Implications of high-penetration renewables for ratepayers and utilities in the residential solar photovoltaic (PV) market

Samantha A. Janko, Michael R. Arnold, Nathan Johnson

Research output: Contribution to journalArticle

34 Scopus citations

Abstract

Residential energy markets in the United States are undergoing rapid change with increasing amounts of solar photovoltaic (PV) systems installed each year. This study examines the combined effect of electric rate structures and local environmental forcings on optimal solar home system size, ratepayer financials, utility financials, and electric grid ramp rate requirements for three urban regions in the United States. Techno-economic analyses are completed for Chicago, Phoenix, and Seattle and the results contrasted to provide both generalizable findings and site-specific findings. Various net metering scenarios and time-of-use rate schedules are investigated to evaluate the optimal solar PV capacity and battery storage in a typical residential home for each locality. The net residential load profile is created for a single home using BEopt and then scaled to assess technical and economic impacts to the utility for a market segment of 10,000 homes modeled in HOMER. Emphasis is given to intraday load profiles, ramp rate requirements, peak capacity requirements, load factor, revenue loss, and revenue recuperation as a function of the number of ratepayers with solar PV. Increases in solar PV penetration reduced the annual system load factor by an equivalent percentage yet had little to no impact on peak power requirements. Ramp rate requirements were largest for Chicago in October, Phoenix in July, and Seattle in January. Net metering on a monthly or annual basis had a negligible impact on optimal solar PV capacity, yet optimal solar PV capacity reduced by 20–50% if net metering was removed altogether. Technical and economic data are generated from simulations with solar penetration up to 100% of homes. For the scenario with 20% homes using solar PV, the utility would need a 16%, 24%, and 8% increase in time-of-use electricity rates ($/kW h) across all ratepayers to recover lost revenue in Chicago, Phoenix, and Seattle, respectively. The $15 monthly connection fee would need to increase by 94%, 228%, or 50% across the same cities if time-of-use electricity rates were to remain unchanged. Batteries were found to be cost-effective in simulations without net metering and at cost reductions of at least 55%. Batteries were not cost-effective—even if they were free—when net metering was in effect. As expected, Phoenix had the most favorable economic scenario for residential solar PV, primarily due to the high solar insolation.

Original languageEnglish (US)
Pages (from-to)37-51
Number of pages15
JournalApplied Energy
Volume180
DOIs
StatePublished - Oct 15 2016

Keywords

  • Electricity rates
  • Energy economics
  • Net metering
  • Residential solar
  • Solar photovoltaic (PV)
  • Techno-economic optimization

ASJC Scopus subject areas

  • Energy(all)
  • Civil and Structural Engineering

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