Page 1038 – RTO Insider

May 20, 2019

PJM Revisits Gas Pipeline Contingency Plan

By Christen Smith

VALLEY FORGE, Pa. — PJM asked for stakeholder feedback last week about how to reshape its gas pipeline contingency plan, three months after FERC turned it down for lacking specificity and clarity.

“We talked with FERC staff to get a read on what they want to see in a new proposal,” Thomas DeVita, PJM senior counsel, told the Market Implementation Committee on Wednesday. “We got an insight to their thinking. … The key point is the commission wants to see a meeting of the minds between generators and pipelines.”

On Feb. 19, FERC rejected the stakeholder-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or alternative fuel source because of pipeline breaks or the loss of compressor stations (ER19-664). The proposal included nine cost categories of switching costs, including park-and-loan service charges and overrun charges.

PJM’s Market Implementation Committee meeting on May 15 | © *RTO Insider*

The commission said PJM’s definition of penalty was “unreasonably narrow and unsupported” because pipeline tariffs delineate between penalties and fuel-switching costs in different ways, meaning what appears to be an appropriate cost for one pipeline could be considered a penalty for another. FERC also faulted PJM for not including events that might trigger fuel-switching directives in its Tariff and for lacking procedures for dealing with such contingencies through the Capacity Performance market design. (See FERC Rejects PJM’s Gas Contingency Pipeline Proposal.)

DeVita said commission staff discouraged PJM from submitting an itemized list of switching costs, as it did in the first filing, and instead focus on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs. Rich Brown, manager of PJM’s system operator training, said FERC’s focus on authorization and fuel burned reflects the commission’s insistence on ensuring reliability is maintained during any switch.

David “Scarp” Scarpignato of Calpine said that approach would not protect his company’s interests.

“I’m not comfortable that we just leave it open and send it to FERC with no guidance on what’s a coverable cost and what’s not,” he said. “Just getting over the hurdle of notice is not enough to give us confidence that our costs will be recovered.”

In a January filing with FERC, Duke Energy and East Kentucky Power Cooperative said they generally supported the idea of compensating generators for switching fuels, but they worried that PJM’s enumerated categories didn’t capture all the possible costs. Without an exhaustive list, they said, generators lacked financial incentive to make the switch or the ability to recoup expenses after-the-fact.

Marji Philips, Direct Energy’s director of RTO and federal services, told the MIC that if generators know PJM will order the switch — instead of generators making the call themselves — the cost of fuel switching is transferred to customers instead. The filing isn’t clear as to whether generators who can’t perform will incur CP penalties, either, she said.

“This is so fundamentally flawed,” Philips said. “It is not pipelines that do the switching. It’s whoever owns the capacity on the pipeline. We need to rethink this and reframe how we think about this.”

The Independent Market Monitor and the PJM Industrial Customer Coalition further alleged that the RTO’s gas-electric coordination remains an information-sharing process, therefore PJM can’t give operational instructions to pipelines. Moving customers with firm contracts off some pipelines — while others with lower levels of service remain unaffected — may discourage the former group of market sellers from taking proper steps to obtain reliable back-up fuel sources, they said.

The D.C. Office of the People’s Counsel crafted the Operating Agreement and Tariff changes detailed in the rejected filing after earning a majority of stakeholder support at the December meeting of the Markets and Reliability Committee.

The supermajority vote was a victory for load interests who opposed a Calpine-authored plan endorsed at the MIC in November. That proposal would have developed a formula for cost recovery to be filed with FERC that did not include pipeline penalties.

Although ongoing services generally include cost recovery formulas, DeVita said FERC may interpret the “rare” event of generators seeking fuel-switching reimbursement as incomparable.

“We are very concerned about cost to load,” said Adrien Ford of Old Dominion Electric Cooperative. “We are also very concerned about generators mitigating their own risk. We are in no man’s land now.”

May 20, 2019

FERC Ends Notices of Alleged Violations

By Michael Brooks

WASHINGTON — FERC on Thursday officially rescinded its controversial policy of allowing its Office of Enforcement to publicly disclose its investigations of possible misconduct and their subjects’ identities, ending a practice in place since 2011 (PL10-2-003).

The commission in 2009 authorized Enforcement to issue a Notice of Alleged Violations (NAV) after the subject of an investigation had the opportunity to respond to the office’s preliminary findings. Enforcement issued its first five NAVs on Jan. 25, 2011, four of which dealt with alleged market manipulation in ISO-NE’s Day-Ahead Load Response Program.

NAVs, however, were not like indictments: They were issued before Enforcement staff had finished their investigations and reached their conclusions in the case. Prior to 2011, the commission only disclosed the existence of an investigation and its subjects’ identities when it approved the issuance of an Order to Show Cause (OSC). NAVs also did not need to be approved by the commission itself; instead, they were issued after approval from the director of enforcement.

