $12,440 $18,628January 277 524 0.41356194 801 114.7 216.6 $54.66 $63.42 $60.38 $6,269 $13,733 $20,003February 187 415 0.41169875 602 76.9 171.0 $55.72 $67.65 $63.95 $4,284 $11,566 $15,849March 234 503 0.405036 737 94.8 203.7 $60.99 $72.84 $69.08 $5,780 $14,840 $20,620April 199 479 0.41213164 678 82.2 197.3 $70.61 $86.42 $81.77 $5,802 $17,047 $22,849May 227 563 0.42231809 790 95.9 237.8 $56.94 $77.49 $71.59 $5,459 $18,424 $23,883June 234 557 0.44053637 791 103.1 245.4 $62.45 $99.31 $88.41 $6,438 $24,368 $30,806July 290 575 0.45402696 865 131.9 260.9 $69.02 $100.02 $89.61 $9,100 $26,094 $35,194August 317 573 0.44835271 890 141.9 257.1 $53.40 $74.99 $67.31 $7,579 $19,278 $26,857September 248 475 0.41853579 723 103.7 198.9 $39.29 $54.76 $49.46 $4,076 $10,890 $14,966Total 2885 6000 8885 1225.5 2546.1 $55.17 $73.67 $67.66 $67,612 $187,565 $255,177

SASF SASF Mwh/af SASF Off-peak priceOn-peak price Composite Off-peak $ On-peak $ Total $

off-peak Kaf on-peak Kaf Kaf ($/Mwh) ($/Mwh) price ($/Mwh) ($1000s) ($1000s) ($1000s)

October 223 308 0.41335801 531 92.0 127.5 $44.59 $59.24 $53.09 $4,104 $7,550 $11,654November 228 285 0.41828059 514 95.5 119.4 $40.31 $50.33 $45.88 $3,851 $6,011 $9,862December 261 303 0.41974884 564 109.5 127.3 $49.99 $58.33 $54.47 $5,474 $7,427 $12,900January 322 408 0.41356194 730 133.1 168.8 $54.66 $63.42 $59.56 $7,276 $10,707 $17,984February 280 379 0.41169875 659 115.5 156.0 $55.72 $67.65 $62.58 $6,434 $10,555 $16,989March 322 408 0.405036 730 130.4 165.4 $60.99 $72.84 $67.61 $7,952 $12,045 $19,996April 339 464 0.41213164 803 139.7 191.2 $70.61 $86.42 $79.75 $9,866 $16,523 $26,390May 527 668 0.42231809 1195 222.5 282.1 $56.94 $77.49 $68.43 $12,666 $21,864 $34,529June 514 642 0.44053637 1156 226.4 283.0 $62.45 $99.31 $82.93 $14,138 $28,104 $42,242July 366 464 0.45402696 830 166.1 210.6 $69.02 $100.02 $86.35 $11,463 $21,068 $32,531August 263 334 0.44835271 597 118.1 149.8 $53.40 $74.99 $65.47 $6,305 $11,230 $17,536September 256 319 0.41853579 575 106.9 133.7 $39.29 $54.76 $47.89 $4,201 $7,321 $11,522

Table 1: MLFF in 10/07 to 9/08 compared to SASF over the same time period

Total 3901 4984 8885 1655.7 2114.8 $56.61 $75.85 $67.40 $93,731 $160,406 $254,136Annual release ratio (SASF/MLFF): 92.63%Annual release ratio (MLFF/SASF): 107.95%Change from MLFF to SASF Change in market values

Off-peak gwh On-peak gwh Off-peak priceOn-peak price Off-peak $ On-peak $ Total $

off-peak Kaf on-peak Kaf Kaf ($/Mwh) ($/Mwh) ($1000s) ($1000s) ($1000s)

