Transmission Incentive Overhaul


FERC’s ROE incentive adder policy sends the wrong signals.

Fortnightly Magazine - February 2009

Since mid-2006, the Federal Energy Regulatory Commission (FERC) has responded to a Congressional directive by considering—and, generally, approving—scores of public utility requests for “incentive” rate treatment of new transmission investment. Recently, FERC has been ruling on incentive rate applications on an almost assembly-line basis. Between September 1 and December 4, 2008, FERC issued nearly a dozen separate incentive rate orders approving requests for hundreds of millions of dollars in incentives. But FERC must confront, directly and consistently, serious flaws in its emerging policy regarding one category of incentive: return on equity (ROE) incentive adders.

The need to delineate when and to what extent ROE adders are appropriate is more urgent than ever. Current transmission plans include billions of dollars in proposed new projects. The Obama Administration has promised to “moderniz[e] the grid,”1 while interest groups have called for new facilities to interconnect renewable generation resources.2 Unless FERC applies more focused guidelines, the ROE incentive regimen will function largely as a windfall for transmission owners and, worse, won’t encourage cost-efficient construction and maintenance of transmission systems.

Incentive Rate Regimen

In Section 219 of the Federal Power Act (FPA), 16 U.S.C. § 824s, enacted as part of the Energy Policy Act of 2005,3 Congress addressed concerns about under-investment in transmission infrastructure. While assuming for purposes of this article that certain incentives may be needed to promote transmission construction, at the time Section 219 was enacted there was evidence suggesting the industry already had begun to remedy past under-investment. The Edison Electric Institute’s 2005 “EEI Survey of Transmission Investment”4 found:

• “[T]he industry has reversed a long-standing downward trend in transmission investment,” id. at 3;

• “[T]ransmission investment, in constant dollars, declined from 1975 through 1998[, but]… has been increasing since 1999,”id.;

• “Over the 1999-2003 period, transmission investment increased at a 12 percent annual rate,” id.; and

• Planned investment for 2004-08 was 62 percent of 2003 net book value, reaching “levels not seen in nearly 30 years,” id. at 5.

EPACT 2005 nonetheless directed FERC to establish, by rule, “incentive-based (including performance-based) rate treatments for the transmission of electric energy[,]” in order to “benefit consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion.” Among other things, Congress directed FERC to provide incentives that promote “reliable and economically efficient transmission” and to offer ROEs that will attract new transmission investment. Congress also instructed FERC to encourage deployment of transmission technologies and other measures to improve the capacity, efficiency, and operations of existing facilities. However, FERC’s discretion to adopt incentives was limited. FPA Section 219(d) provided that all incentive rates would remain “subject to the requirements of [FPA] sections 205 and 206” and must be “just and reasonable and not unduly discriminatory or preferential.”

In its rulemaking proceeding,5 FERC announced its incentives regimen and a new set of procedures, codified at 18 C.F.R. § 35.35. FERC did not “grant outright any incentives to any public utility,” but instead “identif[ied] specific incentives that the Commission will allow when justified in …individual declaratory orders or section 205 filings.” Order No. 679 lists potential incentives—including recovery of 100 percent of construction work in progress (CWIP) payments, hypothetical capital structures, accelerated depreciation, recovery of abandoned plant costs, and incentive ROE adders—and allows applicants to propose combinations that best match their circumstances.

In adopting an incentive rate program, FERC acknowledged the need to balance consumer and investor interests and to ensure that incentives would be based on project-specific evidentiary showings. Thus, FERC determined that applicants must demonstrate a “nexus,” or linkage, between a proposed incentive and demonstrable risks and challenges faced by the applicant. FERC also concluded that multiple incentives would be approved only if the “incentive package as a whole results in a just and reasonable rate,” subsequently noting that “[i]f some of the incentives in the package reduce the risks of the project, that fact will be taken into account in any request for an enhanced ROE.”

