Page 1258 – RTO Insider

August 17, 2017

MISO to Conduct Long-Term Renewable Integration Study

By Amanda Durish Cook

MISO will conduct a study to identify the challenges of integrating growing volumes of renewable generation in its footprint.

The open-ended, multiyear study will be used to “facilitate a broader conversation about renewable energy-driven impacts on the reliability of the electric system,” MISO said.

“We trying to look at the impacts over a much broader period of renewable penetration and quantify the impacts,” said Jordan Bakke, of the RTO’s policy studies group, at an Aug. 16 Planning Advisory Committee meeting. “If we look over the last decade of MISO, we started at very minimal [renewable] penetration … and we’ve grown quite steadily over that time frame.”

Different types of renewables are growing at different rates throughout the MISO regions, Bakke said, and the RTO wants to identify “inflection points” at which the growth of renewables and the retirement of baseload units will require changes in the structure or operation of the system. With more projects moving through the interconnection queue, Bakke said MISO may soon have to begin forecasting for solar output.

The study aims to predict how and when reliability will be impacted under heavy renewable output; if there are limits to the amount of wind and solar generation MISO can support; how long before energy storage becomes a requirement; what parts of the grid will be stressed first; and how much renewable energy can be deployed before significant system changes are needed.

MISO renewable generation — Midwestern wind farm | © *RTO Insider*

“We don’t have a great idea of when certain things will have to take place to integrate renewable generation. We don’t know at what mix that will have to take place,” Bakke said.

MISO’s current registered wind capacity is about 16.8 GW and current registered solar capacity is about 180 MW, but those figures could pale in comparison if all the prospective projects in its generation interconnection queue are realized. The RTO currently has about 31 GW of wind capacity and 15.7 GW of solar capacity advancing through various stages of the queue.

After some stakeholders cautioned MISO not to inhibit state jurisdiction over resource adequacy or renewable portfolio standards, staff stressed that the study will be limited to an impact assessment, and nothing will be built or changed as a direct result of the study.

“We’re looking purely at the technical impacts of the system, and how those can change,” Bakke said, adding that if something significant is discovered, study results will be passed to other departments.

Some stakeholders demanded to know if the study results would eventually inform modeling in MISO’s annual Transmission Expansion Plan.

“It really depends. It’s an exploratory study, and that’s the nature of research,” Bakke said.

Wind on the Wires’ Natalie McIntire asked how this study would differ from other renewable studies the U.S. Energy Department has already conducted.

Bakke said that while national studies seek ways to incorporate targeted amounts of renewables, MISO’s study will lack “a solution-oriented focus.”

Indianapolis Power and Light’s Lin Franks offered to share the company’s data on its solar assets and Harding Street storage facility. “We’ve been trying to get MISO’s attention now for a while to provide real PV data,” Franks said. “We need to bring real data to the table before engaging in a worthless academic exercise.”

Bakke agreed that renewable data for the footprint is hard to come by and said MISO may use IPL’s data.

The RTO will return to the PAC in September with a study scope for stakeholders to review, he said.

August 17, 2017October 31, 2023

Massachusetts Tightens GHG Limits for Generators

By Michael Kuser

Massachusetts regulators have issued new, stricter limits on greenhouse gas emissions from the state’s fossil fuel power plants and ordered utilities to buy at least 16% of their electricity from clean energy sources in 2018.

The regulations, announced Aug. 11 in response to a 2016 court order, include a Clean Energy Standard (CES) that requires utilities and competitive suppliers in the state to procure increasing amounts of electricity from clean energy sources every year, with the minimum percentage increasing 2 points annually to reach 80% in 2050.

The new rules also set annually declining limits on aggregate CO₂ emissions from 21 large fossil fuel-fired power plants in the state, from 8.96 million metric tons in 2018 to 1.8 million metric tons in 2050. The regulations establish an allowance trading program for CO₂ emissions from generators, with allowance auctions beginning in 2019 and direct allocations for 2018. The rules offer flexibility in the form of limited allowance banking and a “deferred compliance” option to address electricity grid reliability.

allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER

The regulations also reduce allowable methane emissions from natural gas pipelines and distribution systems. They also tap the transportation sector by requiring state, city and regional transportation planning agencies to evaluate and report the aggregate GHG emissions of their facilities, fleets and programs.

The new procurement rules are like those of the Massachusetts Renewable Portfolio Standard, while the emissions targets are stricter than CO₂ limits under the Regional Greenhouse Gas Initiative, the cap-and-trade system agreed on by nine Northeastern states.

