Rural Distribution Territories: A Drag On Utility Earnings?
The case for selling off the lower-density areas.
The utility industry is restructuring. As companies abandon the old vertically integrated, energy-sufficient model for operation and adopt a differentiated strategy focused on generation, transmission, distribution, or services, they will also move from a stock valuation based upon dividend policy to one based upon return on assets and earnings growth. The regulatory environment is also moving away from the old rate-based mentality to a greater reliance on market forces and, in the future, performance-based distribution rates. If one looks at any other major industry in the United States, it seems clear that there will be fewer major players in the future. Those survivors will be the companies that extract the best financial performance from their assets and get the greatest multiple on their stock price.
For the companies that opt to remain in the distribution business, there will be a fairly radical change in the way they look at distribution as a business. The days of treating distribution districts as cost centers and regarding return on assets as an overall corporate performance measure has to end. Research conducted by our firm, Management Consulting Services, clearly shows that most investor-owned utilities earn an abysmally low return on assets in rural distribution territories. Compounding this problem is the fact that much of this rural territory has very low load growth. In the past, many companies justified moving into sparse rural territory to position themselves for future growth. In many areas of the country, the demographic changes that lead to that historical growth have petered out. We believe that an asset management approach to the distribution business will quickly convince financially driven companies to consider divestiture of this inherently low-return service territory.
The low return on assets in rural territory is driven by several factors which make the cost of serving rural territory substantially higher than the cost of serving dense urban and suburban load. Rural areas require a higher investment in distribution assets and are substantially more expensive to operate. This is compounded by the prevalence of overlapping and duplicative service in rural areas.
In many places outside of the major metropolitan areas, the mix of electric service territories resembles the random drawings of a four year-old. () While the investor-owned utilities and municipal utilities serve most towns and often the thin strips of highway that connect them, rural cooperatives serve everything else. These territorial assignments reflect political decisions made decades ago, not a current analysis of cost of service, return on investment, or growth potential. This vestigial definition of markets creates a huge cost penalty, which is not sustainable in a more competitive utility market. If current management doesn't react to this drag on financial performance, the managers of the companies that acquire them will.
These cost penalties result, in large part, from two inefficiencies. First, because the cooperatives and investor-owned utilities maintain separate substations, and distribution lines, the utilities suffer from a problem of duplication of costly facilities. In the most severe situations, lines belonging to the cooperative run down on one side of the road, while investor-owned utility lines run down the other side. This occurs even as substations belonging to separate organizations are within sight of each other. This poor use of hard assets leads to a second problem: all of these facilities must be maintained. Each utility manages its own team of linemen to maintain its plant. Even if the linemen stay busy all the time and under-employment is not a problem, most workers must spend time crossing through the other firm's territory to get to the next job. This increased ratio of travel time to work time raises employment costs.
Few utilities have systematically looked at the impact of service territory characteristics-density, load mix, growth, geography, climate, etc.-on the profitability of that territory. The difference can be dramatic.
The Solution? Let the Cooperatives and Skilled IOUs Take Over
Who wants this low-growth territory, with low return on assets? Potentially two groups: 1) investor-owned utilities who develop the specialized skills and approach to serving rural territory; and 2) cooperatives to whom the incorporation of interstitial investor-owned utility territory into the cooperative service area adds density, load mix, and size.
Our analysis focused on acquisition of this territory by cooperatives. They are much more ubiquitous than rural investor-owned utilities and the significant overlap in service territory creates the greatest financial incentive to consolidate the territory. Transferring these rural investor-owned utility service territories to cooperatives will be beneficial to both companies.
These transactions will decrease costs and increase returns for both organizations. For the investor-owned utilities, the advantages come from divestment of poor performing assets, and a refocusing on more profitable, densely populated urban areas. A jump in the utilities' return on assets is inevitable. In the utilities modeled by Management Consulting Services, the cost to serve urban customers on a per MWh and per customer basis was, on average, only 55 percent of the cost to serve rural customers-it costs nearly twice as much to serve rural areas. At the same time, net utility plant per customer falls steadily as population density rises. Divestment of rural areas will lead to larger margins on smaller asset bases.
