Grid Investment & Restructuring: Two Challenges, One Solution


FERC must align the immediate self-interest of profit-maximizing entities with its own view of what is in the public interest.

Fortnightly Magazine - August 2005

The utility industry is operating amidst a hodgepodge of market and non-market regulatory arrangements, but these quasi-competitive circumstances, even if politically tolerable, will prove economically inefficient and therefore detrimental to consumer interests. How can real markets promptly and responsibly be advanced? We see two main challenges.

The first challenge is to reverse a long-term underinvestment in transmission infrastructure. Although the nation's high-voltage electric transmission network properly is viewed as a "public good," investment in the grid is, and long has been, in trouble. The current uptick in construction of (mostly small) transmission projects and recent studies announcing that investor-owned utilities plan to ramp up transmission investments in the next few years1 do not alter that fact. Grid investment fell further and further behind the pace of growth in electricity demand during the past two decades2 —a potentially costly threat to the digital economy and the American standard of living. This infrastructure deficit has direct implications for the possibility of liquid wholesale power markets and reduced congestion costs, continued high levels of reliability, any prospect of achieving stable market institutions and regulatory arrangements, and least-cost economic dispatch of generation across the board.3

The second challenge is to improve upon the uncertain legal and regulatory environment within which the first problem must be solved. FERC's lack of success in inducing transmission investment with higher equity returns is part of a larger failure of federal law to more clearly delineate the appropriate scope of state and federal authority over the delivery of power and to set policy accordingly. Notwithstanding the Supreme Court's unequivocal support of FERC's authority over interstate transmission,4 about 90 percent of transmission revenues remain subject solely to state rate decisions. In other words, the bundling of transmission as an undifferentiated component of the delivery of electric energy to the end user effectively insulates most transmission usage from direct federal oversight and the potentially positive effects of federal rate policies. FERC's incentive returns simply do not have the intended effect on the investment decisions of integrated utilities whose facilities primarily serve native load.

Vertical integration of utility functions affords companies at least the opportunity to grant preferential treatment to their own energy marketing interests, contrary to FERC's decade-long campaign to de-monopolize the industry and introduce competition into wholesale power sales. Recognition of this potentiality may be ample justification for going beyond mere functional unbundling of transmission. However, the agency's prior efforts to mandate the elements of wholesale competition nationwide have encountered substantial and effective political and industry opposition, as demonstrated by the regrettable rebuke to standard market design and the tepid reception given regional grid managers in large regions of the country. As a result, FERC's determination to force profit-maximizing entities to act contrary to their immediate self-interest must now give way to an approach that redefines that self-interest to include an independent transmission sector that FERC generally has regarded as in the public interest.

The Critical Path

FERC presumably will, and should, continue its quest for fundamental change in integrated utility operations and for non-discrimination in the electricity marketplace. If it does so with any reasonable expectation of near-term success (which it currently lacks), its options are limited. Given its limited political capital and limited statutory authority to mandate a new market reality, FERC should instead use its rate policies to promote voluntary separation of transmission from generation, creating an independent, stand-alone business. That does not require a retreat from Order No. 2000 and regionalization or any moderation of its vigilant oversight of market behavior. But letting a thousand flowers (i.e., business models) bloom is merely a recipe for more uncertainty, market balkanization, and queasy investors. Choosing a more deliberate path that jump-starts a critical network business that will have no stake in who wins in the commodity markets effectively could address the two challenges discussed above. Left unresolved, those two problems either will slow progress in wholesale markets or stop it cold every time, for a long time.

