August 2003 · Volume 85 · Number 7

The Siren Call for New Public Power Warrants a Closer Look

Michael McGrath 
Calling the experiences that the nation’s energy markets have faced in the past few years “challenges” would certainly be an understatement: think of California’s experiment with competition, Enron’s trading scandals, and regional supply volatility. In some cities and counties, these issues have focused public attention on a service that had always been taken for granted—electricity. One reaction to this heightened scrutiny has been a call for local government to consider taking on the role of power provider.  
On an emotional level, this idea may hold some appeal. People tend to turn to their local governments to fix things that seem to have gone wrong. But this author encourages managers who hear this call to pause and take a closer look. As the latest municipalization programs have made clear, the process of buying the distribution assets of a local electric company brings with it high and sometimes unexpected costs, risks, and no guarantee of low-priced power for residents. 
Recent Efforts to Municipalize 
“Municipalization” essentially means buying all of an electric company’s assets—its poles, wires, substations, transformers, meters, and more—that are within the local government’s jurisdiction. The government then assumes the responsibility for operating and managing the electricity system and servicing its new customers.
In the past year, the rising concern over uncertainty in the energy markets has caused measures aimed at creating municipal electric utilities to pop up from Florida to the Pacific Northwest. So far, the results have been mixed (see boxed copy on page 14).
If you go back a bit further in time, say, over the past decade, you’ll see that little municipalization activity has taken place nationwide. During this period, the American Public Power Association has counted eight communities that have formed new utilities in areas once served by shareholder-owned electric utilities, plus six communities that have sold their utilities back to private companies.
Cost Considerations Are Key 
Cost is indeed the most important issue for local governments interested in buying the local power assets of a shareholder-owned electric system. But cost is only part of the picture. The buyout process in its entirety should not be overlooked. From the pre-feasibility study through to a final court decision, years may pass before any utility property changes hands.
The buyout by the Sacramento Municipal Utility District from Pacific Gas and Electric Company, for example, took eight years. Similarly, the town of Las Cruces, New Mexico, and El Paso Electric argued for more than 12 years before reaching a settlement. The city, though, ultimately opted not to municipalize.
Looking ahead, the Energy Information Administration forecasts that in 20 years the nation will be using more than 45 percent more electricity than it does today. 
Here are 10 cost-related elements that local governments will need to look at the municipalization process:
1.	Preliminary acquisition costs. Before action can be taken to form a new public utility, a local government will incur out-of-pocket costs. Note that these will not be reimbursed if the new utility does not become operational. For instance, a preliminary feasibility study, typically costing more than $100,000, and a detailed feasibility study—required in order to determine the precise details of the utility property and equipment to be purchased—will need to be completed. A detailed feasibility study can cost $1 million or more. 
  
Additional costs will include fees for attorneys, consultants, engineers, and accountants who may have to be hired to supplement existing government staff. 
2.	System value. The cost of the buyout will be based in large part on the value of the system. What are the electric company’s substations, wires, poles, trucks, equipment, and anything else employed in operating the system worth? Utility property is not bought and sold frequently, so a benchmark market-pricing structure does not exist. Therefore, the existing electric company and the local government pursuing the buyout must agree upon the methodologies to be used to determine the costs. 

A key factor in deciding or learning the value of these assets will be the accounting method chosen: historical cost or replacement-cost value. The choice of system valuation methodologies alone can tell you whether a proposed acquisition will be successful and whether or by how much customer rates will rise or fall. 

R.W. Beck, a consulting firm with a long history of conducting feasibility studies for public agencies, performed a study in 2002 for the East Bay Municipal Utility District, a water and sewer agency in northern California exploring the buyout of electric service there. Beck’s cost estimates ranged from a low of $464 million, using the historical-cost method, to a high of $1.3 billion, using replacement costs. 
3.	Start-up costs. In addition to the purchase price of the system, the new local public utility will incur up-front expenses for everything associated with starting a new business. It will have to lease or build offices and buy any necessary equipment not included in the sale from the shareholder-owned electric company. It will have to absorb additional costs to hire and train personnel to run the utility. The new public utility also will have to set up a billing system of its own, distinct from the billing system of the shareholder-owned electric company. 
4.	Severance. Beyond the hard costs identified as part of the local electric system’s value, the acquiring government will face the cost of “severance,” which is the real cost of separating the service area to be taken over from the balance of the shareholder-owned electric company’s system. Electric distribution systems are not built to conform to the geographic boundaries of governmental jurisdictions. Carving out a district may be an expensive proposition. Electric systems will need to be reconfigured, and new transmission lines and substations may need to be built. 
5.	Stranded costs. Power plants owned by the shareholder-owned electric company and not included in the buyout must continue to provide electricity for the remainder of the electric company’s service area. These facilities were built by the company to serve its existing customer base. Costs were prudently incurred and approved by regulators for inclusion in the rates. 

