Federal Power: Regional Effects of Changes in PMAs' Rates
Released: 1998-12-16T00:00:00

Letter

Background

The Department of Energy’s (DOE) PMAs sell power primarily to preference customers—cooperatives and public bodies, such as municipal utilities, irrigation districts, and military installations—that are located in the PMAs’ service territories. Many of these preference customers then resell the power to industrial, commercial, and/or residential end-users.

To estimate any potential rate changes if market rates are charged (after a divestiture of the PMAs or otherwise), we calculated how much, in cents per kilowatthour (kWh), each preference customer paid, on average, for power purchased from (1) all sources, including the PMAs, and (2) sources other than the PMAs, including the wholesale market, in 1995. Then, we took the difference between these two, considering the latter to be the market rate. To map the areas that preference customers serve, we identified the counties and towns that the customers reported serving in Electrical World: Directory of Electric Power Producers. It is important to note that our analysis included only those customers that purchased power directly from the PMAs and that our analysis shows higher rate increases than would be likely if market rates decline. To develop information on the characteristics of the areas that preference customers reported serving, for each county and town we obtained data on 1989 household incomes and the extent to which the population is urban or rural, as reported in the 1990 census, the latest data available. Appendix III provides additional details on our scope and methodology.

Most Rate Increases May Be Relatively Small, Although Some May Be Larger

Overall, about 68 percent of Southeastern’s, Southwestern’s, and Western’s preference customers may experience relatively small rate increases. In our analysis, the increases that we considered relatively small (0.5 cent per kWh or less), moderate (from greater than 0.5 cent up to 1.5 cents), and relatively large (greater than 1.5 cents) represent amounts above the average rates that preference customers paid for power from all sources (both PMAs and others) in 1995. These base rates typically ranged in 1995 from 3.5 to 6.0 cents for Southeastern’s preference customers, from 1.5 to 3.5 cents for Southwestern’s preference customers, and from 1 to 4 cents for Western’s preference customers. The increases represent the difference between these average rates and what preference customers would have to pay if they purchased all of their power at market rates. For example, if a preference customer of Southeastern paid a combined 3.5 cents per kWh for power from the PMA and other sources in 1995 and paid 3.9 cents for power from non-PMA sources, we assumed the customer’s rates would rise from 3.5 to 3.9 cents—a relatively small increase of 0.4 cent—if it had to pay market rates for all its power. Our calculation of the increase in a residential end-user’s monthly electricity bill represents the amount of the preference customer’s increase times the average monthly consumption of electricity by residential end-users in the preference customer’s state.

As shown in figure 1, 98 percent of Southeastern’s preference customers may see relatively small rate increases of 0.5 cent per kWh or less if they pay market rates for PMA power. For Western and Southwestern, about half of their preference customers would see relatively small rate increases and about 25 to 30 percent of the customers for each PMA would see relatively large increases. Figure 2 breaks out these potential increases by state and, of the total amount of power consumed in each state, indicates the percentage provided by the PMA.

Estimated increase (cents/kWh)

Relatively small, 0.5 cent (or one-half cent) or less Moderate, greater than 0.5 cent to 1.5 cents Relatively large, greater than 1.5 cents (In 85 percent of the cases, this increase is between 1.5 cents and 3 cents.) (Figure notes on next page)

Estimated increase in preference customers' rates (cents/kWh)

As shown in figure 2, in virtually every state Southeastern serves, at least 85 percent of the preference customers may see relatively small rate increases. Slightly more than half of the PMA’s preference customers may see increases of less than 0.1 cent per kWh. If these preference customers pass their rate increases through proportionally to the residential end-users they serve, the residential end-users would see their average monthly electricity bill increase by $1 or less. In most of Southeastern’s states, the maximum increase that a preference customer would pass on to its residential end-users ranges between $1 and $8 per month, depending on the state. The only relatively large rate increase for a preference customer served by Southeastern may be in Illinois, which has one preference customer.

In states served by Western, preference customers may see a variety of rate increases. For example, as shown in figure 2, over 75 percent of the preference customers in California, Colorado, and Nebraska may experience relatively small rate increases. In these three states, residential end-users served by most preference customers would see less than $2.50 increases in their average monthly electricity bills. However, a significant number of Western’s preference customers may see moderate increases. As shown in figure 2, at least 25 percent of the preference customers in many Western states, such as Iowa, Minnesota, and South Dakota, may experience average rate increases from greater than 0.5 cent up to 1.5 cents per kWh. If these preference customers proportionally pass these costs along to their residential end-users, the end-users would pay from $3 to $14 more in their average monthly electric bills, depending on the state.

Finally, in several states served by Western, a number of preference customers may see average rate increases that exceed 1.5 cents per kWh.

For example, 60 percent of the preference customers in South Dakota and 33 percent of the customers in Utah may see rate increases exceeding 1.5 cents per kWh. In turn, residential end-users who receive power from these utilities would see larger increases in their electricity bills. For example, in states with larger rate increases, if a preference customer’s rate increases by 1.5 cents per kWh, residential end-users would pay about $10 to $15 more per month for electricity, depending on the state. Preference customers who may see these larger increases typically paid relatively low rates, ranging from 1.5 to 3.0 cents per kWh and bought most or all of their power from Western.

