EEI’s View: How the Energy Bill Impacts Transmission Investment

By Russell Tucker, Edison Electric Institute

The Energy Policy Act of 2005 offers much needed help for stimulating investment in the country’s electricity grid. Importantly, the new law provides economic incentives and addresses the siting difficulties that are discouraging potential investors.

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Greater investment in the grid will also come about through a closer working relationship between FERC and the states. EEI and its member electric utility companies are working to achieve this goal. Together, the new energy law and a more effective partnership between regulators will lead to a stronger grid, one that can serve the country well into the 21st century.

The country’s electric transmission network was originally built to provide power for local communities and to interconnect neighboring utilities. Today, the grid still serves local needs, but it also provides the platform for the country’s emerging wholesale electricity markets. Both jobs are increasing in size and complexity each year.

Supply and Demand

Since 1980, according to the U.S. Energy Information Administration, the country’s demand for electricity has increased by 75 percent. Within the next 10 years, that demand is expected to grow by another 30 percent. Wholesale electricity markets are becoming more vibrant, too. In the past five years, the volume of wholesale electricity deals has increased by 300 percent. Last year, the North American Electric Reliability Council found that the number of transactions that could not be completed because of congestion had increased almost eight-fold to more than 2,300.

This growth in electricity transactions and related congestion can be considered a good sign that wholesale markets are growing. But, it also means generation from distant sources, which often can be more economical, cannot get through to where it is demanded. The grid will require more investment to continue doing both jobs.

The nation’s electric utility companies recognize the need for more investment. Between 1999 and 2003, EEI member electric utilities increased their annual transmission investment by 12 percent each year, for a total of $17 billion. Looking ahead through 2008, preliminary data indicates that utilities have invested, or are planning to invest, $28 billion more-a 60 percent increase over the previous five years. But, more will be needed.

How much more? EEI recently estimated that capital spending must increase by 25 percent, from approximately $4 billion annually to $5 billion annually.

The new energy law features many provisions for boosting transmission investment. Section 219 of the act gives the Federal Energy Regulatory Commission (FERC) the authority to establish, by rule, incentive-based (including performance-based) rate treatments. These incentives must:

“-Provide a return on equity that attracts new investment in transmission facilities (including related transmission technologies).

“-Encourage the adoption of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities, and improve the operation of the facilities.

“-Allow the recovery of all prudently incurred costs.

FERC issued a Notice of Proposed Rulemaking on incentives last November and is accepting comments about the potential rate incentives through January 11. The new rules must be in place by August 2006.

Another way the energy law will encourage investment is through the repeal of the Public Utility Holding Company Act (PUHCA), which is effective on Feb. 6. Repealing PUHCA will result in a broader pool of capital available for electric infrastructure investment. Potential new investors include foreign utilities, financial institutions, private equity groups, and other energy and industrial groups.

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PUHCA’s repeal may also expand the previously limited structural and geographic options of the current registered holding companies that own utilities. Some also predict that repealing PUHCA will lead to greater efficiencies through consolidation among utilities across the country.

The new energy law contains a variety of other provisions that will directly help to stimulate transmission investment. These include:

“-Reducing the depreciable lives of transmission assets from 20 to 15 years to make them comparable to other major capital assets.

“-Deferring the gain on the sale of transmission assets to a FERC-approved transmission organization through 2007.

“-Authorizing the Western Area and Southwestern Federal Power Administrations to accept private funding for new transmission facilities that do not duplicate proposed or approved facilities.

Siting Issues

Delays and difficulties in siting transmission can also discourage investment in the grid, particularly difficulties siting transmission lines on federal lands. A variety of federal agencies need to be consulted, which typically leads to a fragmented and complicated federal permitting process for rights-of-way, with each agency working under its own deadlines and without any coordination with the state process.

Because of this process, electric utilities and others have gone to extraordinary lengths to avoid siting on federal land if at all possible. As a result, the current method for siting places a greater burden on private lands and, in some cases, state lands. This, in turn, creates the potential for more conflict with private landowners and an under use of federal lands, even where those lands may be best suited for a project.