Pushed to Act

The state acted in response to a 2014 lawsuit by the Conservation Law Foundation that accused Massachusetts officials of failing to enact regulations needed to meet the targets set by the 2008 Global Warming Solutions Act. The state’s top court ruled in favor of CLF in May 2016.

CLF helped win passage of the climate change law, which requires Massachusetts to issue regulations to incrementally reduce greenhouse gas emissions each year.

“These rules re-establish the commonwealth as a national leader in developing sensible, enforceable standards to transition our economy to a low-carbon future,” CLF President Bradley Campbell said in a statement. “Much more needs to be done, and Gov. [Charlie] Baker’s leadership will be essential to getting neighboring states to take meaningful action to prepare New England for the energy future being shaped by the Paris Climate Agreement.”

20-year levelized cost of renewable energy resources | Mass. DOER

Last September, Baker issued an executive order that set a deadline of Aug. 11 for the secretary of energy and environmental Affairs and the Department of Environmental Protection to have “designed such regulations to ensure that the commonwealth meets the 2020 statewide emissions limit mandated by the GWSA.”

That limit — a 25% reduction in emissions below 1990 levels — was established seven years ago by the state to meet the GWSA requirement of a minimum 80% reduction by 2050. Officials estimate that by 2014, Massachusetts had already cut carbon emissions by 21% from 1990 levels.

“These regulations will help ensure the commonwealth meets the rigorous emission reductions limits established in the Global Warming Solutions Act in order to protect our residents, communities and natural resources from the effects of climate change,” Baker said.

Limited Effect on Consumers

The DEP concluded that the emissions targets and clean procurement rules would likely increase customer electricity bills by 1 to 2% per year.

The Bay State has been busy this year ramping up its environmental regulations. Officials earlier this summer announced that the state’s electric distribution utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020. (See Massachusetts Underwhelms with 200-MWh Storage Target.)

In late July, the state received more than half a dozen proposals to meet its call for 9.45 TWh a year of renewable generation. Projects will be selected next January, with contracts to be submitted in late April. (See Hydro-Québec Dominates Mass. Clean Energy Bids.)

In response to public comment, the final CES included limited grandfathering to accommodate electricity sold in 2018 and 2019 under existing contracts. For the next three years, the alternative compliance payment rate is being increased to 75% of the RPS amount, but it will drop to 50% of the RPS amount in 2021. The use of banked clean energy credits is not allowed until 2021.

allowance prices assumed in the main scenarios, (RGGI price) and alternative sensitivity price | Mass. DOER

The RGGI emissions cap represents a regional budget for CO₂ emissions from the power sector, with each CO₂ allowance representing an authorization to emit 1 short ton from a regulated source. The nine RGGI states agreed on a 2014 cap of 91 million short tons. The CO₂ cap declines by 2.5 percentage points each year from 2015 to 2020.

August 17, 2017

Solar Eclipse to have Minimal Impact on SPP

By Tom Kleckner

Next week’s total solar eclipse will not disrupt SPP operations despite 100% obscuration levels in parts of its 14-state footprint, according to a report by RTO staff.

The eclipse will pass over North America on Monday, with parts of Nebraska, Kansas and Missouri experiencing totality — complete obscuration of the sun — for almost three minutes. Kansas City and Lincoln, Neb., are among the municipalities in the totality path. Other states in the SPP region will experience solar obscuration levels of 80% or more.

“The eclipse is expected to have some impact on resources and loads in our region,” said Lanny Nickell, SPP’s vice president of engineering.

The RTO expects to lose about 200 MW of solar PV generation during the height of the eclipse, assuming clear skies. The system currently has 215 MW of registered utility solar resources; SPP has identified another 111 MW of distributed PV on its system, including residential rooftop solar and commercial solar farms.

The eclipse will pass over the SPP footprint for about three hours, beginning at the western edge around 11:30 a.m. CT and ending at the eastern edge around 2:45 p.m.

Although solar generation will be reduced, the eclipse also will reduce air conditioning loads because of falling temperatures. But the temperature drop also will cut wind speeds, reducing wind generation, according to the report, which was prepared by a summer engineering intern. A drop in solar generation connected to the distribution system will appear as an increase in load from the transmission system’s perspective.

The report expects demand for lighting will increase during the eclipse, which would require additional generation.

“The eclipse is worthy of study in light of the increasing numbers of distributed generators in the SPP footprint,” the report said.

That study could come in handy in 2024, when another solar eclipse will cover Texas and Arkansas on its way to the Northeast. The National Renewable Energy Laboratory (NREL) projects the SPP region may have up to 1.1 GW of distributed PV in at that time.

