Page 1198 – RTO Insider

March 16, 2018

Michigan Groups Contest Presque Isle Cost Allocation

By Amanda Durish Cook

In a case pending before a federal court early next month, Michigan regulators have joined with load-serving entities to challenge a 2016 FERC order that reallocated most costs for the Presque Isle system support resource (SSR) agreements to consumers in the state’s Upper Peninsula.

SSR FERC Presque Isle Cost Allocation — Presque Isle Power Plant

Under the suit filed with the D.C. Circuit Court of Appeals late last year, the parties contend that FERC decided to change the longstanding allocation of costs within MISO’s American Transmission Co. pricing zone covering northern Michigan and Wisconsin without substantial supporting evidence. The change saddled Michigan LSEs with surcharges that amount to retroactive rate increases, a practice prohibited by the Federal Power Act, the parties argue (15-1098).

The complainants include the Michigan Public Service Commission, Constellation Energy, Cloverland Electric Cooperative, Tilden Mining Co., the cities of Mackinac Island and Escanaba, Upper Peninsula Power Co., the Sault Ste. Marie Tribe of Chippewa Indians and Verso Corp.

Dueling Presque Isle Proceedings

In a separate but related proceeding, FERC last year ordered Presque Isle owner Wisconsin Electric Power Co. to refund Michigan LSEs $23 million in overcharges stemming from the SSRs over 2014/15. The commission last month accepted MISO’s plan to distribute those refunds. (See FERC Approves Presque Isle Refund Calculation.)

But in their case, the Michigan parties argue that the refunds are only part of the equation, considering that ratepayers now bear nearly all SSR costs for the coal-fired plant, which represents a break from MISO precedent. Under the original 2014 SSR agreement, costs to keep the plant running for reliability were allocated across the ATC zone, with Upper Peninsula ratepayers paying 8% and Wisconsin ratepayers responsible for the rest.

After two years and a complaint by Wisconsin’s Public Service Commission that the state was paying for a majority of the SSR but not receiving a majority of the benefits, FERC allowed MISO to shift 98% of the SSR costs to LSEs in the sparsely populated Upper Peninsula. That change in part stemmed from NERC’s 2014 decision to separate the Upper Peninsula from Wisconsin into its own local balancing authority. FERC at the time said it was unjust to allocate SSR costs on a pro rata basis to all LSEs in the ATC footprint, deciding that costs instead must be allocated to LSEs that require the operation of the plant for reliability purposes.

But the Michigan parties argue that, in reassigning the costs for the SSR, FERC improperly relied upon a preliminary load-shed study that showed Wisconsin receiving only 42% of the reliability benefits from Presque Isle, while a final study showed the state receiving 86% of the benefits.

The reallocation applies retroactively — back to 2014, which means that after receiving $23 million in refunds for the overpayment, Upper Peninsula ratepayers could then owe more than $20 million in retroactive surcharges to implement the change in SSR allocation. The Michigan parties contend that any surcharge is unlawful, but MISO has been cleared by FERC to begin assessing surcharges this month according to the same 10-month schedule for disbursing the refunds.

The D.C. Circuit will hear oral arguments in the case on April 6, with a decision expected by summer. The Michigan PSC and other complainants have filed for a temporary stay of MISO’s assessment of the surcharges while the case is being argued, contending that the “immediate implementation of surcharges to reallocate Presque Isle SSR costs threatens to impose significant irreparable harm on some Michigan LSEs.”

“If MISO begins to invoice surcharges this month, it is anticipated that LSEs paying such surcharges will include the surcharge amounts in their bills to retail ratepayers, assuming that is even feasible,” the PSC said.

‘Middle of the Game’

“This is a reallocation of costs where the surcharges arising from the reallocation will exceed the refunds due to the reduction in permissible SSR costs,” Bill Demarest, an attorney representing Tilden, said in an interview with RTO Insider. “The surcharges are to pay for reallocation of the SSR costs after the substantial reduction in costs ordered by FERC.”

Cloverland attorney Christine Ryan said the reallocation is unfair to Upper Peninsula ratepayers that have for years contributed to grid costs with Wisconsin.

“We can’t just change the rules in the middle of the game. Upper Peninsula customers have shared the costs of this system over the years,” Ryan said.

Demarest agrees, contending that Upper Peninsula ratepayers have subsidized transmission upgrades in the past that have benefited only Wisconsin ratepayers.

Complicating matters is whether Upper Peninsula ratepayers can afford to shoulder all Presque Isle SSR costs over MISO’s 10-month schedule.

“Our client Cloverland is a good example of the problem,” Ryan said. “They are small; they serve a rural population. That part of Michigan is economically depressed. This will be a significant charge that Cloverland will have to pass on to its customers. Administratively, this is a very difficult thing to manage.” If Michigan ratepayers are found to be almost exclusively responsible for the retroactive surcharges, LSEs face the prospect of calculating customer responsibility and tracking down those customers that have relocated during the intervening four years.

The two attorneys also argue that, in changing the historical allocation pattern for the purposes of the Presque Isle SSR, FERC ignored its own finding in Order 1000 to treat generation and transmission-based reliability solutions comparably.