Taken together, Southwestern’s preference customers may experience higher rate increases than Southeastern’s customers but lower increases than Western’s. As shown in figure 2, in most of Southwestern’s states, a majority of the preference customers may see relatively small increases of 0.5 cent per kWh or less on base rates that typically ranged from 1.5 to 3.5 cents. In turn, residential end-users that receive power from most of Southwestern’s preference customers’ would see their electricity bills increase by less than $3 a month. However, in Oklahoma, 79 percent of the preference customers may see larger increases that exceed 1.5 cents per kWh. Most of these customers paid less than 1.5 cents per kWh—less than half the 1995 national average market rate—and purchased all of their power from Southwestern. Residential end-users of these preference customers typically would pay about $22 more in their average monthly electricity bills.

As we discussed in our March 1998 report, it is important to remember that in many cases where rate increases may be relatively large (greater than 1.5 cents per kWh), the preference customers paid about 1 to 1.5 cents per kWh in 1995 for PMA power. These rates on average were about 2.5 to 3 cents per kWh lower than what utilities paid in the private market nationwide. Conversely, in many cases where rate increases may be relatively small, that is, 0.5 cent per kWh or less, preference customers generally paid rates close to the market rates. If market rates are charged (after a PMA divestiture or otherwise), preference customers would pay the same rates as utilities that lack access to PMA power. As we discussed in our March 1998 report, if the Congress chose to change the status quo regarding rates, it could mitigate the size of potential rate increases by using several approaches, such as establishing rate caps.

A preference customer’s rate increase also depends on what portion of its total power comes from the PMA. Generally, the less a preference customer relies on a PMA’s power, the less the rate increase may be. Preference customers in states served by Southeastern may experience small increases because they purchase a small portion of their power from the PMA. In 1995, 99 percent of Southeastern’s preference customers purchased less than 25 percent of their power from the PMA. Overall, most preference customers purchase a majority of their power from sources other than the PMAs and, as a result, currently pay market rates for that power. In contrast, preference customers that purchase a large portion of their power from a PMA are more likely to experience larger increases. For example, among the 60 percent of the preference customers in South Dakota that may experience rate increases of at least 1.5 cents per kWh if market rates are charged, most bought over 70 percent of their power from the PMA in 1995. Overall, PMA power represented about 23 percent of South Dakota’s total electricity consumption in 1995. Usually, preference customers that rely on a PMA for most or all of their power are smaller utilities that deliver 100,000 megawatthours or less to their end-users annually.

It is important to also note that because our estimates of potential rate increases are based on market rates in 1995, our methodology is conservative. If prices for wholesale power decline in the future, as many industry analysts and DOE officials believe they will, customers’ rate increases generally will be smaller than our estimates.

Finally, the likely rate increases we discuss—from relatively small to relatively large, if the preference customers pay market rates for PMA power—would usually affect a relatively small portion of the power consumed in each state, as shown by the shading or patterns in the states in figure 2. We found that the portion of the total power consumed in a state that was provided by the three PMAs was generally relatively small. For example, the PMAs provided 5 percent or less of the total power consumption in 22 of the 29 states in our analysis. The average for the 29 states was 2 percent.

Preference Customers Serve Varying Portions of Many States

As shown in figure 3, preference customers that are directly served by Southeastern, Southwestern, and Western reported serving varying portions of 29 states across the nation. We did not include customers that receive PMA power indirectly, that is, through direct preference customers of the PMAs—generation and transmission cooperatives and municipal joint action agencies—because, with very few exceptions, the PMAs’ 1995 annual reports do not list them.

Our map includes only the counties and towns that preference customers serve directly and does not include preference customers such as generation and transmission cooperatives or municipal joint action agencies, who buy PMA power and then resell it to other publicly owned utilities. The annual reports for Southeastern and Western do not include these utilities as customers, while Southwestern’s does in two cases.

As the figure shows, in most states, the areas the preference customers reported serving directly cover less than half the state. For example, very small portions of Arkansas, Louisiana, and Missouri are served by preference customers. In some cases, small areas are served in part because only a few preference customers directly serve the state. For example, Illinois and Wisconsin have only one preference customer to serve residential end-users, while Kentucky and Montana have three. Other states have more preference customers, but in some cases they serve counties and towns that are concentrated in portions of the state. For example, South Carolina’s 26 preference customers reported serving areas almost exclusively in the northwestern corner of the state. The seven preference customers in Wyoming reported serving four counties, which are clustered in the southwestern and south central portions of the state and two towns but no other areas in the rest of the state. Similarly, the eight preference customers in Texas reported serving 17 counties in the south central part of the state and five towns in eastern Texas but did not serve the rest of the state.

Additionally, as depicted in figure 3, large portions of several of Southeastern’s and Western’s states receive service directly from preference customers. For example, preference customers reported serving almost every county in Georgia and most of the counties in North Carolina and Virginia. In these states, many counties received service from two or more preference customers. In Nebraska, preference customers reported serving over 130 towns located around the state.

Finally, regardless of their geographic coverage, we found, as shown in figure 2, that the preference customers generally provided a relatively small portion of the total power consumed in each state.

