By RTO Insider Staff

FERC’s request for comments on its transmission incentives produced predictable splits between transmission owners and load interests, as well as calls for new policies to increase the efficiency of existing lines and mandates on interregional planning.

Dozens of entities submitted comments in response to the Notice of Inquiry the commission opened in March. The commission asked whether it should change its method of calculating returns on equity for electric transmission and natural gas and oil pipelines (PL19-4). It also solicited input on whether transmission adders should continue to be granted based on a project’s risks and challenges or the benefits that it provides (PL19-3). (See FERC Opens Inquiries into Tx Incentives, ROE Policies.)

Below, based on RTO Insider’s review of more than 50 of the comments, is a summary of the feedback FERC received.

TOs Support Incentives

Since it issued Order 679 in 2006, FERC has granted adders to base transmission ROEs for a variety of reasons, including the formation of a transmission-only company (transco) and joining an RTO or ISO. It also has permitted recovery of 100% of prudently incurred costs for projects canceled because of factors that are beyond the TO’s control.

TOs generally supported the current incentives, with some, such as Consolidated Edison and Eversource Energy, saying the abandoned plant incentive and including 100% construction work in progress (CWIP) in the rate base should become automatic and no longer discretionary on FERC’s part. Eversource said removing any incentives would be an unfair “bait and switch.”

Con Ed said recent transmission rate settlements for public policy transmission projects proposed by New York Transco and NextEra Energy Transmission New York illustrate that incentives can be a cost management tool. The two companies will receive incentives depending on how much they are able to reduce costs below project estimates. “The settlements also include disincentives should the projects’ final costs exceed the project cost estimates,” Con Ed said.

WIRES, whose members include TOs and transmission equipment makers, said the current incentives “are potentially not sufficient to support the level of infrastructure investment and development the nation is likely to need.” It called for additional incentives for projects aiding resilience, energy storage and advanced technologies for existing facilities.

Load: Prune Incentives

Load interests generally opposed expanding the incentives, with some, such as the Oklahoma Corporate Commission’s Public Utilities Division, urging the elimination of the risks-and-challenges and transco adders.

Massachusetts Municipal Wholesale Electric Co. (MMWEC) and New Hampshire Electric Cooperative filed joint comments calling for the end of the RTO membership adder, as it is “no longer just and reasonable.”

The Organization of MISO States said adders should only be granted in “extraordinary circumstances and for specific projects.” The organization said it worried that “overly incenting” transmission construction might lead to planners overlooking non-transmission alternatives. “The commission should reduce its reliance on ROE incentive adders because much of a company’s transmission risk is already accounted for in the company’s base ROE,” it said.

Transmission-dependent utilities, including Golden Spread Electric Cooperative and North Carolina Electric Membership Corp., said the commission should eliminate or minimize the use of existing ROE adders. They said there has been no “systematic study” evaluating the incentives’ effect on transmission investment, “and thus there is no evidence demonstrating that ROE-adder incentives are needed to get new transmission built.”

They also said there is also no evidence that the RTO adder is needed to encourage participation in RTOs, nor that its elimination “would result in an exodus of transmission owners from RTOs.”

Risks or Benefits?

The New England States Committee on Electricity (NESCOE) opposed proposals to change the incentives policy to focus on expected project benefits. It also opposed tailoring incentives for projects based on expected reliability benefits, targeting interregional transmission projects or geographic areas where projects would enhance reliability or have economic efficiency benefits.

“The possibility that a project can benefit consumers does not establish the need for consumers to fund incentivized investments through regulatory recovery beyond what is provided through the base ROE and cost-of-service ratemaking,” NESCOE said.

CAISO said FERC should continue to award ROE incentives based on the risks of a project rather than focusing on its benefits.

“The CAISO believes there is no direct correlation between the net benefits a project approved in a regional transmission planning process provides or the type of transmission need a project meets, and the ROE adder that is necessary to attract capital or encourage a developer to build the project,” it said.

