State regulators and transmission customers of Southern California Edison last week urged FERC to reject the utility’s requested rate hike for 2018, saying it is excessive and unwarranted.
The California Public Utilities Commission on Nov. 17 filed a protest after SCE last month asked FERC to approve a $1.2 billion revenue requirement, including an increased return on equity, enhanced depreciation rate and an adder for its membership in CAISO.
“The CPUC opposes SCE’s proposed formula rate, which eliminates the minimal ratepayer protections contained [in] its current rate and only benefits the company’s shareholders,” the PUC said. “This proposed formula will result in unjust and unreasonable rates in 2018 and beyond and should be rejected.”
Southern California Edison asked FERC to approve an increased return on equity for its transmission facilities.
SCE requested a return on equity of 11.57%, calculated from a base ROE of 10.3%, compared with its current base ROE of 9.3%. The PUC said the utility did not provide evidence that the hike is needed and argued that its return should actually be reduced.
The state commission also disputed SCE’s claim that California is a risky investment environment, and said the 0.5% adder for participating in CAISO is a “windfall” for investors. The utility is required to be in the ISO by state law, the PUC noted.
In its application to FERC, the utility cited the growth of distributed energy resources as a challenge, and said growth in renewables — particularly at the distribution level — has driven the need for new transmission service. It also proposed an increase in its depreciation rate from about 2.54% currently to 2.73%.
“Integrating distributed generation with SCE’s transmission system is capital intensive and complicated, but it is necessary to achieve operational flexibility,” the utility said. “This energy revolution provides great opportunities but also presents a significant amount of uncertainty.”
Also asking FERC to reject the rate hike was a group representing 27 public agencies that hold contracts with the California Department of Water Resources to supply water for drinking, commercial, industrial and agricultural purposes. The group challenged SCE’s “proxy group” — a collection of similarly positioned electric companies — used to determine fair rates, as well as the base ROE.
California water agencies are protesting Southern California Edison’s proposed transmission rate hike.
The state water contractors said that a large number of the capital investments for which SCE wants to recover costs “have been unilaterally approved by SCE management in contravention of the requirements of [FERC] Order No. 890 to develop local transmission plans in an open and transparent planning processes.”
The group asked FERC to establish hearing and settlement procedures over SCE’s request.
The Los Angeles Department of Water and Power filed a separate protest saying the ROE is “dramatically overstated.” The ROE should be no larger than 8%, the agency argued in its protest. The department also protested that the utility’s proposal allows for executive bonuses to derive from transmission rates.
Other parties opposing the rate hike include the DWR; the City of Santa Clara and MSR Public Power Agency; and the cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside.
ALBANY, N.Y. — The planning for pricing carbon into NYISO’s markets should be more clearly defined, stakeholders told ISO and New York state officials Monday.
A good starting point: clarify the charter for the state’s Integrating Public Policy Task Force (IPPTF), some stakeholders contended.
“The problem we’re trying to solve is related to the Clean Energy Standard and trying to get 50% of [electricity] consumption from renewables, and one component of that is to incentivize clean generation. That’s what carbon pricing is doing,” said Anthony Fiore, director of energy regulatory affairs for New York City. “The other part is then to actually get that generation where the load is, which I think would be solved by a different set of tools.”
Carbon Pricing Process | NYISO
Stakeholders shared their views Nov. 20 at a third public hearing stemming from carbon pricing proposals set out in The Brattle Group report, and the second meeting of the IPPTF, a joint effort established by NYISO and the New York Public Service Commission in October to explore the carbon pricing issue. About 60 people attended the meeting, including PSC Commissioner Diane Burman. (See New York Stakeholders Question Carbon Pricing Process.)
Co-chairing the session was Nicole Bouchez, NYISO’s principal economist of market design, who said the purpose of the IPPTF is “to facilitate dialogue on market design alternatives” able to harmonize the ISO’s markets with the state’s carbon policies.
“That’s the goal. It is not a broader review of the [CES]. It is a fairly defined topic for the task force,” Bouchez said.