Utility-scale solar is also likely to increase, given more than 7 GW of solar generation is being studied in the generator interconnection queue.

August 17, 2017

Ohio PUC Upholds FirstEnergy Subsidy

By Rich Heidorn Jr.

Ohio regulators on Wednesday rejected challenges to their order awarding FirstEnergy a subsidy worth more than $600 million, assistance the company said it needed to avoid having its credit rating reduced below investment grade.

The Public Utilities Commission of Ohio also rejected some rehearing requests by FirstEnergy while also granting others (14-1297-EL-SSO).

Opponents of the rider immediately vowed to appeal to the state Supreme Court.

In October, the commission unanimously rejected FirstEnergy’s request for an eight-year retail rate stability (RRS) rider totaling $4.46 billion, which the company said it needed to ensure its financial health at a time in which its coal- and nuclear-fueled generation is challenged by low natural gas prices.

Instead, the commission approved a three-year distribution modernization rider (DMR) totaling about $612 million for subsidiaries Ohio Edison, Cleveland Electric Illuminating and Toledo Edison. The commission said the additional money would allow the company to make investments in grid modernization. (See PUCO Rejects FirstEnergy’s $558M Rider, OKs $132.5M.)

Ohio firstenergy PUCO — Ohio Edison workers in a switchyard | *FirstEnergy*

In December, the commission agreed to consider FirstEnergy’s rehearing request, along with challenges by environmentalists, independent power producers, large customers and the Ohio Consumers Counsel (OCC).

In its unanimous ruling Wednesday, the commission said that it had already “thoroughly addressed” issues raised by OCC, the Northwest Ohio Aggregation Coalition, Cleveland Municipal School District and the Sierra Club. Commissioner Lawrence K. Friedeman recused himself.

It said the risk of FirstEnergy’s and its subsidiaries’ credit ratings dropping to below investment grade was “sufficient to constitute an emergency that threatens the utility’s financial integrity,” rejecting opponents’ claim that it should rely on the current credit ratings of the companies.

The commission also approved FirstEnergy’s request to strike portions of filings by the Ohio Manufacturers’ Association Energy Group, saying “new information should not be introduced after the closure of the record.” It also struck news articles included in filings by the Northeast Ohio Public Energy Council, which it said were hearsay.

In response to a request from FirstEnergy, it clarified its earlier ruling, saying that if Electric Security Plan (ESP) IV is terminated, the Rider Delivery Capital Recovery (DCR) revenue cap increases currently in place will continue until the commission establishes a new standard service offer (SSO). “If FirstEnergy exercises its right to terminate ESP IV at some point in the future following rehearing or an appeal, the Rider DCR revenue cap increases yet to be implemented at the time of termination will also be terminated along with the remaining provisions of ESP IV. However, FirstEnergy will be permitted to continue to recover costs already incurred under Rider DCR,” it said.

PUCO said it was “not persuaded by FirstEnergy’s assertion that DMR revenue could be recovered through a base distribution rate case. We do agree that certain costs of grid modernization, specifically the costs of any acquisition and deployment of advanced metering, including the costs of any meters prematurely retired as a result of the advanced metering implementation, may be recovered outside of an ESP [electric security plan]. Moreover, we also agree that the $568 million annual economic impact of the retention of the FirstEnergy Corp. headquarters is an economic benefit under the ESP and should be included as a consideration in the ESP versus MRO [market rate offer] test.”

Opponents of the rider reacted sharply, saying they will take their arguments to the Ohio Supreme Court.

“There is simply no basis in Ohio law to force utility customers to pay for a slush fund for FirstEnergy Corp. and its shareholders,” said Shannon Fisk, managing attorney at Earthjustice.

“We are very disappointed in the commission’s continued unwillingness to shield customers from FirstEnergy’s poor business decisions,” said Dan Sawmiller, senior representative for Sierra Club’s Beyond Coal Campaign. “The PUCO has missed yet another opportunity to focus the company on real efforts to modernize our electric grid and invest in new, clean energy technologies and instead has forced customers to pay up for unwise investments in outdated coal and nuclear plants.”

The Environmental Defense Fund said it was “confident the Ohio Supreme Court will … reject the regulators’ latest giveaway to dirty energy.”

FirstEnergy spokesman Doug Colafella said the ruling “affirmed the commission’s previous order that will help support future investments to modernize our electric system.”

“Grid modernization will benefit our customers and competitive suppliers by enhancing service reliability and enabling new products and services,” he said.

