Transmission Policy in Flux


More planning, fewer incentives, and a black swan on the horizon.

Fortnightly Magazine - May 2013

More than a decade ago, before passage of the 2005 Energy Policy Act, I was consulting with a utility holding company that was thinking about splitting off its transmission assets and creating a business unit to invest in transmission within and outside its service territory. The CEO, after listening to the conversation for a while, drew a sharp contrast with natural gas.

The pipelines, he noted, enjoyed strong and widespread political and regulatory support for network expansion. But what about the electric grid; are policy makers blind to the value that electric transmission also can provide to society?

He suggested that we think about ways to educate policy makers about the importance of transmission in order to place it on an equivalent plane with natural gas pipelines as an investment option. 

Since that time, there’s been a broader recognition of the value of new transmission investment, but it also remains the case that major electric transmission projects are exceedingly difficult to build, even where their need is evident. With apologies to Robert Frost, something there is that doesn’t love a transmission line. No one wants to pay for it. No one wants it sited in their neighborhood. And very few people outside the industry understand the physics of electricity enough to comprehend the need and benefits. In many cases, new transmission lines get built only because utilities are willing to persevere in a long and tortuous political and regulatory process, risking their time, money and political capital to get them built. The cost in goodwill alone makes transmission investment unusually risky. 

This is true despite the fact that it has become widely accepted that investment in the transmission grid has lagged dangerously for decades. In 2005, Congress gave additional tools to the Federal Energy Regulatory Commission to deal with the problem and directed it to provide rate incentives to reverse the trend. FERC responded by endorsing a number of policy initiatives—price incentives, merchant transmission, and planning reforms—to promote investment. Transmission investment has increased as a result, but FERC’s initiatives haven’t been entirely successful. Some state regulators and customers, focusing exclusively on transmission prices, are pressuring FERC to back away from its pro-investment policies. 

Assuming FERC’s interest in transmission investment hasn’t waned—and the commissioners’ public statements indicate it hasn’t—some new approaches might well be in order. 

The Need Remains

Nothing has changed since passage of the 2005 EPAct that suggests the need for new transmission investment has abated. Arguably, the opposite is true. PJM, for example, recently approved a regional transmission plan with $5 billion of new investment identified to respond to what it describes as unprecedented changes in the generation mix created by the combination of shutting down coal capacity and integrating wind.1 Transmission investment also remains necessary to satisfy mandatory NERC reliability requirements, which recently have been applied down to 100-kv facilities.2 Transmission congestion persists, raising electricity prices, limiting the efficiency of competitive wholesale markets, and preventing new generators from interconnecting and selling their output. More than half the states have renewable portfolio standards that will require the integration of many gigawatts of new renewable generation. The transmission grid is also generally old and it’s being used differently—and more aggressively—than was planned when the system was built. New technologies that will make the grid more reliable and efficient are reaching commercialization and need to be applied. The arguments for significant new investment in this sector are compelling. 

In a few instances, state regulators and customer representatives have come to FERC with complaints about higher transmission prices, but these complainants don’t bother to weigh the higher costs against the benefits of the new investment. In regions where significant new transmission investment has occurred, it has yielded impressive benefits in reduced congestion, resolution of reliability problems, and increased planning and operating flexibility. FERC needs to stand behind its pro-investment policy by firmly resisting one-sided, politically motivated complaints about costs. Transmission isn’t free, but it’s cheap in relation to the benefits achieved in supplying reliable and efficient electric energy and meeting public policy goals. 

Jurisdictional Issues

When a natural gas pipeline developer proposes to build an interstate line, there might be local opposition, but whether to build the pipeline is a decision that’s made ultimately on the basis of national energy policy needs. This is in part a result of jurisdictional lines drawn in the National Gas Act that give FERC exclusive authority to permit the line, but it also represents a difference in the way the two industries are viewed by policy makers and the public. Since FERC issued Order 888 almost two decades ago, an ongoing debate has taken place about whether and to what extent electric power should be treated as an interstate business subject to greater federal control. States have asserted their traditional role as the primary regulators of this industry with a focus on the interests of consumers—and politicians—in their states. The Federal Power Act’s apportionment of jurisdiction between the federal and state government is subject to endless debate and is outdated in light of technological changes in the industry. The overarching debate over federal versus state control has infected policy discussions involving the industry for a few decades, and its lack of resolution is particularly important for the transmission business, which is primarily interstate in nature.