“FERC was going against their own policies here, we pointed that out and they ignored that,” Demarest said.

March 16, 2018

NERC Names WECC Chief to Top Post

By Jason Fordney

NERC said Friday that it has appointed Western Electricity Coordinating Council chief Jim Robb as its new president and CEO, effective April 9.

nerd week jim robb — WECC CEO Jim Robb at the NERC Board of Trustees meeting in February | © *RTO Insider*

Robb, who has led WECC since 2014, has more than 30 years of experience as a power sector engineer, consultant and senior executive. He formerly served in senior roles at both Northeast Utilities (now Eversource Energy) and Reliant Energy.

“The board took this duty very seriously by engaging in a comprehensive, nationwide search culminating in the unanimous selection of Jim Robb,” NERC Board of Trustees Chairman Roy Thilly said in a statement. “We are confident that Jim will provide the combination of strong leadership, vision and commitment to the reliability and security of the bulk power system across North America that is essential to NERC’s continuing success.”

NERC has been without a CEO since Gerry Cauley stepped down last November after being arrested for allegedly assaulting his estranged wife, who told police he had been involved in a sexual relationship with a female employee at the agency. (See Cauley Resigns; NERC Launches Search for Replacement.)

Cauley had served as NERC CEO since January 2010 and was often the face of the reliability agency in hearings before FERC and Congress. NERC General Counsel Charles Berardesco has been serving as acting CEO.

As head of WECC, Robb led NERC’s largest Regional Entity, “where he improved member relations, strengthened the management team and expanded collaboration with NERC and other Regional Entities,” NERC said. WECC’s territory covers all or part of 14 Western states, Alberta and British Columbia in Canada, and the northern portion of Baja California in Mexico.

“I have been fortunate to lead WECC and be a part of the NERC-enterprise family for the past four years, and I look forward to the next chapter of my career leading the” FERC-certified Electric Reliability Organization, Robb said. “This experience, combined with my past industry knowledge, has prepared me for this exciting opportunity at NERC.”

WECC said it will search for a replacement for Robb over the next several months. It has appointed Vice President and General Counsel Steven Goodwill as interim CEO. Goodwill is not a candidate for the top job.

NERC WECC Jim Robb — WECC says it has embarked on a search for a new CEO (pictured are their Salt Lake City headquarters). | © *RTO Insider*

In a written statement, WECC Board of Directors Chair Kristine Hafner said Robb’s “unrelenting focus on effectively and efficiently reducing risks to the reliability and security of the bulk power system in the Western Interconnection has been vital to the 80 million people within our footprint who rely on power for their day-to-day lives.”

Salt Lake City-based WECC is in the midst of revamping its operations following its 2014 restructuring into the current WECC and Vancouver, Wash.-based Peak Reliability. (See WECC Finding New Direction in Old Mission.) Among the changes in the works to refocus the RE on its reliability functions is a renaming to Reliability West. Other changes in the organization’s bylaws are proposed for a possible June vote by WECC members.

March 15, 2018

PJM Responds to Pa. Concerns About Baseload Plants

By Rory D. Sweeney

PJM’s Board of Managers last week assured Pennsylvania legislators that the state has ample power generation for its needs and cautioned that fuel diversity will not ensure reliability.

The RTO was responding to a Feb. 9 letter from the state legislature’s Nuclear Energy Caucus with its own letter that seemed intended to assuage lawmakers’ fears about of blackouts and grid interruptions caused by inadequate resources. While the caucus’s message referred only to “baseload” units, it did voice support for several FERC and PJM initiatives that would benefit coal and nuclear plants.

Peach Bottom Nuclear Generating Station in 1974

“We are losing confidence in the ability of wholesale electric markets to ensure Pennsylvania maintains a diverse supply of baseload generation resources that ensure stable prices for our citizens and a reliable and resilient electrical grid,” the caucus wrote. “Pennsylvania’s baseload power plants continue to face the risk of premature retirement, and we do not see expeditious and sufficient action being taken by PJM or the Federal Energy Regulatory Commission to correct the market flaws at the heart of this problem — flaws that PJM itself acknowledges.”

PJM’s Independent Market Monitor noted last week in its 2017 State of the Market report that just 52% of coal-fired plants in the RTO recovered their avoidable costs in 2017. All of Pennsylvania’s five nuclear facilities made enough money to cover their costs last year, although none did in 2016, the report showed. Three Mile Island has seen negative revenues since 2015 and will continue to through 2020 unless market changes occur, while the other four will remain profitable through that year. (See IMM Report Says PJM Prices Sufficient.)

Adequacy Assured

PJM CEO Andy Ott penned the response to the caucus, which defended the RTO’s operations. Ott noted that Pennsylvania has built more than 12,000 MW of new generation over the 20 years that the RTO has managed its grid, calling it “a direct result of the investment signals sent by the PJM wholesale market.”

In the past six years, Pennsylvania has produced between 18 and 27% more energy than it needed, equating to about 6,500 MW of generation, or nearly two-thirds of the Keystone State’s nuclear fleet, Ott said.

While the caucus’s letter never mentioned costs, Ott remained focused on them, noting that “PJM markets have yielded reliability at the lowest cost for Pennsylvania.”

