The Outlook for Transmission Investment and Ownership

By David Wagman, Contributing Writer

When it comes to electrical transmission, it sometimes seems as though FERC is from Venus and state regulators are from Mars. Like an unhappy couple squabbling, federal and state regulators may see the same transmission system, but they perceive it very differently.

Regulators at the Federal Energy Regulatory Commission (FERC).view the grid regionally, seeing it as a way to open power markets and offer access to independent power suppliers. State regulators focus more on end-use customers and on allocating costs so local ratepayers don’t pay for regional assets with little local benefit.

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The differences in perception have persisted for years. Their legacy includes underinvestment in transmission (see Figure 1, next page) and a climate in which accountability and reliability can sometimes be seen as optional. Taken to the extreme, the federal-state conflicts may well have helped set in motion events leading to the Aug. 14, 2003, blackout.

Transmission investment has not kept pace either with demand or technology for at least 10 years, said Kenneth Rose, an economist based in Columbus, Ohio. “Restructuring changed the incentives transmission owners see,” Rose said. With restructuring’s emphasis on generation, power sales and marketing, transmission investment ended up as “not a major objective.”

At the same time, transmission is a relatively small part of an integrated utility’s revenue mix. Quoting data from the Energy Information Administration, Joseph Welch, president and CEO of International Transmission Co., said around two-thirds of an average customer’s bill is attributable to generation, not quite one-third to distribution and 7 percent to transmission. Competition for investment dollars within the utility sees generation or distribution coming away as the winner. As an executive formerly responsible for transmission at Detroit Edison, Welch said his transmission division had to compete with its “big brothers” regularly for money. Now, as a stand-alone company, ITC makes transmission its sole priority.

During 2003, the company spent about $30 million on capital improvements. This year it plans to spend about $80 million.

Receptive Capital Markets

The federal-state differences on transmission appear genetic, meaning an easy fix seems unlikely. As in many dysfunctional Venus-Mars relationships, however, everyone tries to make the best of it. Some firms actually are thriving. That’s because transmission remains a fundamentally good asset to own. With corporations focused on sustainable, long-term returns, few investments are more attractive. It doesn’t hurt, either, that transmission is regulated and incentives are available to encourage investment. And finances can be structured so the assets carry a fair amount of leverage and earn returns in the high teens.

“Access to money is very good,” said Welch, whose company owns DTE Energy’s former lines in southeast Michigan. ITC enjoys good regulatory support, which offers assurances to lenders that their loans will be repaid and enhances the investment’s risk profile.

“We’ve seen a high level of receptivity to our (debt) needs,” said Dale Landgren, vice president and chief strategic officer with American Transmission Co., a multi-state transmission-only company based in Peewaukee, Wis. The company has negotiated with FERC to use forward-looking rates, an arrangement that has helped the start-up achieve much needed cash flow. The company also has a settlement agreement before FERC that would include construction work in progress (CWIP) as an expense, again to improve cash flows.

With a capital structure of 50 percent debt and 50 percent equity from private investors, the company has a 10-year plan to invest $2.5 billion to $2.8 billion in transmission infrastructure in Michigan, Wisconsin, Illinois and Iowa. That means American Transmission expects to go to debt markets for about $200 million a year to fund projects related to reliability, interconnection and market access, Landgren said.

“There is money chasing these assets,” said Bernie Schroeder, president and COO of Reston, Va.-based Trans-Elect. The independent transmission company owns 5,400 miles of transmission lines in Michigan and 7,200 miles of lines in Alberta, Canada. Trans-Elect also is building the Path 15 interconnection in California for the Western Area Power Authority.

“In the wake of the dot-bombs and trading activity, Wall Street is looking for blue-haired ladies with regular, steady returns,” Schroeder said. Even a modest transmission system can represent a $200 million to $300 million investment, he said. “The trick is to get more people to sell.”

And there’s the rub.

Few transmission assets are up for sale. As part of the “back-to-basics” strategy many investor-owned utilities are pursuing, transmission assets are back in style as a part of the corporate structure. This trend coincides with an anti-divestiture backlash following the spotty record regulatory reform has shown in many states.

Your Father’s Oldsmobile?