The issue isn’t just that FERC has insufficient authority to site transmission lines—although that’s important. It’s about whether political leaders support a national electric infrastructure that’s consistent with lowest cost and reliability measured on a regional and national basis, as opposed to an electric system that’s the product of individual state policies and needs. FERC typically has endorsed the federal, interstate paradigm, but sometimes it’s been tepid and wavering in this support. To be fair, the commissioners have learned that whenever they tilt too far in favor of the national viewpoint, their fingers get singed. The dispute over RTOs and the long-since buried standard market design illustrate this fact. Nonetheless, if FERC isn’t a strong and unwavering voice for the proposition that bulk power infrastructure decisions need to be guided by national policy and not state interests, no one will be that voice. The Federal Power Act gives FERC that responsibility. Even those utilities that support this viewpoint have too much of their revenue and political capital at risk at the state level to lead the charge consistently and effectively. 

One instructive debate is happening in my home state of Maryland. The governor recently convinced the legislature to enact a bill mandating the construction of offshore wind generation that my utility will have to purchase and I will pay for. As a utility customer, I’m prepared to accept that it’s worthwhile to diversify our power sources by integrating wind into the generation mix. But according to the Energy Information Administration’s 2013 forecast of levelized generation costs—including transmission—offshore wind will cost $221.5 per megawatt-hour in 2018, whereas on-shore wind in the same year will cost only $86.6 per MWh. Offshore wind is almost three times the cost! And yet, the governor argues for offshore wind on the basis that the state needs to support efficient green energy.3 He wants local jobs and green bragging rights, and he is prepared to (regressively) tax citizens with higher power bills without disclosing all of the relevant economic facts. It’s akin to the state government mandating that the state get its natural gas in the form of LNG imports at three times the cost of domestic gas delivered over the interstate pipeline system, in order to create a handful of jobs at the in-state LNG import terminal. 

This situation and policies like it in other states directly affect national transmission policy. For example, the evidence strongly suggests that building EHV transmission to get low-cost wind generation from the middle of the country to load centers near the coasts makes more economic sense than building offshore wind. The resulting transmission infrastructure also would support more robust interstate bulk power competition and bulk power system reliability. And yet, efficient transmission decisions are being preempted by preferences for local generation based on parochial interests. The current paradigm dictates that decisions like these are properly made by individual state regulators and politicians. At heart, the debate is about who’s in charge of the bulk electric system. No comparable debate takes place when major infrastructure decisions are made in the gas pipeline industry, even though states regulate retail gas service.

The issue also has important implications for the long-term competitiveness of the utility industry. Regulatory decisions are routinely made at the state and local level that make electricity delivered over wires more expensive by loading it with hidden costs imposed to comply with local policy mandates. But, the electric equivalent of wireless telephony—rooftop solar, a black swan that can deliver electricity without transmission—has now come into view. The wired electric industry soon will have to compete with this new product. Minimizing the cost of electricity that’s delivered to load over the bulk power system will therefore emerge as a critical competitive issue for the industry. Being told as a utility that you can pass the cost impacts of questionable state and local initiatives through in retail rates is seductive, but dangerous over time. As the competitive threat increases, the industry might see more clearly the importance of a highly efficient, interstate bulk power system that yields delivered energy at the lowest feasible cost. 

Incentives from FERC

In the wake of EPAct 2005, the FERC promulgated Order No. 679, providing transmission pricing incentives in accordance with new Section 219 of the Federal Power Act.4 The FERC began issuing return on equity (ROE) decisions that gave transmission developers ROEs approaching those approved for natural gas pipelines, with opportunities to earn a bit more for non-routine, large projects. During the recession, these FERC-allowed ROE numbers for electric transmission have come down steadily in light of reductions in interest rates and a change in FERC ratemaking policy that has produced generally lower allowed ROEs.5 In 2012, the FERC issued a policy statement that makes it much more difficult to obtain approval of ROE investment incentives. FERC seemed to reason that granting a return on CWIP plus the opportunity to go through a few years of hearings over whether the utility is entitled (by a future commission) to recover some abandoned plant costs, was sufficient incentive to satisfy Section 219 in most cases. 