Diversity Necessary?

The caucus said its “concern has only been heightened by” the cold snap in January known as the “bomb cyclone.” (See PJM: Cold Snap Uplift Shows Need for Pricing Changes.)

“The dramatic increase in wholesale power prices during that period highlight the risk of overreliance on any single fuel source, a risk we believe PJM can and should avoid by swiftly enacting reforms,” the legislators wrote. “We believe that [PJM’s price-formation proposal] is an important first step in recognizing the benefits of fuel diversity within this market, and one that will help keep our grid — and power prices — stable for many years to come.”

Ott noted in his response that both the RTO and Pennsylvania are more fuel-diverse today than ever, but downplayed the significance of that fact.

“Fuel diversity, however, is not a metric with which PJM can measure reliability,” he said. “Instead, fuel security — the certainty of fuel availability for power production — affects reliability.”

Market Changes

The caucus supported PJM’s efforts to revise its energy price-formation methodology, calling the current process “a flaw in its market rules that unfairly disadvantages certain low-cost baseload generation resources” by not allowing them to set clearing prices. As a result, “market prices are artificially low and do not reflect the true cost of meeting customer demand.” It gave PJM “credit” for developing “a potential solution.”

The RTO’s solution is a controversial plan to allow large, inflexible units like coal and nuclear to set clearing prices. Currently, those plants’ bids are often among the highest of dispatched units, but only “flexible” units that can regulate their output in response to price signals are allowed to set prices. The inflexible units receive subsequent “uplift” payments to cover their operating costs. In PJM’s plan, those units would set price and the flexible units would be paid additional revenue to back down their output to avoid oversupply.

Critics of the plan argue that plants that don’t receive enough revenue in the competitive market should take that as a signal to shut down, not change the rules.

The caucus called the proposal “an important first step” but said it “will not fully correct the existing market flaws nor fully provide the compensation necessary to maintain baseload resources.” Still, a failure to implement the plan “will continue to inequitably exacerbate the financial challenges” those units face, the lawmakers said.

While Ott did not specifically address PJM’s price-formation proposal, he acknowledged “there is room for markets to more sharply define power grid requirements.”

“Efforts are underway to improve wholesale market price efficiency for all the resources that rely upon the wholesale market to compensate them for their services, and appropriately to provide transparent investment signals,” he assured the legislators.

Ott has previously said that the proposal would result in increased energy prices but decreased uplift and capacity prices. (See “PJM Pushes Price Formation Plan,” FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)

Monitor’s Position

In his market report, Monitor Joe Bowring said the changes were not based on market flaws. Nearly 79% of the $24.7 million in uplift costs from day-ahead operating reserve differences were paid to coal units in 2017, but not because of market design issues, he said.

“That actually has to do with some very specific circumstances about coal units that have nothing to do with convexity and non-convexity and would not be affected by PJM’s price-formation proposal,” Bowring said.

FERC Resilience

The caucus also applauded PJM’s proposal as “entirely consistent” with the state legislature’s resolution in October calling on FERC to address the U.S. Department of Energy’s Notice of Proposed Rulemaking to financially support baseload generation. FERC denied the NOPR request in January but opened a docket to investigate concerns about the resilience of the nation’s energy grid.

The caucus endorsed the new docket as “an early step” and said it plans to press for any recommended changes that emerge from it.

“We are encouraged that FERC valued our concerns,” the caucus wrote. “You should know that as elected lawmakers ultimately responsible for our commonwealth’s energy policy, we will engage in the discussion and strongly support urgent implementation of critical findings.”

March 15, 2018

Stakeholders Mull BTM Impact on MISO Tx Planning

By Amanda Durish Cook

CARMEL, Ind. — After six months of little progress, stakeholders are now asking MISO to consider changing its billing practices to reflect how behind-the-meter resources use the transmission system.

But the RTO says it’s still collecting stakeholder input before it develops an official stance on multiple BTM measures.

behind-the-meter transmission planning miso — Webb | © *RTO Insider*

“In large part, we’re still in listening mode here,” MISO Director of Planning Jeff Webb said at a March 14 Planning Advisory Committee meeting.

The RTO is still working with stakeholders to determine whether it should account for net or gross BTM load when it assesses network integration transmission service.

“I think that’s the debate here: whether behind-the-meter uses the transmission system for load, uses it sufficiently enough or uses it on peak,” Webb said. “Under what circumstances are costs incurred [from load typically served by BTM generation] when building the transmission system?”

The RTO must also settle on planning study assumptions for both registered and unregistered BTM generation and determine whether BTM retirements should be subject to a formal Attachment Y notice and subsequent reliability studies.

Last year, WEC Energy Group proposed that all resources be required to register with MISO as a network resource before being authorized to fulfill capacity obligations. That proposal aligns with an existing RTO plan to implement a one-time deliverability test for BTM generators that could trigger a requirement to acquire network service in an upcoming capacity auction. (See WEC Takes Stab at MISO Behind-the-Meter Definition.)

behind-the-meter transmission planning miso BTM — The MISO Planning Advisory Committee met on March 14 | © *RTO Insider*

Webb said MISO will continue to discuss how to plan for BTM generation at the PAC’s April meeting and that the conversation would likely extend until the end of the year.