The Energy Policy Act of 2005 addresses this problem by giving the U.S. Department of Energy (DOE) the authority to become the lead agency to coordinate and set deadlines for the federal environmental review and permitting process. Now DOE can streamline this often-cumbersome procedure.

Another siting issue addressed in the energy law pertains to those locations around the country where the transmission grid has become so congested that the bottlenecks hold-up the flow of electricity from generation source to point of use. The new law instructs the DOE to assess congestion along critical transmission paths and designate the most significant ones as electric transmission corridors of national interest. The DOE must do the first assessment by August 2006, and every three years thereafter. Once the assessment is completed, FERC can then step in and approve the siting of electric transmission facilities within those corridors, if states cannot or will not act in a timely manner to approve the siting. Although traditional state siting processes are adequate for most local upgrades to existing transmission systems, building lines between states or regions can sometimes result in lengthy delays or even cause the construction to end.

Congressional and FERC action alone, however, is not enough to ensure transmission investment. States must support these measures as well. As part of retail restructuring, 20-plus states have imposed caps or freezes on the rates paid by retail customers. Such caps and freezes can discourage utilities from investing in transmission since there is no mechanism to recover their investments.

In other states where restructuring has not occurred, there may not be rate mechanisms in place that will allow prompt and assured recovery of FERC-approved transmission investment costs. These state-level issues create the potential for conflict with federal regulatory policies. This can result in unrecoverable, trapped costs for investors, which is a further disincentive for investment.

Cooperation is Key

FERC and the states must work together closely to ensure the necessary regulatory mechanisms are in place to allow for the full recovery of all prudently incurred costs-and to avoid any situations where an investment is put at risk due to it being approved by one regulator and not another. Toward this end, EEI has offered FERC and state regulators a number of principles to increase regulatory certainty, and as result, stimulate investment in the grid. Among them is that:

“-FERC and the states should allow full recovery of all prudently incurred costs to design, study, pre-certify and permit transmission facilities.

“-FERC should amend its rules to allow full recovery of the prudently incurred costs of abandoned transmission projects that had to be abandoned.

“-FERC should allow utilities to include “construction work in progress” in their rate base in lieu of “allowance for funds used during construction,” to encourage transmission construction through improved cash flow and greater rate stability.

“-FERC should allow for accelerated depreciation in ratemaking to improve financial flexibility.

“-Where states require purchases of renewable resources that lack siting flexibility, FERC should allow alternative transmission pricing and cost recovery approaches to support the building of transmission facilities to help achieve state renewable resource goals.

“-With new transmission being considered by vertically integrated utilities, independent transmission companies, and merchant transmission entities, FERC transmission policies should not favor one corporate structure, business model or retail regulatory model over another. Many different structures and business models can coexist in a competitive wholesale marketplace for the construction of transmission provided there are fair rules in place for all market participants.

Several states have come up with innovative laws and regulations that give investors greater certainty over cost recovery. Kansas, for example, recently enacted a law assuring cost recovery pre-approval for generation and transmission projects. And Iowa has advanced ratemaking treatment that cannot be undone in future rate cases.

The hybrid nature of the electric power industry today-with some regions operating in a competitive environment and some in a regulated one-also underscores a need for cooperation between FERC and the states, if each is to achieve its goals. The newly forming regional state committees (RSCs) may be the link that is needed to create this cooperation. FERC itself has advocated the formation of RSCs-representing the states within a regional power market-as a means for states to develop consensus on regional policy and planning issues. But right now, the role of the RSC is still evolving.

The Organization of Midwest Independent System Operator States (OMS), the first RSC, has been proactive since its inception in June 2003. Its three major functions are to advise MISO, advise FERC and be a resource to the states. Other RSCs now in operation include the Southwest Power Pool (SPP) RSC, and the New England Governors’ Conference has filed a comprehensive plan for the New England RSC (NE-RSC) with FERC.

The Energy Policy Act of 2005 is a welcomed boost for strengthening the grid. The new law, coupled with a strong federal and state partnership, will give the country the transmission network it needs to meet tomorrow’s demands.<<

Russell Tucker is the director of Federal Regulatory Affairs at the Edison Electric Institute (www.eei.org).

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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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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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