In Income, End-Users Are Similar to the Population of the Entire State; Most Service Areas Are Either Urban or “Mixed”

Although preference customers serve areas with incomes lower than the national average, most of the households they serve have incomes that are similar to those in the entire state. As shown in figure 4, in 21 of 28 states, households in the counties and towns preference customers report serving had median incomes within 15 percent of the statewide median income, as reported in the 1990 census.

In some states, the median incomes of the end-users and statewide are close because almost every county in the state receives power from preference customers. For example, in Georgia, preference customers reported serving 151 of the state’s 159 counties. Furthermore, the distribution of income for households receiving PMA power generally mirrors the distribution of household income in the entire state. For example, in Alabama, about 35 percent of the households in preference customers’ service areas had annual incomes of less than $15,000 in 1989, while 24 percent had incomes exceeding $40,000. Similarly, in the entire state, 33 percent of the households had annual incomes under $15,000, and 26 percent had annual incomes exceeding $40,000. This compares with the 1995 national average household income of $35,004.

However, in a few cases, preference customers serve areas that are significantly poorer than the remainder of the state. For example, in 1989 in Texas, the median income of the households preference customers served was almost 40 percent lower than median household income of $27,016 in the entire state. In preference customers’ service areas, over 45 percent of the households had annual incomes smaller than $15,000, compared with 28 percent of the households in the entire state. Similarly, in Montana, preference customers served households with median incomes 20 percent, or about $4,500, below the state median of $22,988. In commenting on our draft report, DOE officials noted that the PMAs also provide a valuable service to Indian reservations, which are among the poorest areas of the nation. Our analysis shows, for example, that about 53 percent of the households in Shiprock, New Mexico, which is located on the Navajo Indian Reservation, had median incomes of less than $15,000, compared with about 31 percent statewide.

In contrast, preference customers in some states send PMA power to a number of counties and towns where a large portion of the households have relatively high incomes. For example, in California, preference customers reported serving areas in the southern part of the state such as Orange County, where about 45 percent of the households had incomes in 1989 exceeding $50,000—at least 40 percent higher than the state median income of $35,798. In the northern part of the state, preference customers reported serving Palo Alto, where 55 percent of the households had incomes exceeding $50,000. Throughout California, about 45 percent of the households in areas preference customers reported serving had annual incomes exceeding $40,000. Similarly, in Colorado, about 33 percent of the households in Aspen had 1989 incomes that exceeded $50,000 or at least 65 percent greater than the state median income of $30,140.

We estimate that, overall, about 53 percent of the towns that preference customers reported serving are urban. States where most of the towns are urban include California, Georgia, and North Carolina. In addition, about 47 percent of the towns preference customers reported serving are rural. States where large numbers of these towns are rural include Florida, Iowa, and Nebraska. Less than 1 percent of the towns are “mixed”—that is, they have populations that are neither urban nor rural. Most counties that preference customers reported serving, or about 52 percent, are mixed. Alabama and South Carolina, for example, have high percentages of mixed counties. About 39 percent of the counties are rural, about 9 percent of the counties are urban. North Dakota and South Dakota have large proportions of rural counties.

Finally, although preference customers sell PMA power in many less densely populated areas, most of the households they serve are located in a small number of more urbanized places. This suggests that most PMA power is consumed by customers in more highly urbanized places. For example, although preference customers reported serving 150 counties in Georgia, 11 of those counties contain over half of the households in the areas preference customers reported serving.

Agency Comments

We provided copies of a draft of this report to DOE for its review and comment. We received comments from DOE’s Power Marketing Liaison Office, which is responsible for Southeastern, Southwestern, and Western, and have included its comments and our responses as appendix V.

DOE commented that our data sources were flawed because we relied on incomplete and/or inaccurate data and that it was impossible to have confidence in conclusions drawn from analysis of the data. To address each of our objectives, our analyses used data reported by the PMAs and their preference customers—data that we believe to be the best available. DOE recognizes that obtaining complete data on the electric utility industry is not easy. We believe that we used the data appropriately to satisfy the objectives of our review and that our methodology is sound. However, we agree that the data we used have limitations, and we have pointed out the limitations in our report. Many of the concerns that DOE expressed do not deal with the data we used but with the definition of a preference customer of a PMA. DOE stated that our analyses omitted generation and transmission cooperatives, their members, and municipal joint action agencies. For our analysis, we included only the preference customers who purchased power directly from the PMAs—as listed in the PMAs’ 1995 annual reports. We did not include generation and transmission cooperatives, their members, or municipal joint action agencies because the annual reports of two of the three PMAs—Southeastern and Western—do not include them in their lists of customers. Because Southeastern and Western together represent over 90 percent of the total preference customers of the three PMAs, we used their approach. If our rate analysis had included the utilities that indirectly buy PMA power through preference customers, the rate increases for these utilities would have been, at most, the same as the increases for the preference customers. For our analysis of urban/rural populations, we used the counties and towns that the preference customers that were included in our rate analysis reported to Electrical World: Directory of Electric Power Producers. We acknowledge that the data in Electrical World may not match the actual service territories. However, we used these data because they were reported by the preference customers and were the best available.