“We’ll make some sort of strawman proposal and let people beat up on that for awhile until we get something,” Webb said. “Let’s keep the dialogue going here.”

Stakeholders: Tx Charge Rewrite?

The question of how to bill BTM generation for transmission use sparked a larger conversation on revising transmission use charges in the face changing load shapes in MISO.

Veriquest Group’s David Harlan said MISO is headed for a future of more complex and “spiky” load shapes attributable in part to BTM generation, possibly requiring the RTO to reassess how it bills for transmission use.

“In the past we’ve expected load shapes to be fairly predictable and planned around peak. I think what we’re increasingly seeing is that when you connect to the transmission or distribution system, there’s an option value. You can either inject or withdraw. What’s the proper way of accounting for that option right?”

Wisconsin Public Service’s Chris Plante said his company has also been discussing a more nuanced approach to transmission billing.

“I think more and more we’re not just building transmission for the peak, but for energy withdrawal,” Plante said.

Representing Illinois Industrial Energy Consumers, Jim Dauphinais said he’d like to see the transmission charge issue contained within the broader BTM subject, noting that MISO’s Regional Expansion Criteria and Benefits Working Group is responsible for proposing transmission cost-sharing policies.

Webb said he supported limiting the issue to how MISO plans for and bills for BTM generation ― for now.

“I think maybe we bite off what we can here,” Webb said. “I think we’re in a — every generation says this — but we’re in a transitional period. There’s growing uncertainty about the load that we plan for.”

March 15, 2018

CAISO Day-ahead Could be Tailored for West

By Jason Fordney

LOS ANGELES — CAISO’s proposal to extend its day-ahead market across the Western Energy Imbalance Market (EIM) could be tailored to uniquely fit a region historically resistant to organized markets, a key participant in the roll-out of the EIM said.

The ISO’s Extended Day-Ahead Market (EDAM) proposal could also be done without the political and economic entanglements involved with an RTO, Portland General Electric Director of Transmission Services Sarah Edmonds said during a March 9 public meeting of the EIM Regional Issues Forum (RIF). It could strike a balance between an ISO transmission access charge and a full RTO construct, she said.

“It is possible that with EDAM, a different construct will be born,” Edmonds said, adding that her comments reflected her own opinions, but they are “illustrative of the kinds of questions and issues the EIM community would be looking at” to determine their interest in day-ahead market participation.

In her previous job as general counsel for PacifiCorp, Edmonds served on the EIM’s Transitional Committee, which advised CAISO’s Board of Governors on the development of the market’s governance structure.

Sarah Edmonds Day-ahead market western RTO CAISO — The Western EIM Regional Issues Forum met last week in Los Angeles | © *RTO Insider*

A “winning feature” of the EIM has been that participating balancing authority areas retain their responsibilities and control, Edmonds said, pointing also to the benefits of voluntary participation and no exit fee. But as they explore EDAM, industry participants will need to address the many issues around how excess transmission capacity is shared. (See CAISO Plan Extends Day-Ahead Market to EIM.)

As for an RTO, the issue of governance — which was still being debated in the California legislature when last year’s regionalization effort stalled — is “center stage,” Edmonds said. Lawmakers are working on new legislation this session. (See Calif. Lawmakers Relaunch CAISO Regionalization.)

Governance is important because “the power of who gets to decide what issue is a big deal when you are talking about what comes with a full regional ISO,” Edmonds said.

Industry stakeholders still have many questions about transmission development and costs in a Western RTO because of the longer transmission lines, distance between loads and other planning considerations such as increased adoptions of distributed energy. Other complications include state roles in resource adequacy planning, transmission access charges and a regional transmission planning framework, she said.

“These issues really come up and are of particular concern in a regional ISO context,” she said, adding that there is also a “deeply ingrained culture of self-determination in the West.”

‘A Lot of Work’

Kathy Anderson, Idaho Power systems operations leader, told the RIF that her utility has been working on EIM implementation for two years and is due to go fully live on April 4, having shifted the date from April 1 because of the Easter holiday. One of the uses of the market will be to market renewable energy from qualifying facilities under the Public Utilities Regulatory Policies Act.

Sarah Edmonds Day-ahead market western RTO — Anderson | © *RTO Insider*

Anderson told the forum that the two-year process to integrate into the EIM has not been easy.

“I don’t think I really appreciated it until I was right in the middle of it. It was a lot of work,” Anderson said. “There were very few places in the company that we didn’t touch with this.”

The company employed three full-time external contractors and hired 6 employees to work directly on the EIM. It also required new software applications and outage management system.

Idaho Power and Canadian marketer Powerex have been in parallel operations with the EIM, in preparation for going live early next month. (See EIM Participants Seek Resource Test Tweaks.)

March 14, 2018

Updated: SPP Begins Work of Integrating Mountain West

By Tom Kleckner

SPP’s Board of Directors and Members Committee on Tuesday approved a set of conditions that will guide Mountain West Transmission Group’s pending membership into the RTO.