Fiore had a more expansive take of the IPPTF’s possible role.
“I understand that we can narrowly focus this task force, but I think it’s a mistake and a missed opportunity if we don’t lay out what the bigger issue is that lies behind this, because this is not the whole thing,” he said.
Erin Hogan of the Utility Intervention Unit at New York’s Department of Public Service shared Fiore’s concerns.
“If we had a defined goal of what we are trying to achieve, it would help develop the criteria to have an alternative analysis of the market design concepts,” she said. “As an analogy, in western New York, we had various transmission proposals and one party was advocating that their larger carbon reduction was a better option than the lower-priced transmission and also increased operability. So by not having those clearly defined criteria, it’s going to make it a little challenging to evaluate the alternative market design concepts.” (See Public Policy Tx Project Wins Key NYISO Endorsement.)
New York City Deputy Director for Infrastructure Susanne DesRoches said, “Our comments to the charter speak to needing to fully identify what the parallel processes are. For instance, how does transmission play into this conversation? We don’t want to be in a position to be pricing power in one part of the state higher than the other because we can’t get low-carbon power to the downstate region.
“Before we can go to the granular level of the questions on the table, we need consensus around what is the objective that we are trying to solve and how our other processes get us to that resolution as well.”
IPPTF co-chair Marco Padula, DPS deputy director for market structure, said, “You should identify those other processes and we should add them to this list. If you believe there are other processes that need to be studied, please, let’s add them.”
Preventing Leakage
The hearing’s agenda listed 15 recommended topics, starting with carbon leakage and resource shuffling.
Carbon leakage is defined as an increase in emissions in states parallel to one reducing them. Resource shuffling refers to the practice of utilities scheduling their lowest-emission generators to serve areas with emission caps, while letting heavier polluters simultaneously serve customers in neighboring regions.
Bouchez emphasized the task force was looking more for questions than answers at this point, and that it would address the leakage issue more fully at a Dec 11 technical conference.
She identified questions arising from the group’s prior hearing, which included:
How would a carbon charge be applied to interregional transactions?
Should specific charges be applied to each neighboring region, or should the same charge be applied to all?
Would crediting the carbon charge on exporting interregional transactions create incentives to sell power out of state?
Will the biggest emitters see this as an incentive to export more energy from New York?
Mark Younger of Hudson Energy Economics said the question of whether to apply a carbon charge to resources under 25 MW or to any fossil-fuel backed distributed energy resource also has leakage implications.
“In other words, not applying to those examples is a form of leakage,” Younger said. “You can take a relatively efficient wholesale generator, and because you’re adding a carbon charge to it, [you’re] making it look like it’s [more] desirable to run a sub-25-MW, much-less-efficient resource rather than take power from there. And that’s the same thing we’re talking about with external areas as well.”
Miles Farmer of the Natural Resources Defense Council said that leakage is a retail — as well as wholesale — market issue. “As we’ve heard, there’s DER leakage, potentially, leakage to other sectors, and then I think there’s also a role for DPS in setting the policy in regard to leakage that then NYISO could implement,” he said. “To some extent, that’s a substantive question that I imagine different stakeholders will have different views on.”
Pricing Carbon Affects Everything
Stakeholders said many of the topics were interrelated, such as whether locational-based marginal prices should transparently reflect carbon charges, how to apply the cost of carbon to generator emission rates ahead of delivery, how to allocate carbon revenues, and the possible effects of a carbon price on the capacity market.
NYISO Senior Manager for Market Design Michael DeSocio said, “If you take a DER that is a combination of renewable and non-renewable, I’m not sure when we aggregate those two pieces up to a single resource that we will know exactly how to apply that cost of carbon, but we certainly know after it runs what it did and how much to charge it.” He said the carbon charge might be an opportunity cost-based process in which a resource will be charged after the fact but will need to determine beforehand what cost to incorporate into its offer.
“Or do we need to figure out all the permutations of every configuration of every facility to then apply a cost up front directly into the offer?” he said. “There are some pros and cons to both sides. We first start to think about this with generator fuel blends, but then you take it down the path where we had discussions this morning about DERs, and it gets even more complicated.”
Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said that pricing carbon would not change the dynamics of New York’s grid, where lopsided load balances create transmission constraints between upstate and downstate, particularly around New York City and Long Island.
“Thinking about changes and what’s needed in the capacity market, we’ve said look at what New England has been talking about and what PJM has been talking about,” Joseph said. “They’re talking about moving towards a two-tiered clearing market where you have resources that are brought on because of state policy, and that’s highly likely to continue here even if you price carbon because of this transmission issue. … Even if we price carbon, what we do in the capacity market has to be a big part of this discussion.”
Howard Fromer, director of market policy for PSEG Power New York, asked how the sector will determine the social cost of carbon.
“We can’t have a situation where we define the problem at $45 but our solutions are multiples of that,” Fromer said. “I don’t know how you sell that to the public and explain to them why you should pay more than what you said the problem is worth. That doesn’t work too well.”
DeSocio said NYISO planned to use a Dec. 5 joint Market Issues Committee and ICAP Working Group meeting to brief stakeholders on what other RTOs are doing to integrate public policy in wholesale markets.
Bouchez said the task force would hold a technical conference Dec. 11, but that it was unclear whether it would be necessary to hold the public hearing scheduled for Dec. 18, given its proximity to the holidays. Regardless of what meetings take place in December, the task force still plans to issue an initial work plan to stakeholders by the end of January, she said.
BALTIMORE — More than 1,300 regulators and other stakeholders attended the National Association of Regulatory Utility Commissioners’ 129th Annual Meeting and Education Conference at the Hilton Baltimore Inner Harbor, where the theme was “Infrastructure, Innovation and Investment.” The National Association of State Utility Consumer Advocates (NASUCA) attracted more than 200 to its annual meeting at the same hotel.
FERC Commissioner Robert Powelson said it will take a while for the commission to move forward on rulemakings that languished during its six months without a quorum.
Powelson and Neil Chatterjee joined Cheryl LaFleur on the commission in August, restoring a quorum. Two other commissioners, Kevin McIntyre and Richard Glick, are waiting to be sworn in after being confirmed by the Senate on Nov. 2.
“It’s kind of hard to calibrate around some of these high-level decisions that need to be made. It’s critical that people have a little bit of patience as we get back up and running,” he told NASUCA.
Powelson said he expects FERC to act on its November 2016 Notice of Proposed Rulemaking on electric storage within the next three months. (See FERC Rule Would Boost Energy Storage, DER.)
Powelson said he is using the Department of Energy’s NOPR for coal and nuclear plants as an “inflection point to see what’s working and what’s not working in the organized markets. What I know is working hyper-efficiently is wholesale power prices have dropped and that’s a darn good thing. … Let’s not screw that up.”
The commissioner said he also wants to explore “friction” between RTOs and their market monitors, an issue he said was raised by Virginia State Corporation Chairman Mark Christie at a recent conference.
Christie said in an interview later that he was raising a “structural issue that applies across all RTOs.” (See Order 719: FERC Balanced MMU Independence Against RTO Autonomy.) “What constitutes truly independent market monitoring?” Christie asked. “As the regulator of RTOs, FERC is the appropriate forum to tee up the issue and air it out.”
“I don’t want to go back to the old days,” Powelson said. “I really believe in the independence, and protecting the sanctity of that compact for these independent market monitors. I think they should have the ability to file [with FERC]. And I get a sense that Big Brother RTO wants to say, ‘Yeah, you can be seen and heard when it’s appropriate.’ That’s not a good thing in this world of transparency that we live.”
Powelson expressed skepticism that Order 1000 has resulted in competitive transmission development, saying it is another subject worthy of a “conversation” to determine “what’s working and not working” under the order. “I’m not saying we’re going to amend FERC Order 1000, but I think we owe it to ourselves to have that conversation,” he said.
