Renewable Portfolio Standards Work, But at What Cost?

by Todd J. Griset, Preti Flaherty

As policymakers consider energy and environmental goals, renewable portfolio standards (RPSs) are one popular tool to encourage the development of renewable power resources.

These regulations, also called renewable electricity standards, typically require utilities to source a specified percentage of their power from qualified renewable sources.

States adopt RPS programs to incentivize the development of new capacity, reduce their carbon footprints and mitigate volatility in fossil fuel prices. While such regulations have cost impacts to ratepayers, proponents argue that their benefits exceed their costs.

In the U.S., roughly 30 states have adopted such regulations. Each jurisdiction’s program varies depending on local policy objectives and political climates.

State RPS programs differ on the amounts of renewable energy required, timelines for implementation and which technologies qualify as renewable. For example, power from large-scale hydro and municipal solid waste combustion qualify in some but not all states. The U.S. has no national RPS. In recent years, House and Senate initiatives have failed to obtain bicameral support. Challenges include the debate whether a federal RPS program is good policy, as well as the cost impacts and value proposition of the renewable mandate.

RPS programs generally are considered effective in incentivizing renewable generation development. For example, a 2007 Lawrence Berkeley National Laboratory report shows that more than 50 percent of nonhydroelectric renewable capacity additions between 1998 and 2007 occurred in states with RPS programs.

In 2007 alone, 76 percent of new nonhydro renewable capacity occurred in these states. As more states adopt RPS measures, the market demand for renewables continues to grow. By 2025, some 61 gigawatts of new renewable capacity must be developed in the U.S. to satisfy the existing state RPS goals.

Consumers and policymakers are right to examine these policies’ cost impacts. The cost of an RPS varies depending on the program’s details, as well as on the nature of the existing power landscape in the jurisdiction. Where existing renewable resources already exceed the mandated portfolio target, cost impacts might be small.

The 2007 Lawrence Berkeley report suggests that existing state RPS programs resulted in rate increases of less than 1.2 percent. A 2008 California study predicts that a more ambitious 33 percent RPS combined with significantly expanded energy efficiency would increase costs 4 percent.

At first glance, these findings appear dissonant with reports of the prices to be paid to some new renewable resources. For example, Massachusetts developer Cape Wind Associates recently reached an agreement with utility National Grid to sell 50 percent of the output from its 454 MW offshore wind project at a price starting at 18.7 cents per kilowatt-hour, escalating 3.5 percent annually for the 15-year life of the contract. The contract, which has been approved by the Massachusetts Department of Public Utilities, is projected to add $1.50 to the average residential consumer’s monthly bill.

This proposal, driven largely by Massachusetts’ ambitious RPS, strikes many as a high price for power. The average U.S. retail rate for electricity across all sectors is just less than 10 cents per kilowatt-hour, with consumers in many states paying 7 cents or less.

Consumers complain that more expensive renewable power purchase agreements are uneconomic, with costs exceeding the benefits. Renewable projects have faced regulatory rejection because of their rate impacts, such as the Rhode Island Public Utilities Commission’s initial March 2010 rejection of the proposed 24.4 cent per kilowatt-hour contract between utility National Grid and Deepwater Wind’s proposed Block Island Wind Project as too expensive. (In the wake of this initial rejection, the Rhode Island General Assembly passed a law giving the public utilities commission a broader mandate and tools to place a higher value on power from renewable projects. The commission subsequently approved the Deepwater Wind contract at 24.4 cents per kilowatt-hour.)

Proponents of RPS measures argue that the increased costs are justified. Even in the states with the most aggressive RPS programs, less than 50 percent of the total power must come from renewables. Prices for offshore wind draw attention because they tend to be more expensive than other new renewable resources. Where existing low-cost renewables such as hydroelectricity qualify for RPS compliance, however, this blend offsets the price impacts of more expensive projects.

Portfolio standards provide one tool to allow policymakers to incentivize renewable generation, but RPS measures are not the only way to encourage renewable power development. Other regulatory approaches, including federal and state tax credits, feed-in tariffs and long-term contracts for renewable projects’ output, encourage power developers to build new renewable projects. These measures are not mutually exclusive with portfolio standards. Each alternative approach, however, imposes cost impacts on ratepayers because each serves to pay a price premium to renewable projects. RPS programs can compare favorably to these measures.

Regardless whether the U.S. adopts federal regulations, RPS mechanisms likely are here to stay. RPSs are effective at incentivizing the development of renewable power resources.

The challenge to policymakers is to implement stable measures that will balance policy objectives against cost impacts, resulting in a predictable market for affordable renewable power.


Todd J. Griset is an attorney with Preti Flaherty’s Energy and Telecommunications Group. He frequently represents clients before federal and state regulatory agencies and has practiced extensively before the Federal Energy Regulatory Commission and the Maine Public Utilities Commission and ISO-New England. Reach him at

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