Among the most formidable and most easily-identified obstacles to transmission planning and construction5  are state siting laws and local politics.6  Initially these seem like problems susceptible only to incremental solutions that do not fiddle with the industry’s structure. Yet, non-structural solutions have not met with success. Under Order No. 888 (and possibly its forthcoming update) and Order No. 2000, however, the power market forever was changed—and still transmission infrastructure languishes, in some places more than in others. The sorry state of transmission investment argues that additional measures be taken. Not surprisingly, FERC’s members seemed to acknowledge at its June 15 open meeting that the industry should  move in the direction of stand-alone, independent transmission companies (ITCs), whose sole business it is to produce and manage the most efficient delivery system for power. Despite discussion of elasticizing passive ownership requirements, the agency thus far has given only a tentative indication of how it might induce existing transmission owners and their state regulators to seriously consider repositioning transmission assets to make investment in that sector more attractive.7

Why ITCs?

As with RTOs, ITCs may stand a better chance of acceptance in regions where a tradition of multi-system coordination has facilitated regional planning and a system of sharing cost responsibility. In some instances, transmission-only companies have been given both the rate flexibility and the legal ability to address deficiencies in transmission investment successfully.8 ITCs already have shown they are well equipped to supply the strategic thought, capital, and management skills needed for transmission development. RTOs often labor under such complex policies and massive market administration responsibilities as to open themselves to criticism.9 Consequently, while RTOs will be suited for certain purposes, such as overseeing regional markets and transmission access, there is some question as to their ability to plan and implement capital-intensive projects. The investment strategies of vertically integrated utilities in non-RTO regions, on the other hand, may be suspect when financial opportunities and rate considerations favor not making infrastructure investments, especially of an interregional nature.10 Because ITCs will be regulated by a single federal regulatory authority, that small part of the overall cost of delivered power that transmission comprises will be more predictable to retail customers, who also should have access to more diverse suppliers as a result. Moreover, we do not perceive a threat to native load if the states and FERC work together to ensure no decline in service quality.

ITCs will need grid investment for growth. For sustained throughput, they require expanding energy markets and reduced congestion, as they continue to depend on regulatory approvals for siting and operations. They will make valuable new partners in regional planning processes, where such processes exist, and will be important proponents for renewable resources and other alternatives to new generation. Moreover, ITCs are a practical means of including all transmission facilities, including those of public power entities like large municipal utilities, G&Ts, and joint action agencies, within a single operating company.11

Finally, with ITCs, investors would be better able to assess the risks and rewards of the sector and to judge actual performance. The advantages of handing off management and development responsibilities, such as the siting of major facilities in what the Secretary of Energy calls "national interest corridors," to transmission companies that do nothing else are apparent in terms of motivation, accountability, expertise, and commitment to non-discrimination and markets.

If it intends markets to work, FERC must pick one direction and hold course, rather than let a thousand flowers bloom. As we discuss below, it already has the resources to encourage voluntary separation of transmission from other utility functions. In addition, Congress has supplied additional incentives to divest transmission to independent transmission companies by permitting deferral of capital gains from transmission divestiture for up to 8 years.12 Of course, across large commodity markets served by network facilities like electric transmission, it is both impractical and uneconomic to carve out systems or regions for exception. We nevertheless recognize that electricity markets vary, and that restructuring demands some flexibility. Nevertheless, there is no reason that ITCs cannot supply that flexibility.13

Specific Measures

What does FERC need to do? Because policy needs to follow facts, FERC first must cure the glaring data inadequacies regarding what transmission is being built, by whom, and for what purpose. With only limited exceptions, even after assembling information from NERC, trade associations, the Energy Information Administration, and the RTOs, no precise picture emerges of what transmission is being planned or built. FERC therefore needs to collect its own information upon which to make decisions in this area.