Several complaint proceedings now are pending before FERC in which the complainants are demanding that allowed ROEs be reduced to below 9 percent. In one Section 205 case, Pacific Gas & Electric was ordered to summarily revise its ROE proposal to take into account FERC’s new requirement that individual utilities use the “median” of the proxy group numbers in the DCF analysis to calculate its allowed ROE. The result was a filing—by the utility but based on FERC’s directions—showing an allowed ROE of 8.6 percent.6

With these rate decisions, whether by design or not, FERC has now created a disconnect with the pro-transmission investment policy that it (and Congress) have so earnestly favored. Allowed ROEs allocate capital investment in the utility industry. Returns at the level proposed in recent complaints and calculated in the PG&E case send an unmistakable signal to the investment community that transmission investment is a less-favored use of capital. The recent numbers bandied about in FERC proceedings are lower than the returns provided by most of the states for investment in distribution. They’re also far lower than the returns typically allowed to natural gas pipelines under FERC regulation. One hopes FERC doesn’t believe that it can simultaneously promote transmission investment and drive allowed returns down to these levels.

Transmission, like breaking up, is hard to do. The level of difficulty was related recently during an informal presentation by a utility CEO, in which he described what his company went through when it proposed to build a relatively small transmission line in a populated area of his company’s service territory. He said the process took five years, during which his company lost the goodwill of the community as well as local and state politicians in pressing for approval for the line—a loss that he worried would come back to haunt the company in future rates cases, and when they needed local support for another project or initiative. In his words: “I had no choice. My transmission planners told me it was needed, but I wouldn’t do it again if there is any feasible alternative.” 

This problem might not be how risk is normally defined in the financial literature, but it’s a unique and substantial risk faced by most utilities that invest in electric transmission facilities. It’s one of the main reasons that the country suffered from decades of under-investment in transmission, and local opposition hasn’t abated. The FERC’s incentive pricing policy adopted several years ago, which provided for ROEs above those granted by most states for distribution, created an incentive for utilities to allocate capital to the transmission business and carry through on difficult projects. It began producing positive results. The cost associated with slightly higher ROEs is small in comparison with the benefits of new transmission, and so it’s hard to understand why FERC would back away from what has been a successful incentive policy. 

Order 1000

FERC’s most important ongoing transmission initiative is Order No. 1000, which creates obligations for transmission owners to engage in regional and interregional transmission planning. In a recent private conversation, a FERC staffer explained that FERC understood the limits of its authority to get transmission approved and built, but thought that putting in place a mandatory process in which transmission providers would be required to formally analyze regional and interregional transmission solutions and publish the results would provide a strong record for the need to build transmission and help the investment process overcome other political and regulatory obstacles. That, he said, was the heart of Order 1000.

The compliance process has been messy, however, and getting the requirements of the order into effect might take some time. Order No. 1000 is notable for the extent to which the commission gave the industry flexibility to comply with very broad directives. But experience shows that in most regions the largest share of the compliance process has been spent debating the ROFR issue, with fairly limited time spent focused on creating an effective process to accomplish the core objective the FERC staffer described. The ROFR issue, which upset a lot of people, hijacked the compliance process, making it more difficult to focus enough attention on what FERC was primarily trying to accomplish. 

As FERC enters the compliance phase, it needs to bear in mind that, unless regional and interregional planning processes themselves are effective—and carried out in good faith—the ROFR issue will be relatively less important, because without an effective plan, nothing will get built. FERC therefore should focus its compliance reviews on the regional and interregional planning processes themselves, the guts of how transmission needs and solutions will be identified, evaluated and resolved. Any process that doesn’t have the minimum essential steps of (i) formally identifying transmission needs for reliability, public policy and congestion, (ii) formally identifying and evaluating potential solutions to those needs, and (iii) publication of a determination of the best solutions, won’t provide much value to the industry.

In addition, FERC’s longstanding policy of requiring the functional separation of generation and transmission is proving to be less effective when applied to the issues that need to be addressed in successful interstate transmission planning. This is because generation policy choices drive transmission planning. So long as generation choices are based on uncoordinated regulatory policies in individual states, planning an efficient interstate transmission system will remain problematic. FERC attempts to deal with this issue by directing transmission owners to engage in regional and interregional transmission planning for public policy purposes. Many of the compliance filings, however, don’t do a good job of specifying how the applicable public policies will be identified for regional and interregional planning purposes, and the issue is fraught with political peril.

FERC’s authority in this area is limited, but the commission has already asserted jurisdiction over utility solicitations to acquire power at wholesale, which should include purchases of power to meet public policy needs. This jurisdiction might provide a vehicle for FERC to be more forceful in requiring more specificity in compliance with the order. Beyond public policy needs, Order No. 1000 provides no guidance on how other generation assumptions should be made on a regional and interregional basis, and this is likely to frustrate successful transmission planning. The issue highlights the problems created by unclear lines between federal and state jurisdiction over different components of the bulk power system.  