“There are tremendous benefits to having integrated utilities,” said Ken Rose. Among them are economies of scale and scope and the ability to coordinate all aspects of electricity production and delivery. The list may sound familiar. That’s because the benefits are largely unchanged from decades ago when utilities first were regulated.

The Aug. 14 blackout won few converts to the idea of asset spin-offs. Duquesne Light in Pittsburgh and Oklahoma Gas & Electric are among the companies now proposing that they buy generating assets to enhance reliability. Purchases such as these may ease worries among state regulators, but they raise red flags at FERC.

Late last year, FERC began to look into OG&E’s $160 million deal to buy a 77 percent interest in the 520-MW McClain power plant from a business unit of NRG Energy Inc. The acquisition was billed as part of the utility’s “Customer Savings and Reliability Plan” filed with state regulators in October.

FERC’s concerns lie with market power issues related to utilities buying merchant generating capacity. The worry is that a utility will reacquire sufficient generating capacity so that it no longer needs to buy from merchant generators. In a potential reversal of fortune reminiscent of the 1990s, those assets could even become stranded, said Mark Kubow, senior managing director of Navigant Consulting in Chicago. A utility could further decide to favor its own generation in dispatch, exert market power and unfairly control prices. Not surprisingly, FERC sees this sort of “local” generation issue as having a potentially major effect on regional markets and transmission.

(Last month, FERC adopted two market power analyses, designed to indicate generation market power. The first test is called a “pivotal supplier analysis” and is based on a control area’s annual peak demand. The second test is a “seasonal market share analysis.” Both tests consider native load obligations, operating reserve requirements and other commitments.)

Public vs. Private Good

Reliability has become an issue because of regulatory changes and the way companies react to those changes, Rose said. When utilities were vertically integrated part of their responsibility was ensuring all parts of the system worked reliably. Economists call this a private good. But deregulation forced some utilities to sell off assets—including transmission—and introduced a regional market focus. This shifted the notion of reliability from a private good to being a public good. Economic theory holds that public goods typically suffer from underinvestment unless incentives are offered. “It’s not a surprise reliability issues are showing up” as a result of deregulation, Rose said.

The Aug. 14 blackout brought transmission reliability into the homes of some 50 million people living in the Northeast and parts of Canada. The largely voluntary nature of the operating rules, along with hazy responsibility for keeping the grid in good working order, fostered an atmosphere where trouble could happen.

In testimony last September to the House Committee on Energy and Commerce, Joseph Welch said, “It was apparent that parties were choosing to operate the grid within their sphere of influence for their own purposes without regard to rules, procedures or the impact of their actions on other users of the grid. Further, the convoluted RTO configurations which major entities have contrived to create virtually guarantees that communication, when it occurs, will be a matter of luck.”

Incentives and Disincentives

Federal regulators offer incentives for transmission investment. Leonard S. Hyman, in a paper written for Charles River Research Corp., outlined three bonus adders FERC may apply for grid investment: 150 basis points to encourage independent transmission asset ownership, 100 basis points for new transmission investment and 50 basis points to join a regional transmission organization (RTO).

Those incentives are offset somewhat by the taxes utilities would likely have to pay on the sale of their assets. Bernie Schroeder of Trans-Elect said energy legislation before Congress would offer some relief, allowing a seven- or eight-year deferral.

And Ken Rose said FERC needs to devise incentives to prompt owners to think regionally, “which they don’t do naturally.”

Regardless, few utilities are motivated right now to sell their transmission assets, said Navigant’s Mark Kubow. With assets earning 12 percent to 14 percent returns on equity, transmission has regained much of the sex appeal it lost during the high-tech, dot-com fever of the 1990s. What’s more, any divestiture would require state regulatory approval. And that would mean state regulators would have to give up to FERC part of their authority.

“There’s not a clear answer,” Kubow said. “It’s an incredibly complex situation.”

Faster and Cheaper

In what may be the oddest incentive of all, merchant power generators may see their business prospects improve due to ongoing transmission constraint problems.