FERC said it had “acknowledged the potential risk of reputational harm that might result from the issuance of a NAV but sought to strike a balance between protecting the confidentiality of investigations and promoting the public interest of heightened transparency.”

But the commission found that issuing NAVs generated little information for Enforcement’s investigations. And since the policy’s adoption, the commission found that other sources, such as data provided by RTOs under Order 760, have been more useful.

“Accordingly, the commission finds that the potential adverse consequences that NAVs pose for investigative subjects are no longer justified in light of the limited transparency NAVs have generated and the more effective, alternative means of adding transparency that the commission has developed since the NAV order.” These means include providing guidance through orders on settlement agreements, OSCs and orders assessing civil penalties.

At FERC’s open meeting Thursday, Commissioner Richard Glick said the policy had been unofficially ended for some time. Indeed, the last time Enforcement issued a NAV was in April 2018, the only one that year. (See FERC Investigation Shows PSEG Violated PJM Bidding Rules.) Prior to that, the office on average issued seven to eight per year.

While Glick acknowledged that NAVs had provided limited value, and joined in the unanimous vote to end the practice, he said that “the Office of Enforcement must act aggressively when there is evidence of market manipulation or other malfeasance that could adversely impact our jurisdictional markets, and I intend to review any future proposals affecting Enforcement’s role with that in mind.”

Asked by reporters after the meeting whether the commission was considering any other changes to Enforcement policies, Chairman Neil Chatterjee declined to comment.

May 20, 2019

FERC Approves Expansion to Freeport LNG Export Terminal

By Michael Brooks

WASHINGTON — FERC voted 3-1 on Thursday to approve the construction of a fourth liquefaction unit at the Freeport LNG export terminal in Brazoria County, Texas (CP1 7 -470).

The unit, called a “train” in the LNG industry, will allow for the export of an additional 5.1 million metric tons per annum (mtpa), equivalent to about 0.74 Bcfd. Currently, the facility has a capacity of 15.49 mtpa (2.14 Bcfd), according to FERC.

The approval of the so-called Train 4 Project marks FERC’s fourth approval of an LNG project this year, following last month’s approval of the Driftwood and Port Arthur projects, and February’s approval of the Venture Global Calcasieu Pass project. And as has become common, the order elicited celebration from Chairman Neil Chatterjee, a reluctant concurrence from Commissioner Cheryl LaFleur and a dissent from Commissioner Richard Glick over the commission’s reticence to assess the project’s impacts on global climate change.

“I’m proud of the efforts by the commission and its staff to process today’s and our previous LNG orders,” Chatterjee said in a statement. “Exporting LNG from the United States can help increase the availability of inexpensive, clean-burning fuel to our global allies who are looking for an efficient, affordable and environmentally friendly source of generation.”

FERC disclosed in its order that its environmental assessment (EA) of Train 4 estimated that operation of the project may result in emissions of up to 491,500 metric tons per year of carbon dioxide equivalent, increasing national emissions by about 0.01%. “Currently, there are no national targets to use as benchmarks for comparison,” the commission said.

This was enough to secure LaFleur’s vote, though she warned that the order, as with previous LNG approvals, are vulnerable to judicial scrutiny. She also noted that an additional risk existed for Train 4 because the commission issued an EA instead of an environmental impact statement (EIS). Under the National Environmental Policy Act, federal agencies issue an EIS when they find that an action will have a significant impact on the environment.

“This tension between the finding of no significant impact, and the commission’s failure to assess significance of climate change impacts, heightens the risk that a court could vacate and remand this project, simply on the basis of which environmental document was prepared,” LaFleur said in her concurrence.

At Thursday’s meeting, Glick noted that Chatterjee has said that the Natural Gas Act doesn’t give the commission authority to analyze the impact of natural gas infrastructure on climate change. He then turned and appealed directly to Chatterjee, suggesting that they “work together to send some draft legislation to Congress to fix the problem and clarify that FERC does have such authority.”

Asked by reporters about Glick’s remarks after the meeting, Chatterjee dismissed the idea, saying “there is a 0% chance that such legislation could get through the United States Senate. We have so many things to focus on, that to me is not a worthwhile thing to spend time on.”

Commissioner Bernard McNamee said the approval was “another great achievement.” He emphasized “that we have considered all the environmental effects, including greenhouse gases. I know there’s a disagreement about … how those should be measured. … But a disagreement about that does not mean they were not considered.”

May 20, 2019

Refund Hearing Ordered in Pseudo-Tie Complaint

By Amanda Durish Cook

Refunds appear imminent in a three-year dispute over MISO and PJM’s past practice of double-charging pseudo-tied generation for congestion fees after FERC last week ordered settlement proceedings to determine how much the RTOs must remit to address the redundant costs incurred from 2016 onward (EL16-108).

