James Fama, Edison Electric Institute
An investment in the nation’s transmission network is a gamble many are not willing to make today. The Federal Energy Regulatory Commission (FERC) has proposed an innovative incentive package, but it is only one of many issues that need to be addressed to entice new investors.
For the past 25 years, transmission investment has been dropping by $100 million a year. Looking ahead, the North American Electric Reliability Council predicts that while the demand for power is expected to increase 25 percent this decade, investment will grow only 4 percent. Recent estimates point out that just to maintain the country’s transmission adequacy at its 2001 level would require over $50 billion in new investment during the next 10 years.
Little financial incentive is one reason behind this drop in transmission investment. But other factors–lengthy depreciation times, local siting issues, and regulatory turf battles–are also conspiring against new investment in transmission lines. All these issues will need to be resolved to ensure that the country has a robust transmission grid to meet the needs of tomorrow’s energy markets.
In the early 1970s, the annual growth rate in lower voltage line-miles that support localized grid operations and interconnections was 1.9 percent, while the annual growth rate for high-voltage line-miles was 3.2 percent. By the latter half of the 1990s, this relationship had reversed: the higher voltage line-miles were growing at only 0.3 percent, while lower voltage line-miles were growing at 3.5 percent.
The U.S. Energy Information Administration (EIA) has projected an increase in consumer demand for electricity of roughly 50 percent over the next two decades. To meet this demand, capital investments in upgrades and new transmission lines must increase from their current level of $3 billion annually to roughly $5.5 billion annually over the next 10 years.
FERC’s proposed policy
One hurdle to grid investment has been that the profits for owning and operating transmission networks, which are closely regulated by FERC, are less than those allowed on other types of electric infrastructure investment. On average, it takes more than 20 years to get your money back.
To remedy this, FERC, in early 2003, offered its “Proposed Pricing Policy for Efficient Operation and Expansion of Transmission Grid (Docket No. PL03-1-00).” With a deadline of December 31, 2004, FERC offered electric utilities the following:
“- Transfer control of your transmission facilities to commission-approved RTOs and you can add 50 basis points to your company’s return on equity (ROE);
“- Invest in new transmission facilities, add 100 points;
“- Divest your transmission facilities to an independent transmission company, add 150 points.
Responses from transmission owners and shareholder-owned electric companies to FERC’s proposal were mixed–ranging from insufficient to holding great promise for stimulating RTO formation. Some consumer advocates, public interest groups and state public service commissions have sided against the proposal on many grounds, with higher costs for consumers being the prime argument.
In an early test of FERC’s proposed incentives, several groups, including the state consumer advocates and a variety of municipal and rural electric co-operatives in the PJM service area, have demanded a rehearing on FERC’s January 2, 2004, order to grant the PJM’s transmission owners a 50-basis-point ROE adder for their membership in an RTO, and a 100-basis-point ROE adder to recover their costs of transmission enhancement and expansion, once the commission finalizes its pricing policy statement.
The interveners say there is no proof that such incentives will produce any new benefits for consumers, or if they are even necessary to encourage new transmission investment.
Incentives for transmission investment likely will, in fact, end up lowering retail energy bills. Given that transmission costs account for 6 percent of the average monthly electric bill for retail customers, FERC believes that a $12.6 billion increase in transmission investment would add 87 cents to an electric customer’s average monthly bill. And, the decreased congestion on the lines that would result would enable lower cost power to reach consumers more easily.
For example, if greater transmission capacity resulted in just a 5 percent savings in generation costs, FERC estimates that consumers would see more than a $1.50 decrease in their average monthly bills. Ten percent generation savings would cut the average monthly bill by $4.00.
A more basic complaint is that FERC’s proposal ties its incentives to particular corporate structures, with the result being that FERC too narrowly prescribes how independent operation of transmission facilities, the ultimate policy goal, can be achieved.
FERC’s approach to incentives also suffers from restrictive eligibility rules. Only companies that meet certain requirements and strict deadlines can enjoy the benefits of an increased return on equity in transmission assets. On the other hand, if all new transmission did qualify for the incentive, the cost would be minimal. To finance $4 billion in new transmission investment (the current yearly average utilities spend on transmission) with incentives under FERC’s plan, the dollar equivalent of the incentives would be $20 million, an amount that would increase the average monthly electric bill by less than a penny.
Comprehensive approach needed
FERC’s proposal is a good start for spurring transmission investment and strengthening the grid, but FERC action alone–even if effective–is not enough. The commission should seek state support for these incentives. Without such support, companies may not be able to take advantage of them.
The states and Congress must address the transmission investment issue as well. Many states, as part of retail restructuring or rate cases, 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 through retail rates.
In other states, where restructuring has not occurred, there may not be rate mechanisms in place that allow prompt and assured recovery of the costs of transmission incentives. Deciding who pays for transmission construction–all customers or just the power marketers who stand to benefit from the access–is another divisive issue.
At the federal level, Congress needs to address two critical issues: amending the U.S. tax code to accelerate depreciation of transmission assets, and granting the federal government “backstop” siting authority to step in, if necessary and site important transmission facilities.
Consumers and businesses have come to depend upon, and to a certain degree, take for granted access to reliable and reasonably priced power. Last summer’s blackout and the country’s increasingly congested wholesale power markets show how easily both of these can be put at risk. A coordinated state and federal approach–with the right incentives and rules–will help to ensure that our transmission network can continue to meet the growing challenges it is facing.
Fama is executive director, energy delivery at EEI.