DOE also stated that using 1995 data does not reflect today’s market situation. As the electricity market continues to evolve, many industry experts believe that market rates for wholesale power have declined since 1995 and will fall farther. If market rates fall more than the PMAs’ rates, our estimates of rate increases will prove to be overstated. We have seen no evidence that the PMAs’ overall rates have fallen more than rates in the wholesale market. DOE also commented that more balance was needed in our report because the report goes beyond reporting data and does not present all opposing points of view. We believe that our report is balanced and that, throughout the report, we present a neutral description of our objectives and findings. Nevertheless, we have added additional detail to our report, such as including all options for the PMAs’ future role in the changing electricity market and noting that a PMA provides power to Native American households with low incomes.

We met with officials from the American Public Power Association and National Rural Electric Cooperative Association, which are national representatives of the PMAs’ preference customers, and discussed the methodology we used to perform our analysis and the results we obtained. On our rate analysis, the officials commented that certain preference customers may see larger rate increases than what we estimated because, to replace the power they buy from the PMAs, they would pay more than what they paid for non-PMA power in 1995. The officials also commented that, although we classified many of the rate increases as relatively small, these increases could nonetheless have significant economic impacts on preference customers or their end-users. However, these officials said that they could not provide more detailed comments until they and the members of their organizations had an opportunity to review the final report and its appendixes.

We also met with representatives of the Edison Electric Institute and discussed the methodology we used to perform our analysis and the results we obtained. They commented that our analysis was credible, although they suspected that it could have overstated the rate increases that may occur because competition is increasing and market rates for electricity have been declining. They believe that the impact of the preference customers’ paying market prices for power would be quite modest. They also commented that, if the wholesale rate impacts were translated to the prices that the ultimate consumer would see, the impacts would be even less.

We conducted our review from May through November 1998 in accordance with generally accepted government auditing standards.

As agreed with your offices, unless you publicly announce its contents earlier, we plan no further distribution of this report until 30 days from the date of this letter. At that time, we will send copies to appropriate House and Senate committees and subcommittees; interested Members of the Congress; the Administrators of Southeastern, Southwestern, and Western; and other interested parties. We will also make copies available to others upon request.

If you have any questions or need additional information, please contact me on (202) 512-3841. Major contributors to this report are listed in appendix VI.

Tennessee Valley Authority’s Service Area

The Tennessee Valley Authority (TVA) sells power to 159 municipal and cooperative distributors and to a number of directly served large industrial customers and federal agencies. As shown in figure I.1, TVA sells power to customers located in Tennessee and parts of six other states in the Southeast. According to the Southeastern Power Administration (Southeastern), TVA purchased nearly 1.9 billion kilowatthours (kWh) of electricity from the PMA in fiscal year 1995 and over 2.9 billion kWh of electricity in fiscal year 1996 for resale to TVA’s municipal and cooperative distributors. However, as described in appendix III, we did not include Southeastern’s sales to TVA in our analysis.

Power Marketing Administrations’ Service Areas

As figure II.1 shows, according to the Department of Energy (DOE), its power marketing administrations (PMA) serve preference customers located in all or parts of 34 states.

Bonneville Power Administration Southeastern Power Administration Southwestern Power Administration Western Area Power Administration Both Western and Southwestern market power in Kansas.

Objectives, Scope, and Methodology

Since the New Deal, the federal government has established about 130 water projects that—in addition to promoting agriculture, flood control, navigation, and other activities—produce electric power. To sell this power to large portions of rural America, the federal government created five PMAs and TVA.

Now that nearly all of America has electricity, some believe the PMAs have completed their mission and should be divested. Others suggest that the PMAs be required to charge market rates for power. However, since PMAs have historically served rural areas, concerns have been raised that a change in PMAs’ ownership or the means by which they establish rates could adversely affect the rural or poorer areas they serve. Yet few analyses to date have identified the places that ultimately consume PMA power or the characteristics of the households the preference customers serve.

To aid in congressional deliberations on the future role of the PMAs, you requested that we provide a state-by-state analysis of the preference customers who buy power from Southeastern, Southwestern, and Western. More specifically, you asked that we identify (1) the extent to which preference customers’ rates may change by state if market rates are charged, (2) the areas the three PMAs’ preference customers report serving, and (3) the incomes in these areas and the extent to which they are urban or rural.

Estimating Preference Customers’ Potential Rate Changes

To estimate how much preference customers’ rates may change if the customers paid market rates for the power they currently purchase from the PMA, we calculated the average rates that each PMA preference customer paid for wholesale power from (1) all sources, including the PMAs, and (2) sources other than the PMA, including the wholesale market, in 1995. Then, we took the difference between these two rates, considering the latter to be the market rate.

Estimating the potential changes required several steps and assumptions. First, to calculate how much preference customers paid for the PMAs’ power, we obtained data from Southeastern’s, Southwestern’s, and Western’s fiscal year 1995 annual reports. Then, to learn how much each preference customer paid for the power it purchased from other sources, we used the “sales for resale” databases compiled by the Energy Information Administration (EIA). We found that for about one-third of the three PMAs’ preference customers, EIA’s data lacked the volumes of wholesale power the customers purchased from non-PMA sources, the amounts the customers paid for power, or both. In these cases, we assumed the customer paid a rate equal to the average market rate paid by customers of the same type (for example, municipal utilities and cooperatives) for wholesale power in the customer’s state. We then combined each preference customer’s purchases of PMA power and non-PMA power to estimate how much the customer paid for wholesale power from all sources in 1995.