The issue stretches back three years to when Tilton Energy lodged a complaint against the RTOs for assessing overlapping congestion charges on pseudo-tied resources. American Municipal Power, Northern Illinois Municipal Power Agency, Dynegy and Illinois Power Marketing soon filed similar complaints. FERC consolidated the proceedings.

The RTOs introduced a temporary rebate program in 2017, then began including pseudo-ties in the day-ahead scheduling process in 2018 to end redundant congestion costs. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.) In March, MISO got FERC approval for a second piece of the solution, where participants with pseudo-tied resources can use the day-ahead market to hedge against real-time congestion.

In its order, FERC noted that it has already accepted two filings apiece from MISO and PJM to address overlapping charges and has since discovered that those proposals have eliminated the congestion overlap. But those corrections come too late for the transmission customers already assessed those charges, FERC said.

“We find that the potential for overlapping or duplicative charges for congestion existed prior to the effective dates of the revisions,” the commission said.

As such, FERC established settlement procedures to determine the appropriate refunds owed to owners of pseudo-tied generation. The commission said if the involved parties don’t settle, a settlement judge will decide the case by May 18, 2020. FERC set a refund effective date of Aug. 25, 2016.

FERC: MISO Congestion and Admin Charges Appropriate

However, the refunds will not include the costs of MISO’s non-duplicative congestion and administrative charges that Tilton also challenged.

Tilton claimed MISO violated its Tariff by erroneously using financial schedules to assess charges on pseudo-tied generation, arguing the schedules are meant to represent contracts between two market participants and that the RTO is not a counterparty to the pseudo-tie transactions.

The company said MISO circumvented a Tariff provision and implemented Business Practices Manual language when it used its financial schedules to record transmission transactions for pseudo-tied generation “despite the nonexistence of a bilateral transaction that is a prerequisite for the use of a financial schedule.”

Tilton also argued that MISO’s assessment of real-time congestion costs against generation pseudo-tied from MISO to PJM is improper because the charges cannot be hedged and are “inconsistent with market fundamentals.” The company asked FERC to put a stop to MISO’s assessment of congestion and administrative charges.

In response, MISO argued that Tilton failed to show the RTO was acting counter to its Tariff and said the complaint should be thrown out. It also said Tilton failed to initiate dispute resolution procedures prior to filing the complaint, a break with commission precedent.

“Although Tilton has purchased long-term firm transmission service from MISO to PJM, paying for transmission service does not exempt Tilton from paying for congestion and losses,” the RTO explained.

The commission sided with MISO, ruling that Tilton must pay to use the RTO’s system.

“We conclude that MISO’s assessment of congestion costs and administrative charges on Tilton does not violate the MISO Tariff. Specifically … we find that the MISO Tariff authorizes MISO to assess congestion costs and administrative charges on pseudo-tie transactions. We also find that it was not a violation of the MISO Tariff for MISO to use financial schedules as a vehicle for imposing congestion and administration charges on Tilton,” FERC said.

The commission pointed out Tilton is a MISO transmission customer taking transmission service “to facilitate its pseudo-tie transactions” and is thus required to pay applicable charges.

Pseudo-tie transactions that use the the RTO’s system nevertheless contribute to its real-time congestion, FERC added.

May 20, 2019October 30, 2023

NEECE Panelists Discuss Public Policy Drivers

By Michael Kuser

GROTON, Conn. — As Northeast states continue to expand their clean energy goals, the region faces the prospect that multiple overlapping public policies will create an oversupply of renewable resources at certain periods.

NEECE conference - discussing the impact of renewables targets and public policy on power markets

CPES and NECA hosted the 2019 New England Energy Conference and Exposition in Groton, Conn., on May 14-15. | © RTO Insider

“We’re very soon, even with the contracts we have in place, going to be in a position where our supply of contracted resources is going to exceed demand in some hours,” Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection (DEEP), said Wednesday at the 2019 New England Energy Conference and Exposition, hosted by the Connecticut Power and Energy Society and the Northeast Energy and Commerce Association.

Katie Dykes | © RTO Insider

Dykes noted that the Connecticut House of Representatives had a day earlier approved legislation (H.B. 7156) that would authorize DEEP to procure up to 2,000 MW of offshore wind resources over the next decade, “with a real focus on looking at a solicitation to be issued as soon as possible after the ink is dry on the governor’s signature.”

“It’s really an exciting time, [and] the question society has to be focusing on in the integrated resource planning process in Connecticut is how are we meeting resource adequacy with the public policy resources,” Dykes said. “We have to think about when we’re buying zero-carbon resources that are just displacing other contracted resources in certain hours, those benefits aren’t going to materialize in terms of meeting the carbon goals … and be reflecting that in our procurements.”