Second, FERC should revisit its independence criteria as applied to passive ownership of ITCs. No inducement to reorganize the transmission function will work if there are net losers. The current transmission owners should be allowed to retain passive ownership interests and participate financially in the new stand-alone network business, provided they have no control over the day-to-day operation of the system. FERC's significantly enhanced market oversight capability is a major reason why more liberalized ownership criteria can be employed without increasing the risk of abuse. In the final analysis, we believe the benefits of ITCs warrant significant creativity in this area. We believe that the success of American Transmission Company (ATC) provides a compelling case for flexibility on independence criteria. This company was created by the transfer of transmission assets from integrated electric utilities operating primarily in Wisconsin, in exchange for stock in the new company. The bargain, dictated by Wisconsin statute, puts in place independent management over a company that is 100 percent FERC-jurisdictional. The management proposed a set of investment incentives in FERC filings and then negotiated in settlement discussions with stakeholders a set of defined incentives that were approved by FERC. The company has been highly successful in raising capital and building substantial new transmission infrastructure in a region long characterized by substantial underinvestment.

Finally, a set of incentives must be designed to make transmission investment more attractive and enhance the market value of existing facilities. Naturally, an incentive applied to just 10 percent of an enterprise's revenues will fail to elicit results-hence the need for stand-alone transmission companies. On the other hand, it would not be in the public interest to afford transmission owners a premium disproportionate to the benefits they provide to consumers. Moreover, a set of cost-conscious consumers purchases energy and transmission separately. Transmission owners ignore them at their peril. We believe that in the context of clearly articulated incentives with strong support from FERC, practical accommodations with these vested interests will be achieved.

FERC's Rate Incentive Tools

FERC should establish or, as appropriate, unequivocally restate specific incentives that it will make available to any entity that qualifies as an ITC. These incentives should be open to any person that acquires transmission assets presently owned and controlled by a vertically integrated electric utility. The following incentives, most of which reflect established FERC ratemaking proceedings, are the minimum FERC should offer:

  1. A premium of 100 basis points in return on equity over the required cost of equity that would otherwise be dictated by FERC precedent;14
  2. The ability to use a hypothetical capital structure for a defined period of time;15
  3. Construction work in progress (CWIP) in rate base and an additional 50 basis points for new infrastructure development designed to produce a measurable reduction in transmission congestion;16
  4. Asset depreciation on shorter than historical lives;17
  5. Authorized creation of regulatory assets to the extent that pre-existing retail-rate orders prohibit the passthrough of the increased bulk transmission-service rate in retail rates, with a defined beginning date and a defined recovery period for amortization of the regulatory asset;18
  6. Use of a formula rate for bulk transmission service;19 and
  7. Inclusion of Mobile-Sierra language prohibiting either the transmission owner or transmission customers from seeking to change the approved rate for a defined period of time.20

These rate options could afford direct and quantifiable benefits to investors, not to mention a meaningful opportunity to reduce congestion by adding new transmission capacity. Congestion fragments service areas with often deleterious, temporal effects on the level of competition within the resulting sub-markets. FERC will need to ensure that new investment addresses this problem.

By now, it is apparent that the mere suggestion of "innovative rate treatments" in Order No. 2000 has elicited neither universal RTO participation nor sufficient transmission investment. The required showing of a cost-and-benefit analysis to support these "innovative rates" invariably are subjective and invite litigation over the adequacy of the supporting evidence, creating uncertainty and undercutting the incentive purpose of the policy. This is not to say that the FERC automatically must authorize all of the above incentives to any applicant that can satisfy the independence criterion. Incentives 1, 2, and 6 should be available presumptively to any such applicant, but the availability of incentive 1 would be subject to a demonstration that the company is eligible for a FERC-approved return on equity on the assets. FERC could provide additional certainty by establishing a baseline return on equity that need not be independently proved and to which the 100 basis premium would be automatically applied. For incentive 2 (use of a hypothetical capital structure), FERC could set a hypothetical capital structure that would apply for a certain number of years. For instance, a 50/50 structure based on the incentive return on equity and the actual cost of debt could be used and guaranteed to be available for five years.21 Incentive 6 requires no justification; FERC long has accepted formula rates that accurately reflect the elements of FERC ratemaking policy as just and reasonable rates. A notable variation on the usual formulation is that used by ATC, which employs a projected test year with an after the fact true-up of the projected to the actual costs experienced during the year. The use of such a formula is especially valuable to a utility with a heavy construction budget, like ATC.