SPP said the board’s endorsement during a special meeting in Dallas represents “a vote of confidence in the value of Mountain West’s membership and the benefits it will bring to SPP’s existing members, the Mountain West entities” and their customers.

SPP Mountain West Transmission Group — Platt River Power Authority’s Andy Butcher shares details on his company with SPP stakeholders in July | © *RTO Insider*

COO Carl Monroe, who has been leading the RTO’s team during the negotiations, told RTO Insider he has been pleased with the work so far.

“We have been able to alleviate some of [Mountain West’s] concerns with joining SPP,” Monroe said Wednesday. “We’ve been able to work together and move forward. We’re pleased to come to this point, where we have general agreement of the things that are required to have Mountain West join SPP.”

The board approved 18 policy statements and directed staff and stakeholders to begin revising SPP’s Tariff, bylaws, membership agreement and other governing documents. The RTO’s Corporate Governance Committee and working groups will coordinate the work through the normal stakeholder process.

Changes to SPP’s Governing Documents Tariff will be presented for approval by stakeholder groups prior to going to the Members Committee and board.

The policies govern the terms of SPP membership, governance, the cost to operate the four DC ties in the SPP footprint, transmission planning and resource adequacy, and rates and revenue. SPP’s Regional State Committee would be expanded to include state commissioners from the Mountain West region.

SPP has scheduled a webinar on March 22 to provide further detail on the policies.

SPP and Mountain West members have been meeting behind closed doors since October to discuss the move. Monroe told stakeholders in January that a small negotiating team had been working to resolve a subset of “real contentious” issues. The Mountain West entities have suggested several governance changes important to their side of the footprint. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)

Mountain West has said studies have shown participating in SPP’s markets and efficiently using the DC ties between the two footprints would yield annual savings of $80 million to $154 million for its members. The entities also expect to realize additional benefits from regional transmission planning and SPP’s other services.

SPP has estimated its current members could receive more than $500 million in total net benefits over the first 10 years of Mountain West’s membership through reduced administrative costs because of a larger customer rate base, adjusted production cost savings from east-west energy exchanges and capacity cost savings from increased load diversity.

The RTO projects it will take about two years to fully integrate the Mountain West entities as members, but it plans to begin reliability coordination services in late 2019.

SPP currently serves a 546,000-square-mile, 14-state region. Mountain West’s membership would add 165,000 square miles, 16,000 miles of transmission lines, 21 GW of generating capacity and parts of three more states (Arizona, Colorado and Utah) to the RTO’s footprint.

Mountain West, which primarily services Colorado, Wyoming and Nebraska, began discussing RTO membership in 2013. It announced in January 2017 it was pursuing membership in SPP, and discussions entered a public phase in October. (See SPP, Mountain West Integration Work Goes Public.)

March 14, 2018

Emissions and Dispatch Top Talk at NY Task Force

By Michael Kuser

New York stakeholders on Monday wrestled with the complex issue of how to evaluate the impact of a carbon charge on the dispatch of energy resources — especially in neighboring regions.

It was part of an ongoing effort by the Integrating Public Policy Task Force (IPPTF) to determine how to price carbon emissions into NYISO’s wholesale electricity market.

The group, a joint effort between N Y IS O and the state’s Department of Public Service, also discussed a method for calculating marginal emission rates, the allocation of carbon revenues and the effect of carbon pricing on customer bills — all part of “Track 5” of the carbon pricing initiative.

IPPTF NYISO RGGI Carbon Charge — | *PJM*

The group also touched on issues related to “Track 4,” which covers the interaction of carbon pricing with other state and regional programs, such as the renewable energy credit and zero-emissions credit programs, as well as the Regional Greenhouse Gas Initiative.

Assumptions and Metrics

“We are interested in looking at not just the financial impacts but also at what happens to emissions,” said task force co-chair Nicole Bouchez, NYISO market design specialist.

“How do we assume the cases?” Bouchez asked. “Do we assume there’s a change in RGGI or not? In realization that we’re not going to be able to run dozens of permutations, what are the key assumptions?”

If the group “ends up modeling emissions in neighboring regions, for example in Ontario, which trades with MISO, then you have to model all of MISO’s resources,” she said. “While Ontario may look like a low-carbon import … if all it’s doing is causing MISO coal use to go up, then not so much.”

Marc Montalvo, representing the DPS Utility Intervention Unit, said, “If we’re designing a policy and implementation, if success is highly dependent on having perfect or near-perfect information about our neighbors’ emissions rates and those kinds of things, then it’s probably not a good policy in the first instance.”

Bouchez said the group’s May 7 and 21 meetings would focus “on how to structure the analysis, what questions, what metrics we’ll be reporting, etc.”

Defining Impacts

During a discussion of the impact of carbon pricing on consumer costs, Bouchez said the ISO’s locational-based marginal pricing (LBMP) represents “only the beginning of impacts on consumers because we’re also going to be looking at the return of these residuals associated with a carbon charge to consumers, so you can’t just look at the LBMP increase on its own.” The “residuals” refer to leftover money refunded to load under a carbon pricing scheme.

Representing a coalition of large industrial, commercial and institutional energy users, Couch White attorney Michael Mager said his clients were seeking “two big things” from the impact analyses. First, “a thorough, unbiased analysis” of the impacts on market prices and what consumers are paying.