Stefanie Brand, director of New Jersey’s Rate Counsel, asked Powelson if he was aware of concerns by industrial customers and others about the rising cost of supplemental transmission projects, which are not required by FERC or NERC reliability rules. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“Yes, it is something we’re looking at,” Powelson confirmed without elaboration.
Resolutions on Solar Tariffs, Tax Policy OK’d
NARUC’s Committee on Electricity approved a resolution urging the U.S. Trade Representative “to carefully weigh the harm that could result to energy customers from increasing the costs of solar inputs across the country, and the potential challenges to achieving state renewable energy and greenhouse gas goals that may result from higher solar energy prices.” (See Federal Trade Panel Recommends Solar PV Quotas.)
It also approved a measure asking Congress not to restrict state regulators’ ability to determine how any reduction in corporate income tax rates are addressed in utility rates. The resolution said any reductions in taxes on state-regulated investor-owned utilities “should result in a direct benefit to customers, so long as it is captured in the state ratemaking process.”
NARUC members formally elected Connecticut Public Utilities Regulatory Authority Vice Chair John W. “Jack” Betkoski III as its new president for a one-year term. Betkoski has been serving as president since August, when Powelson, a former Pennsylvania regulator, vacated the post to join FERC.
Ellen Nowak, chair of the Wisconsin Public Service Commission, was elected first vice president, and Edward S. Finley Jr., chair of the North Carolina Utilities Commission, as second vice president.
NARUC also named Andreas D. Thanos, of the Massachusetts Department of Public Utilities, the winner of the 2017 Terry Barnich Award. The award, which recognizes commissioners and staff who promote international cooperation among utility regulators, is named for the former chairman of the Illinois Commerce Commission, who was killed in 2009 while working for the U.S. State Department in Iraq. Thanos was named in recognition of his work in Europe, Latin America and elsewhere.
HOUSTON — It’s a sign of the Mexican electricity market’s growing strength that at least some industry experts expect little change after the country’s presidential elections next year.
The country’s constitution limits presidents to single six-year terms. That means every six years, a new president and administration — usually from the Institutional Revolutionary Party (PRI) — is guaranteed to take power, leading to months of transitory uncertainty for the energy sector.
Derek Woodhouse, a partner with Woodhouse Lorente Ludlow, has been advising Mexico’s Energy Ministry (SENER) on implementing the wholesale market and drafting the geothermal energy law and regulations. He expects 2018 to be different.
“Regardless of who wins the election … they’re not going to be able to dramatically change what’s being done,” Woodhouse said during a Gulf Coast Power Association luncheon last week.
For one, Woodhouse said, market reform was written into Mexico’s constitution three years ago. “Second, because the market rules have been put in place, and can only be changed now by the market itself. It will be hard for them to mess up things,” he said.
“I think in many ways, that’s why it was assigned this way, so it can support political changes, and political changes will not affect dramatically what is going on.”
Continuity or Inertia?
Woodhouse would know. In the late 1990s, he was part of a team drafting the country’s initial market reform proposal. When Vicente Fox ended 71 years of PRI rule with his surprise victory in the 2000 election, it put a halt to the market reforms.
“When Fox won the election, nothing happened — not for 12 months,” Woodhouse said. “That’s a political risk of having a new party [in control], because then you cannot have the same teams running the show.”
Woodhouse said the difference now is the nearly three dozen market rules that have been — or soon will be — put in place since new industry laws and regulations were passed in 2014. They govern everything from financial transmission rights auctions to market registration and outage scheduling. A code of conduct and operating guidelines and procedures are among those rules yet to be developed.
Still, further changes will only be expedited if the PRI manages to replace incumbent President Enrique Pena Nieto with another one of its own, Woodhouse said.
“Then you have continuation. At the end of the administration, people … probably know they’re not going to be here, so why take any risk? Why start something you’re not going to end? That triggers a year of nobody doing anything,” Woodhouse said.
Continuity does reign within the Energy Regulatory Commission (CRE), an independent body from the state-owned Comision Federal de Electricidad (CFE) that has long controlled Mexico’s electricity business. CFE is currently being restructured into separate generation, transmission and distribution businesses.