Rural cooperatives are ideally suited to serve customers in these high cost regions. Acquiring these customers will increase a cooperative's customer density and allow it to rationalize the combined asset base (closing unneeded substations and abandoning duplicative stretches of distribution line). Additionally, given the not-for-profit, tax-free status of rural cooperatives, they are much better suited to financially succeed in the asset-intensive rural distribution business. Management Consulting Services built a series of models to recreate investor-owned utility operations in rural areas and compare operating results between service territories. Using only publicly available information,1 we built statistical models to predict how much net utility plant was likely to exist within a given service territory and the cost required to serve customers within that area.
Each model was built using a database of FERC Form-1 and RUS Form-7 reports from over 650 electric cooperatives and utilities. Each model was built with an eye towards avoiding problems caused by the enormous size differences between the companies in the database. Besides a model to predict net plant, individual models were built to predict distribution O&M costs, combined customer accounting, service, and sales costs, and administration and general expenses. Every model has an adjusted R-squared statistic exceeding 94 percent. Important independent variables include the size of the service territory, the number of residential and small commercial customers in a given region, and the intensity of energy consumption by the utilities' large industrial customers. To test how well the model incorporates data from the cooperative and public utility worlds; predicted and actual expenses were plotted on a scatter chart. The residuals appear random and there seem to be little, if any, difference between investor-owned utilities and cooperatives in the model's performance. () The ability of these models to explain costs in both types of organizations was key to our analysis.
Four utilities were then selected for study in our analysis: Florida Power, Commonwealth Edison, Carolina Power & Light, and Entergy Arkansas. The goal was to select utilities with large customer bases and service territory that extends over both metropolitan and rural areas. Additionally, we were interested in studying utilities from different geographic regions and whose service areas overlap with electric cooperatives.
The population of each utility's service area was studied intensely using data available from the 2000 census. Household numbers were compared to customer reports for the investor-owned utilities, cooperatives, and municipal utilities within each area. From this analysis, customers were allocated to each service provider on a county and/or township basis. The utilities' service territories were than broken down into "urban" and "rural" regions, usually along county or township lines. Each utility was divided into a number of regions, depending upon the service territory's geographical complexity. For example, Carolina Power and Light was broken into three primary rural areas and multiple urban centers, while Florida Power was split between one urban area and one rural area.
Four IOUs: Urban and Rural Characteristics
Florida Power's service territory is characterized by a heavily populated southern region and a sparsely populated northern region. The differences between the north and south are magnified since the two largest cities in the north (Gainesville and Tallahassee) are served by municipal utilities. The utility was split nearly in half for our study - the northern section relabeled "Florida Power Rural" and the southern section "Florida Power Urban." "Florida Rural" comprises slightly less than half of Florida Power's service territory but contains only 7 percent of the utility's 1.2 million residential customers.
Commonwealth Edison, unlike the other utilities this study analyzed, does not have a great deal of overlap with electric cooperatives. However, it does have a large section of service territory that fits the "Rural" descriptor, and there are cooperatives in the vicinity. Commonwealth Edison's distribution network is, of course, focused in and around Chicago. The territory west and southwest of the metropolitan area is the focus of our research. This area, "ComEd Rural", encompasses 60 percent of ComEd's territory but only 6 percent of the its 3.1 million residential customers.
Carolina Power and Light
Carolina P&L has the most complicated and diverse service territory of the four utilities. It covers portions of two states and diverse geographical regions.
For the purposes of our research, we defined three different rural areas within the utility's service area: rural counties in South Carolina surrounding Florence, rural counties along the North Carolina/Virginia border, and a combination of territory that surrounds Wilmington, Fayetteville, and Asheville. These three areas contain nearly one-third of CP&L's customers. For the purposes of our simulation, we used separate scenarios for each rural area. In other words, when we tested the impact of divesting CP&L North, we assumed that CP&L would maintain control over the rest of the service territory-including the other rural areas. This was done to work around Administrative and General expense allocation issues.
While not as drastic as the differences in Illinois and Florida, there is a fairly well defined urban and rural electric service territory in Arkansas. Entergy Arkansas's service territory covers nearly two-thirds of the state. The most densely populated regions center around Little Rock in the central part of the state and El Dorado in the South. For this study, we focused our analysis on two large rural areas: "Rural South" includes most of the land south of Little Rock and "Rural East" runs along the Mississippi River. These two rural areas comprise roughly 60 percent of Entergy Arkansas' territory but less than 30 percent of the utility's customers. As we did with Carolina Power & Light, the two rural areas were treated under two different scenarios. When "Rural East" was considered, "Rural South" was considered part of the urban area. Again, this was to avoid the implications of allocating A&G expenses between the rural and urban areas. As the model works now, there is very little change in the estimated A&G expense the core utility will face.
