One of these days you may see a former chairman of the American Gas Association become the new chair of the Edison Electric Institute. Or maybe the other way around.
I broached this subject...
be met with the existing wire system.
The proposed wire system upgrade included replacing the 23-KV subtransmission system with an extension to the 69-kV transmission system and upgrading one of the island substations to match this greater voltage, at a total estimated cost of $10 million, or about $90/kVA. Considering the annual load profile and the customer classes (, few, if any, pay demand charges), the return on this transmission and distribution investment was limited. Therefore, two DER solutions to these challenges were explored in the case study-utility-leased and customer-owned DER.
Based on the expected load growth, the utility-leased DER option offered financial benefits and enhanced reliability and was more flexible than the alternative wire solution. A cash-flow analysis showed that the subtransmission wire solution could be deferred for six to seven years, saving approximately $1 million. The local installation of DER would also increase the reliability of service to this island location, and additional units could be quickly installed to meet unexpected growth or additional contingency requirements. Alternatively, if the growth was less than expected, the low-cost leased units could extend the deferral time before the wires needed to be replaced. If the existing wire system failed prematurely, necessitating early replacement, the leased units could be used elsewhere in the system, or the lease could be terminated.
The customer-owned DER option on this island could offer financial advantages to a resident with a thermal load sufficient to justify a cooling, heating, and power (CHP) system. 7 However, for these circumstances, this option offered few if any benefits to the utility. The location of the DER was critical if it were to offer useful relief to the island's distribution system; it is unlikely that there would be a sufficient number of suitable CHP applications in the relevant locations. In addition, although a customer-owned DER system would decrease the island's peak load, it would be attractive only to year-round residents. It would therefore decrease the already small load during the non-summer periods, making the utility's low load factor during that part of the year even worse, along with lowering its revenues.
Looking at Cogeneration
In a second case study, we examined a cogeneration plant, built primarily in response to PURPA regulations. The plant provided steam to a food processing facility in Idaho and was connected to the local utility, Idaho Power, at the transmission level. For PURPA installations, societal environmental and energy conservation benefits typically are balanced against slightly higher costs for ratepayers. Since this plant was located in a region with a traditionally sufficient supply of lower-cost power, the 10-MW gas-fired unit has not offered any advantages to Idaho Power, which is contractually obligated to purchase power from the cogeneration unit for approximately $50/MWh. Nor was the Idaho Power system in need of voltage support or reliability services at this location. However, for the unusual utility economics (marginal prices reached $250/MWh and higher) that occurred during the time period under study, this plant also contributed profits to the local utility.
The third case study examined a CHP application at the Brookfield Zoo