Stephen Fairfax, president of Framingham, Mass.-based MTechnology, said that firms such as investment houses and even public service agencies are investing in private generation to guarantee the kind of reliability the national grid cannot. He said private sector investment in backup generation outspends grid investment by a ratio of 2-to-1 to 3-to-1.

In Arizona, meanwhile, a large amount of merchant power generation was built on the eastern side of the Palo Verde hub, said Gary L. Hunt, vice president of consulting services for Sacramento, Calif.-based Henwood Energy Services. Trouble is, not enough transmission capacity exists to get all of the available power to Southern California markets.

“In some cases, plants in Arizona are having extraordinary trouble with their debt service,” Hunt said. The opportunity may be for power developers to build on the unconstrained side of a bottleneck like Palo Verde where they would enjoy easier access to markets.

Given the difficulties in siting new transmission lines, it may be faster and cheaper to build power plants than transmission lines, Hunt said.

Easing a transmission bottleneck through new construction can also have unintended financial consequences, Kubow said. Many observers agree that New York City could benefit from additional transmission capacity, which would improve the city’s access to lower-cost power. But improved access could mean that $70/MWh power could fall to $55/MWh power once the transmission constraints are breached. That sort of price drop could well make the transmission investment uneconomic, Kubow said.

“Unless you have a counterparty to sign up for the line, it’s hard to make sense” of such an investment, he said. “We’re caught in a vicious circle.”

Valuing Lost Load

One way to help justify transmission projects would be to look not only at their economic cost, but also their larger economic contribution. Elliot J. Roseman, principal with Fairfax, Va.-based ICF Consulting, suggests calculating an indicator he calls “value of lost load” or VOLL. During the Aug. 14 blackout, economic losses across eight states reached around $6.4 billion, including $380 million in lost perishables, mostly food.

Those numbers suggest to Roseman that the cost of not having electricity is far greater than the monthly electricity bill suggests—perhaps as much as 60 to 100 times greater. He suggests using VOLL as one tool to help regulators evaluate proposed transmission additions. The indicator would show the extent to which a transmission improvement helps to reduce the overall value of a lost load.

The bottom line, he said, is that “the economic benefit from making the right transmission investment is many times the investment cost.”

In gauging whether FERC or the states ultimately will prevail in the contest of wills over transmission, FERC seems to have the advantage. For one thing, FERC has “drummed a steady drumbeat” when it comes to supporting independent transmission, said Bernie Schroeder. That support began at least with its Order 636 in 1992, followed by the Energy Policy Act and Order 2000, along with its plans for standard market design and its overall pricing policies.

Because it has review authority over a wide range of utility investments, including acquisitions, FERC can achieve its policy goals in part by conditioning approval on a company’s compliance with its long-term objectives.

“It’s a combination of FERC gaining influence and peddling influence,” Kubow said.

Kicking and Screaming

Regulatory influence peddling eventually could bring companies such as Entergy and Southern Co. into line with FERC thinking. Both companies are frequently cited as holdouts when it comes to RTOs, a cornerstone of FERC policy. Objections also come from the Pacific Northwest, where Bonneville Power Administration has balked at joining an RTO.

Some large systems don’t see the benefit in joining an RTO, Rose said. Entergy and Southern are both large, multi-state operators whose systems already may be capturing RTO-like benefits. One difficulty is that FERC prefers voluntary RTO membership and may lack the authority to force membership even if it wanted to. The approach has been for companies, states and regions to draw boundary lines and then seek FERC approval. The process can take years to complete and even then may not be successful.

Last December, sponsors of the SeTrans RTO in the southeastern United States suspended their organizing efforts, which began in 2000. In announcing the collapse, sponsors said state regulators had expressed concerns all along about the role an RTO would play in deciding issues related to native load protection and cost impacts. Those concerns remained unresolved and ultimately sent SeTrans to the scrap heap.

“Some regulators are happy, others are kicking and screaming, and the FERC lacks authority to impose a structure,” Hunt said. “Unless Congress becomes more supportive of having organized regional markets, the FERC will have to deal on a case-by-case basis.”

That raises the specter of Venus and Mars turning to Congress for help in resolving their long-standing transmission disputes. And just what planet Congress is from remains anybody’s guess.

David Wagman is based in Denver where he writes about energy issues.

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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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