The use of formula rates provides significant benefits both to the regulated utility and to its customers, with a significant reduction in rate-case expense, regulatory lag, and regulatory uncertainty, which has beneficial effects on cost of capital. The Midwest Independent System Operator (ISO) provides in its tariff a Formula O methodology for pre-approved use by its transmission-owning members. FERC recently encouraged PJM Interconnection to adopt a similar approach.

FERC previously authorized utilities to use CWIP in rate base when heavy capital requirements have threatened the ability of a utility to raise capital on reasonable terms. (See 18 C.F.R. § 35.25, which authorizes a utility to include 50 percent of CWIP in rate base under very specific circumstances and subject to strict showings.) It is noteworthy that there appear to have been no successful applicants to satisfy the requirements of this regulation. We therefore propose that CWIP be pre-authorized for independent transmission companies without a special showing of need, at least for an interim period. The need for additional capital investment at a level far exceeding recent levels is sufficiently established, such that the commission has a rational basis for such a rule. For example, ATC successfully included 100 percent of CWIP in rate base, pursuant to a company-specific modification of the Attachment O formula rate authorized for MISO transmission owners. FERC's approval was predicated on ATC reducing its ROE below the generically approved Midwest ISO ROE, limiting the CWIP treatment to construction that commenced after the filing of the rate proposal that was modified in the settlement, and forgoing the ability to file for rate incentives for new construction. While ATC bargained away an otherwise available premium to equity for new infrastructure development, the availability of enhanced returns for new investment remains a valuable inducement to the creation of ITCs. The 50 basis-point adder for new infrastructure is consistent with, and in fact less generous, than what FERC specifically has approved for Midwest ISO transmission owners.

In proposing CWIP for new infrastructure investment, we recognize that FERC will want assurance that the new facilities will be in the public interest. FERC therefore could make incentive 3 (CWIP in rate base) available under two alternative justifications. CWIP would be authorized if the planned transmission addition is proposed by an RTO, ISO, or regionally established transmission authority that reviews transmission additions as necessary for reliable service or to relieve congestion found to be uneconomic.22 It also would be authorized where the independent transmission owner identifies a level of congestion that it proposes to relieve, and seeks authority from the FERC to construct new infrastructure to relieve the congestion. In this situation, the ability to retain the incentive return and to retain the benefit of CWIP in rate base would be dependent on producing the projected level of savings. This approach is akin to performance-based ratemaking, which we discuss below.

Eligibility for incentive 4 (asset depreciation) would require a showing that new infrastructure is likely to have a shorter economic life than the observed historical service life of the infrastructure element. In Order No. 2000 FERC suggested that accelerated depreciation could be justified for new transmission infrastructure investment. We believe that this incentive is particularly important given that much new investment is warranted by the need to reduce congestion costs. As other measures may lessen the need for transmission investment for this purpose, such as demand-side bidding, distributed generation, and new power plant construction within congested areas, it is reasonable to conclude that economic life for such investment may be shorter than its historical life. We urge FERC to reject arguments that that prospect negates the need for accelerated depreciation. While these alternative measures cannot be implemented speedily, transmission infrastructure promises demonstrable benefits based on established technology. In such instances, FERC should not make the perfect the enemy of the good.

Incentive 5 (creation of regulatory assets) would be available in those situations where a valid state order otherwise would preclude the passthrough of the new owner's transmission charges, most often due to a retail rate freeze that applies to the retail rates of a bulk transmission service customer.