The California Public Utilities Commission questioned the continuing need for incentives. “In the [CAISO] control area there are no systemwide, chronic, long-term transmission reliability or congestion issues that warrant the continued award of electric transmission incentives,” it said.

The National Rural Electric Cooperative Association also was skeptical, saying FERC’s questions “raise concerns that the commission is contemplating going down a path of adding new incentives without having any concrete sense as to whether its existing incentives are achieving their desired goals.”

But the Transmission Access Policy Study Group, an association of TDUs from more than 35 states, said the incentives under Order 679 “successfully reversed the long-term decline in transmission investment that spurred Congress to enact Section 219” of the Federal Power Act — the legislation that led to Order 679. It said there was no need for a “fundamental reform” of the incentive policies.

Americans for a Clean Energy Grid, a coalition of utilities, TOs and transmission equipment manufacturers, said FERC should expand the definition of transmission benefits “beyond economics and reliability to include resilience, ability to serve demand for sustainable energy, ability to meet public policy requirements and other benefits.”

The commission should encourage “low-cost, high-benefit” new transmission technologies, it said. “Existing incentives to transmission providers do not help at all in getting a new project accepted for planning, sited, permitted or its costs allocated, because they do not motivate the decision-makers involved.”

Performance-oriented Incentives

The Energy Storage Association called for a shift to a “performance-oriented” incentive policy to increase transmission capabilities and reduce costs. “ESA recommends that the commission create a specific incentive that rewards maximization of value, delivery of cost-savings or both, through investments that increase flexibility and other operational capabilities of transmission facilities.”

It also said the commission should open a separate docket to address barriers to storage as transmission assets (SATA). “Energy storage is for the most part absent from consideration in transmission planning processes. As a result, even if a SATA resource might be cost-effective and viable to meet RTO/ISO transmission reliability needs, there is not an adequate means to identify it in the planning process,” it said.

The National Electrical Manufacturers Association also supported performance-based ratemaking in considering incentives, noting the commission is required to do so under Section 219. “A performance-based approach would encourage transmission owners and operators to adopt the latest technologies to drive performance outcomes.”

Advanced Technology

Several commenters recommended FERC take steps to incent TOs to employ dynamic line ratings and other advanced technologies to increase the capacity of existing infrastructure.

Potomac Economics, which provides market monitoring services for MISO, ERCOT, NYISO and ISO-NE, said FERC should allocate to TOs the “congestion surplus” — the shadow price of the constraint ($/MW) multiplied by the difference between the dynamic line rating and the static seasonal rating. Potomac President David Patton also said the commission could improve outage scheduling by allocating outage costs to TOs and that it should consider incenting topology optimization — reconfiguring the system based on line loadings and contingencies to reduce flows on highly congested facilities. It also should encourage investment in additional transmission by allocating rights related to the congestion benefits and capacity market benefits of the expanded capacity, he said.

Oklahoma regulators called for FERC to reinstate the advanced transmission technology adder, which the commission abolished in 2012. The current rules incentivize utilities to build more expensive projects and discourage “much cheaper” advanced transmission technologies, it said, recommending the commission direct utilities “to optimize the current [bulk electric system] before upgrading the current system or building new transmission lines.”

The Natural Resources Defense Council said “utilities all too often ignore cost-effective advanced technology and other solutions to optimizing capacity and power flows of the existing system.”

The American Council on Renewable Energy said FERC should shift from a “risks and challenges” to a “benefits” framework, which, it said, “can unlock private sector investment with minimal regulatory reform.”

“Transmission incentive reform should be augmented with transmission planning reform to more effectively promote new transmission. The incorporation of grid optimization and advanced technologies in the planning process, more standard and broad cost allocation, and increased inter-RTO transfer capability will lead to a more robust and efficient electric grid. …

“Newly available grid operations technologies such as more advanced dynamic line ratings, power flow control systems and topology optimization can reduce this congestion and curtailment for less cost than new lines. Currently, utilities earn little to no money from the process of delivering more over existing wires.”

Interregional Transmission

Where incentives are really needed is for interregional transmission projects, according to R Street Institute, a think tank that promotes “free markets and limited, effective government.”

