By John S. Ferguson

Alternative electric generation sources are all the rage as a consequence of mandates for minimum portions being from renewable sources and for limits on greenhouse gas emissions, as is demonstrated by articles in the June 2009 Public Utilities Fortnightly. “IOUs under Pressure,” shows ranges of levelized costs per kilowatt hour for eight renewable resources taken from the September 2008 Renewable Energy Data Book of the U.S. Department of Energy, and that wind, geothermal, biomass, concentrating solar, and photovoltaics have experienced significant cost decreases since 1980, and wind and geothermal aren’t expected to experience significant future decreases.

Mandating the use of alternative sources assures that they become part of the generation mix, as has already happened with wind and has always been with hydro. What happens in the future with the alternative sources other than hydro will depend in part on the impact of mandates concerning emissions of greenhouse gases (GHG) on fossil-fuel generation sources. “The Costs of Going Green” asserts that CO₂ emissions costing more than $30 per ton and natural gas prices of $7 to $8 per million Btu would shove coal down in the dispatch order and that any needed environmental control equipment would compound this situation, which likely would cause existing coal units to change their mode of operation or to be retired earlier than previously expected. Renewable resources may have a similar impact on combined-cycle generating units.

My interest in these mandates is their impact on depreciation accounting for power plants and transmission systems.

Base-Load Plant Depreciation

Past experience has long been recognized as being unlikely to provide a reasonable basis for determining depreciation rates suitable for existing power plants, and the common response has been to rely on predictions of generating-unit retirement dates. Mandates for alternative sources of generation and for GHG emission limitations will make it more difficult to predict the future generating unit usage needed to adequately depreciate power plants, and also have the potential for causing past experience to not provide a reasonable basis for depreciating transmission systems.

Coal-fired generating units historically have been installed for base load service and have shifted late in life to peak load or standby service. However, more recently such units have been refurbished instead of their mode of operation changing. The requirement of U.S. GAAP that depreciation (in this case the depreciation rate) match asset usage causes either course of action to impact power plant depreciation. Initially serving a base load function and later shifting to a peak load or standby function results in a distinctive lifecycle that dictates a pattern of depreciation rates that is higher during the early years of operation than during the later years. If refurbished for continued base load service, depreciation rates should remain about the same over the entire lifetime, even though midlife refurbishment requires substantial capital expenditures.

It hasn’t been difficult to predict generating unit lifespans and any related capital expenditures needed for calculating depreciation rates that are consistent with usage. However, mandates for renewable generation sources and greenhouse gas emission limits will complicate such efforts in the future, especially for coal units. It always has been difficult to obtain regulatory approval of power plant depreciation rates that are consistent with usage, and this difficulty had little to do with how easy or difficult it is to predict lifespans and future capital expenditures. Recognition that the future influence of the mandates precludes the lifespans experienced by coal units in the past from being useful for depreciation purposes might be obvious enough to dissuade those in the habit of proposing past lifespans in regulatory proceedings from doing so in the future or to dissuade the regulators in those proceedings from giving credence to such proposals.

Transmission Depreciation

There are two aspects to the potential for the mandates to influence the life of transmission systems. One is a consequence of transmission lines being dedicated to generation sites, and is unlikely to have much influence. The need for dedicated lines from remote wind farms is well known. However, wind farms are comprised of multiple units that are easily replaced after wearing out or becoming obsolete. Therefore, dedicated wind farm lines can be expected to be useful well beyond the lives experienced by the initial generating units, and the same situation is likely for tidal and wave resources. This situation is similar to what happened with transmission lines dedicated to remote hydro stations, where reservoir urbanization resulted in local load centers developing that continued to be served by the lines after local generation ceased.

The other aspect is a consequence of generation sites moving closer to load centers, and likely will influence transmission system life. This movement, currently in progress, is referred to as “distributed generation,” and began for reliability reasons. The speed of the movement will increase as a result of the mandates causing economic considerations to exhibit a less constraining influence in the future. My March 21, 1985 Fortnightly article, “Is Central Station Generation Becoming a White Elephant?” notes that improved technology brought central station generation into existence and likely will cause its ultimate demise. I credit Samuel Insull for developing central station generation as a result of his construction in the early 1900s of high-voltage transmission lines to connect suburban communities with power plants located at load centers in Chicago. This allowed large generating stations to be located remotely, thereby taking advantage of cost savings from economies of scale, load diversity, lower losses from higher delivery voltages, and the substitution of transportation of power for transportation of fuel. Mr. Insull’s “high” voltage was what is currently a common primary distribution line voltage.

In 1985 I expected PV modules or fuel cells to be the technology that would move the generation source back toward the load, but developments since then suggest that fuel cells are more likely to be utilized to mitigate GHG emissions from transportation sources than from electric generation sources. I asserted that regulation is an impediment to introduction of new technology, because entities operating in regulated markets can exercise some control over the timing of introducing new technology. The mandates demonstrate that regulation also can impose conditions for speeding up the introduction of new technology.

I also asserted that it was then time to begin considering the implications of new technology for the depreciation of power plants and transmission systems. The mandates since then and currently being considered have increased and will continue to increase the speed of developing and implementing new technology. Therefore, now is the time for those who have not already begun considering the implications of new technology on the depreciation of power plants and transmission systems to start doing so. It’s conceivable that technology eventually will make PV roofs and attic storage devices feasible, which might move the generation so close to the customer that distribution systems also would be affected. A significant unknown is the extent to which nuclear sources will be allowed to be part of the generation mix, because nuclear is unlikely to be anything other than a central generation resource.

These comments address depreciation accounting implications of the mandates, but there are also implications for feasibility studies of new facilities. What is even more interesting is the potential for the mandates to influence the future physical, organizational, and cost structures of providers of electric service.-JSF