A successful initiative should reduce state dependence on volatile supplies.
California's Renewables Portfolio Standard (RPS) requires retail sellers of electricity to increase the relative percentage share of all such sales represented by renewable electricity by an absolute increment of at least 1 percent of additional share per year, thus achieving a releative share of at least 20 percent of all power sales by 2017. This will be a formidable task, even in resource rich California, where renewable energy sales already account for 11 percent of all utility sales today. This requirement raises interesting questions:
- How will the RPS affect generation and capacity from all power sources moving forward?
- How will that development affect electric secto natural gas use?
- What will happen to the market price of power?
To answer these questions, we conducted an hourly unit-level simulation of California's power market through 2015. We constructed a "No RPS" case that assumes only currently planned renewable energy additions are added to California's capacity mix, and a "Full RPS" case that assumes the RPS targets are met fully with in-state resources. In this analysis, we assume that the vast majority of new renewable power capacity will be developed in-state since California possesses very favorable resources.
In terms of renewable energy capacity and generation, our market simulation indicates that if California utilities achieve their RPS goals, California's installed fleet of renewable electric energy capacity must increase from 5.4 GW today to about 18.6 GW by 2015. Renewable generation must increase from just over 28 Terawatt-hours (TWh) today, to 69.5 TWh by 2015.
How will this impact electric sector gas use? As illustrated in Figure 1, in the "No RPS" case, natural gas generation is expected to increase from 91 to 214 TWh. In the "Full RPS" case, natural gas generation is expected to increase only to 177 TWh by 2015, a reduction of 37 TWh, or 17 percent. Our results indicate that new renewable power generation-mostly wind-in the "Full RPS" case competes almost exclusively with natural gas generation, as coal, oil, and nuclear generation are essentially the same in both cases.
In terms of gas-fired capacity, in the "No RPS" case natural gas capacity is expected to increase from 38 to 56 GW. In the "Full RPS" case, natural gas capacity increases only to 51 GW by 2015, a reduction of 5 GW, or 9 percent. Our results indicate that new construction of baseload gas combined-cycle units is most affected as a result of RPS-driven new renewable energy capacity. The addition of peaking gas combustion turbine units is similar between the two cases.
Looking at electric sector natural gas consumption, we find that consumption drops 262 trillion Btus by 2015 when moving from the "No RPS" to the "Full RPS" case, representing a reduction of nearly 17 percent. At $4/mmBtu, this means that California will save approximately $1 billion in annual natural gas expenditures by 2015 as a result of the RPS.
What about power prices? Our modeling efforts indicate that market clearing power prices in California are likely to remain relatively unchanged when comparing the "No RPS" to the "Full RPS" case. This is primarily because our market model automatically installs capacity as needed to meet demand, thereby eliminating the possibility of unpleasant price surges (if only the real world worked in a similar manner). It bears mentioning that market clearing energy prices do not reflect the capital investment cost required to bring new resources to market. We expect total investment costs under California's proposed renewable energy capacity expansion to be substantially higher than the "business-as-usual" capacity expansion plan embodied in the "No RPS" case.
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