“The commission should acknowledge that [the lack of interregional projects] is a political economy problem and induce cooperation across seams through financial incentives that face the transmission-owning members of ISOs,” said R Street’s Director of Energy Policy Travis Kavulla. “These transmission owners exercise significant stakeholder influence over ISOs. Providing incentives to obtain efficiency gains across ISOs’ footprints could therefore reduce the insularity of the wholesale markets.”

Kavulla said TOs should receive incentives for projects that cross an RTO/ISO seam and be “incentivized to dedicate their existing facilities to a co-optimized market between two ISOs.”

NRDC said commission-approved transmission planning and cost allocation policies “are providing disincentives to meaningful investment that financial incentives alone cannot counteract.”

“For that reason, we encourage the commission to examine more broadly the barriers to the continuing development and optimization of the bulk power system. Many of these barriers are well known, including, for example, limited accounting of transmission benefits, the ‘triple hurdle’ required for approval of interregional projects and the discriminatory status accorded to projects necessary to meet system needs driven by public policy requirements (i.e., planners must only ‘consider’ needs driven by public policy requirements).”

Expanding the Definition of Benefits

The Union of Concerned Scientists said FERC should clarify that operational constraints on congested interfaces should be used in congestion and economic studies rather than only the planning limits of such interfaces. It cited New England’s challenge with unbottling Maine’s wind resources.

An ISO-NE study that used the planning limits — modeling the system with the maximum transfers that can only be assumed if all the best conditions are met for all hours — concluded there would be minimal economic benefit from a proposed increase in the capability of the Orrington South interface. “However, the particular interface is limited to lower … levels for most of the year,” said UCS’ Michael Jacobs. “In a study of the congestion that comes closer to approximating actual system congestion and potential benefits, the typical range of hourly operating limits must be used, rather than a fixed upper planning limit.”

Joint Ownership Incentive

MMWEC and the New Hampshire co-op said they’d like a new incentive for companies that are jointly owned by jurisdictional utilities and nonpublic utilities “in recognition of the risk-reducing benefits of these arrangements.”

GridLiance, whose business plan is built on that joint ownership model, also called for such an incentive for projects approved by a regional or local transmission planning process that are at least 15% owned by nonpublic utilities.

ROE Methodology

In docket PL19-4, the commission asked for comment on whether it should adopt as policy the new ROE formula it outlined in an October 2018 ruling regarding the New England Transmission Owners (NETOs). In that order — issued in response to the D.C. Circuit Court of Appeals’ remand in Emera Maine v. FERC — the commission said it would no longer rely solely on the discounted cash flow (DCF) model it has used since the 1980s and would instead give equal weight to results from the DCF and three other techniques: the capital asset pricing model (CAPM), expected earnings model and risk premium model. (See FERC Changing ROE Rules; Higher Rates Likely.)

PJM TOs expressed support for the new methodology.

“It makes sense to use multiple models to establish ROEs because, as the commission has noted, investors use multiple models, in addition to the discounted cash flow model, to inform their investment decisions,” they said. “Moreover, the use of multiple approaches provides a hedge against the shortcomings of any one approach in particular financial conditions.”

The NETOs said they spent most of this decade litigating their ROE and want the commission to stand by the 2018 order, including the establishment of an evidentiary screen to dismiss some ROE complaints. The commission said it would dismiss ROE complaints if the targeted utility’s existing ROE falls within the range of presumptively just and reasonable ROEs for a utility of its risk profile unless the presumption is “sufficiently rebutted.” The new threshold came in response to complaints by TOs over “pancaked” ROE complaints being filed while prior cases remained pending. (See EEI White Paper Calls for End to ‘Pancaked’ Rate Cases.)

But TDUs and state regulators said they opposed at least portions of the new methodology.

OMS said the four-model approach “broadens the scope of potentially contested issues in ROE proceedings, making it even more difficult for analysts to predict the outcome on any ROE litigation.” It asked the commission to give the DCF model “substantial weight” over any other models.

