California Energy Commission

Structural and regulatory factors have allowed utilities in some countries to leapfrog America’s utility industry in terms of technology leadership. But U.S. utilities are learning valuable lessons from international advancements.

California hopes to reap $3 billion in benefits from demand response over the next 20 years. Maximizing the potential may require the California Energy Commission to exert its statutory authority. CEC’s chair co-authors.

Policy mandates might erode public support for green-energy efforts, even in an environmentally conscious state like California, by frustrating consumer demands instead of allowing them to be fulfilled more efficiently. Recognizing real consumer value will help policy makers develop economically rational green-energy regulation.

By displacing electricity produced from fossil fuels, renewable power plants produce two distinct products—commodity electricity and a set of environmental attributes (particularly avoided emissions). These environmental attributes can be packaged into a product called a renewable energy certificate, or REC, and sold separately from the electricity. As REC markets develop, key issues are being addressed regarding market interaction.

Recent predictions suggest that the U.S. electric industry will invest $300 billion in new transmission and distribution (T&D) facilities (including advanced meters) over the next decade, and $400 billion in new power plants over the next 25 years to meet forecasted demand growth. If we start now, we can build interoperability principles and capabilities into those investments and hasten the improvements in reliability, costs, innovation and value that interoperability can deliver.

Part way through the Feb. 27 conference on electric competition, it was so quiet you could hear a hockey puck slide across the ice. No, hell had not frozen over. Rather, it was Commissioner Marc Spitzer, who had found a clever story to ease the tension and allay fears that FERC somehow might want to undo the sins of the past, and give up its dream of workable markets for wholesale power.

Despite overwhelming theoretical and empirical evidence, we aren’t seeing more DR when it is needed most—during emergency periods. The reasons boil down to two obstacles, both of which must be addressed before widespread DR implementation can move forward.

In the minds of many policy-makers, DR has become associated with rate shocks, rate volatility, unpredictability, and loss of control over energy costs—the very things DR was designed to overcome. What can be done to change this?

A 2007 law essentially prohibits California utilities from signing long-term contracts for power, including those from out of state, unless they emit less than 1,000 pounds of CO₂/MWh of electricity produced. While the law does not specifically bar coal-fired generation, the limit is set low enough to rule out all coal-power plants. A modern, highly efficient natural gas-fired plant barely would qualify. These measures, plus the new carbon-cap law going into effect by 2012, have sent utilities—large and small, private as well as municipal or city-owned—into a frenzy as they scramble to find alternatives to coal to meet their future demand.

(December 2006) Charles A. King, California ISO: “Kicked Off and On Schedule” reasonably captures many of the implementation issues and stakeholder concerns surrounding the California Independent System Operator Market Redesign and Technology Upgrade program. However, I was somewhat disappointed that the article offered few details about the benefits MRTU will provide.