October 42 -113 -71 17.5 -46.8 $44.59 $59.24 $780 -$2,775 -$1,994November 32 -121 -89 13.3 -50.6 $40.31 $50.33 $538 -$2,548 -$2,010December -34 -205 -239 -14.3 -86.0 $49.99 $58.33 -$713 -$5,014 -$5,727January 45 -115 -71 18.4 -47.7 $54.66 $63.42 $1,007 -$3,026 -$2,019February 94 -36 57 38.6 -14.9 $55.72 $67.65 $2,150 -$1,010 $1,140March 88 -95 -7 35.6 -38.4 $60.99 $72.84 $2,172 -$2,795 -$624April 140 -15 125 57.6 -6.1 $70.61 $86.42 $4,065 -$524 $3,541May 300 105 405 126.6 44.4 $56.94 $77.49 $7,207 $3,439 $10,646June 280 85 365 123.3 37.6 $62.45 $99.31 $7,700 $3,736 $11,436July 75 -111 -35 34.2 -50.2 $69.02 $100.02 $2,363 -$5,026 -$2,663August -53 -239 -293 -23.9 -107.3 $53.40 $74.99 -$1,274 -$8,048 -$9,322September 8 -156 -148 3.2 -65.2 $39.29 $54.76 $126 -$3,569 -$3,444Total 1016 -1016 0 430.2 -431.3 $26,119 -$27,159 -$1,040

Additional SASF market value because annual releases from SASF were increased from 8230 kaf to MLFF levels, and revenues increased proportionately: $18,724

Net impact on customers if annual releases with SASF equalled annual releases with MLFF, based on proportionate increase in SASF value -$1,040Net impact on customers if annual releases with SASF equalled annual releases with MLFF, with extra generation all valued at off-peak average price -$4,038Net impact on customers if annual releases with SASF equalled annual releases with MLFF, with extra generation all valued at lowest monthly off-peak price -$8,850
I. Data on sales and household electricity usage; EIA 2006 data from "State Electricity Profiles 2006," 11/21/2007, DOE/EIA-0348(01)/2; household usage data from http://www.swenergy.org/factsheet

State Retail sales (total) Retail sales (public/federal/coop) Retail sales (public) Retail sales (federal) Retail sales (coop) Av

gwh $/Mwh MM $ gwh $/Mwh MM$ gwh $/Mwh MM$ gwh $/Mwh MM$ gwh $/Mwh MM$ ele

AZ 73,253 $82.40 $6,034 32,779 $76.57 $2,510 28,683 $76.40 $2,190 1,443 $39.00 $56 2,653 $99.50 $264 CO 49,734 $76.10 $3,785 20,404 $76.75 $1,566 8,619 $66.60 $574 58 $21.30 $1 11,727 $84.50 $991 NV 34,586 $96.30 $3,330 4,045 $61.56 $249 2,259 $60.80 $137 28 $8.30 $0 1,758 $63.50 $112 NM 21,435 $73.70 $1,579 6,933 $75.15 $521 2,277 $70.30 $160 207 $23.40 $5 4,449 $80.00 $356 UT 26,366 $59.90 $1,578 5,139 $72.39 $372 4,180 $74.60 $312 48 $25.90 $1 911 $65.20 $59 WY 14,947 $52.70 $788 5,265 $52.80 $278 582 $66.30 $39 33 $15.80 $1 4,650 $51.20 $238 Total 220,321 $77.59 17,094 74,565 $73.71 5,496 46,600 $73.22 3,412 1,817 $35.22 64 26,148 $77.25 2,020 Non-profit entities as share of total (sales): 33.8%Non-profit entities as share of total (revenue): 32.2%

MLFF actuals for 10/07 to 9/08with SASF releases increased 7.95% above 8.23 Mafto match actual WY2008 MLFF releases and theincreased SASF releases valued:At annual At average At lowest monthly Avaverage price off-peak price off-peak price (a

(a

Table 2: Residential household impacts of changing from MLFF to SASF in WY 2008

II. Calculation of impacts of changing Glen Canyon Dam operations

(a

$1.040 $4.038 $8.850

Pu

0.02% 0.07% 0.16%

$0.01 $0.05 $0.12

0.82 3.19 6.99 $1.44 5.61 12.29 $1.19 4.60 10.09 $

Average impact on residential household bill if cost spread proportionally to all electricity users in the 6-state area: 0.40 1.56 3.42