While declining to enumerate specific incentive-worthy project types, FERC explained that the “most compelling case for incentives are new projects that present special risks or challenges, not routine investments made in the ordinary course of expanding the system to provide safe and reliable transmission service.” For example, FERC stated that large interstate transmission projects can face substantial and unique risks. Moreover, FERC asserted, such projects are built only at the election of investors, as no single entity is required to undertake them, thus rendering an incentive-based ROE appropriate to encourage proactive behavior. In contrast, FERC noted that routine investments “have [generally] been adequately addressed through traditional ratemaking because there is an obligation to construct them and high assurance of recovery of the related costs.” FERC also observed that “formula rates can provide the certainty of recovery that is conducive to large transmission expansion programs.” But even for investments that do not require enhanced ROEs, FERC observed that other incentives (such as 100 percent CWIP recovery) may remain appropriate.

Incentive Rate Regimen in Practice

FERC’s rate incentives program has not functioned as laid out in its rulemaking orders. Although FERC denied establishing a lenient test for incentives and vowed not to “provide incentives that only serve to increase rates without providing any real incentives to construct new transmission infrastructure[,]” in practice it has granted requested incentives, including enhanced ROEs, almost routinely. Moreover, FERC has done so (often on a 3-2 vote) based on highly general “nexus” findings that appear at times to lack substantive content. The approved ROE adders have been substantial, including some as high as a 2 percent or 200 basis points.6 While FERC caps any approved ROE incentive adder at the top of the zone of reasonableness, this doesn’t per se establish that the ROE in any individual proceeding is reasonable.7 More generally, regulation seeks to ensure that reliable service is provided at the lowest, and not the highest, reasonable rate.8

FERC has awarded substantial ROE adders notwithstanding the concurrent approval of CWIP and abandoned plant incentives or the presence of other risk-mitigating factors.9 While it has sometimes reduced the ROE adder to reflect approval of the other incentive rate treatments, generally by 25 basis points (from 150 to 125 basis points),10 it has not adequately explained why any adder, let alone 125 basis points, is appropriate.11 The presence of a formula rate, which Order No. 679 acknowledged as reducing transmission owner risk, has since been deemed irrelevant.12

Likewise, while Order No. 679-A (P 122) stated that a “prior contractual commitment or statute may have a bearing on our nexus evaluation of individual applications[,]” FERC has awarded ROE adders in spite of them.13 FERC also has awarded ROE adders for projects that, while substantial, address basic system-reliability concerns. As an example of both phenomena, National Grid and Northeast Utilities sought a battery of incentives for their “New England East-West Solution” (NEEWS) Project, which involves additions to the 345-kV system in three states to address identified transmission reliability issues. FERC granted the requested CWIP and abandoned plant protections and, on that basis, a reduced ROE adder of 125 basis points (down 25 points from the requested 150).14 In NEEWS, Order P 69, FERC justified these incentives based on financial, regulatory, and environmental risks, and internal competition for project financing. However, FERC explained neither how approval of the ROE adder would address those concerns nor why such an enormous adder was justified in the face of the other approved incentives.15

Nor did FERC explain why an incentive ROE is justified when the applicants already were obliged to construct the project, both through contractual arrangements associated with the formation of RTO New England and because the project addresses system-reliability issues. While FERC dismissed the latter concern on the ground that Section 219 “specifically authorizes incentives for transmission projects that ensure reliability,”16 the statute doesn’t specify the particular incentives to be made available for such projects, which may be more effectively and appropriately encouraged through advanced technology adders, CWIP recovery, or abandoned-plant protections. Section 219 likewise doesn’t direct FERC to authorize enhanced ROEs for projects that applicants must build under existing RTO agreements and planning procedures.

Moreover, while enhanced ROEs are awarded in part to address perceived siting difficulties, it’s not obvious increased ROEs will eliminate or even mitigate such challenges. Raising a project’s price tag doesn’t make it easier to gain siting approval. If FERC’s theory is that a higher ROE encourages recipients to resolve environmental concerns or to overcome other siting barriers, then FERC should require applicants to identify specific barriers to be overcome and explain how an enhanced ROE will aid the company in overcoming them. If FERC is to follow through on its assurance that it would allow only “real incentives to construct new transmission infrastructure” and not “incentives that only serve to increase rates without” materially enhancing the probability of construction, as Order 679 specifies, then ROE-incentive applicants should be required to specify what steps they would take for an enhanced ROE that they would not pursue for a “normal” one.