Woodhouse said inertia during the transition between administrations can still be a problem, however.
“You need to wait for the new panel to take over those positions, to learn what to do, and start doing it,” he said. “You have 12 to 18 months that nothing happens. It’s sad because it shouldn’t be like that. They have the tools to make changes, and they’re simply not using them.”
Growing Private Sector Role
SENER is implementing the wholesale market in phases through 2018. It consists of short-term markets (day-ahead, hour-ahead, real-time and ancillary services), medium-term auctions (three-year energy and capacity contracts), long-term auctions, FTR auctions, a capacity balancing market and the 20-year clean energy certificates market for instruments equivalent to 1 MWh of energy from clean sources.
The market’s third long-term auction last week set a new low for average prices at $20.57/MWh, bettering the $33.47/MWh average set in September 2016, according to preliminary results. Mexico will add 2.56 GW of capacity from 16 new projects, with a total investment of $2.36 billion by international players from Canada, China, France, Italy, Japan and Spain.
“We’re devising something that will allow them to look good politically but still incentivizes the private sector to negotiate contracts,” said Woodhouse, who has focused his career on private-sector participation in infrastructure projects traditionally reserved for the public sector.
“Hiring consultants would lengthen the process by 12 months, so we came with the idea of allowing them, from the top, to sit down and negotiate,” he said. “They’re not used to doing that. That was perceived as something corrupt. We are giving them that option because now, legally, they can do it. But they’re still very nervous. ‘Yeah, but how is it going to look if I sit down and discuss a contract with someone?’”
Woodhouse said the market is just awakening, with many players “just learning how to play the game.” Only five companies are listed as qualified suppliers, and a number of their contracts are in the 1- to 3-MW range.
“They’re testing the waters to see how their software runs,” Woodhouse explained.
FERC last week rejected NERC’s request to eliminate public posting of self-reported compliance exceptions and to expand compliance exceptions to include some moderate-risk violations.
“In most situations, information on NERC’s resolution of compliance and enforcement matters should be transparent and publicly available,” the commission said. The rejections came in an order in which the commission accepted NERC’s annual report on its Compliance Monitoring and Enforcement Program (CMEP) (RR15-2-005).
In February 2015, the commission allowed NERC to move to a risk-based approach to compliance monitoring and enforcement, which allowed low-risk violations of reliability rules to be recorded and mitigated without formal enforcement actions. It also allowed registered entities that passed a NERC review of their internal controls to self-log and mitigate minimal-risk violations, subject to periodic, rather than individual, reviews by the Regional Entity. (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.)
Incentive Lacking?
NERC said the commission “unintentionally removed an incentive for registered entities to participate in the program” when it required public logging, contending that it had reduced interest in the program.
| NERC
The Edison Electric Institute, the ISO/RTO Council (IRC) and MISO transmission owners were among those supporting NERC’s proposal to eliminate public posting. The IRC noted that only 59 of more than 1,200 registered entities participate in self-logging, saying that the incentives to participate were inadequate.
The American Public Power Association, Electricity Consumers Resource Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group opposed the elimination of public posting in a joint filing, saying the transparency was needed to educate the industry and preserve the credibility of NERC’s enforcement program. They said that because compliance exceptions are a significant percentage of noncompliance, the public disclosures allow registered entities to understand compliance requirements. They also said the public posting could help identify unnecessary or redundant reliability requirements.
The commission said it agreed with the commenters who supported continued public disclosure. “The value of maintaining the transparency of self-logged noncompliance continues to outweigh the asserted benefit that might accrue from increasing the incentive to participate in the program,” FERC said, citing the “minimal” burden of public posting and the benefits it provides in “educating industry and ensuring consistency across NERC’s and the Regional Entities’ compliance and enforcement programs.”
Find, Fix and Track Program
FERC also rejected NERC’s proposal to expand the compliance exceptions program to include moderate-risk noncompliance, although all commenters supported NERC’s request.