“And the second piece is, what are the emission reductions, if any, that reasonably could be anticipated if this were to be done,” Mager said.

New York could see some really material carbon reductions if it starts retiring unused RGGI allowances, he said.

“On the other hand, if nothing is being done to RGGI whatsoever, and it’s just going to simply reduce the price of allowances that are going to be then used up by other states such that there’s little to no reduction in carbon throughout the RGGI region, then this whole effort strikes us as somewhat symbolic and not getting much for any price impacts,” he said.

Howard Fromer of PSEG Power New York asked, “Consumer impacts compared to what?

“And the what is not identified here,” Fromer said. “Obviously, the what, in my mind, has to include the fact that New York state right now is already spending and writing checks on a monthly basis and potentially, over the period that we’re talking about, could be spending billions of dollars.”

Fromer said that, aside from considering dispatch issues, the task force process also needs to consider the impact of a carbon charge on price signals, demand response and investment in the state’s 40,000-MW generation fleet.

No Pot of Money

Stakeholders asked how the trend of increasing electrification — in the transportation sector, for example — should affect pricing carbon into the wholesale market.

Bouchez said many experts have told her the price of electricity has very little to do with electrification.

Bob Wyman of Dandelion Energy countered that electricity prices definitely affect consumer choices in New York City, where Consolidated Edison learned that city residents who install heat pumps use them for air conditioning but simply turn them off in winter because of high electricity prices for heating.

“Whether this approach is complementary or designed to supplant the mandated programs [such as the state’s Clean Energy Standard] … to the extent that you are supplementing the existing programs, the issue is always about what are the incremental benefits, does it affect dispatch, new investment, how are the effects by zones, and you have to address those transition overlap and windfall revenue questions as part of the impact analysis,” said James Brew of Nucor Steel Auburn.

He said New York is relatively unique in trying to pursue both mandated and market programs, which means any analysis has to examine how the two programs interact.

David Clarke, director of wholesale market policy at the Long Island Power Authority, said carbon revenue collections within RGGI states would be a useful metric for examining the cost of abatement.

“I know we’re going to be looking at how much folks are paying for carbon allowances within New York as kind of the pot of money that we’re going to be splitting, but it would also be useful, depending on what scenario you are running, to find out what folks are collecting in terms of RGGI revenues within the other RGGI states,” Clarke said.

“There will be no pot of money,” Bouchez said. “I’ve been talking about them as residuals, which is how NYISO sees them, residuals being the difference between what we collect and what we pay out. How you allocate that within the wholesale settlements is a question. Do you give it back on a per-megawatt-hour basis? Do you give it back based on the impact of the increase in the LBMP?”

Warren Myers, DPS chief of regulatory economics, said that the joint staff are “nowhere near having an answer” on how to integrate multiple analyses into something useful but that “the work would get done by rolling up our sleeves” over the next few months.

The task force will next meet on March 19 to discuss Track 5 at NYISO headquarters.

March 14, 2018

MISO Cleared to Collect More Customer Info

By Amanda Durish Cook

FERC on Monday approved MISO Tariff revisions allowing the RTO to gather more information about proposed energy resources before they enter the interconnection queue.

Key among the changes is a requirement that a developer provide clearer upfront information about who will own a generating unit once its clears the queue.

In its ruling, FERC agreed the changes will “provide greater clarity to interconnection customers and greater transparency to all parties in the interconnection process” (ER18 –636). The new measures became effective March 1.

MISO FERC SPP Tariff attachment Z2 Western RTO — | © *RTO Insider*

Under the new rules, interconnection customers must provide MISO upfront documentation of “legally binding relationships” with parties that may claim ownership rights to a facility during the interconnection process.

MISO said the change will reduce the time it spends confirming ownership changes and will be necessary only when an interconnection customer “reasonably anticipates” another entity may claim ownership rights. The documentation would be limited to “that necessary to confirm the legal status and relationship of the relevant entities,” the RTO said.

Interconnection customers associated with a project can sometimes change during the definitive planning phase (DPP) of the interconnection queue, MISO said in its filing. In those cases, the RTO must confirm the legal status and relationship between the original and newly designated interconnection customers, creating an “administrative burden … that hinders the ability of MISO staff to administer other aspects” of the DPP.

“Requiring documentation proving legally binding relationships with entities that the interconnection customer reasonably anticipates may claim rights under the interconnection request upfront in the interconnection request form will ease administrative burden if a facility changes ownership later in the interconnection process,” FERC said, adding the change will help expedite projects moving through the DPP.

The commission rejected EDF Renewable Energy’s protest that MISO didn’t justify its need for the additional detail and that the changes would give the RTO more information than it needed. The company alternatively proposed that interconnection customers provide MISO with documentation “confirming a legally binding status upon requesting a name change,” rather than at the outset of the process. FERC said EDF was conflating name changes with changes in ownership status.

The Tariff revisions also require interconnection customers to provide MISO with IRS W-9 forms; banking information (including for other companies that may claim ownership in a generating facility); GPS coordinates for the point of interconnection for a project; descriptions of the number of generators, inverters, and transformers involved in the interconnection request; and additional contact information when a customer uses an agent.