Similar concerns arise when awarding ROE adders to address financing risks. Higher returns always will be more attractive to external investors and more successful in competition for internal capital. But that proves too much and doesn’t justify routinely awarding transmission owners enhanced ROEs near the top of the range of reasonableness. While the purpose of both Section 219 and FERC’s rulemaking was to encourage cost-effective transmission expansion bolstering reliability and reducing delivered power costs, higher returns will not achieve these objectives unless they are targeted at real impediments to transmission construction. There is no evidence that transmission construction has been impeded because the baseline ROEs applied to completed projects in rate base are too low, or that baseline ROEs will be insufficient to encourage new transmission investment once other risks are addressed by other incentives. Legitimate cash-flow concerns during construction can be addressed through permitting recovery of CWIP. Concerns that a project may not gain siting approval, leaving investors responsible for unrecoverable project development costs, can be addressed through abandoned plant protections. Concerns about the timeliness of rate recovery should be assuaged where formula rates are present. None of these factors justifies ladling an enhanced ROE on top of project costs.

Incentive Rates: The Road Ahead

FERC should address several questions concerning ROE incentives adders. Most fundamentally, it should delineate, through the adoption of objective incentive-ROE eligibility criteria, the risks associated with, and the performance expected from, transmission owners under commission-approved base ROEs.

ROE adders aside, customers and FERC should expect transmission companies to plan, construct, operate, and maintain their systems in accordance with applicable reliability criteria, including periodic assessments of system reliability and timely pursuit of basic system upgrades. The commission said as much in a pre-incentives regimen decision rejecting a proposed transmission incentive program that would have “unjustly reward[ed a transmission owner] for doing what it’s supposed to do, i.e., to adequately maintain its facilities in a prudent, cost-effective manner.”17 Likewise, customers and FERC should expect transmission owners to follow through, without additional incentives, on prior commitments to build new transmission facilities. Such commitments may include obligations to build facilities identified as needed through regional planning processes under an RTO tariff, conditions on FERC approval of dispositions of jurisdictional assets, or obligations undertaken in satisfaction of state regulatory requirements.

Where investment is truly optional, FERC should consider carefully whether enhanced ROEs are necessary to induce it. ROE adders should be available only where optional investment involves a risk of loss that: A) goes beyond the risks reflected in the base ROE; and B) is not eliminated by other granted incentives, such as inclusion of CWIP in rate base or recovery of abandoned-plant costs. Where FERC approves an ROE adder, it should support that determination with factual findings about how the enhanced ROE will help overcome project risks and why the ROE adder was set at the specific level chosen.

FERC also should explain fully why ROE adders are appropriate where they are part of a package of incentive rate treatments or where other risk-mitigating factors (such as formula rates) are present. While FERC’s rulemaking orders opined that transmission owners might not be eligible for any ROE adder when CWIP and abandoned-plant protections are granted, in practice FERC has reduced ROE adders only slightly (and inconsistently) in light of the grant of such incentives. Indeed, FERC since has rejected the notion of generic ROE-adder reductions in such cases,18 and the question whether any ROE adder is justified (and not one that is simply reduced from 150 to 125 basis points) has been raised only in dissenting opinions. Similarly, FERC has deemed irrelevant whether costs are recovered pursuant to a formula rate.

While Congress directed FERC to “establish … incentive-based (including performance-based) rate treatments” and to “provide a return on equity that attracts new investment in transmission facilities,” [see FPA §§ 219(a), (b)(2)] that doesn’t mean an ROE near the top of the zone of reasonableness is appropriate in every case—or even most cases. Indeed, FERC’s emerging policy toward incentive ROE adders for new transmission facilities may have serious unintended, adverse consequences. First, transmission owner investment is not an end in itself. The Congressional and regulatory goal is construction of “economically efficient transmission” for the purpose of “ensuring reliability and reducing the cost of delivered power,” (id., §§ 219(a), (b)(1)), but overly generous ROEs may impede those goals—particularly where state regulatory authorities (including siting authorities) oppose new transmission that would allow low-cost resources to be exported out-of-state. Increasing the cost of such transmission facilities by awarding incentive ROEs will make it even harder to obtain the necessary state approvals. In other words, increasing the cost of new transmission (by what can amount to hundreds of millions of dollars over the life of a facility) can be expected to incentivize both transmission owner investment and opposition to the project.19