August 16, 2017

NY Clean Energy Commitment Spurs Procurement

By Michael Kuser

NEW YORK — While timelines for completing large power projects can be especially long in New York, developers are finding it easier to invest here now that the state is providing more predictability around clean energy procurement and market fundamentals.

That was the consensus of panelists discussing the impact of the state’s Clean Energy Standard (CES) on procurement at the Infocast New York Energy REVolution Summit held earlier this month at Times Square.

new york clean energy procurement — Procurement Panel (L-R) Noah Hyte,Cypress Creek Renewables; Karlis Povisils, Apex Clean Energy; Jack Godshall, Invenergy; Dennis Phayre, Entersolar; Doreen Harris, NYSERDA; and moderator Sean Garren, Vote Solar. | © *RTO Insider*

Gov. Andrew Cuomo’s Reforming the Energy Vision (REV) and its associated CES aim to meet two goals by 2030: a reduction in New York’s greenhouse gas emissions to 40% below 1990 levels and that renewables generate 50% of the state’s electricity.

To support those objectives, the governor in June announced the largest-ever state-mandated clean energy procurement, authorizing the New York State Energy Research and Development Authority (NYSERDA) and the New York Power Authority to oversee up to $1.5 billion of investment in major renewable energy projects, including offshore wind and solar.

“We’re encouraged by the number of projects, both in the interconnection queue at the ISO, and also in the pipeline of projects that are moving through Article 10,” said Doreen Harris, director of large scale renewables at NYSERDA. Article 10 is New York’s primary permitting process for authorizing the construction and operation of all utility-scale power projects 25 MW and above.

“It’s a good signal to us of the interest in New York and the supply that’s to come.”

Steady Wind

Harris said NYSERDA is focusing on three main areas around renewables: solicitation of long-term contracts; behind-the-scenes work running tracking systems and working with 152 load-serving entities; and aggressive pursuit of offshore wind.

Cuomo in January called for the development of 2,400 MW of offshore wind projects by 2030, starting with the 90-MW South Fork Project off Montauk, Long Island. (See New York Seeks to Lead US in Offshore Wind.)

“The way we are evaluating proposals is more complex than it used to be under the [renewable portfolio standard] in the sense that, first of all, we are looking to signal through some new threshold criteria the desire to really move projects through the pipeline in New York state,” Harris said.

Having the state replace goals with actual standards to achieve over five to 10 years “enhances the ability of developers to focus specifically on development of the best possible assets, with appropriate timelines,” said Jack Godshall, vice president of origination at Invenergy, the largest renewable energy provider in North America.

Firm procurement targets allow companies to spend time and capital developing assets for which they know there will be a market in coming years, Godshall said. “And that’s great for the state and also for the developers.”

Beneficial Load

Corporate clients deciding to “go solar” have shifted toward more and more larger procurements and off-site developments, according to Dennis Phayre, director of business development for EnterSolar, the top solar developer in New York.

Phayre (left) and Harris | © *RTO Insider*

“New York state now is limited to 2 MW on the distributed generation level, soon going up to 5 MW, but in our world, with the clientele we deal with, we certainly have to be looking at what comes beyond that,” Phayre said. “Having appropriate maturity barriers, so that we don’t have churn in awards, is super important to ensure that NYSERDA isn’t rebidding the same 100,000 MWh over and over again.”

NYSERDA Director of Policy and Regulatory Affairs John Williams said people tend to think of the DG outcomes of REV, but the program “always envisioned the supply side needing to undergo some pretty dramatic changes as well, and the Clean Energy Standard is the primary mechanism. When planning for a dynamic grid, we always imagined that there’s going to be a lot of dynamic activity on the supply side.”

Why all the focus on the power generation sector when it only represents about 20% of GHG in New York? Over the past decade, New York has nearly halved the sector’s GHG emissions, with an accompanying shift in load, according to Williams.

“The CES actually needs to take account of the shift of load,” Williams said. “We like to call it beneficial load, but clean energy-powered load only becomes beneficial to the degree that we can get consistent and continuous emissions reductions and a shift in that emissions profile in that electric generation sector. The value in an aggressive, continuous focus on power generation sector emissions is necessary because it winds up being the solution to emissions reductions that we need to see in other sectors.”

August 16, 2017

Great River Energy Seeks Test for Inverter-Based Generation

Great River Energy is urging MISO to account for the effects of inverter-based generation in the RTO’s transmission planning studies.

Inverter-based generation — often new technology resources asynchronously connected to the grid via an electronic interface — can harm reliability in weak power systems, Great River Energy’s Mike Steckelberg said at an Aug. 15 MISO Planning Subcommittee meeting. The Minnesota utility discovered the issue during a recent analysis, he said.