Michelle Morin | © RTO Insider

Many stakeholders are not that familiar with the technical aspects of offshore wind, so it’s important to have someone who can bridge that knowledge gap, said Michelle Morin, chief of the environment branch in the U.S. Bureau of Ocean Energy Management’s Office of Renewable Energy Programs.

“For example — the [OSW transmission] cable landfall. I get a lot of concerns that [it] will industrialize an area, so showing people what that will look like goes a long way,” Morin said.

The region’s switch from fossil fuels to wind, solar and storage is being driven by customer demand for cleaner energy, falling costs of new technologies and public policy, said Marc Montalvo, president of Daymark Energy Advisors.

“And the policy interests have many dimensions, like protecting the environment, building strong neighborhoods and communities, making sure the economy is robust,” Montalvo said. “It’s really interesting that we’re talking now about harmonizing markets and public policy, when the wholesale markets that we have in the region, and the way they’re organized, are themselves a response to public policy.”

Out of Market

Markets are very product-specific, and until recently the social science of economics was treated almost like a hard science, which created pejorative assumptions about what constitutes out-of-market actions or mechanisms, said Theodore Paradise, counsel and senior vice president for transmission developer Anbaric.

“Certain orders of market constructs have been protected because people thought that’s what they should do,” Paradise said. “But I think, again, not in 2030 but now, that we’re at the end of that paradigm. At this point, buyers are being told they can’t purchase what they want.

“And this is the proof that the bigger buyers and sellers that are outside this smaller market are really a market, because what do buyers do in a market when they’re being told you can’t buy that?” he said. “They go buy it elsewhere, and that’s what has happened.”

Paradise said the region has arrived at the point where buyers are making direct contracts for resources.

“It’s being conducted in a space that’s not out-of-market; it’s just a different market,” he said.

In addition to competitive contracts for resources, there will continue to be system dispatch, but buyers and sellers are having an impact there, too, he said.

“In the not-too-distant future, we’ll see a New England that has satellite control centers around the region that will become something more like distribution system operators … dispatching based on price, with a grid operator at the transmission level … to make that all work at the higher voltages,” Paradise said.

From a utility perspective, Avangrid’s vision would be to serve as the distribution system platform provider, or the smart integrator, said Rita King, senior director of smart grids innovation for Avangrid Networks.

“The smart integrator role really supports public policy and the region’s targets for climate change and deployment of clean energy,” King said.

David Ismay, a senior attorney with the Conservation Law Foundation, envisioned “an increasingly clean energy market” in 2030 run by Connecticut, Massachusetts and Rhode Island “with a seven-year price lock sufficient to mobilize capital for a range of zero-marginal-cost generators.”

Pentti Aalto of PJA Energy Systems Design asked, “Who is the customer? Is the state or the commonwealth the customer, and I’m just the bill payer? What happens if I find a cheaper way to get power and you’ve already contracted for me?”

Public policy resource choices are made by elected officials, so people can vote them out of office if they disapprove, Paradise said.

Greener Cities

Day Pitney attorney Alex Judd highlighted the increasing incidence of billion-dollar storms in the U.S. — in the Northeast in particular — and noted that the Boston Planning and Development Agency last year released the Imagine Boston 2030 initiative focused on climate change, the first citywide plan in 50 years. (See “Climate Change is Here,” Overheard at NECA Environmental Conference 2018.)

“However we get to carbon neutrality, efficiency is going to be very important, because whatever renewables you’re substituting for fossil [fuels], you lower the total needed,” said Rick Malmstrom, senior energy manager for the Dana-Farber Cancer Institute in Boston.

Malmstrom pointed to another influential initiative coming out of Boston: the 2013 Building Energy Reporting and Disclosure Ordinance (BERDO), which mandated that any building more than 50,000 square feet must report all its energy usage.

“They do have the ability to fine, but they do not want to do that,” he said. “They want to help all building stock get to that kind of reduction [15% energy consumption cut over five years], so now they’re exploring pathways to compliance, such as requiring energy audits be performed, etc.”

Aimee Chambers, director of planning for the city of Hartford, said the city represents “a great example of being able to integrate energy into its large-scale decision-making” through a zoning overhaul and related planning processes.

“The city was most surprised to learn that people … really care about affecting the environment,” she said. “We’ve incorporated a lot into the [building] code with relation to energy. Our code offers density bonuses if buildings use renewable energy or co-generation.”

Hartford also allows building-mounted solar and wind “everywhere, and for those who produce big energy, we allow large-scale wind along our highways, and we also would welcome solar parking canopy development,” Chambers said, adding that the city requires electric vehicle charging stations for lots with space for 35 cars or more.

Louise Yeung, energy portfolio manager for the New York City Economic Development Corp. (EDC), highlighted the value of leveraging a large real estate portfolio, which in her case is 62 million square feet.

