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.”
WESTBOROUGH, MA — Boston leads large, northeastern cities in economic growth, outpacing both New York and Philadelphia in payroll employment, Moody’s Analytics economist Ed Friedman told the ISO-NE Planning Advisory Committee on Thursday.
| BLS, Moody’s Analytics
According to figures compiled by Moody’s from the U.S. Bureau of Labor Statistics, Boston posted better than 2% growth in payroll employment for the three months ending September 2017, compared to approximately 1.7% growth in Philadelphia and less than 1.5% in New York City.
“The job growth in Boston is quite strong and significantly above the U.S. pace, which is around the 1.5% mark,” Friedman said.
Friedman characterized New England job creation in the aggregate as “slow but steady” at 1% per year and said that housing price gains in the region are mostly keeping up with the national average of just more than 6% for the year ending in August 2017. Of the six states in the region, only New Hampshire and Massachusetts exceeded the national average; housing prices in Massachusetts, where health care remains a strong economic driver, increased by almost 7%.
| BLS, Moody’s Analytics
Both Connecticut and Vermont lost population in the past two years. Nonetheless, Moody’s expects economic growth in the region to continue in 2018 at about 1.3%, with “some deceleration consistent with the demographic challenge” of lost population, Friedman said.
RTO Readies Maine Resource Integration Study
ISO-NE on Thursday presented a draft of its Maine Resource Integration Study to the PAC, its first transmission planning study to employ queue clustering under Tariff revisions approved by FERC Approves ISO-NE Queue Clustering.)
The Northern and Western Maine grid was built to serve the small loads in the area and lacks capacity for the more than 5,800 MW of proposed new resources, mostly wind, that have filed interconnection requests. The 5,800 includes duplicate requests.
The resource integration report will provide the basis for system impact and facilities studies, which will identify the upgrades required for resources that proceed to interconnection and their cost allocations, said Al McBride, ISO-NE director of transmission strategy and services.
Maine 2027 Needs Assessment Moves Forward
The RTO’s draft Maine 2027 Needs Assessment study is ready for stakeholder comment, Jinlin Zhang, ISO-NE lead engineer for transmission planning, told the PAC.
Comments and notifications by proponents of state-sponsored requests for generation should be submitted to pacmatters@iso-ne.com by Dec. 3.
The study identifies reliability-based needs in Maine for the year 2027, considering future load distribution, resource changes in New England based on Forward Capacity Auction 11 results, and 2017 solar and energy efficiency forecasts.
Planners look at reliability over a range of generation patterns and transfer levels, how the study coordinates with the New Hampshire Needs Assessment, and all applicable NERC, Northeast Power Coordinating Council (NPCC) and RTO transmission planning reliability standards.
The completed draft report and intermediate study files will be presented to the PAC in the first quarter of 2018.
RTO Begins Zone Planning for FCA 13
ISO-NE has begun assessing transmission transfer capability, generation retirements and new resources to set capacity zone boundaries ahead of FCA 13 for 2022/23.
The process includes evaluation of the zones as determined for FCA 12, McBride said.
| ISO-NE
Each year, the RTO must identify weaknesses and limiting facilities that could impact the transmission system’s ability to reliably transfer energy in the planning horizon. Any new boundaries require a filing with FERC, McBride said.
The process of certifying transmission projects begins in October and is coordinated with that month’s Regional System Plan (RSP) Project List update to ensure consistency. Transmission owners are required to provide models and contingency definitions. The RTO will determine certifications by January; the list of certified projects will be presented at the January Reliability Committee meeting.
Transmission upgrades identified for Southeast Massachusetts/Rhode Island (SEMA/RI) are not expected to change the boundaries of the area. Planners do not expect such upgrades to be fully certified for FCA 13, nor will transfer limits be updated in time for that auction in 2019.
Any major resource retirements received for FCA 13 will be considered in the zone formation process, McBride said. No major retirements were received for FCA 12.
Time-Sensitive Tx Needs Determination
Pradip Vijayan, ISO-NE senior transmission planning engineer, made a presentation on how the RTO identifies time-sensitive transmission upgrades — those required within three years and thus not subject to the competitive solicitation process.
RTO officials consider when an upgrade will be required after identifying improvements in a needs assessment.
Needs identified from a short-circuit analysis are considered time sensitive unless they are driven by future projects that have an in-service date beyond three years of the completion of the needs assessment.
Steady-state needs observed at off-peak load levels are considered time sensitive. Those seen at peak load levels may or may not be time-sensitive.
The RTO will add a document detailing the process to its Transmission Planning Technical Guide, Vijayan said.
Tx Planning Assumptions Update
ISO-NE is continuing to update the probabilistic methodology and minimum load level used in its transmission planning assumptions, Director of Transmission Planning Brent Oberlin said.