There also is a concern that FERC’s current approach to determining when an ROE adder will be granted creates perverse incentives. A major factor in the commission’s decisions about whether to approve an incentive ROE has been the scope of the project(s) at issue. FERC has explained that assessment of project scope involves “factors such as size, dollar investment, increase in transfer capability, involvement of multiple entities or jurisdictions, and effect on the region” and that applicants must present “data distinguishing the project from other transmission projects or upgrades that are constructed in the ordinary course of maintaining a utility’s transmission system.”20 FERC has encouraged submission of data comparing “total investment in a range of projects to some other aggregate measure of investment, such as total rate base or recent annual investment levels,” and it has held that groups of projects that are routine when considered individually may be treated as non-routine in the aggregate. (Id.) Thus, applicants frequently tout the magnitude of investment(s) at issue, particularly in contrast to historical levels.21

The magnitude of investment should not be a basis for determining whether an incentive ROE is justified, at least not without a searching inquiry into whether the need for a large investment could have been avoided through steadier, incremental investments. Absent such an inquiry, a policy favoring enhanced, incentive ROEs for large projects encourages transmission owners to manufacture crises needing big solutions and perhaps to short-change what should be routine activities. Unfortunately, FERC has exacerbated this problem by rejecting assertions that current needs have resulted from past under-investment, for which a transmission owner ought not to be rewarded, and concluding instead that the timeliness of an investment response is irrelevant.22 A timeliness requirement should be established.

Where the scope of the project for which an incentive ROE is sought appears to be a function of past under-investment, the commission should seek to eliminate the immediate disincentives to fixing the problems created by past under-investment, but without rewarding that behavior or encouraging similarly dilatory behavior going forward. Thus, in such situations, the commission may include 100 percent of CWIP in rate base (thereby bolstering cash flow during construction), and may provide abandoned-plant protection (thereby ensuring against a risk of loss in case the project is canceled for reasons beyond the applicant’s control), but should deny ROE adders for projects that merely make up for past under-investment leading to imminent reliability violations. Moreover, to ensure that internal capital goes where it’s needed, FERC should deny ROE adders for other projects by the same applicant until its transmission system is brought up to a reasonable baseline reliability level.

More generally, linking higher ROEs to the magnitude of proposed transmission projects may hit consumers with a quadruple punch. First, large investments result in large depreciation expenses. Second, linking higher ROEs to the magnitude of investment produces non-linear increases in the ROE component of transmission rates, as additional investment increases both rate base and the rate of return applied to rate base. Third, linking higher ROEs to the magnitude of project costs encourages inflated cost estimates (justifying higher ROEs) and the incurrence of actual cost over-runs (which inflate rate base, subject only to notoriously difficult-to-mount prudence challenges). Fourth, widespread reliance on incentive ROEs for large transmission projects creates a feedback loop that threatens to increase base ROEs. In Order No. 679-A (P 62), FERC “reject[ed] the contentions of certain customer groups that incentive ROEs [would] ‘destabilize’ the DCF methodology,” finding that “any incentive ROEs granted under 219 should have a minimal effect,” because “the ‘cash flows’ being measured in the DCF method are the cash flows of entire companies,” which “should not be significantly affected by an incentive return for any particular transmission project.” But projects like the Maine Power Reliability Project, which will increase CMP’s plant in service six-fold, contradict that assumption, and reliance on project size to justify higher ROEs simply magnifies that feedback problem.

Finally, in acting on incentive-rate applications, FERC nominally considers whether a proposed project would improve reliability or reduce congestion. What major transmission project would fail to accomplish one or the other, if not both? But thus far it’s refused to inquire into whether the project would achieve those ends cost-effectively. Indeed, in FERC’s view, such cost-benefit inquiries are themselves disincentives to transmission investment.23 This is bad policy, and its impacts will get worse over time. Transmission investment reduces congestion but will not eliminate it, because resolving one bottleneck generally unmasks another latent one elsewhere on the grid. Attempting to eliminate every bottleneck (and paying incentives for efforts to do so) would be tantamount to undertaking an impossibly expensive game of “Whac-A-Mole.” Likewise, transmission systems built to withstand N-3 contingencies would be more reliable than those built to withstand N-1 or N-2 contingencies, but achieving such levels of reliability is generally not cost-effective and has not been attempted. Unfortunately, nothing within the four corners of FERC’s incentive-rate policy precludes granting incentive ROEs for such efforts. FERC’s exclusive focus on whether a transmission project will produce benefits, without considering whether those benefits are worth the cost, leaves the incentive-rate bus without any brakes.