2007-08 annual cost increase due to changing Glen Canyon Dam operations to SASF ($ millions):Percentage impact of changing dam operations on 6-state retail cost of electricity for public/federal/coop utilities:Average increase in average rates from changing GCD operations to SASF ($/Mwh):Average impact on residential household bill for 589 kwh (NM average monthly household usage), in cents/month:Average impact on residential household bill for 1035 kwh (AZ average monthly household usage), in cents/month:Average impact on residential household bill for 850 kwh (6-state regional average monthly usage), in cents/month:
State Utility with Utility with Utility with Utility with Utility with

100% market- 93.1% market-priced 85% market-priced 50% market-priced 0% market-priced

priced electricity electricity sources electricity sources electricity sources electricity sources

sources and 6.9% CRSP and 15% CRSP and 50% CRSP and 100% CRSP

AZ

Energy bill with MLFF $70.05 $67.02 $63.47 $48.11 $26.17

Energy bill with SASF $70.05 $67.07 $63.59 $48.52 $26.98

Increase due to SASF $0.00 $0.06 $0.12 $0.41 $0.81

CO

Bill with MLFF $45.62 $43.64 $41.33 $31.33 $17.05

Bill with SASF $45.62 $43.68 $41.41 $31.60 $17.57

Increase due to SASF $0.00 $0.04 $0.08 $0.26 $0.53

NV

Bill with MLFF $63.40 $60.65 $57.44 $43.54 $23.69

Bill with SASF $63.40 $60.70 $57.55 $43.91 $24.42

Increase due to SASF $0.00 $0.05 $0.11 $0.37 $0.73

NM

Bill with MLFF $39.85 $38.13 $36.11 $27.37 $14.89

Bill with SASF $39.85 $38.16 $36.18 $27.60 $15.35

Increase due to SASF $0.00 $0.03 $0.07 $0.23 $0.46

UT

Bill with MLFF $51.49 $49.27 $46.66 $35.37 $19.24

Bill with SASF $51.49 $49.31 $46.75 $35.67 $19.84

Increase due to SASF $0.00 $0.04 $0.09 $0.30 $0.60

WY

Bill with MLFF $58.20 $55.68 $52.74 $39.98 $21.75

Bill with SASF $58.20 $55.73 $52.84 $40.31 $22.42

Increase due to SASF $0.00 $0.05 $0.10 $0.34 $0.67

Total

Bill with MLFF $57.53 $55.04 $52.12 $39.51 $21.49

Table 3: Effects on energy portion of typical residential monthly bill of switching from MLFF to SASF in WY2008 

(ignores transmission and other portions of bill not affected by MLFF/SASF)

Bill with MLFF $57.53 $55.04 $52.12 $39.51 $21.49

Bill with SASF $57.53 $55.08 $52.22 $39.85 $22.16

Increase due to SASF $0.00 $0.05 $0.10 $0.33 $0.67

Input data:

AZ monthly usage: 1035 kwh

CO monthly usage: 674 kwh

NV monthly usage: 937 kwh

NM monthly usage: 589 kwh

UT monthly usage: 761 kwh

WY monthly usage: 860 kwh

6-state monthly usage: 850 kwh

Average market price: $67.66 per Mwh (from Table 1, MLFF analysis, cell K21)

CRSP rate: $25.28 per Mwh (in WY2008)

Annual increase in CRSP cost

due to SASF: $4.038 million (per Table 1, next-to-last line)

CRSP revenues w/ MLFF: $130.265 million (per http://www.wapa.gov/CRSP/ratescrsp/documents/Presentation.pdf)

CRSP rate with SASF: $26.06 per Mwh

CRSP sales: 5154 gwh (per http://www.wapa.gov/CRSP/ratescrsp/documents/Presentation.pdf)

6-state muni/coop/Fed sales: 74565 gwh (per http://www.wapa.gov/CRSP/ratescrsp/documents/Presentation.pdf)

CRSP share of 6-state sales

by munis/coops/Fed agencies: 6.9%