Finally, incentive 7 (Mobile-Sierra language) would be available to a new owner that desired a certain stream of revenues for a defined period of time. The purpose for this incentive is the expectation that certain investors might purchase the assets with a pre-determined investment horizon. We expect that certain stakeholders will decry any policy that would facilitate the entry of financial interests with relatively short-term investment horizons. Under normal circumstances, such objections would require careful consideration. Capital intensive industries such as the electric industry undeniably have benefited from long-term, stable capital sources. However, the present situation is not typical. There is a genuine need for expanded investment and valid policy reasons to create independent control. Under these circumstances, investors with short-term return objections can align their interests with valid regulatory objectives.

Performance-Based Ratemaking

Above, we mention a special kind of inducement to relieve congestion. The principle is simple: The regulated company proposes delivery of a measurable level of improved service in exchange for higher rates or a prescribed addition to the allowed equity return. Typically, the return on equity incentive is achieved by moving the allowed return to the upper end of the zone of reasonableness. If the promised level of performance is delivered, the company retains the rate incentive. If the promised delivery improvement is not produced, the rate increment is returned to the ratepayers through retroactive or prospective rate adjustment. Performance-based ratemaking typically requires that the company also accept a downside risk, requiring a refund below the otherwise allowable return if performance falls below a predetermined level.23

The example described is predicated on a reduced level of incurred congestion costs, but other performance targets also could be used, such as reduced maintenance time or lower forced outage rates, both of which should reduce congestion-related generation costs.

FERC has had virtually no success in obtaining proposals for performance-based rates. The reasons for this are not clear, but part of the problem may be that reduced congestion costs could entail a net loss to the current integrated utility transmission owner, if it is the owner's generation that benefits from out-of-merit order dispatch. An ITC will have no motivation to perpetuate historical congestion patterns, especially if the ITC directly is compensated for reducing congestion and out-of-merit order dispatch costs. The current state of bifurcated jurisdiction over transmission and the absence of adequate investment incentives both appear to have a major role in discouraging transmission investment. We believe that the promotion of ITCs remove a major disincentive to develop performance-based rates.

The policies we advocate are all about making the most of FERC's somewhat defensive regulatory posture. Current holders of wholesale transmission rights certainly will object that any increase in present rates is but a windfall to investors, even though allowed returns on transmission investment have not attracted the needed capital investment up until now. FERC needs to pull out the stops-perhaps for a limited time-with respect to returns on investment, cost-recovery opportunities, and ownership structure. The allocation of the resulting costs always can be worked out in rate cases. We understand that rate adjustments, however small, and jurisdictional realignments always are fought over. But FERC either must make the case for the economic value, as well as the competitive virtue of ITCs, or indefinitely endure the uncertainties and lack of policy resolution associated with mixed or directionless wholesale power markets.