Second, to estimate how each preference customer’s rates would change if it paid market rates for PMA power, we assumed that the customer would pay a rate equal to the average rate it paid for wholesale power from sources other than the PMA(s) in 1995. We used this assumption because it is likely that in the period immediately after a divestiture, the new owners of the PMAs’ assets would charge the prevailing market rates for wholesale power in the area. We also took this approach because we were unable to obtain forecasts of future wholesale rates. Although EIA used its National Energy Modeling System to forecast future electricity rates, according to agency officials, its projections are only for retail rates. Others’ projections of future wholesale rates are proprietary.

Finally, we compared the average rate each preference customer paid for all its power in 1995 with the rate the customer paid for the power it purchased from sources other than the PMA. The difference in these two rates represents our estimates in cents per kWh of each customer’s potential increase in average rates if it paid market rates for the power it currently purchases from the PMA.

After estimating how much preference customers’ rates may change, we analyzed the rate changes by state. To do this, we had to determine the state in which each preference customer primarily sells power. We obtained state designations for each preference customer from EIA’s Form 861 database of utilities for 1995. However, in cases where the preference customer did not sell retail power, EIA did not provide a state designation. In these instances, we consulted EIA’s PURCH and SALES databases of wholesale electricity transactions in 1995 and assigned the preference customer to the state where it sold most of its wholesale power. In the few cases where the preference customer did not sell a large majority of its power to a single state, we assigned the preference customer to the state where it is listed in the Electrical World: Directory of Electric Power Producers (1997 ed.).

Because we assumed that, after a divestiture, each customer would pay a rate for power that equals what the preference customer paid for non-PMA power in 1995, our methodology is conservative. If prices for wholesale power decline in the future, as many industry analysts and DOE officials believe they will, customers’ rate increases would be smaller than our estimates.

It is important to note that we estimated potential rate increases for the preference customers that the PMAs listed in their 1995 annual reports. These customers buy power directly from the PMA. We did not include utilities that indirectly buy PMA power through direct preference customers such as generation and transmission cooperatives and municipal joint action agencies. We did not include these indirect customers because, with very few exceptions, the PMAs did not count them as customers in their 1995 annual reports.

Estimating Changes in Residential Customers’ Electricity Bills

To estimate how each preference customer’s rate change would affect the rates paid by its residential end-users, we assumed that (1) the preference customer would pass the rate change on proportionally to its end-users and (2) that each state’s residential end-users would consume a quantity of electricity equal to the average residential consumption for that state in 1995, according to EIA. The monthly increase in a residential end-user’s electricity bill equals the preference customer’s rate increase after the PMA begins charging market rates (in cents per kWh) times the residential end-user’s average annual electricity consumption for the appropriate state (in kWh), divided by 12.

Defining Preference Customers’ Service Areas

To define the preference customers’ service areas, we identified the counties and/or towns in Electrical World: Directory of Electric Power Producers (1997 ed.) that each of the customers in our analysis reported serving. As was true with our rate analysis, we included only the preference customers that purchased power directly from the PMAs—that is, those customers the PMAs listed in their 1995 annual reports. If we had included utilities that indirectly purchase PMA power (through direct preference customers), such as generation and transmission cooperatives and municipal joint action agencies, more counties and towns would be shown on our state service territory maps. According to DOE officials, many additional counties would be shaded in, among other states, Montana, South Carolina, and Wyoming.

Characterizing Incomes and Urban and Rural Populations in Preference Customers’ Service Areas

To examine the incomes in areas that ultimately consume PMA power, we obtained 1990 census data (based on calendar year 1989) from the Census Bureau on household incomes in each county and town the preference customers reported serving in Electrical World.

To determine the degree to which preference customers’ service areas were urban or rural, we obtained 1990 census data from the Census Bureau on the urban and rural populations in each county and town the preference customer reported serving. We classified a county or town as urban or rural if at least 80 percent of its population is urban or rural as defined by the Census Bureau. If the county’s or town’s population is less than 80 percent urban or rural, we classified it as “mixed.”

Because the PMAs historically are believed to have served areas that had lower median incomes and were less urbanized, our use of census data from 1990 yields conservative results, as income and urban populations generally increase over time.

We conducted our review from May through November 1998 in accordance with generally accepted government auditing standards.

We provided a draft of this report to DOE’s Power Marketing Liaison Office, which represents the views of Southeastern, Southwestern, and Western. Its comments and our responses are included in appendix V. We also met with representatives of the American Public Power Association, the Edison Electric Institute, and the National Rural Electric Cooperative Association—national organizations representing groups concerned with the pricing of power provided by the PMAs, among other things—to discuss our methodology and the results of our review.

State-Specific Data on Potential Rate Impacts and Service Area Demographics

This appendix provides, for each state that receives PMA power from Southeastern, Southwestern, and/or Western, (1) the counties and towns that the preference customers included in our analysis report serving and a map showing these areas and (2) the estimated rate changes if market rates are charged, by number and percentage of preference customers; household incomes in areas potentially receiving power; the extent to which these areas are urban or rural; and the extent to which the individual state’s total power consumption is provided by the PMA(s) through the preference customers included in our analysis.