Moderate-risk violations that have been corrected are currently subject to the Find, Fix and Track (FFT) program, which allows NERC to process them through informational filings instead of the formal Notice of Penalty procedure.
“We are not persuaded that the claimed efficiency gains in processing certain moderate-risk violations as compliance exceptions, rather than as FFTs, are sufficient to outweigh our concerns with treating many moderate-risk noncompliances through a nonenforcement track,” FERC said. “While this approach may be appropriate for minimal risk violations, NERC has not adequately justified this limited approach for moderate-risk violations.”
The commission also raised questions about the FFT program, saying its staff had identified a compliance exception involving falsification of battery testing records by a registered entity’s employee that was disposed of via the FFT process. “The commission does not consider it appropriate to process instances of noncompliance involving falsification of records as compliance exceptions or FFTs,” it said. “Rather, such circumstances warrant a full Notice of Penalty.”
NOPR on Training, Coordination of Protection Systems
In a separate Notice of Proposed Rulemaking, the commission proposed reliability standards PRC-027-1 (Coordination of Protection Systems for Performance During Faults) to ensure protection systems used to detect and isolate faults operate in the intended sequence.
The NOPR also proposed the approval of reliability standard PER-006-1 (Specific Training for Personnel) to ensure that personnel involved in real-time operations are adequately trained (RM16-22).
FERC set a refund effective date of Sept. 30, 2016, the date NEPGA filed its complaint.
NEPGA filed a rehearing request asking the commission to apply the revised PER — and any resulting refunds to capacity suppliers — to an Aug. 11, 2016, scarcity event.
FERC on Thursday rejected the request, saying it would impose “an unforeseen and significant increase in costs” to load.
“Such application is inconsistent with the commission’s notice requirements under the [Federal Power Act],” FERC said. “We recognize that there is a lag between when the event occurs and when the billing to reflect the PER adjustment takes place; that lag in billing, however, does not satisfy the notice requirements under the FPA.”
The January order said the amount of the PER increase would be determined in an evidentiary proceeding if stakeholders were unable to reach a settlement.
On Aug. 31, Settlement Judge H. Peter Young certified an uncontested settlement requiring ISO-NE to increase the daily PER strike price for each hour “by the amounts that actual five-minute reserve shadow prices exceed the pre-December 2014 reserve constraint penalty factors (RCPF) values for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively).”
The revised strike price will replace the strike price value in hourly PER calculations for Sept. 30, 2016, through May 31, 2018. The settlement has not been approved by the commission.
NEPGA President Dan Dolan and ISO-NE officials could not be reached for comment.
FERC last week accepted network transmission service agreements between SPP and Kansas Municipal Energy Agency (KMEA) and Sunflower Electric Power, pending modifications to address the inconsistent treatment of a generation resource (ER17-889).
KMEA’s Jameson Energy Center | KMEA
The commission directed SPP to make a compliance filing within 30 days to resolve a modeling discrepancy in the power-flow analysis, which failed to account for a 9-MW gas turbine (Garden City 2) at KMEA’s Jameson Energy Center in Garden City, Kan.
SPP agreed to file revisions to KMEA’s service agreement to reflect the additional network resource, with an effective date of March 1, 2017, and to remove a reference to the unit that imposes revenue crediting requirements.
The RTO filed with FERC in January service agreements between it and KMEA as a network customer, and between it and KMEA and Sunflower as a network customer and host transmission owner, respectively. Commission staff tentatively accepted the agreements in March while FERC lacked a quorum.
Sunflower and its Mid-Kansas Electric owner, which also includes five co-ops and a not-for-profit electric company, intervened to point out the initial service agreement with KMEA excluded Garden City 2 but required the unit to pay revenue credits as a network resource. They requested FERC require SPP to remove the unit from the revenue credit payment or add Garden City 2 as a network resource.
SPP acknowledged its mistake and said it performed an additional analysis using updated model information, reposting the results in an aggregate transmission service study in February. It confirmed network service for KMEA used Garden City 2 as a designated network resource, effective March 1.