  1. Edison Electric Institute, EEI Survey of Transmission Investment: Historical and Planned Capital Expenditures (1999-2008). EEI’s survey finds (based on a sample of utility capital budgets) that investor-owned utilities plan to spend $28 billion on transmission between 2004 and 2008.
  2. Eric Hirst, U.S. Transmission Capacity: Present Status and Future Prospects, for EEI and the U.S. Department of Energy (June 2004). Hirst cites various estimates of the amount of investment needed in the next decade to correct for underinvestment, ranging from $27 billion to $100 billion. For the causes and implications of increasing transmission congestion, see North American Electric Reliability Council (“NERC”), 2004 Long-Term Relibability Assessment: The Reliability of Bulk Power Electric Systems in North America, at pp. 33-46.
  3. Transmission Independence and Investment (Docket Nos. AD05-5-000; PL03-1-000)(hereinafter “Technical Conference”). See also, Federal Energy Regulatory Commission (“FERC”), Office of Market Oversight and Investigations, 2004 State Of The Markets Report, June 2005, at p. 26-28 (“Market Report”).
  4. New York v. FERC, 535 U.S. 1 (2002). The Court majority observed that, even though FERC had discretion to decline to regulate the transmission component of a bundled retail power sale, it believed that FERC could (indeed should) have exercised its full Federal Power Act authority over transmission since  competitive interstate power markets were the objective of its principal electric rulemakings. We note that, on average, about 10 percent of the cost of delivered retail energy is transmission.  
  5. Underinvestment probably has many causes—low returns, the competition for capital within utilities, large upfront costs, regulatory uncertainty, lack of state cooperation, or a perception that projects have no societal benefits. See, e.g., Testimony of  Dr. Brendan Kirby, Oak Ridge National Laboratory, Technical Conference (Transcript, p.16).
  6. Perhaps the most widely recognized obstacle to expansion of the transmission system is state-siting regulation, which can be used to frustrate construction of projects in sensitive areas or can cause undue burden and delay for facilities planned for multiple jurisdictions.  Congress is therefore likely to give FERC authority to effectively preempt state siting laws in circumstances of inordinate delay. No states have tried to consolidate approvals of the multi-state lines through interstate compacts, although innovative multi-state planning is becoming more prevalent in RTOs and on the non-RTO West.
  7. Policy Statement Regarding Evaluation of Independent Ownership and Operation of Transmission, 111 FERC ¶61,473 (2005).
  8. A case in point is American Transmission Co. (“ATC”). Madison Gas & Electric Co., et al., Order Authorizing Disposition of Jurisdictional Facilities, 93 FERC ¶61,215 (2000). We believe that, while ATC has not been found to satisfy specific independence criteria, it has delivered the benefits expected of ITCs.
  9. For example, A Special Report of the Problems in the Organized Markets, (2005).
  10. FERC’s recent Market Report states (at page 28) that stand-alone transmission companies in the Midwest “continued [in 2004] to pursue investment levels that far exceeded what they had pursued when they were part of integrated utilities and far exceeded the 3 percent investment planned by investor-owned utilities.”
  11. See, e.g., TRANSLink  Transmission Co. LLC., et al., 99 FERC ¶ 61,106 (2002).
  12. American Jobs Creation Act of 2004, Pub. L. No. 108-357, sec. 909, 118 Stat. 1476. The U.S. Senate Finance Committee is now considering extending for an additional year (until January 1, 2007) the deadline for closing eligible transactions.
  13. We note that the operation of the massive transmission systems of the Tennessee Valley Authority, Bonneville Power Administration and other PMAs lies outside FERC jurisdiction. Congress should consider disaggregation of those taxpayer-subsidized operations as well.
  14. See ITC Holdings Corp, et al., 102 FERC ¶61,182, P 68 (2003).
  15. See Offer of Settlement filed in Docket Nos. ER01-677-00 and ER01-1577-000, proposing transmission rates for American Transmission Co., accepted by a letter order reported at 97 FERC ¶ 61,139 (2001).
  16. See  American Transmission Company LLC, 107 FERC ¶ 61,117 (2004).
  17. The principle is that an asset may have a shorter economic life than principal life.
  18. See ITC, 102 FERC at PP 69, 74.
  19. FERC has long accepted formulae that accurately reflect FERC ratemaking principles as a "just and reasonable rate."
  20. The use of such language, when agreed by affected parties, is common place in FERC practice.
  21. Note that in ITC, FERC authorized the use of a capital structure comprised of 60 percent equity, a level higher than typical for regulated utilities.  FERC accepted the applicant’s assertion that the nature of the investment required the return offered by such a capital structure. See ITC, 102 FERC at PP 64, 68.
  22. By “uneconomic,” we mean that the level of transmission congestion produces out-of-merit order dispatch costs that would make the annual cost of the transmission expansion less costly than projected annual incurrence of the out-of-merit order dispatch costs. The cost of the transmission expansion could be assigned to identified beneficiaries or rolled in, depending on whether the projected cost savings were predominately limited to a defined set of users or predominately general to all users.
  23. For more detail on these concepts, see “Independent Transmission Companies: The For-Profit Alternative in Competitive Electric Markets,” Stephen Angle and George Cannon, Jr., 19 Energy L.J., 229 (1998).