“Part of our goal is to generate income for the city to fund other programs and functions, but we also want to make sure we are doing this with clear policy objectives in mind,” Yeung said. “Sometimes those are jobs. In my portfolio’s case, we are looking at emissions reductions and looking at how energy investments can support broader climate targets.”

Most of the EDC’s income comes from leasing, so hosting on-site renewables or generation is a way to diversify the revenue stream and realize the full potential of the assets, she said.

Nithya Sowrirajan, director of global product solutions for Google, showed how her company is using geospatial data and technology to help cities track their carbon emissions and improve their planning abilities.

“San Jose, Calif., was able to look at solar potential for their city as seen today in Google’s Environment Insights Explorer and see that their roofs had [potential] capacity of 4 GW, and thus confidently set a target to be the first 1-GW solar city,” Sowrirajan said. “We started with a small set of cities to pilot our platform, which of course is easier to do in our backyard in California. But as a proud New Yorker, I’m excited to be here alongside fellow panelists from New York City and Hartford to speak about smart cities and to see how we can drive partnerships farther on the East Coast.”

May 20, 2019

DC Circuit Again Rejects MRES Appeal

By Tom Kleckner

The D.C. Circuit Court of Appeals last week rejected rehearing requests from Missouri River Energy Services (MRES) following the court’s earlier determination that SPP could charge the utility for certain transmission fees (18-1166).

The court denied MRES’ request for rehearing by the panel that issued the March ruling or a rehearing en banc. The utility group had asked the court to review FERC Rejects ‘Carve-Out’ from SPP Congestion, Loss Charges.)

MRES, an organization of 61 municipal utilities in the upper Midwest, appealed the ruling, saying the court had committed multiple errors in its decision. It said the opinion “directly conflicts” with a 2007 decision by the court involving Wisconsin Public Power and FERC.

In that case, “FERC agreed with [MISO] that imposing significant changes in scheduling practices between parties to pre-existing agreements would amount to ‘significant changes’ … affect[ing] the bargain between the parties,’” MRES said in its appeal.

Quoting the 2007 panel, the organization said, “Not carving out this narrow class of [grandfathered agreements] would modify them, thereby triggering application of Mobile-Sierra’s public interest standard.”

In rejecting MRES’ original argument in March, the court said SPP “did not seek to impose congestion and marginal loss charges on the 1977 reservation until Missouri River subsequently came within the pool’s footprint.”

FERC in 2017 ruled that the SPP members were ineligible for “carve-out treatment” under the SPP Tariff and a 1977 transmission service contract between Nebraska Public Power District and Basin Electric Power Cooperative.

The 1977 contract arose from construction of NPPD transmission needed to deliver power to the Western Area Power Administration’s Upper Great Plains region and Lincoln Electric System from the Missouri Basin Power Project — a venture owned by six public power and cooperative utilities that includes the 1,710-MW Laramie River coal-fired generator, the Grayrocks Dam and reservoir, and more than 500 miles of extra-high-voltage transmission.

May 20, 2019

Eversource Balks at ISO-NE Plan on CIP Costs

By Rich Heidorn Jr.

ISO-NE on Thursday proposed a “hybrid” filing Section 205 of the Federal Power Act to allow some generators to recover the costs of NERC critical infrastructure protection (CIP) requirements, but Eversource Energy suggested alternatives, saying it doesn’t want the costs collected as part of its transmission rates.

The RTO’s Jonathan Lowell made the proposal at a meeting of the New England Power Pool’s Transmission Committee on Thursday. It would allow cost recovery for generators designated by the RTO as “critical” to the determination of interconnection reliability operating limits (IROLs), which have higher CIP standards than other generators.

Violations of IROLs can lead to instability, uncontrolled separation and outages cascading into neighboring regions. Generators are designated as IROL-critical because of their characteristics and locations relative to other control areas, the RTO said.

ISO-NE says it has about as many IROLs as all other ISOs and RTOs together. “Because New England is at the eastern end of the Eastern Interconnection, a contingency in New England can have significant reliability impacts on systems to the west,” explained ISO-NE spokeswoman Marcia Blomberg. “Many interconnection reliability operating limits have been identified in New England to avoid creating those impacts, and many facilities have been determined to be critical to the determination of those limits.”

The RTO is proposing to make a Section 205 filing with FERC to add a new OATT Schedule 17 for the billing and collection of FERC-approved IROL-CIP costs, with the RTO serving as billing agent. It would be based on a formula rate template listing recurring and nonrecurring costs.

The initial filing will “facilitate a smooth and efficient FERC review of the Section 205 formula rate filing by having resolved most controversies in advance,” the RTO said in a presentation.

Critical generators and similarly situated transmission facilities would then make their own Section 205 filings itemizing their costs for FERC review and approval.

ISO-NE said the two-step filing is necessary because the RTO cannot be responsible for supporting the costs of individual facilities.