“Should the commission choose to ignore the overall cost impact to customers, the just and reasonableness of the resulting ROE will be called into question and might lead to more complaints and less regulatory certainty,” Alliant Energy warned.

TDUs said the two-step DCF analysis should remain the primary, “if not the exclusive, method” for ROE determinations.

“While the [CAPM] and risk premium models can, when properly applied, corroborate the results of the DCF analysis, they should not be relied upon as primary analyses and should not dilute the DCF results,” they wrote. “Under no circumstances should the non-market-based expected earnings model be used.”

The TDUs also said FERC shouldn’t deviate “from its current policy by imposing additional burdens on complainants bringing an action against an existing ROE” under FPA Section 206.

The Maryland Office of People’s Counsel opposed the idea of using a “vintage approach” that fixes ROEs for the life of the asset at the time that each asset is completed. “Such an approach could lead to erratic investments in that investors, if they believe returns will increase in the future, may delay making critical infrastructure improvements so they could lock in relatively high returns for the life of the asset,” it said.

R Street said FERC’s ROEs are unduly generous. In 1980, it noted, the average ROE in the U.S. was about 200 basis points above the 30-year U.S. Treasury bond yield. “Today, the gap has widened to approximately 600 basis points, even as many transmission owners enjoy regulatory devices such as formula rates that serve to diminish financial risk,” it said. “There is little reason to believe that widely available incentives are necessary to promote necessary, but routine, capital investment in commission-jurisdictional infrastructure.”

Pipeline ROEs

The Natural Gas Supply Association, which represents natural gas producers and marketers, said the commission should not abandon use of the DCF model in determining pipeline ROEs. “While the discounted cash flow methodology is not perfect, no capital market evaluation technique is. But the DCF methodology is the soundest, most robust, most accepted and most reasonable methodology the commission has for determining investor-expected ROEs for natural gas pipelines.”

The American Gas Association, which represents more than 200 local distribution companies, said it did not favor a review of FERC’s pipeline ROE policy.

“Matters related to pipeline ROEs are likely to raise issues that differ from those addressed by the court in Emera Maine. Therefore, the commission should not presuppose issues exist in the natural gas industry before fully examining the matter,” it said.

The Interstate Natural Gas Association of America (INGAA), which represents most of the interstate pipeline companies in the U.S., said it “continues to believe that the DCF methodology should be used to determine gas pipeline ROEs but recognizes that the performance of the DCF model, like the other models discussed in the NOI, is not precise and may be distorted by unusual capital market conditions.”

INGAA said it supports the consideration of some of the other models but that the commission should not adopt a formulaic averaging of the models and should “retain the flexibility to place appropriate weight on, or exclude, any of the models in light of prevailing financial conditions at that time and the facts and circumstances of each case.”

It opposed use of the risk premium model, saying it “cannot be applied to determine sufficiently reliable interstate natural gas pipelines’ ROEs due to the absence of data required by the model.”

Public Citizen and environmental groups, including the NRDC and Sierra Club, said FERC’s current policy provides incentives to overbuild capacity. “For many natural gas pipelines, applicants often involve self-dealing contracts between pipeline developers and their regulated utility affiliates. These utility affiliates can then pass costs onto its captive ratepayers. This affiliate abuse is then combined with FERC’s high rates of return,” Public Citizen said.

“The commission’s allowance of a 14% ROE for gas pipeline investments is a much higher profit margin than regulated utilities receive for other capital-intensive investments such as electric transmission — up to 40% higher,” the environmental groups said. “State public service commissions on average have granted utilities a 9.92% ROE in recent years. A review by the Edison Electric Institute shows that the average ROE granted to utilities in 56 new rate cases filed in 2017 was approximately 9.7%. Financial markets have changed since FERC began granting the 14% ROE to new pipelines over two decades ago, including declining corporate bond rates and lower interest rates.”

Tom Kleckner, Christen Smith, Rich Heidorn Jr., Michael Kuser, Hudson Sangree and Amanda Durish Cook contributed to this article.