It is more complicated to determine the deferred investment in T&D capacity than it is to determine that in generation capacity. The complexities come from the following issues.
One can examine the benefit of cogeneration and small power production on a single T&D feeder or for a geographically defined T&D network. The approach used to determine the benefit of deferred investment
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in a single T&D feeder is different from the approach used to determine the benefit for a defined T&D network.
While the capacity (in megawatts) of each and all generation facilities connected to an alternating current power system is usually known with reasonable certainty, the capacity of a single feeder or a bundle of transmission facilities in an interconnected alternating current power system is not known with certainty, as discussed in Section 2.
Transmission and distribution loading relief that can be provided by DG helps defer utility T&D investments either for reliability or for commercial energy transfers. Transmission and distribution loading relief may come from all three major services provided by DG resources, i.e., reduction in peak power requirements, provision of ancillary services including reactive power, and emergency supply of power.
Unlike deferred real power generation investments, estimating deferred T&D investment does not readily lend itself to linear programming production cost model-based analytic techniques. This example
methodology includes estimating deferred T&D capacity for a defined T&D system.
Example Approach for a Defined Transmission and Distribution System
The approach described below may be used to determine the T&D investment deferral benefit of cogeneration and small power production facilities on the entire utility T&D system as a whole rather than a specific feeder. This approach was used by ICF Consulting to estimate the avoided cost of T&D capacity for the Avoided-Energy-Supply-Component (AESC) Study Group of the New England region (ICF Consulting 2005).
This approach comprises four major steps:
1. Develop data that provide the benefits in $/kW per year of deferred transmission capacity from the analysis.
2. Develop data that catalogue investments in transmission and distribution over a historical and/or forecast period of years.
3. Develop data that catalogue peak demand growth over the same historical period of years.
4. Develop data that calculate the annual carrying charge of those investments based on assumptions on taxes, financing costs, operational expenses, and other recurring costs.
Data on Deferred Investment
The deferred investment in $/kW per year (similar to the deferred generation investment) are here defined as the incremental investment that occurs over a period of time that can be attributed to load growth divided by the actual load growth in that period. This approach is a reasonable approximation for the incremental costs of investment associated with T&D.
The time period for which data are available and the quality of those data are very important to this calculation. A period of about 25 years is recommended (preferably 15 historical years and 10 forecast years) given the lumpiness in the T&D investment cycle. Depending on the accuracy of the data, appropriate weighting factors may be applied to the historical and the forecast data.
Data on Historical or Projected Transmission Investment
The time period requires a duration over which a reasonable amount of investment occurred or is projected to occur. The recommended period of time is 25 years in length, (i.e., 15 historical years and 10 forecast years). The data on investment costs specified each year in nominal dollars are summed to determine the incremental investment which has occurred over the base year to the final year in the series. The share (in a percentage) of the total investment which is believed to be related to load growth is
specified. The default for this is set to 50% of the T&D investment. This share is particularly important because even without the benefit of installed cogeneration and small power production or other demand side management activity, some reliability upgrades may become necessary. The data are entered in nominal dollars but are converted to real dollars using the Handy-Whitman index for utility T&D costs trends for a long-term historical period. T&D investment costs have increased at a rate above general inflation which is reflected in the Handy-Whitman derived escalation factor. Note, the historical relationship of transmission costs to general inflation is assumed to continue at the historical rate going forward.
Data on Carrying Charge Rate
The annual carrying charge for T&D includes insurance, taxes, depreciation, interest, and operations and maintenance (O&M). These line items should reflect the costs associated with new investment which can be deferred or avoided. In several cases, such as insurance and property tax expense, the full value associated with that item would be avoidable and it is appropriate to apply the share of the costs
associated with that line item calculated as a percent of the total existing costs as the avoidable amount. However, in the case of O&M cost, new investment projects benefit substantially through economies of scale gained from existing investment. Given these economies, the O&M for new investments would be a much smaller share of the total project costs than the existing O&M expenses are of the current existing plant.
The standard data for the carrying charge calculation largely rely on Federal Energy Regulatory
Commission (FERC) Form 1. As with all other inputs in this analysis, the carrying charge is required to be in real dollars. Values entered in nominal dollars should be converted to real dollars using an inflation rate input. A schedule for distribution capacity having identical formulation and format may be used for distribution investments.
Data on Peak Load Growth
The peak demand growth over a specific historical and/or future time period consistent with the investment data is used to determine the incremental load growth for which T&D investments are planned. Special consideration to the following factors:
1. Since peak demand can vary widely from year to year, as seasonal temperatures affect
consumption during peak periods, it is important to consider the effect weather may have had on historical information used in this analysis.
2. If peak is measured at the generation point, transmission and distribution losses will need to be added to the values to capture the $/kW per year incremental costs savings at the load level. 3. When using historical and forecast demand data, users should verify that the point of
4. The peak load for the forecast period should reflect the driver of the forecast investment data. For example, if planning is done to an extreme peak load condition rather than a normal peak load condition, the forecast demand data should be entered for the extreme case that is consistent with the investment dollars.