‘Inappropriate’

But Cal Bowie, representing Eversource, told the committee in a presentation that it is “inappropriate” for generators to recover expenses through regional network load transmission charges. “Transmission charges should primarily reflect the costs of building, operating, maintaining and ensuring the reliability of the transmission system,” Eversource said.

The company said the RTO should instead consider collecting the costs under its capacity load obligation (used to recover the “missing money” not recovered by generators in the energy market) or real-time non-coincident peak load obligations (Schedule 3 reliability administration service costs). Eversource also said the RTO should create a separate billing item for CIP costs to make them transparent.

According to the New England States Committee on Electricity, transmission costs are between 11 and 18% of total electric bills for residential customers in the region. Total transmission charges have risen from about $869 million in 2008 to $2.25 billion in 2018, NESCOE says.

Asked whether ISO-NE could accommodate Eversource’s proposal, Blomberg said the RTO believes its cost-allocation plan “is the most appropriate solution to ensure compensation” for the NERC compliance requirement.

“The ISO is continuing to listen and discuss this issue with stakeholders,” she added.

In a presentation to the Transmission Committee on March 27, ISO-NE had proposed a cost-of-service reimbursement method, saying a 2017 effort to create a formula rate failed because the RTO was unable to identify a methodology to determine an IROL-critical “proxy” generator or estimate reasonable costs for compliance with the NERC standard.

ISO-NE says the lack of “clear and precise CIP requirements” in standard CIP-002-5.1a Attachment 1 may lead generators to differing interpretations on what steps they need to take. The RTO said costs disclosed by the operators of seven IROL-critical generating stations showed both one-time capital costs and recurring O&M expenses. There was no obvious correlation between costs and generator size, type or vintage, ISO-NE said.

Blomberg said a formula rate is not the same as a proxy rate approach. “Under a formula rate approach, the facility submits its specific costs for approval. A proxy rate is an estimate of the costs of a generic, but similar, facility without consideration of the actual costs. IROL-CIP facilities all have different characteristics, which make proxy rate approach extremely challenging.”

ISO-NE said IROL-CIP costs should be allocated to regional network service and through or out service because accurate IROLs allow the RTO to maximize use of the transmission system.

Lowell told the committee at the March meeting that the ISO-NE would consider alternatives to the cost-of-service proposal if it had broad support within NEPOOL and had a cost estimation methodology the RTO could defend as just and reasonable.

NERC spokesman Martin Coyne declined to comment on the RTO’s characterization of the CIP requirements.

“[We] can’t comment on a presentation that’s not ours or for security purposes discuss details on critical facilities,” he said.

He added: “It is common for entities to seek information from NERC on how specific requirements in our stakeholder consensus-based standards apply to them.”

Business Procedure Change Approved

In other matters, the committee approved ISO-NE’s proposal to make administrative changes to Ancillary Service Schedule 2 of Section II of the Tariff and the VAR Business Procedure, along with revisions to accommodate electric storage reactive resources. The changes move requirements from the Business Procedure into the Tariff and incorporate electric storage facility language into the Schedule 2 capacity cost compensation program.

The RTO said the changes were related to FERC’s Feb. 25 approval of revisions to Section II that created multiple constructs for storage devices to participate in the RTO’s day-ahead and real-time energy markets (ER19-84). (See FERC Accepts ISO-NE Storage Tariff Revisions.)

May 19, 2019

PJM MIC Briefs: May 15, 2019

VALLEY FORGE, Pa. — The PJM Public Power Coalition will draft a problem statement and issue charge that examines capacity interconnection rights in the wake of a new rule permitting the RTO to take them from generators under certain circumstances.

Carl Johnson, representative for the coalition, said his group wants a broader discussion about CIRs and whether the current structure makes sense.

“The reason I want to have a broader conversation is so that we can get to some sort of agreement about what those rights are,” he said. “We argue a little about what those rights represent.”

PJM’s Market Implementation Committee meeting on May 15 | © *RTO Insider*

The decision came after stakeholders debated whether to revise the existing must-offer exception process problem statement to address CIR relinquishment, or create an entirely new document for approval during Wednesday’s Market Implementation Committee meeting. Stakeholders at both the MIC and the Markets and Reliability Committee have expressed concern over a joint plan from PJM and the Independent Market Monitor that revokes CIRs from generators without plans to become Capacity Performance-capable after seeking a must-offer exception. (See Load Interests Endorse PJM-IMM Must-offer Proposal.)

The new rule, however, doesn’t apply to renewable resources because those generators don’t have a must-offer requirement. The Monitor said it will prevent others from “hoarding” CIRs indefinitely.

“All resources should not be able to hoard CIRs,” David “Scarp” Scarpignato of Calpine said Wednesday. “If you are going to have a rule like that, it should apply to everyone.”