The generator dispatches used in base cases in his report showed the potential for a significant number of generators to be simultaneously unavailable, especially in the Eastern Connecticut (ECT) area. ISO-NE said in October that it would revise the scope of its 2027 needs assessments for ECT, Southwest Connecticut and New Hampshire over stakeholder questions about dispatch modeling assumptions. (See “Tx Planners Rethink 2027 Needs Assessment,” ISO-NE Planning Advisory Committee Briefs: Oct. 18, 2017.)
The ECT data showed that up to 488 MW of generation could be unavailable at peak load. The largest generator in the ECT study area is Montville 6 (413 MW), with 13 other generators totaling only 253 MW, which shows that the presence of a single large generator in an area with a low number of smaller generators can skew the results, Oberlin said.
The new methodology solves the issue by recalculating the upper limit of generation outages using the probabilistic method by excluding the large generator for dispatches in which it is assumed in service. By applying this method to ECT, the maximum amount of generation unavailable is limited to 115 MW in cases with Montville 6 in service.
The new methodology lowers the minimum load level to 8,000 MW from 8,500 MW, correcting an error on the handling of Maine mill loads (currently 320 MW) in the evaluations, Oberlin said.
NERC announced Monday that its Board of Trustees had accepted the resignation of CEO Gerry Cauley, effective immediately, following his arrest for domestic abuse.
The organization said General Counsel Charles Berardesco will continue to serve as acting CEO while the board seeks a search firm to recruit a replacement.
“NERC has a talented staff and an experienced leadership team that is well-equipped to continue the forward momentum on key initiatives,” Board Chair Roy Thilly said in a statement. “I am confident we will continue to meet milestones and expectations going forward. NERC remains committed to maintaining the reliability and resilience of the bulk power system.”
A NERC spokeswoman declined to comment when asked whether Cauley would receive any severance payment. “Any personnel action is confidential,” she said.
NERC CEO Gerry Cauley (center) and General Counsel Charles Berardesco (to Cauley’s left) attend a NERC board meeting in New Orleans Nov. 9, hours before Cauley’s arrest for domestic abuse. Also pictured are Board Chair Roy Thilly (to Cauley’s right), and board members Jan Schori (left) and Frederick W. Gorbet (foreground). | NERC
NERC had placed Cauley on a leave of absence after his arrest for battery, a misdemeanor, for allegedly assaulting his estranged wife in the early morning of Nov. 10. The police report documenting his arrest states that his wife, Jean Cauley, sustained bruises and scratches and was experiencing a great deal of pain in her back.
Jean, a former probation officer and child abuse investigator for the state of Florida, posted a comment about the incident on her LinkedIn page Sunday: “Who knew that when I married a CEO — and me with a background in law-enforcement — [I] would be a victim of a violent crime by her husband to the point of a back being broken,” she wrote. “It shows that no one is exempt from domestic violence and that we should all support each other as women.”
Cauley, 64, had served as NERC CEO since January 2010, and was often the face of the reliability agency in hearings before FERC and Congress. By Monday afternoon, however, his biography and photo had been removed from the web page listing the organization’s management.
BALTIMORE — State-federal tension over electricity policy is likely to continue even after current debates over nuclear and coal subsidies end, speakers told the National Association of Regulatory Utility Commissioners’ Annual Meeting last week.
Clark, an adviser for Wilkinson Barker Knauer who left the commission in September 2016, said there will be pressure for additional state interventions because of the impact of renewables on energy market prices. “Increasingly we see even … relatively new gas units that are stressed in certain markets. Any resource that has higher fixed costs and variable operating costs is going to be challenged in any sort of market where you have price takers with zero variable cost units that are at the margins.”
In addition, he said, FERC may begin asserting its authority on power “from the edge of the grid,” such as rooftop solar.
“Up until this point, FERC has kind of walled that off and basically … been able to ignore what happens since that’s been on the state jurisdiction side of things,” he said.
“It’s hard to argue that all of these exponentially growing resources at the edge of the grid — in which a sale is by default a sale for resale — [is not] federally jurisdictional activity. To this point it hasn’t been that big a deal. It’s becoming a very big deal.”
Ari Peskoe, of Harvard Law School’s Environmental Policy Initiative, said legal challenges to Illinois’ and New York’s zero-emission credits for nuclear plants “expose a question that courts have not addressed in the 20 years of restructuring: May a state provide an incentive for energy production without intruding on FERC’s exclusive jurisdiction over energy sales? Perhaps the state authority over generating facilities means just that — the facilities themselves, and not the energy that they produce,” he said.
