Net metering is a policy that many states already have implemented to encourage the use of small renewable energy systems. Approximately 40 states have adopted some form of net metering law for small wind and/or photovoltaic technologies; the customer receives a credit for excess power sold to the utility.
Under most state rules, all retail customers are eligible for net metering; however, some states restrict eligibility to particular customer classes {such as farm subsidies}. Customer participation in net metering programs has grown significantly.
In 2004, a total of 15,286 customers were in net metering programs—a 132-percent increase from 2003. Residential customers accounted for 89 percent of all customers participating in such programs.
{With the fourth-best wind power in the nation at 1,030 kWh per year, nearly every South Dakotan who installs a small or community wind turbine would be eligible for net metering. Diversifying income in this manner occurs any time the wind is blowing faster than 14 mph (probably five days out of seven in SD, yes?)}
The use of net metering with current metering technology is problematic, however, because standard meters cannot account for the difference
• between high-cost peak and low-cost off-peak electricity or
• in wholesale and retail electricity costs.
For example, a conventional meter only can record that over a given month an onsite generator sold a net of 100 kWh to the local utility, but will have no record of when the 100 kWh was sold. Sales at 4 p.m. on a hot summer weekday will have a much higher value than sales at 3 a.m. on a Saturday morning.
In order for electric utilities to remain financially viable in the current era of increased operating costs and continued need to invest in infrastructure development and expansion, rates must increase.
Indeed,electricity prices in many regions already have increased and further increases will be necessary in many cases. For example, between January 2005 and January 2006, U.S. electricity prices increased by an average of 11.6 percent, which predominantly reflected increased fuel and purchased power expenses.
These increases affected all customer classes
• residential prices rose by 12.5 percent
• commercial prices rose by 10.5 percent and
• industrial prices rose by 12.6 percent.
Table 9-1 provides a comparison of retail electricity prices over time, as well as similar measures for other key consumer price indices. The 2000 to 2005 picture, however, shows electricity prices growing at a slightly greater rate than that of all items in the CPI. However, even in this period, other energy prices are growing much more rapidly than electricity prices.
Retail prices have become more complex and varied in the past decade. This is a result of
• regional and state differences in rate regulation
• wholesale market organization
• generation mix and
• the individual characteristics of utilities themselves, such as their reliance on owned generation or purchased power to serve load.
It is clear that the fundamental cost driver of increased fuel prices ultimately will increase electricity prices across the country andcharacter of the price increases will have a substantial impact on the ability of utilities to pursue needed investment priorities.
By 2003, average household electricity consumption increased 21 percent, from 1.07 kilowatt (kW) per hour to 1.30 kW per hour. In 2030, average household consumption is expected to increase by more than 11 percent, to 1.45 kW per hour. Greater demand for electric power, however, does not translate directly into higher household expenditures.
Pie charts on p101 - 102, show inter-relationships of these figures.
"Impacts of Price Increases on Electricity Demand Growth Forecasts," is Appendix B.
Figure B-1 shows key inputs and outputs for Energy Information Administration's (EIA) most recent long-term forecast. EIA projects significant declines in the real price of electricity, with a
flattening in later years. This steady-to-declining trend in real electricity prices in 2006 and beyond closely tracks historical trends, and accordingly, demand follows a steady upward trajectory.
In the context of EIA’s modeling framework, the fall in prices is likely due to several factors.
• first and most important, both the rise and fall in electricity prices correspond closely with projected fuel costs.
• second, generating capacity additions underlying EIA's forecast are not dramatic in the near term, as EIA projects about 50 GW of additions over the period through 2014, well below NERC’s forecast of 86 GW.
Thus, the rate base for generation is not growing at a significant pace in the near term under EIA's projections.
While {the authors} have no reason to doubt the internal consistency {even with the contradicting comment a few paragraphs previous to this one?} of EIA's projections and the underlying data, this will impact the projection of demand growth. In EIA's projection assumptions fuel prices (notably natural gas) drop rapidly in price from a 2005 high, bringing
electricity prices down with them.
{What justification does EIA have for expecting fuel prices to decrease?! Peace in the Middle East? "Big Oil" rebates because of its massive profitability? Ease of developing Russian oil fields? What?}
In particular, real prices are assumed to increase 10 percent between 2005 and 2006, and then no change in real price is forecasted through 2014.
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A handful of South Dakota wind-
• 6 PM Jun 08, WSW at 21 mph
• 3 PM Jun 08, W at 16 mph
• 9 AM Jun 08, W at 7 mph
• 4 AM Jun 08, WNW at 15 mph
• 9 PM Jun 07, NNW at 25 mph.
Do contact me if you want to buy any of this blog's content or would like to have other specific wind power-related content uncovered.
'Til next time. Best Wind.