Sharon Midgley, Exelon’s director of wholesale development, argued the conversation can move forward but with its own approved problem statement and issue charge. Exelon lobbied against the mandatory revocation of CIRs during the stakeholder process, including the presentation of its own proposal to do exactly that. Despite earning a majority of MIC support in March, the PJM/IMM plan won out at the April MRC meeting.

“They should define the problem and not try to piggyback off this process, which was supposed to deal with a very narrow administrative issue,” she said.

PJM Offers Peek at Carbon Pricing Study

PJM’s Gary Helm offered stakeholders a peek inside the RTO’s methodology for its ongoing internal carbon pricing study and said staff chose the social cost of carbon (SCC) as a simulation metric.

“We don’t care what the price is; we just want a significant price for simulation,” Helm said of the choice, noting a number of states have been using the SCC since August 2016. “[The Regional Greenhouse Gas Initiative] is a few dollars, so it’s not really impacting dispatch. What if we have a carbon price that is such a level that it impacts dispatch?”

PJM’s simulation will observe the impacts of a $52.79/ton price on the market, including cases where prices rise or fall within 25% of that baseline.

Helm said one simulation will divide PJM into a non-carbon zone and a carbon zone — Maryland, Delaware and New Jersey, the three states the RTO expects to be participating in RGGI. Another simulation will measure a regionwide carbon price, ultimately considered the simplest policy to accommodate.

Staff will research the effects of one-way and two-way border adjustments to minimize both environmental and economic leakage between the regions.

Stakeholders Lukewarm on Revisiting Market Seller Offer Cap

As members await a FERC ruling on PJM’s market seller offer cap (MSOC), the RTO said it would consider alternative measurements for performance assessment hours (PAHs) — if stakeholders want to revisit negotiations.

The change of heart comes after PJM asked FERC to dismiss the Monitor’s complaint that its default MSOC was overstated, arguing that a lack of stakeholder consensus and prior commission approval of CP proved otherwise. (See PJM: Dismiss Monitor’s Offer Cap Complaint.)

In August, the Monitor concluded that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 Base Residual Auction because of economic withholding encouraged by the inflated MSOC.

The timespan for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAIs) in compliance with FERC Order 825 in 2018. PJM triggers a PAI when it determines a supply reliability issue exists, providing credits for generators that overperform their capacity commitments and penalties for those that underperform.

So far, only one load shed event has occurred within PJM since the CP overhaul in 2015. The event spurred stakeholder action to revise the MSOC calculation, with four proposals failing to garner enough support for inclusion in the Tariff. PJM subsequently dropped the issue, insisting no further investigation was required. (See Monitor Defends Offer Cap Complaint.)

Stakeholders, however, expressed a mix of appreciation and hesitation on Wednesday at the offer to reopen negotiations.

“Does PJM believe in its heart of hearts that its answer is where we should be or is PJM open to other constructs?” Johnson said. “If we are just going to have the same conversation we had last year, then I think we are just better letting the complaint play out at FERC.”

“We don’t want to rehash the stakeholder process and use time to discuss matters that have already been discussed,” said Jason Barker of Exelon. “We keep having the conversation go around and around. I think we should get guidance from the commission first.”

Monitor Presents Updated 5-Minute Dispatch Problem Statement

The Monitor presented a revised problem statement about review processes for real-time security-constrained economic dispatch (RT SCED) and market pricing that PJM uses to send dispatch signals to generators and calculate LMPs.

Siva Josyula of Monitoring Analytics said a publishing price delay on April 8 — as well as a July 10, 2018, low area control error (ACE) event and corresponding Manual 11 revisions — call into question the transparency of PJM’s RT SCED processes.

The Monitor added work activities to the issue charge that ask the MIC to review the triggers for price-bounding violations and the timeline of publishing LMPs, as well as potential updates to LMP thresholds and procedures for validation checks and publishing prices. Stakeholders must also identify metrics for operator actions, including — but not limited to — biasing in the intermediate-term SCED, RT SCED and locational price calculator.

Double Payments Extend Beyond Fast-start

Adam Keech, executive director of PJM’s market operations, said a recent FERC order saying that current accounting practices provide double payments to fast-start resources puts the RTO in a difficult position.

“The issue is more of a day-ahead uplift issue,” he said. “We are left in this issue of how do we address it. If we just apply it to fast-start, it could be conceived as discriminatory. If we apply it everywhere else, it could be out of scope.”

The problem arises when PJM pays a generator for uplift in the day-ahead market but then dispatches that same resource in real time at a higher commitment. The generator has the ability to recover uplift costs PJM already paid it for a day earlier — except the issue is far broader than just fast-start resources.