They also expand the service options listed on MISO’s interconnection request form, allowing customers to specify a net-zero interconnection service request for an existing facility with no increase in capacity; indicate whether a request should be considered for the RTO’s fast-tracked process offered to small generating facilities; and inform MISO when a request for network resource interconnection service is intended for an existing facility.

The new rules additionally stipulate that net-zero interconnection customers must attach a system impact study to their requests and provide MISO with all necessary data before generator interconnection agreement negotiations can begin.

March 14, 2018

MISO Plan Provides Tx Treatment for HVDC Lines

By Amanda Durish Cook

CARMEL, Ind. — MISO and its stakeholders have agreed on a plan to treat merchant HVDC lines as transmission instead of generation when physically connecting to the RTO’s system.

A year in the works, the proposed Tariff revision would subject merchant HVDC lines to MISO’s traditional transmission schedule charges and make them ineligible for interconnection service. The RTO will file the proposal with FERC by the end of this month.

merchant hvdc lines miso — Godbole | © *RTO Insider*

Speaking at a March 14 Planning Advisory Committee meeting, MISO Director of Resource Utilization Vikram Godbole said the proposal does not prescribe any revenue plans for developers of merchant HVDC service. Developers would instead be responsible for determining the “net economic viability of their merchant HVDC project by considering their revenue streams and cost to connect to MISO transmission,” he said.

Some stakeholders asked how the RTO will treat transmission upgrades needed to connect HVDC lines in the interconnection queue.

“They’re not going to have interconnection rights,” Godbole said, adding that the lines will instead connect to the MISO system at a 0-MW status.

Under the changes, MISO will hold discussions with HVDC developers and owners before grid connection to determine whether a line is designed to withdraw or inject energy into the system, Godbole said. The RTO will require upstream generators contracting with injecting lines to procure network resource service through the interconnection queue, subject to system impact studies. Those units will be modeled like MISO’s other network resources, showing up in planning studies. Merchant HVDC customers that have secured injection rights and interconnection customers will share the costs of any needed network upgrades.

Meanwhile, merchant HVDC developers will be required to acquire MISO injection rights or a precertification that the system will be able to reliably handle the capacity and energy from proposed lines at the point of connection. (See “HVDC Interconnection,” MISO Eyes Small Queue Changes, Merchant DC Interconnections.)

Godbole acknowledged that MISO may eventually need to develop a more nuanced connection plan for merchant HVDC lines, but that, for now, it is focused on allowing such lines to connect to the system.

March 13, 2018

PJM PC/TEAC Briefs: March 8, 2018

PJM TEAC Duff-Rockport-Coleman project RTEP — Kern | © *RTO Insider*

VALLEY FORGE, Pa. — PJM’s plan to switch which side of a transformer is considered for cumulative ramping impact is “a win-win” because it models the system better without implicating expensive upgrades, the RTO’s Jonathan Kern explained to stakeholders at last week’s Planning Committee meeting.

The RTO was proposing to include in its calculations only transformers whose lowest terminal voltage level is at least 500 kV rather than any whose high side is at least 500 kV. PJM justified the change because distribution factors for transformers are generally closer to the lower-side system they connect to than the higher side. The plan was part of a larger package of revisions to Manual 14B developed through an annual review. Stakeholders endorsed moving the proposal to the Markets and Reliability Committee but not before examining PJM’s determinations.

Kern said an analysis found that two transformers — the 500/138-kV Wescosville and 500/230-kV Ladysmith — could potentially be overloaded by the change at a cost of $18 million and $25 million, respectively. He said the change would only take effect starting with the 2023 Regional Transmission Expansion Plan, an initial analysis of which doesn’t show any impacts.

“There’s very strong evidence for the technical change we’re proposing to make here,” Kern said. “To us, it appears like a win-win change. In other words, it’s meeting the obvious technical intuition we have for generation delivery but also not creating any new overloads.”

However, American Municipal Power’s Ryan Dolan reminded everyone that no cost increases come without impact.

“I would argue that over $30 million of required upgrades wouldn’t be minimal,” he said.

External Capacity

PJM’s Aaron Berner successfully urged stakeholders to endorse rule revisions that would allow pseudo-tied external resources wanting to offer into the RTO’s capacity auctions to deliver into the energy market any additional generation beyond what’s authorized for capacity.

The RTO’s rules for external resources impose requirements that can limit how generation those units can offer into the Reliability Pricing Model.

“That doesn’t mean though that the transmission service is not deliverable for energy use,” Berner explained. “So with the addition of this language, the studies that PJM performed previously or would perform for new generation would still allow that generation to be delivered as transmission service for participation in the energy market.”

The revised language was added to changes developed for Manual 12 to address pseudo-tied capacity resources. Berner fielded several clarifying questions before stakeholders requested that PJM add detail to their proposed revisions.

“The current language does not explain in detail what you explained,” said James Manning with the North Carolina Electric Membership Corp.

Berner agreed to work with stakeholders on that issue, but he asked that they endorse the intent of the revisions so it can move on to the MRC.