To define the preference customers’ service areas, we identified the counties and/or towns in Electrical World: Directory of Electric Power Producers (1997 ed.) that each of the customers considered in our analysis reported serving. As was true with our rate analysis, we included only the preference customers that purchased power directly from the PMAs—that is, those customers that the PMAs listed in their 1995 annual reports. If we had included utilities that indirectly buy PMA power (through direct preference customers), such as generation and transmission cooperatives and municipal joint action agencies, more counties and towns would be shown on our state service territory maps. According to DOE officials, many additional counties would be shaded in, among other states, Montana, South Carolina, and Wyoming.

Figure IV.1: Potential Service Areas - Alabama Counties (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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According to DOE, no preference power is sold to customers in eastern Minnesota, although some customers have their headquarters offices in that part of the state.

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Counties (none)

Towns (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Counties (potential service areas)

Towns (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Counties (potential service areas)

Towns (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Counties (potential service areas)

Towns (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Counties (potential service areas)

Towns (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

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Figure IV.27: Potential Service Areas - Virginia Counties (potential service areas)

Towns (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Counties (none)

Towns (none)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Counties (potential service areas)

Towns (potential service areas)

Urban/rural classification of preference customers’ reported service areas PMA-provided (in kWh)

State total (in kWh)

Comments of the Department of Energy’s Power Marketing Liaison Office

The following are GAO’s comments on the Power Marketing Liaison Office’s letter dated October 30, 1998.

GAO’s Comments

1. DOE comments that our data sources are flawed because we relied on incomplete and/or inaccurate data and that it is impossible to have confidence in conclusions drawn from the data’s analysis. To address each of our objectives, our analyses used data reported by the PMAs and their preference customers—data that we believe to be the best available. DOE recognizes that obtaining complete data on the electric utility industry is not easy. We believe that we used the data appropriately to satisfy the objectives of our review and that our methodology is sound. However, we agree the data we used have some limitations and we have noted the limitations in our report. Many of the concerns that DOE expresses do not deal with the data we used but with the definition of a preference customer of a PMA. For our analysis, we included only the preference customers who purchased power directly from the PMAs—as listed in the PMAs’ 1995 annual reports. We did not include utilities that indirectly purchase PMA power because the 1995 annual reports of two of the three PMAs do not include them in their customer lists. Southwestern’s 1995 annual report states that two of its customers also serve a number of municipal utilities and includes these municipal utilities in the total number of customers. The annual reports of Southeastern and Western, however, list only the customers that buy power directly from those PMAs and do not include the municipal utilities that purchase power from generation and transmission cooperatives or municipal joint action agencies. Because Southeastern and Western together represent over 90 percent of the total preference customers of the three PMAs included in our analysis, we used their approach. However, to address DOE’s concerns, we added statements to the report in several places explaining that our analysis did not include utilities that indirectly purchase PMA power.

For our analysis of urban/rural populations, we used the counties and towns that the preference customers included in our rate analysis reported to Electrical World: Directory of Electric Power Producers. In connection with identifying the areas that preference customers report serving, we acknowledge that the data in Electrical World may not match the actual service territories because utilities report to Electrical World the counties and/or towns they serve without specifying the exact service boundaries within these counties and towns. However, we used these data because they (1) were reported by the preference customers and (2) were the best available. We believe this approach adequately addresses our objective of identifying the areas that the three PMAs’ preference customers report serving and does not affect our primary objective, to estimate potential rate impacts by state. 2. DOE states that we omitted from our analysis generation and transmission cooperatives and municipal joint action agencies that purchase power from the PMAs. We did not exclude them. We estimated a potential rate change for every generation and transmission cooperative and municipal joint action agency that purchased wholesale power from Southeastern, Southwestern, and Western in 1995. We also attempted to include them in our maps and urban/rural analysis. However, in many cases, the generation and transmission cooperatives and municipal joint action agencies sell only wholesale power to other utilities and do not provide retail service and, thus, do not report serving any counties or towns. As a result, we were unable to reflect such service territories on our maps. Similarly, since our urban/rural analysis relied on the Census Bureau’s data of populations in the counties and towns that the preference customers report serving, we did not include in our analysis the service territories of the utilities that purchase power from the generation and transmission cooperatives and municipal joint action agencies.