After specific regions had been broken out and the customer numbers ascertained the data were fed into our model. Because commercial and industrial customers were allocated on a per residential customer ratio across service territories, rural financial results will be overstated in many cases, a source of conservatism in the analysis. The model calculates the net plant and operating expenses required to serve a certain area. Additionally, it treats a utility's distribution system as a separate entity from its power production and transmission operations and thus computes an average cost of power charge. This allows us to build not only expense estimates, but also entire pro forma income statements for each geographical area. This, in turn, allows us to compute profitability ratios such as ROA.
Divestiture: A Path to Increased Earnings?
In every simulation we ran there was a notable increase in the utility's ROA after a hypothetical divestment of rural service territory.2 () It is important to note that the greatest differences in performance between rural and urban areas correspond with those areas where the demographic situations are the most varied. In Illinois, where extremely dense Chicago is surrounded by fairly unpopulated farmland and small towns, the non-urban distribution system is operating only at the breakeven point. In the Carolinas, where the differences in population density are muted, the rural system is showing an ROA of nearly 6 percent. However, that is still far below the ROA for the remainder of the utility. With divestment, every utility stands to increase its ROA by 1 percent to 2 percent.
This ROA increase is the result of a number of factors. First, less utility plant is employed per customer in more densely populated regions. Thus, greater revenues are generated per unit of net plant in an urban area versus a rural area. The slight drop experienced in net plant per customer after divestment is enough to slightly boost ROA. The impact is multiplied when distribution operation and maintenance cost per MWh sold also falls after divestment. Distribution O&M costs are closely correlated to the amount of utility plant. When the amount of net plant employed on a per MWh or per customer basis drops, so does the O&M expenses. This drop () leads to increased margins. Additionally, line loss in rural areas is going to cut into margins. As electricity is forced to flow longer distances through distribution lines, less of the generated electricity will reach the end customer. The power costs are absorbed by the utility. Divesting rural territory will lower average power costs and raise margins. Increased margins on a smaller asset base lead to greater profitability.
The results discussed above are, in the opinion of Management Consulting Services, conservative. It is quite likely that utilities will actually realize greater savings than those resulting simply from the divestment of underutilized assets. Additional factors that could have cost implications include overhead expenses, environmental conditions, and management focus.
The models as presented assume very little impact on a utility's administrative and general expenses. These expenses on a per customer and per MWh basis actually rise in our scenarios for the base utility. However, if a utility could take advantage of these streamlining transactions to reduce non-allocated overhead expenses, savings could grow.
Additionally, environmental factors could adversely affect a utilities current cost structure. While environmental conditions did not appear to be significant in the models we used in this analysis, we have found that they are important when comparing cost structures between electric cooperatives. Important considerations include vegetation cover and precipitation. Urban and sub-urban service territories are not likely as rural areas to be affected by the problems posed by vegetation growth and collapse. Additionally, rural areas are likely to have inadequate or non-existent drainage systems. Saturated ground and standing water could complicate efforts to repair storm damage in these rural areas.
Finally, a rural divestment program could help focus a utility's management team on its core business. Not only would divestment reduce crew-dispatching complexity, but also it would allow management the ability to reduce the intensity of relationships with many of the communities currently served. Utilities must now spend time maintaining contacts with the variable constituencies within each of these small towns. It is likely that on a per MWh sold basis, management teams spend much more time addressing the concerns of its rural rather than urban customers.
Investor-owned utilities are likely to benefit from this proposed service territory realignment in a couple of ways. First, as this article has attempted to make clear, operational profitability will receive a boost. Additionally, these transactions will likely provide utilities with a large infusion of cash. Utilities can take advantage of these streamlining moves and the availability of new cash resources to tighten their focus on strategy and move the companies in a healthier, more profitable direction.
- FERC Form 1 reports (1995 - 2000): www.fercform1.com) RUS Form 7 reports (1997-1999): Rural Utility Service Census 2000 data: www.census.gov
- The ROA figures for Carolina P&L and Entergy Arkansas represent averages from the different scenarios tested. For example Entergy Arkansas figures represent the average result between divesting "Rural South" and "Rural East".
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