Limiting Meetings Causing Stakeholder Strain

In explaining why proposed revisions to Manual 21 were only presented at the Planning Committee, staff said they were only trying to comply with stakeholder requests to limit meetings.

PJM’s Jerry Bell explained the revisions, which would change how generators are tested to receive and retain capacity interconnection rights (CIRs). Stakeholders argued that the changes are wide-ranging, requiring input from experts who don’t typically attend committee meetings, and asked why the considerations hadn’t been put to a task force or other high-level committees.

“This is really a generation operations issue, but we’re looking at it in the Planning Committee. We’ve got mostly transmission planners in the room here. We really need to expose this to all of the people this is really going to affect,” FirstEnergy’s Jim Benchek said. “These changes are pretty major.”

“I don’t necessarily think there’s any ill intent here, but it’s just that sometimes what looks to be just something for the Planning Committee has broader impacts,” said Adrien Ford with the Old Dominion Electric Cooperative. She suggested that PJM’s problem statement/issue charge process could have arrived at a result faster because the necessary stakeholder groups could have been identified up front.

“We’re trying to balance the needs of the stakeholders where we’ve gotten feedback about having too many other meetings and having the agendas jammed and the days of the week jammed with other meetings,” said Ken Seiler, who chairs the Planning Committee. He said he would confer with the chairs of the Operating and Market Implementation committees about how to handle the requests.

Stakeholders noted several concerns with the proposal, which would eliminate June from the summer testing period (leaving July through August) and require simultaneous testing of all resources at a plant except wind and solar units. They would have to be able to start within five minutes.

“If you were to call on all the units at a plant and apply the test simultaneously, the start-up costs could get quite expensive,” Benchek said, adding that his company didn’t favor the reduced testing period either.

Solar and wind would be exempt because they use their average capacity factor during the peak hours included in the testing, but all capacity factors will be determined by calculating the median rather than average performance going forward. Bell confirmed those calculations won’t become fully effective until 2021/2022.

Mike Borgatti with Gabel Associates was concerned that the proposed language changes didn’t adequately enunciate that units’ capacity factors wouldn’t be affected for three years.

Bell also walked stakeholders through analysis that shows that the 650 MW of non-dispatchable hydro generation might be overstated by 520 MW because the expected capacity factor of 20% shows that 130 MW is predicted to be available.

AEP Project Removed from RTEP Modeling

American Electric Power’s portion of Duff-Rockport-Coleman project has been placed on hold and will not be modeled in the 2018 RTEP, PJM told the Transmission Expansion Advisory Committee on Thursday.

Robert Bradish, AEP’s vice president of transmission grid development, informed PJM of the change in a letter Feb. 20. Bradish said the supplemental project was proposed to address voltage stability limitations and eliminate the special protection scheme at the Rockport plant by interconnecting the Rockport 765-kV station with the MISO Duff-Coleman 345-kV market efficiency project.

“The current generation situation at Rockport plant is quite different from the situation when this supplemental project was included in the 2015 RTEP,” Bradish wrote. “There is currently significant uncertainty regarding generation-related conditions which may affect future operation of the Rockport units. Certain of these generation conditions can only be addressed through coordination with third parties, regulatory proceedings and other circumstances outside of AEP’s control.”

Retirement Studies Update

PJM has completed reliability analyses on retirements at six generating stations and is conducting reviews for three others.

The retirements of Buggs Island 1 and 2 (138 MW), Bremo 3 and 4 (227 MW), and Bellemeade CC 1 (265.7 MW) are all effective April 16; Possum Point 3 and 4 (317.7 MW) and Chesterfield 3 and 4 (262.1 MW) are both scheduled for Dec. 1. PJM said it has asked Dominion Energy, the transmission owner for all the plants, to perform additional analysis to identify any required upgrades.

PJM said it identified no impacts from the scheduled May 3 closing of Evergreen Power United Corstack (25 MW) in Met Ed.

It is conducting analyses on the Morris Landfill Generator (1.9 MW) in ComEd and the Reichs Ford Road Landfill Generator (1.7 MW) in APS, both set for May 31, as well as FirstEnergy’s Pleasants Power Station 1 and 2 (1,278 MW), scheduled for Jan. 1, 2019. (See FirstEnergy Shutting down Unsold Coal Plant.)

Market Efficiency Update

PJM planners have selected a $25.4 million proposal by Baltimore Gas and Electric to address constraints on the Conastone-Graceton-Bagley 230-kV corridor after finding it cleared their reliability and cost/constructability analyses. The project (proposal 5E), which involves reconductoring and upgrades to equipment at the Conastone and Windy Edge substation, is expected in service in 2021. It will be recommended for approval at the Board of Managers meeting in April.

Planners said they won’t be recommending any market efficiency projects in the PPL zone after seeing the projected congestion benefits from the proposed Susquehanna–Harwood drop by about half under the base case because of a lower load forecast and changes in generation expansion since the start of the 2016/17 project window.

PJM is now developing assumptions for its 2018/19 RTEP long-term window, which it expects to open between November and February 2019.

Officials also said they expect to open a 60-day reliability project window in May or June.

— Rory D. Sweeney & Rich Heidorn Jr.