Similarly, the shareholder-owned electric company entered into long-term contracts to purchase power on behalf of its customers, including those in the service territory subject to buyout. These costs can become “stranded” when all or a portion of the service territory is taken over. These costs, too, must be valued and included in the calculation of the total cost of the buyout. 

In Lakewood, New York, for example, the public service commission stipulated that the city would have to pay the stranded costs of the incumbent utility’s electrical system. The total cost turned out to be much higher than Lakewood had originally assumed and more than the community was willing to pay. (This stipulation by New York State may signal the end of municipalization efforts there.) 
6.	Interest on debt. The new municipal utility will have to borrow money to meet all of these costs. Revenue from its new utility customers will not come in until some time after the costs have been incurred. As the federal government limits the amount of tax-exempt bonds that a state may issue, a newly formed municipal utility may have to sell bonds that are not tax-exempt and therefore may have to pay significantly higher interest rates. 
7.	Non-bypassable charges. These charges are costs included in utility bills that would have to continue even if the shareholder-owned electric company was no longer involved. State legislative and regulatory decisions may require a local government utility to continue to charge customers for certain items like assessments mandated by the state, including environmental surcharges, the expenses of public benefit programs, and nuclear-plant decommissioning costs. 
8.	Lost tax revenues. Among the taxes paid by shareholder-owned electric companies are income taxes to federal, state, and local authorities, where applicable; property taxes to local authorities, including school districts; and franchise fees to local authorities. The amount of the income from these sources needs to be determined and factored in as lost revenue to various local taxing authorities. 
9.	Power costs. The new municipal utility will need to purchase power at market prices or acquire generation capacity. Because surplus federal power or discounts to government power agencies are no longer available for new municipal customers, the new public utility will have to buy power in the deregulated marketplace, where prices fluctuate. 
10.	Risk. Under a municipal utility system, the risk of buying power is transferred from the electric company to the local government. Any increase in power costs is reflected in customers’ utility bills. Attempts to avoid this volatility by deferring the costs can affect the credit-worthiness of the locality and possibly endanger the delivery of other services. 
The process of buying the distribution assets of a local electric company brings with it high and sometimes unexpected costs, risks, and no guarantee of low-priced power for residents.
Complicating Factors
Next to handling the costs and processes involved in forming a new municipal utility, the most important task will be getting the electricity to sell to community residents. The first municipal electric utility was founded in 1882, although most were formed during the 1920s and 1930s. A crucial factor in the early development of these public power systems was the availability of low-cost federal “preference power,” or electricity generated primarily by hydroelectric dams built by the federal government in the first half of the 20th century.
For instance, Hoover Dam and Grand Coulee Dam, which were built by the federal government, generated far more electricity than was needed by the small communities located near them. So the federal government sold the surplus electricity at low prices to other entities, mostly government-owned electrical systems in the West.
Today, this low-cost federal electricity is committed under long-term contracts for decades into the future. A newly formed municipal power agency would likely buy its power in a deregulated market. (The U.S. Energy Policy Act of 1992 set the stage for competition in the wholesale electricity markets.) The price for power in the open market tends to be volatile, making it difficult to predict future energy prices. The alternative to buying power in the open market—building new power plants—brings with it its own set of costs and risks. 
Another factor complicating the municipalization process is that the electric power industry is transforming itself, from a completely regulated enterprise into one in which retail customers of shareholder-owned electric companies in a number of states can choose their generation provider. Typically, local government utilities have been somewhat insulated because they have not been affected by the state laws mandating retail electric competition. However, should municipal electric utilities have to increase their power prices, they will likely feel pressure from their customers, especially large industrial companies, to offer the option of choosing a different provider.
Other elements also complicate present-day municipalization efforts. In the past, for example, communities were much smaller. Distribution systems could expand slowly, as the need for electric power climbed. Capital costs were incurred over time, and municipal electric systems grew gradually, keeping pace with expanding populations.
Today, most communities already are built out, and large distribution systems are in place. Those communities that seek to buy out distribution systems have to purchase entire systems at today’s market prices. Large amounts of capital have to be raised and spent all at once—and other local government priorities for capital investment can be threatened by such a massive outlay.