FERC should consider introducing a cost-benefit component into its incentive-rate analyses. Cost-benefit evaluation is necessary to avoid incentivizing over-investment in transmission, and is consistent with Section 219. That section doesn’t require FERC to “promot[e] capital investment” without regard for whether such investment is cost-effective. Rather, it requires the commission to promote “economically efficient transmission” that will “reduce the cost of delivered power” (see FPA §§ 219(a), (b)(1)). FERC’s unchallenged authority to consider non-cost factors in setting transmission rates should not be confused with a much more extreme proposition: That FERC may ignore cost-benefit considerations while fulfilling its duty to ensure just and reasonable rates under FPA Sections 205 and 206.

While quantifying reliability benefits and conducting cost-benefit analyses may be difficult, the perfect should not be the enemy of the good. FERC should attempt to do so, because the effort would bring much-needed focus to the attempt to reach reasoned decisions on transmission incentive-rate applications. In the meantime, the commission should begin by tying incentive ROE adders to applicants’ meeting of project cost and deadline targets. For example, applying incentive ROE adders to budgeted, rather than actual, expenditures would avoid exacerbating incentives to bring in new transmission projects at the maximum prudent cost that will be allowed in rate base. Significantly, applying enhanced ROEs only to budgeted amounts imposes no risk of loss on the public utility. Above-budget but still prudent amounts would continue to be placed in rate base and earn a normal return. Moreover, if a public utility believed that cost-overruns experienced in a given case were truly outside its control, the public utility could make a later Section 205 filing seeking to earn an enhanced ROE on the full cost of the project. Linking enhanced ROEs to an applicant’s ability to construct new transmission facilities on time and within budget (absent factors outside its control) is nothing more than straightforward compliance with Congress’s command that FERC “shall establish … incentive-based (including performance-based) rate treatments,” [FPA § 219(a)] (emphasis added), a requirement with which the commission has not yet even attempted to comply.



1. See Barack Obama and Joe Biden: New Energy For America at 8, available at

2. Broad Coalition Shaping Grid Upgrade Plan Aimed At Congress, Obama,” ENERGYWASHINGTON WEEK (Dec. 3, 2008).

3. Pub. L. No. 109-58, 119 Stat. 594 (2005) (“EPACT 2005”).

4. Available at

5. Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 Fed. Reg. 43,294 (July 31, 2006), [2006-2007 Regs. Preambles] F.E.R.C. Stat. & Regs. ¶ 31,222 (“Order No. 679”), on reh’g, Order No. 679-A, 72 Fed. Reg. 1152 (Jan. 10, 2007), [2006-2007 Regs. Preambles] F.E.R.C. Stats. & Regs. ¶ 31,236 (“Order No. 679-A”), clarified, 119 F.E.R.C. ¶ 61,062 (2007) (“Order No. 679-B”)

6. E.g., Pac. Gas & Elec. Co., 124 F.E.R.C. ¶ 61,305 (2008); N.Y. Reg’l Interconnection, Inc., 124 F.E.R.C. ¶ 61,259 (2008).

7. The Commission has made clear that not every rate within the zone is per se just and reasonable. Bangor Hydro-Elec. Co., 122 F.E.R.C. ¶ 61,038, P 11 (2008).

8. Louisville Gas & Elec. Co., 62 F.E.R.C. ¶ 61,016, at 61,143 (1993) (“One of the Commission’s primary regulatory goals is to ensure the lowest, reasonable cost energy to consumers, consistent with reliable service.”). The same standards are applicable to ISOs and RTOs. ISO New England Inc., 118 F.E.R.C. ¶ 61,105, P 21 (“ISO-NE … seeks only to provide reliable service at the lowest reasonable cost.”), reh’g denied, 120 F.E.R.C. ¶ 61,122 (2007); PJM Interconnection, LLC, 119 F.E.R.C. ¶ 61,063, P 6 (2007), reh’g denied, 122 F.E.R.C. ¶ 61,082 (2008). See also Atl. Ref. Co. v. Pub. Serv. Comm’n, 360 U.S. 378, 388 (1959) (Natural gas “shall be sold in interstate commerce … at the lowest possible reasonable rate consistent with the maintenance of adequate service in the public interest.”).