As we noted in comment 1, we did not include the generation and transmission cooperatives or municipal joint action agencies in our analysis because the PMAs’ annual reports, with very few exceptions, do not include them either. However, it is important to note that if our rate analysis had included the municipal utilities that buy from preference customer generation and transmission cooperatives and municipal joint action agencies, we believe that the rate increases for many of these utilities would have been very small: If a municipal utility purchased all its power from a direct preference customer of the PMA, the municipal utility’s rate increase would equal the increase we estimated for the direct preference customer. If the utility purchased a portion of its power from sources other than the preference customer, its rate increase would be lower. For example, according to Southwestern’s fiscal year 1995 annual report, Kansas Municipal Energy Agency (Kansas MEA) purchased power from Southwestern and transmitted it to 24 municipal utilities. We estimate that if the Kansas MEA paid market rates for the power it purchased from the PMA, its average rate would rise by 0.22 cent per kWh, a relatively small increase. If a municipal utility purchased all its power from the Kansas MEA, its rate would also rise by 0.22 cents per kWh. If a municipal utility purchased half of its power from the Kansas MEA, its rate increase would be 0.11 cents per kWh. Municipal utilities’ increases would often be small because the direct preference customers who sell them power often purchase a small percentage of their total power from the PMA. 3. DOE states that our maps do not show the service areas of the customers of the generation and transmission cooperatives and municipal joint action agencies. We agree. However, to be consistent with our rate analysis, we included only the counties and towns that the preference customers (those that purchase power directly from the PMAs) report. If we had included the service territories of the utilities that purchase power from preference customers as DOE suggests, our state maps would have had more shadings for counties and/or dots for towns. However, it is important to note that, in many cases, the additional counties and towns in our maps would receive relatively small portions of their power from the PMA. For example, Southwestern’s 1995 annual report states that the PMA sells power to the Louisiana Energy and Power Authority, which, in turn, serves nine municipal utilities. We estimate that Louisiana Electric and Power, purchased 8.15 percent of its power from the PMA in 1995. This means that the nine municipal utilities received, at most, 8.15 percent of their power from Southwestern. If the municipal utilities purchased portions of their power from other sources, the counties and towns they serve would consume a smaller portion of PMA power. Our analysis shows that many of the preference customers that sell power to other utilities purchase less than 10 percent of their power from the PMA. Moreover, regardless of how many utilities buy PMA power indirectly through preference customers, the portion of a state’s electricity consumption that comes from the PMA remains the same—for example, 0.7 percent in Louisiana. 4. In its comments, DOE states that our analysis shows that Southwestern is serving 14 towns and one county in the State of Missouri, with 93 percent of PMA power going to urban areas of the state. We believe that DOE misinterpreted our analysis. Our analysis does not show that 93 percent of Southwestern’s power in Missouri goes to urban areas. Our analysis does show that of the 14 towns that preference customers who buy directly from the PMA report serving, 13, or 93 percent, have populations that are at least 80 percent urban, as defined by the Census Bureau. DOE states that Associated Electric Cooperative has a “PMA power allocation serves rural areas throughout the State of Missouri.” However, this power is distributed to these areas by the utilities that purchase power from Associated Electric, not Associated Electric itself. Associated Electric did not report serving any counties or towns to Electrical World, the source of our data. Moreover, Southwestern, in its 1995 annual report, does not include the utilities that purchase power from the Associated Electric Cooperative in its total count of customers. Therefore, neither did we. 5. DOE states that using 1995 data compromises our rate analysis because (1) PMAs’ rates have recently declined and (2) prices for power purchased during periods of peak use have recently increased. These two factors would increase potential rate increases, but only if market rates remain the same. However, according to officials of the Edison Electric Institute, market rates for wholesale power have also declined since 1995. As the market continues to evolve, many industry experts believe these rates will fall farther. If market rates fall more than the PMAs’ rates, our estimates of rate increases will prove to be overstated. We have seen no evidence that the PMAs’ rates have fallen more than rates in the wholesale market. 6. DOE maintains that power from the Pick-Sloan project will be reallocated to 25 Native American tribes and 11 other new customers in the Upper Midwest in 2001 and that, as a result, our analysis will be “even further outdated.” However, we were asked to examine the three PMAs’ sales, based on the most recent data—1995, not their sales in the future. In addition, although Western may be reallocating its power, this does not necessarily mean that the new allocation would appreciably change the profile of the service areas (in terms of the extent to which they are urban or rural and in terms of their household income). This profile would change only if the areas losing Western’s power are more urban or rural or different in income than the areas that would gain access to Western’s power. Moreover, although Pick-Sloan sold more power than other of Western’s projects, it nonetheless represented about only about one-third of Western’s total sales in 1995. Consequently, the reallocation would have to be very large to significantly change the overall profile of Western’s preference customers’ service territories. 7. DOE states that average rates are not a good proxy for specific power services from PMAs. We acknowledge that average revenue per kWh (total revenues/total electricity sales) is an imperfect indicator of electricity rates because it combines the costs of several types of services, such as capacity, peak service, and off-peak service. However, as we have stated in several past reports, we believe it is a strong, broad indicator of the relative power production costs of the PMAs compared to those of investor-owned utilities and publicly owned generators. We agree that preference customers would likely pay higher than the average rate per kWh in replacing the portion of PMA power that is used during periods of peak demand. 