“There’s little doubt that states can enact all sorts of command-and-control regulations over pollution from those facilities. States can issue emission limits or simply prohibit the burning of fossil fuels within their borders. But what about financial regulation of pollution and avoided pollution? And what about state regulation of utility portfolios? ls there some limit on state power that limits states just to those traditional integrated resource plan tools?”
Peskoe filed an amicus brief defending the Illinois ZECs. “Expanding the scope of FERC’s exclusive jurisdiction to swallow up ZECs, [renewable energy credits] and other emissions taxes and allowances will disrupt how the industry and how regulators have understood jurisdictional limits,” he said.
If the courts accept opponents’ reading of the Federal Power Act, “we can expect lawsuits about a range of state programs,” he said, adding, “Now concerns about market distortions from ZECs seem pretty quaint in light of [the U.S. Department of Energy’s] recent Notice of Proposed Rulemaking.”
Peskoe said that if ZECs survive the current legal challenges, “existing state policy would be relatively safe from these pre-emption challenges going forward. Then the action turns back to FERC and what FERC is going to do.”
He said FERC’s May 1-2 technical conference on integrating wholesale markets and state public policies “was a really positive step … so I hope that the DOE NOPR and whatever happens after it doesn’t sort of suck the air out of the room and that conversation keeps happening.” (See RTO Markets at Crossroads, Hobbled FERC Ponders Options.)
Clark said FERC must determine when state actions reach a “tipping point” for its markets. “Whether you think the ZEC is the tipping point or the DOE NOPR is the tipping point, there is a tipping point that FERC has to be concerned about in terms of its maintenance of the integrity of the wholesale market,” he said.
“What happens when say … coal-friendly states decide, ‘It looks like RECs and ZECs are the way to go. What we need now is a coal energy credit,’” Clark asked.
“We are called the Environmental Policy Initiative, so we don’t love the idea of coal credits,” Peskoe responded. “I’m somewhat comforted by the fact that about 30 states actually enacted RPS and, so far, zero states have enacted coal standards.”
Former Commissioner Marc Spitzer (2006–2011) was more succinct: “If they’re zero-emission coal, go for it!” he joked.
Spitzer, a partner with Steptoe and Johnson, also supported ZECs, saying states are “entitled to deference and forbearance.”
BALTIMORE — Speaking last week to an audience of consumer advocates, John P. Hughes, CEO of the Electricity Consumers Resource Council (ELCON), led off his critique of RTO stakeholder processes with a blunt assessment: “The main takeaway is it can’t be fixed.”
Other participants who joined Hughes in a panel discussion at the National Association of State Utility Consumer Advocates (NASUCA) annual meeting Wednesday were more optimistic.
Unfortunately, the speakers’ opening presentations at the discussion — cheekily titled “20 Years of RTO Meetings and We’re Still Not Done?” — swallowed up the entire 70-minute session. As a result, Denise Foster, PJM’s vice president of state and member services, never got a chance to respond to the critiques.
Room for Improvement
AARP’s Bill Malcolm, a former MISO manager of state regulatory affairs, opened his presentation by praising RTOs for improving generation dispatch and eliminating rate pancaking.
But he said they should be required to follow open meetings laws and enact ethics reforms, including a ban on revolving-door hiring. He also called for tightening cost controls. “RTOs don’t print money,” said Malcolm, AARP’s senior legislative representative for state advocacy and strategy integration. “It’s ratepayer dollars at the end of the day.”
He also said RTOs should add ways to better represent residential ratepayers in stakeholder proceedings, including establishing an RTO-funded organization like the Consumer Advocates of PJM States (CAPS).
“Let’s make a good thing better,” Malcolm said.
Unstable Market Design
Hughes, whose organization represents industrials, said a large manufacturer might have only one or two electricity buyers for national or international operations — making it impossible to monitor the hundreds of RTO stakeholder meetings annually.
“The market design has never — and may not ever — be stabilized. Therefore, the stakeholder process will forever be the resource hog that it is today,” he said, citing capacity markets as an example.
“It is the wrong solution to the problem, caused by not having shortage pricing or surge pricing. And since the capacity market doesn’t really work, it’s under continual attack for tweaks and fixes that will go on forever unless we come up with a different market design — which I don’t think will happen.”
Hughes said almost all the proposals that go through the stakeholder process are efforts to increase charges to ratepayers. “The current driver of market design changes — which is [the call for] price formation, including the new [Department of Energy Notice of Proposed Rulemaking] — is very low-cost shale gas. There seems to be a conspiracy to deny consumers the benefit of this resource,” he said.
Hughes said ERCOT — which has a board seat reserved for industrial consumers — is the only governance structure his group likes. Industrials’ presence on the board means “you gain respect in the whole food chain,” he said.
PJM Study
Christina Simeone, director of policy and external affairs for the Kleinman Center for Energy Policy at the University of Pennsylvania, spoke about her May 2017 study on PJM’s governance, which asks “Can Reforms Improve Outcomes?”