FERC last week approved cost responsibility assignments for 39 baseline upgrades recently added to PJM’s Regional Transmission Expansion Plan (ER17-2362).
The allocations were filed on Aug. 25. Thirty-five projects will be allocated to the transmission zone in which they are located, including five projects of less than $5 million each. Two projects will address Form 715 local planning criteria, and 28 involve circuit breakers and associated equipment. The remaining four projects are “lower voltage facilities” that are allocated based on the solution-based distribution factor (DFAX) method.
PJM’s control room | PJM
Old Dominion Electric Cooperative challenged two of the DFAX allocations, saying it was unable to replicate PJM’s analysis. It asked the commission to direct PJM to provide the detailed information “for the sake of transparency” and to determine whether the upgrades are appropriately allocated entirely to the American Electric Power zone. ODEC questioned PJM’s 100% allocation of another project to the American Transmission Systems Inc. zone, arguing that the results of the DFAX analysis produce a 1.32% allocation to ATSI.
FERC accepted PJM’s defense of its allocations. The RTO said because only ATSI had a DFAX percentage greater than 1% for project b2898 — reconductoring the Beaver-Black River 138-kV line — that zone was assigned the entire cost of the $20 million project.
PJM said it used “an appropriate substitute proxy” for the baseline projects, reactive power upgrades that can’t be addressed by DFAX analysis, which measures over transmission lines or transformers. PJM developed an “interface comprised of the lines and transformers that surround the entire AEP system,” a localization method PJM often uses “because the majority of reactive power upgrades are intended to provide local voltage support.”
ODEC has also asked the D.C. Circuit Court of Appeals to overturn FERC’s policy of allocating all costs from Form 715 projects to the zone of the transmission owner whose criteria triggered the upgrades. ODEC said the cost allocation for the two Form 715 projects should be subject to the outcome of its challenge.
FERC said last week it didn’t have enough information to decide on complaints that American Electric Power affiliates are raking in unreasonable returns for transmission projects in PJM and SPP, instead establishing hearing and settlement judge procedures.
In PJM, American Municipal Power, Blue Ridge Power Agency, Craig-Botetourt Electric Cooperative, Indiana Michigan Municipal Distributors Association, Indiana Municipal Power Agency, Old Dominion Electric Cooperative and Wabash Valley Power Association filed complaints that AEP’s current 10.99% base return on equity is excessive. They requested a base ROE no higher than 8.32% and asked for refunds with interest. The change would save them $142 million annually in transmission costs, they said (EL17-13).
The complainants hired a consultant to develop a peer-group analysis that included 25 utilities similar to AEP. That analysis found a “zone of reasonableness” of between 5.62 and 9.46% and that the median of the values, 8.32%, was more appropriate than the midpoint.
Multiple state agencies intervened to support the complaint, including the Indiana Office of Utility Consumer Counsel, the Office of the Ohio Consumers’ Counsel, the Virginia Division of Consumer Counsel, the Virginia State Corporation Commission and the Indiana Utility Regulatory Commission.
An ad hoc group of large commercial and industrial end-use customers also commissioned an analysis, which found an appropriate zone between 5.64 and 9.44%, recommending a base ROE of 8.22%.
AEP responded with its own analysis that found an appropriate zone between 6.41 and 11.71% and that using the midpoint of the upper half of the range, rather than the median, was consistent with FERC rulings.
FERC found the complaint compelling enough to explore further and called AEP’s argument that the current rate falls within the reasonable zone “unpersuasive.”
“The commission has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE,” the order said, setting a refund effective date of Oct. 27, 2016.
SPP Complaint
FERC also established identical procedures for East Texas Electric Cooperative (ETEC) in its complaint against AEP subsidiaries Public Service Company of Oklahoma (PSO), Southwestern Electric Power Co. (SWEPCO), AEP Oklahoma Transmission and AEP Southwestern Transmission, setting a refund effective date of June 5, 2017 (EL17-76).