Keech presented the issue as the first of several MIC educational sessions about the impacts of FERC’s recent order on the RTO’s fast-start pricing rules. (See FERC Orders Fast-start Rules for NYISO, PJM.) The RTO loses “tens of millions” annually on double payments — a relatively small problem by PJM’s standards, he said.

FERC wants PJM to address this matter in a compliance filing due July 31, as well as an informational report due Aug. 30 about how the new rules don’t raise market power concerns.

– Christen Smith

May 19, 2019

NYPSC Modifies Standby Rates for DERs

By Michael Kuser

The New York Public Service Commission on Thursday continued to tweak compensation and billing for distributed energy resources, adjusting the structure of existing standby and buyback service rates and extending standby rate exemptions for two years (Case 15-E-0751).

NYPSC — The PSC held its regular monthly session in Albany on May 16.

The PSC’s order modifies rates “to more accurately reflect costs and benefits and to ensure that those rates are available to all interested ratepayers.”

“Standby service rates generally apply to customers who have on-site generation that serves much of their load but still depend on the utility to provide partial or backup service,” said Ted Kelly, assistant counsel for the Department of Public Service. The buyback rates determine the price customers receive for selling excess energy back into the grid.

“With interval metering becoming much more widely available due to the rollout of advanced metering infrastructure (AMI) throughout New York state, mass market standby service rates no longer need to be limited to flat fees and volumetric energy usage,” the PSC said. “Rather, rates for mass-market standby service can be measured and billed on the basis of demand in the same manner as the standby service rates applicable to larger customers.”

The order requires that all customers be eligible to opt into a demand-based rate option, irrespective of whether they have on-site DERs. It also requires greater granularity by using off-peak, on-peak and super-peak charge components, and allows the load of multiple customers in multiple buildings to be offset by a common generator.

“This is obviously a complex topic,” PSC Chair John Rhodes said. “Though a complicated subject, this is a very practical approach going forward.”

Commissioner Gregg Sayre said he was “comfortable establishing a rate design that more closely tracks the cost of service.”

“Standby rates have been controversial and hotly debated,” said Commissioner Diane Burman, who concurred in the approval. “I do think we were overly ambitious in 2015 in thinking that it could happen overnight and that the signal was we were ready to go.”

The order also modifies the design and administration of buyback service tariffs to eliminate or reduce barriers to deployment of DERs, and clarifies the application of grid access demand charges for energy storage systems.

The commission also voted unanimously to continue existing statewide exemptions from standby rates, and to extend the in-service date deadline for eligible DERs until May 31, 2021 (Case 19-E-0079).

These exemptions apply to certain DERs with a capacity of 1 MW or less, including fuel cells, wind, solar thermal, solar photovoltaic, biomass, tidal, geothermal, methane waste-powered resources, and efficient combined heat and power projects, the order said.

New York utilities must implement the rule changes effective July 1.

Grid Prepared for Summer

DPS staff presented the commission a report on summer electricity preparedness that forecasts a 1 to 3% decline in energy prices compared with last summer, depending on load zone and weather conditions.

“This is very comforting for New Yorkers,” Rhodes said.

The state bases its energy price forecasts on futures trading at the New York Mercantile Exchange, and the commission said that financial hedging by utilities will also reduce any price increases this summer.

“The big driving factor of course is ICAP [installed capacity], which tends to be fairly stably high in the summer downstate and, year after year, quite low upstate,” said Warren Myers, DPS director of market and regulatory economics. “And with respect to delivery charges, those, by their design through rate cases, are very stable.”

New York has sufficient generating capacity resources to supply expected customer demands and all of the state’s electric utilities are prepared to serve those expected customer demands, the report said. Peak load this summer is forecast to be 32,382 MW, down slightly from last year.

May 19, 2019

LS Power Gets Incentive for NY Public Policy Project

FERC on Thursday granted LS Power Grid New York’s (LSPG-NY) request for an abandoned plant incentive for a transmission project approved by NYISO (EL1 9 -30).

LSPG-NY (formerly known as North American Transmission) had partnered with the New York Power Authority to jointly propose two 345-kV transmission projects to address capacity shortfalls at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (Segment B) interface.

NYISO’s Management Committee had backed both projects — part of the broader AC Public Policy Transmission Project — but the ISO’s Board of Directors in April selected only one of them, awarding Segment B to a competing proposal by National Grid and New York Transco. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

“In particular, we find that LSPG-NY’s Segment A project is entitled to the rebuttable presumption that it meets [Federal Power Act] Section 219’s requirement that the project will ensure reliability and/or reduce congestion because it has been approved through a relevant regional transmission planning process,” the commission said.

LSPG-NY said in its petition that NYISO estimated that Segment A will cost $750 million (in 2018 dollars, including 30% contingency).

The commission rejected LSPG-NY’s request for the incentive for its Segment B project, as NYISO did not select it. The company filed its request in January.

— Michael Kuser