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Alternatives to the Indian Point Energy Center for Meeting New York Electric Power Needs
APPENDIX G-4 ESTIMATING PHOTOVOLTAICS FOR DEMANDREDUCTION
Current and Projected Costs
Table G-4-1 presents an overview of the current and projected cost of electricity from photovoltaic technology through the year 2016. The two key markets for photovoltaics (PV) are assumed to be distributed residential systems and distributed commercial systems. Thus, the high and low ranges are based on current and projected costs in these two market segments. As shown in the table, the levelized cost of energy from PV is projected to drop from the current 23 to 38¢/kWh to 12 to 20¢/kWh in 2016.
It is important to note that the costs shown in the table are those experienced by the end user—that is, they should be compared with retail rather than wholesale electricity rates. In addition, since the production from PV is nearly coincident with peak demand in New York State,1 a strong argument can be made for valuing PV in a planning context at a rate higher than the average retail rate in New York. For example, Perez et al. (2004a) used average NYISO day ahead hourly wholesale price of electricity data in the metropolitan New York City and Long Island during 2002 to estimate the “solar-weighted wholesale price” (weighted by PV output as a proportion of the total output). Using these data, they concluded that combining PV with a limited amount of load management (to enable PV to claim a capacity value close to 100 percent) would have increased the value (i.e., the systemwide cost savings) of residential PV during 2002 from 15¢/kWh (the average retail rate in that year) to 21.3¢/kWh in NYC and from 12¢/kWh (the average retail rate in that year) to 20.3¢/kWh on Long-Island. As shown in Table G-4-2, if PV system owners could capture this value through interconnection rules, rate-structures, etc., then PV technology could become a rapidly expanding and self-sustaining industry in New York State during the next decade.
Accelerated Photovoltaic Technology DeploymentScenario for the New York City Area
The rapid growth in the global PV market during the past decade was driven largely by government subsidy programs, particularly in Japan, Germany, and a few states in the United States (including California and New York). New York State provides a variety of incentives, in the forms of loans, grants, and tax credits for the installation and use of PV systems by residential and business customers.2 The projection discussed here also will not be achieved without subsidies, but they will be phased out over 10 to 15 years. By about 2018, the technology should be cost-effective without subsidies, and New York will have a substantial energy contribution from a source with attractive environmental and security attributes.
The existing subsidy programs for PV systems in New York are well subscribed, indicating that accelerated PV deployment is quite possible. Current installed system prices are about $8/W in New York State, with a $4/W buy-down, leaving a final cost to the consumer of about $4/W. If financed over the life of a system (30 years) at a 6 percent interest rate (~4 percent real interest rate after tax benefits) the levelized cost of energy from such a PV system would be about 13.5¢/kWh. With current average residential electricity prices above 20¢/kWh in New York City, an investment in a PV system could look attractive to many consumers.
The accelerated deployment scenarios considered in the present study is modeled on a Japanese program, which provided a declining subsidy to residential PV systems over the past decade. Residential PV installations expanded in Japan from roughly 2 MW in 1994 to 800 MW in 2004 (Ikki, 2005). In its accelerated scenario, the committee contemplated a growth rate of roughly one-half that experienced in Japan to compensate for the difference in circumstances from the Japanese conditions to those in New York. The average price of residential PV systems installed in Japan in 2004 was $6.2/W—that is, about 25 percent lower than in New York today. This cost differential is a reflection of the difference between a well-functioning and an emerging market for PV systems. PV modules and inverters are commodities whose prices are largely driven by international markets; however, labor and balance of system cost (which typically account for 30 to 40 percent of total system cost) are driven by local policies and market development.
Figure G-4-1 shows an accelerated market-development path for the New York City area. This scenario is not a model result, but an estimate of what could be achieved under the following assumptions:
The estimated technical potential for rooftop installations in the New York City area (Hudson Valley, New York City, and Long Island) in 2025 is 18-20 GW (NYSERDA, 2003; Navigant Consulting, 2004).
The cost projection is in line with what the DOE Solar Energy Technology Program and the U.S. PV industry believes will be achieved over the next 10 to 15 years in the
Letendre et al. (2003) analyzed data on the day-ahead hourly wholesale price of electricity from NYISO from the summer of 2002, combined with satellite-derived solar resource data, and found that the average PV availability for all 32 peak power price days in the summer of 2002 was 79 percent. In other words, on average in the NYISO control area, distributed PV systems would have been operating at roughly 80 percent of their ideal output during the days when power prices spiked above 20¢/kWh in the wholesale market.
Information is available online at http://www.irecusa.org. Accessed November 12, 2005.