9. E.g., Pepco Holdings, Inc., 125 F.E.R.C. ¶ 61,130 (2008); Duquesne Light Co., 123 F.E.R.C. ¶ 61,139 (2008).

10. E.g., Centr. Me. Power, 125 F.E.R.C. ¶ 61,079 (2008); Ne. Utils. Serv. Co., 125 F.E.R.C. ¶ 61,183 (2008) (“NEEWS Order”); PPL Elec. Utils. Corp., 124 F.E.R.C. ¶ 61,229 (2008); S. Cal. Edison Co., 123 F.E.R.C. ¶ 61,293 (2008).

11. The few instances in which the Commission has denied an ROE adder have been situations in which the Commission has denied any incentive treatment of the project at issue. Commonwealth Edison Co., 119 F.E.R.C. ¶ 61,238 (2007), on reh’g, 122 F.E.R.C. ¶ 61,037 (2008), on reh’g, 124 F.E.R.C. ¶ 61,231 (2008) (no incentives for project that was completed before incentives were requested); Commonwealth Edison Co., 125 F.E.R.C. ¶ 61,250 (2008) (no incentives for project that does not meet “nexus” or “advanced technology” requirements). NSTAR Electric Co., 125 F.E.R.C. ¶ 61,313 (2008) (same).

12. Compare Order No. 679 P 386 with Cent. Me. Power Co., supra.

13. E.g., Cent. Me. Power Co., supra, P 45; Ne. Utils. Serv. Co., 124 F.E.R.C. ¶ 61,044, P 89 (2008). The Commission previously approved (by a 3-2 vote) an across-the-board, 100 basis point ROE adder for any new transmission project included in ISO New England’s regional system plan, notwithstanding that the region’s transmission owners were under an express contractual obligation to construct all such facilities. The decision is now before the D.C. Circuit. Conn. Dept. Pub. Util. Control v. FERC, No. 08-1199 (D.C. Cir. filed May 23, 2008).

14. NEEWS Order, supra.

15. Protestors asserted that the requested 150-point adder would cost customers between $370 million and $400 million over the estimated 30-year life of the project. NEEWS Order P 72. Based on those figures, a 125-point adder would cost between $300 million and $333 million over that period.

16. Cent. Maine Power Co., supra, P 59 (footnote omitted).

17. New England Power Pool, 97 F.E.R.C. ¶ 61,093, at 61,477 (2001), on reh’g, 98 F.E.R.C. ¶ 61,249 (2002).

18. Tallgrass Transmission, LLC, et al., 125 F.E.R.C. ¶ 61,248, P 61 (2008).

19. Ironically, the net result may be to increase the probability of project abandonment and the magnitude of costs to be recovered under abandoned-plant incentives.

20. Baltimore Gas & Elec. Co., 121 F.E.R.C. ¶ 61,167, P 28 (2007) (“BG&E”), reh’g denied, 123 F.E.R.C. ¶ 61,262 (2008); Baltimore Gas & Elec. Co., 120 F.E.R.C. ¶ 61,084, P 53 (2007), reh’g denied, 122 F.E.R.C. ¶ 61,034 (2008).

21. See Cent. Me. Power Co., supra, P 55 (“Over the last five years, Central Maine has spent approximately $17 million annually on transmission projects,” whereas the project will “require an average annual investment of nearly $280 million” and will increase six-fold the company’s total plant in service).

22. Id. PP 47, 56 (rejecting argument that massive investment needs were self-imposed and holding that “[t]here is nothing in Order No. 679, Order No. 679-A, or subsequent Commission precedent that requires an applicant for incentives to show that it … addressed reliability concerns in a ‘timely fashion.’”).

23. Order No. 679-A P 37 n.59 (“We believe that the requirement of a cost benefit analysis [for innovative rate treatment under Order No. 2000] was perceived as an insurmountable hurdle which inhibited the utilities from seeking innovative rate treatments.”)