Among her conclusions: PJM’s stakeholder process is very effective on less contentious issues but is less effective on the most contentious issues that are subjected to sector-weighted votes.
Because of affiliate voting, the lower committees are subject to a “huge supply-side bias,” she said, citing the now-closed Seasonal Capacity Resources Senior Task Force, where 190 votes were cast by 34 respondents. Just 10 companies can prevent any proposal from passing at the lower level, she said.
But while suppliers can muscle their proposals through the lower committees, she cited a Pennsylvania State University study that found a load-side bias at the upper levels, where End Use Customers and Electric Distributors have formed a tight voting coalition. “What ends up happening is all the proposed solutions are supply-side biased and then they get knocked down by the load-side bias at the higher level. This is a phenomenon I think we’re seeing more and more,” she said.
She said RTO management has an interest in preventing political backlash over price volatility and blackouts, “so the organization may seek to prevent those things, perhaps at any cost.”
She recommended that states have a vote through their governors and that PJM review the makeup of its five sectors, noting the dispersion of stakeholders representing the fastest-growing industry segments: renewable energy (Generation Owners), energy efficiency (Electric Distributors, Transmission Owners and Other Suppliers) and demand response (Other Suppliers).
“In competitive markets, new market entrants are very important. However, they’re being lumped in with everybody else and that does a disservice to both the larger firms and the new market entrants because of vote dilution. The larger the sectors get, the less impact any individual firm can have on the process.”
She said FERC should require RTOs to re-evaluate their governance process regularly to comply with the “ongoing responsiveness” principle of FERC Order 719.
FERC on Thursday rejected a rehearing of MISO’s subregional flow limits and accepted the RTO’s method for calculating the limits.
The commission declined to rehear its December 2016 dismissal of a complaint seeking to overturn the results of MISO’s 2016/17 planning year capacity auction. A coalition of transmission customers had argued that subregional transfer constraints where MISO flows must cross FERC Backs MISO on Transfer Limit, Seeks Details.)
MISO calculates the transfer limits between its Midwest and South regions by deducting firm reservations from 2,500 MW of available capacity flowing from South to Midwest and 3,000 MW estimated to be available in the opposite direction. The initial limits were set out in a settlement with SPP that became effective in early 2016.
| MISO
Several MISO stakeholders and the Independent Market Monitor argued that the RTO’s subregional constraint calculation is flawed, with a group of transmission-dependent utilities in Wisconsin arguing that the subtraction of all firm transmission service reservations “incorrectly assumes that those holding the reservations will use them all the time, even when it would be counter to their economic interest.” The Monitor agreed that the calculation is too conservative.
In its Nov. 16 order, FERC pointed out that while it’s possible that not all firm transmission customers will use their service simultaneously, it’s also possible they could.
“All parties appear to agree that the regional directional transfer limits established in the settlement agreement are a reasonable starting point for the calculations,” FERC wrote. “We agree … MISO’s proposal requires it to make two reductions, when applicable, to the regional directional transfer limits: (1) a reduction, based on a feasibility analysis, for reliability purposes; and (2) a reduction by the amount of firm transmission service reservations in the prevailing direction.”
Multiple companies submitted alternative proposals for calculating subregional constraints, but FERC declined to examine their fairness.
“There may be more than one just and reasonable methodology that MISO can use to calculate subbegional constraints. We need not analyze whether the various alternative proposals are also just and reasonable,” the commission said.
FERC also clarified — at WPPI Energy’s request — that its finding regarding the 2016/17 auction should not be construed as “conclusive proof” that MISO’s approved methodology will be considered the best course for future capacity auctions.
Monitor Concerned with Cost of Midwest-South Constraint
The order comes as the Monitor is reiterating concerns about the cost of the SPP contract path with respect to make-whole payments.
“We’ve been coming at MISO with concerns about the RSG [revenue sufficiency guarantee] on the North-South constraint for some time now,” Monitor David Patton said.
Patton said the constraint contributed to $3 million in revenue sufficiency guarantee payments in April 2017 alone.
“It’s a vexing constraint because it’s not a physical constraint; it’s an agreement,” Patton said during an October Market Subcommittee meeting.
He said the constraint created about $9 million in RSG payments from September through mid-October, with $6 million of that paid to a single company. “These are wasteful costs,” he added.
Earlier this year, MISO conducted a study to evaluate the benefits of constructing transmission to link the Midwest and South areas. The RTO concluded that not one of 35 potential projects could pass the 1.25-to-1 benefit-cost criteria based on adjusted production cost benefits. (See “No Tx Coming for North-South Constraint,” MTEP 17 Proposal: 343 New Transmission Projects at $2.6B.)
