Economic Challenges of Integration

by Tanya Bodell, Charles River Associates

Until recently, integrating renewable resources into the transmission system has focused primarily on technical issues. (For example, see the January 2010 study for the Southwest Power Pool at http://spp.org.)

Although operational impacts are still under review, conversation has evolved to include the integration of other technologies such as demand response, smart grid technology and plug-in hybrid electric vehicles.

The most contentious issues surrounding integration, however, remain economic: Who will be responsible for integrating the grid, how will those costs be recovered and to whom will those costs be allocated?

Who Will Build the Infrastructure?

Should incumbent utilities or independent developers be responsible for building the infrastructure to support integration?

This battle is being waged on multiple fronts before judges, regulators and ratepayers by transmission developers and power producers.

On one side are the incumbents: franchise monopolies in regulated markets and regulated and competitive players in open markets.

These incumbents are increasingly questioning why they should be forced to buy transmission or renewable power from a new entrant rather than obtain their own regulatory preapproval of large capital investments that offer a sufficient return on investment.

Facing off against incumbents are the new entrants—independent transmission companies and independent power producers—intent on maintaining their toehold in currently competitive markets and expanding into the geographic territory of regulated utilities where, in many cases, renewable resource potential is greater and necessary transmission lines longer.

How Will Costs be Recovered?

Although it may seem that costs of building and connecting renewable resources ultimately are paid by either ratepayers or taxpayers, infrastructure owners take a hit to profit margins if costs cannot be recovered. To create a sense of certainty and motivate investment, California, Colorado, Minnesota, Missouri, New Mexico and Texas have passed legislation in some form to provide for recovery of the costs to build transmission to meet renewable policy objectives. Yet, the amount and level of incentives to recover transmission costs to integrate renewables are few compared with state and national incentives to build renewables. The most prevalent might be the Federal Energy Regulatory Commission’s (FERC’s) incentive-based rates to encourage transmission investment that ensures reliability or reduces congestion and therefore costs to customers.

In addition to return on equity, regulators have other levers available to allow for recovery of costs required to integrate capital-intensive infrastructure, including accelerated depreciation, regulated capital structure and for operating utilities, construction work in progress and recovery on abandoned investment. Such tools, however, only apply to regulated entities with approved projects. Which projects get approved creates another battleground of contention.

Who Will Pay?

Cost allocation is contentious, particularly with integration of renewable resources requiring transmission lines that span multiple regions, markets and regulatory jurisdictions. Cost-benefit analyses are used to show the overall benefit of such projects as a precursor to regulatory preapproval and can be used as a basis for allocating costs. Results, however, depend on assumed financial incentives for renewable generation and associated transmission. Furthermore, final cost allocation often reflects relative bargaining positions more than any single economic measure of who benefits from the infrastructure investments.

Many cost-effective investments that have received regulatory approval for regulatory or tax incentives have stumbled on the final hurdle of finding someone to pay for their services. Although FERC open-access rules allow independent power producers to connect to the network, access to transmission does not guarantee economic access to markets:

  • Incumbent members of power pools have rejected incorporation of a new transmission line into their system or planned their own generation and transmission projects that make competitive projects less economic.
  • Utilities have chosen to build their own fleets of renewable generation vs. purchasing under power purchase agreements (PPAs).
  • Regulators have rejected PPAs and cost recovery of investments in rates.
  • State legislators have refused to allow renewable power imported from other states to count as fulfillment of renewable portfolio standards.

Moreover, the current gap between low power prices and high project capital costs can be an obstacle, especially in the current economy where state commissions are reluctant to raise rates.

Technical requirements of transforming our decentralized, fossil-fuel system to renewable resources should not be underestimated. But technical requirements do not elicit intense debate until economic issues are introduced. Who will incur the costs, how will costs be recovered and who will pay the costs are all critical issues that have yet to be resolved.

Author

Tanya Bodell is vice president of Charles River Associates. E-mail her at  Tanya.bodell@fticonsulting.com

“The real world is not as rational and dynamically optimal as economists would like to believe.”
Robert Pindyk

 

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The Clarion Energy Content Team is made up of editors from various publications, including POWERGRID International, Power Engineering, Renewable Energy World, Hydro Review, Smart Energy International, and Power Engineering International. Contact the content lead for this publication at Jennifer.Runyon@ClarionEvents.com.

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