Reducing Uncertainty in Electricity Markets
Local government buyouts of electric company systems of and by themselves can’t address the core problems that are causing uncertainty in some of the country’s electricity markets. To reduce this uncertainty at the local level, we need to have specific solutions at all government levels. The nation’s power companies are seeking the support of the local governments they serve in obtaining these needed measures.
One problem being addressed now lies in this country’s wholesale electricity markets. To create truly competitive retail markets—and the lower prices and added services they promise—the United States will need more liquidity and transparency in its wholesale markets. Last summer, the agency that regulates the country’s wholesale electricity market, the Federal Energy Regulatory Commission (FERC), presented a plan to standardize the rules governing wholesale power markets regionally. The hope is that a standard set of rules to govern power markets with regional flexibility will generate a robust wholesale electricity market.
Also needed is comprehensive federal electricity legislation enabling the country’s electric system to keep pace with demand. Demand for power has been growing at an average of 2 percent a year in the past two years. Although this rate is a bit lower than it was during the booming 1990s, demand continues to rise. Looking ahead, the Energy Information Administration forecasts that in 20 years the nation will be using more than 45 percent more electricity than it does today.
One area in which this growing demand is already being felt is in the transmission grid. A federal study has found that transmission bottlenecks have cost consumers in parts of the United States more than $1 billion over the past two summers alone. The need for Congress to provide the right incentives to expand the grid is becoming critical. Without action now, these problems will only get worse.
An important aspect of keeping pace with demand is encouraging a diversity of fuel supply options for new power plants. A variety of fuel sources will reduce the economic impact of a shortage in any one fuel source. Power-plant builders should have the option of using coal, nuclear, hydro, other renewables, or natural gas when considering constructing a new plant.
The nation’s shareholder-owned electric companies are longtime partners with local governments on community service and economic development activities. Combined, our efforts can help electricity once again become the service that both of our constituencies can take for granted.
Munization Measures in 2002
Concerted efforts were made to create, strengthen, or challenge municipalization activities in a number of U.S. states during 2002. Several of these involved referendums. Below is a summary of key actions.
California
Last October, the Davis City Council, in a unanimous vote, asked Sacramento’s municipal electric utility to consider expanding its territory by annexing one or more Yolo County cities.
In November, the ballot initiative Proposition D, which would have created a public power entity for the city of San Francisco, failed by a 53-to-47 margin.
In December, the city council of Corona, California, voted to condemn the distribution system of Southern California Edison and take over the system via eminent domain. The city had offered to purchase the system for $70.2 million in November.
Florida
In November, municipalization advocates won election in the towns of Casselberry and Longwood. The mayor of Longwood, who was opposed to the municipalization effort, resigned his post as mayor but stayed on as a city commissioner.
Massachusetts
In December, the cities of Arlington and Lexington appointed committees to research buying out the local electric company’s systems.
Montana
In November, the citizens of Montana voted by a two-to-one margin not to empower the state to purchase 13 hydroelectric facilities from private companies.
Nevada
In November, voters in Clark County (home of Las Vegas) approved a ballot measure by a 57-to-43 percent margin asking the state legislature to grant the county permission to set up a public power authority.
Oregon
In the summer and fall of 2002, the city of Portland, as well as several surrounding counties, studied the alternative possibilities of purchasing Portland General Electric from Enron or of doing a more traditional form of municipalization. The city/county coalition, however, was plagued with battles over the political structure of the new entity. The city and surrounding counties may attempt separate efforts.
In December, a petition drive was started to establish a new public utility district in Multnomah County (of which Portland is the county seat).
South Dakota
In a special October election, the citizens of Wagner voted against municipalization by about a two-to-one margin.
Wyoming
In January 2003, the city of Cheyenne asked the state legislature for permission to ask city residents whether they favored forming a public utility and, if so, whether the city should issue bonds to do so. The bill failed to pass committee.	

Michael McGrath is executive director for retail energy services at the Edison Electric Institute, Washington, D.C. The Edison Electric Institute (http://www.eei.org/) is the association of shareholder-owned U.S. electric companies, international affiliates, and industry associates worldwide.  
In an upcoming issue: An article from the American Public Power Association will describe how local governments benefit from evaluating the option of owning and operating a municipal electric utility.