8. DOE states that in many parts of the Upper Midwest and Southeast, it is typical for towns in a county to be served by an investor-owned utility while the remaining parts of the county are served by a rural electric cooperative. Thus, DOE believes that our analysis is flawed if the data do not account for this difference. We agree this may be an issue. However, as stated previously, we relied on the set of counties and towns that the preference customers reported serving to Electrical World. The preference customers did not specify which portions of a county they served when they reported serving a county. Also, in Midwestern states, such as Iowa, Missouri, and Nebraska, preference customers primarily reported their service areas as towns rather than counties. Thus, the problem concerning counties that DOE identified would not arise there. In addition, even if, within a particular county, an investor-owned utility serves a town, it may not follow that the area outside the town has lower household incomes. 9. DOE states that we omitted state/federal agencies. We excluded state and federal agencies because, with a few exceptions, they are not utilities and thus are not in EIA’s Form 861 or “sales for resale” databases. As a result, we could not perform calculations on potential rate impacts with the approach we used for preference customers who are utilities. We excluded state and federal agencies from other analyses because (1) they do not provide retail service to residential end-users and (2) we wanted to keep the group of customers consistent across the analyses. In addition, DOE provides no economic analysis that the PMAs’ sales to these agencies provide a “large benefit to the state they are located in.” In most cases, even if the sales to these agencies were included in the analysis, the PMAs’ portion of a state’s total electricity consumption would be relatively small. We agree that some indirect economic impact may be attributable to the lower price of the power—relative to other retail prices—consumed by the preference customers not included in our analysis, but its measurement is uncertain. 10. DOE states that TVA is omitted. We agree that if we had been able to include the 160 distributors that received TVA power in 1995 in our analysis, the percentages of PMA power provided to the seven states served by TVA would have increased. However, because of data limitations, such as EIA’s designating TVA as an Alabama utility in its Form 861 database and TVA’s not reporting a service territory in Electrical World, we could not apply the methodology used in our analysis and were unable to develop and implement a methodology to appropriately incorporate TVA. However, our draft explained that Southeastern sells power to TVA, provided information on the amount of power that Southeastern sold to TVA in 1995 and 1996, and provided a map of TVA’s service territory. In addition, we have added a more detailed explanation of our methodology concerning TVA in appendix III. 11. DOE believes that Wisconsin should not be included in our analysis because Wisconsin Public Power received only “nonfirm” (interruptible during peak periods) power from Western. However, Western listed Wisconsin Public Power as one of its customers for 1995, and we believe that it was appropriate to include this customer in our rate analysis because we did not differentiate between firm (always available) and nonfirm power sales. Also, because Wisconsin Public Power sells only wholesale power and did not report serving any counties or towns in Electrical World, we could not include it in our other analyses. 12. DOE states that our report does not maintain a neutral description of the findings because the report goes beyond data reporting and does not present all opposing points of view. It cites as an example our observation that in cases where potential rate increase may be relatively large, PMAs currently sell power at relatively low rates and rate caps could be used to mitigate these increases. We believe that our report is balanced and that, throughout our report, we present a neutral description of our objectives and findings. We mention that PMAs’ rates are relatively low to provide context for the relatively large rate increases. It is easier to understand the significance of a rate increase that exceeds 1.5 cents per kWh if the reader understands the base rate upon which the increase is calculated. On the issue of rate caps, we did not intend for our discussion to be a recommendation. We included it because, as in previous reports, this issue has been an important consideration in other deregulatory initiatives. 13. DOE states that our classifications of rates are subjective. We agree. However, we devised the parameters of these classifications on the basis of our examination of all the rate changes in our analysis. Moreover, we explicitly describe the values attached to each of these classifications in our report. We used these categories to simplify the discussion, not as a definitive statement. 14. With regard to selling power to high-income areas, DOE misinterprets our analysis. In the examples cited, we refer to the percentage of households with higher incomes, not the median income. More generally, a county may have a median that is relatively close to the statewide median, yet still have a large portion of households with higher incomes. We agree with DOE’s comment regarding Native Americans’ receiving PMA power and have added an example for balance. 15. With regard to our not reporting rate increases as percentages, we made a subjective judgment not to do so. As we stated in appendix III, we believe that reporting rate changes in cents per kWh more accurately portrays the true value of the changes. In addition, the base rates preference customers paid in 1995 differ greatly from customer to customer. As a result, if we expressed the rate changes as percentages, the same increase measured in cents per kWh would be reported as different increases for two customers with different base rates. 16. In response to DOE’s assertion that our methodology is not conservative, we disagree. We believe our methodology is conservative because we assume no changes in wholesale market prices. If wholesale prices decline in the future, as many industry experts predict, our estimates of rate increases will prove to be overstated. Because we could not incorporate forecasts of wholesale prices, we believe our approach is conservative. 17. DOE states that our urban/rural terminology may be misleading. As suggested, we have included the Census Bureau’s definition of urban in the body of our report and appendix III.

Major Contributors to This Report

Resources, Community, and Economic Development Division

Office of the General Counsel

Related GAO Products

Federal Power: Options for Selected Power Marketing Administrations’ Role in a Changing Electricity Industry (GAO/RCED-98-43, Mar. 6, 1998).

Federal Electricity Activities: The Federal Government’s Net Cost and Potential for Future Losses (GAO/AIMD-97-110 and 110A, Sept. 19, 1997).

Federal Power: Issues Related to the Divestiture of Federal Hydropower Resources (GAO/RCED-97-48, Mar. 31, 1997).

Power Marketing Administrations: Cost Recovery, Financing, and Comparison to Nonfederal Utilities (GAO/AIMD-96-145, Sept. 19, 1996).

Federal Electric Power: Operating and Financial Status of DOE’s Power Marketing Administrations (GAO/RCED/AIMD-96-9FS, Oct. 13, 1995).

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