On cost allocation, the FERC has been saddled with a questionable decision from the Seventh Circuit7 that, together with political pressure, has limited its flexibility to address cost allocation issues without endless debates over cost responsibility in individual proceedings on single projects. From recent FERC decisions, it appears that FERC intends to push forward with modified versions of cost socialization and take on the fight with stakeholders who are demanding more precise measurements of transmission line benefits as part of the cost allocation process for individual projects. 

I believe it isn’t generally meaningful to assign cost responsibility for individual additions to the interstate AC transmission grid based on an ex ante calculation of relative benefits, and the process is almost certain to produce gridlock. New transmission facilities don’t operate in isolation; they’re enhancements to an existing interstate grid that provides myriad benefits across a large area. Most significant transmission lines enhance regional and interregional wholesale competition by creating opportunities for sellers and buyers to transact across broader areas, and these opportunities often aren’t identifiable until the new transmission is in operation and its impact can be evaluated by market participants. The generation and transmission topology will also change over time, producing different opportunities for use of the network during the life of a new facility. 

Proponents of calculating consumer price effects also focus too narrowly. Electricity costs in the selling region might not go down because of a specific project, but the economy in the selling region will benefit nonetheless through job creation. Reliability needs could be localized in some cases, but the economy as a whole (and the reputation of the industry) suffers when there’s an outage, and outages can cascade. Transmission lines constructed to improve the integration of renewables benefit all of society and not just the sellers and buyers of the power. If renewables didn’t provide broad societal benefits, one wonders why they should be built in the first place since they are usually more expensive than fossil-fueled alternatives.

Taking all of these factors into account in the cost allocation process simply isn’t feasible, and attempting to do so likely will produce process failure. Prof. William Hogan has argued otherwise,8 but I don’t agree with him because his definition of benefits is too narrow and he understates the difficulties of applying his proposed methodology. Moreover, the first approved line might provide greater benefits to one region, but the next one might provide greater benefits elsewhere.9 The interstate grid is a single machine, and we should enjoy its benefits on a shared basis and with a national outlook. 

My taxes helped pay for Interstate 90 in Colorado, and the taxes of Coloradans helped pay for Interstate 95 on the East Coast.  

Nevertheless, the core problem is that the nation hasn’t yet embraced the value of a national electric system, and this fact has limited the opportunities for new transmission investment. FERC’s efforts to promote transmission by providing a price incentive were beginning to work, but FERC seems to be backing off from those efforts in response to local pressure. FERC will need to be more aggressive in asserting its authority vis-à-vis the states in order to promote its vision of a highly efficient interstate bulk power system. The utility industry should get behind this effort—not only to reduce the cost and enhance reliability in the near term, but also because electricity delivered over the bulk power system, the core product of the electric industry, will face increasing competition in the future.


1. “PJM Grid Operator Plans Billions in Transmission Improvements to Meet Massive Generator Fuel Shift,” PJM News Release, March, 7, 2013.

2. Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure, Order No. 773, 141 FERC ¶61,236 (2012).

3. Renewable energy advocates shouldn’t welcome the governor’s position. The proposed legislation puts a cap on the increases in retail rates that will be permitted to integrate wind. This means substantially less green energy will be procured than would be achievable under a policy based on least-cost renewable generation. 

4. 16 U.S.C. §824s (2006).

5. Several years ago, FERC chose to require individual electric utilities to use the median of the range of reasonableness to establish ROEs, as opposed to the midpoint. Golden Spread Elec. Coop. Inc. v. Sw. Pub. Serv. Co., Opinion No. 501, 123 FERC ¶61,047 at pp. 62-64 (2008). This has generally produced much lower ROEs. FERC allows groups of utilities subject to a single ROE to use the midpoint of the DCF range of reasonableness. 

6. Pacific Gas & Elec. Co., Compliance Filing in FERC Docket No. ER12-1271-000, Dec. 21, 2012.

7. Ill. Commerce Comm’n v. FERC, 576 F.3d 470 (7th Cir. 2009).

8. “Allocating Costs Commensurate with Multiple Transmission Benefits,” PJM RPPTF Workshop presentation, June 8, 2012.

9. Cost socialization also could eliminate barriers to local approval of transmission lines. A local regulator might have more incentive to approve a line when the cost is being spread more broadly, and where the local regulator understands that local ratepayers are paying for a share of the costs of lines constructed elsewhere.