The cooperative in June asked the commission to reduce the companies’ 10.7% base ROE to 8.36% within SPP’s AEP West pricing zone. PSO and SWEPCO’s current base ROE derives from a transmission formula rate settlement agreement filed Feb. 23, 2009.
ETEC contends the base ROE is no longer just and reasonable and that its ratepayers are currently overcompensating the AEP West companies by $36.6 million annually.
The companies countered that the 9.53% upper end of an ETEC consultant’s zone of reasonableness falls more than 100 and 80 basis points below the ROE that FERC previously approved for ISO-NE and MISO, respectively.
The commission said it was “unpersuaded” by the argument, saying “the relief [ETEC] seeks here is an ROE that falls well below the current ROE, based on different facts, risks, proxy companies and time periods” than those in previous decisions.
FERC on Thursday approved NYISO Tariff revisions ordering downstate residents to pay 90% of the cost of AC transmission projects stemming from public policy needs (ER17-1310-001).
The projects, which include the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, are intended to relieve downstate congestion by upgrading the AC transmission systems north and west of New York City.
| National Grid
The cost allocation was proposed by the ISO at the direction of the New York Public Service Commission, which said 75% of the costs should be allocated solely to the downstate load zones that will benefit from the congestion relief, with the remaining 25% allocated regionally based on load-share ratio. “According to the New York commission, this method will allocate approximately 90% of the transmission project’s cost to ratepayers in the downstate region, and about 10% to upstate ratepayers,” FERC said.
FERC rejected a protest by four State Assembly members, who said the regional allocation of 25% was too low to account for “some of the financial and societal benefits to ratepayers statewide.”
The commission said the proposed allocation satisfies Order 1000’s requirement that it be “roughly commensurate” with the benefits that the load zones receive, citing a study published by the PSC that found 89.5% of the costs should be allocated to the downstate load zones.
However, the commission added that the ISO’s filing “does not prevent the selected transmission developer from submitting its own proposed cost allocation method for the AC transmission upgrades. The Tariff specifically provides that the selected transmission developer may also file, for the commission’s approval, an alternate cost allocation method or request that NYISO use the default cost allocation method (i.e., load-share ratio).”
ROE Settlement
In a related order, the commission approved a settlement with New York Transco — affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric — to decide questions regarding their potential compensation for the projects (ER15-572).
The settlement, which will apply only if NY Transco is selected as the developer, includes a 9.65% base return on equity and a 100-basis-point adder that will apply up to the cost cap, which was defined as the capital cost bid plus an 18% contingency and an inflation factor of 2% per year.
The commission said the settlement, which was unopposed and endorsed by both the New York PSC and FERC staff, “appears to be fair and reasonable and in the public interest.”
Cost Containment
FERC did not rule on state regulators’ proposed cost-containment mechanism, under which ratepayers would be responsible for 80% of any overruns above the estimated cost of the project and retain 80% of any savings.
The commission said it couldn’t rule because the ISO had provided only a description of the risk-sharing proposal without Tariff language. “As such, [the mechanism] is not properly before us,” the commission said. “NYISO states that it plans to file Tariff sheets for the 80/20 risk-sharing mechanism after concluding its stakeholder process.
“In regard to implementing the 80/20 risk-sharing mechanism, because the New York commission recognizes that [FERC’s] policy on cost recovery allows transmission developers to recover costs that are prudently incurred, it proposes to limit the selected transmission developer’s ability to recover costs associated with cost overruns by reducing the allowed return on equity for the transmission project,” FERC added.
Selection Process
NYISO received 16 proposed projects from six developers in response to a February 2016 solicitation for solutions to address the transmission congestion. In a January order, the PSC told the ISO it “should proceed to a full evaluation and selection, as appropriate, of the more efficient or cost-effective transmission solution to meet the” public policy transmission need.
NYISO spokesman Michael Jamison said the ISO hopes to release draft results of its analysis by the end of the first quarter of 2018. “Subsequent to that, the NYISO will select the more efficient or cost-effective project. At that time the NYISO will work out a developer agreement with the chosen party, and that party can initiate actions with the state under the Article 7 transmission siting process.”