Great River Energy linemen | *Great River Energy*

Steckelberg cited a June NERC report warning that such resources can affect dispatch and reliability — including voltage control, frequency response and ramping — when too many of them are interconnected into weak power systems.

The company said MISO’s annual Transmission Expansion Plan study process should include screening for transmission with low short-circuit currents, comparing the megavolt-ampere level before a inverter-based resource is connected to the nominal power rating of that resource. If the calculation does not meet a certain threshold, MISO should remedy the transmission by modifying controls, connecting to a stronger source, planning for more transmission or reducing the size of the generation project.

“This is a fairly easy screen to be doing ahead of time,” Steckelberg said. While the screen would not have to be a “full-blown study,” it does need to be incorporated into MISO’s generation interconnection studies.

Steckelberg said MISO’s Interconnection Process Task Force and Planning Subcommittee both need to address the issue, and transmission owners and planners should be able to review new interconnection requests for low short-circuit current issues.

Entergy’s Yarrow Etheredge and American Transmission Co.’s Patrick Gerum said their companies shared GRE’s concerns.

Customized Energy Solutions’ Ginger Hodge asked for MISO’s response on the issue.

MISO Director of Planning Jeff Webb said he and his staff would review the request and put together a response at the Planning Subcommittee’s next meeting in October.

— Amanda Durish Cook

August 16, 2017

CAISO Demand Response Problems Erode Participation

By Jason Fordney

Frequent rule changes and an uncertain market structure are causing dissatisfaction among CAISO demand response providers and eroding participation in the programs, those providers say.

Problems with data verification and settlement required the ISO to recalculate its 2016 DR results, and providers say there are other issues with the program, which aggregates utility customers to facilitate their participation in the ISO’s wholesale markets.

“We have not received any energy payment of any dispatch of our resources going back to June 2016,” EnerNOC Director of Regulatory Affairs Mona Tierney-Lloyd told RTO Insider. While Tierney-Lloyd doesn’t think there are large payments still outstanding, “it is obviously sub-optimal,” she said.

EnerNOC and other companies aggregate retail electric customers and bid the load reductions into the CAISO market to offset the need for generation. Wholesale DR aggregates and compensates electricity users that reduce their consumption to below a pre-established baseline. Separately, utilities also maintain DR programs in which they provide customers a financial incentive to decrease load.

Tierney-Lloyd believes there are several factors causing the decline in DR program participation, including rule changes and modifications to the way DR resources are dispatched. There are also inconsistencies between CAISO and California Public Utilities Commission rules, she said. Agency misalignment is the primary cause of what she said is significant decline in DR program participation.

Participation in PG&E, SCE Demand Response Programs, 2011-2016 | *EnerNOC*

“It takes work on our side to get those customers familiar with those rule changes,” which also adds costs, she said.

During hot weather, it is more difficult for customers to reduce their usage below baseline, resulting in some taking efforts to reduce demand without getting paid. Others keep a close eye on CAISO operations and don’t understand why they are getting dispatches when no shortages are seen on the system.

CAISO uses DR as a way to make the grid more efficient and reduce greenhouse gases associated with climate change. While the ISO has a number of DR program improvements underway, its past problems slowed payments to market participants. (See CAISO Resettling 2016 Demand Response Results.)

In 2016, the DR system was sometimes unaware that an event had occurred, or the system did not deliver settlement data, CAISO said. The system was not receiving the correct “payload” to identify that a DR event occurred, so the system was unaware of the event and no performance measurement was completed. But even when the event day and historic meter data were available, the DR system in some cases did not send the values to the settlement system, so no settlement occurred. The ISO’s full resettlement should be completed in October.

The CAISO Board of Governors recently approved the second phase of a program meant to make distributed resource integration easier, dubbed the Energy Storage and Distributed Energy Resources (ESDER) Phase 2 proposal. (See New CAISO Rules Spell Increased DER Role.) ESDER includes a set of alternative energy usage baselines to assess the performance of proxy demand resources, one of a series of refinements to the DR program.

August 15, 2017

New York City Ramps Up Community Solar

By Michael Kuser

NEW YORK — New York must improve its policies and regulations around distributed energy resources in order to ensure that community solar can help meet Gov. Andrew Cuomo’s goal of 325 MW installed solar capacity in the city and nearly 3,000 MW statewide by 2023.

That was the perspective of participants on a community solar development panel at the Infocast New York Energy REVolution Summit held Aug. 1-3 at Times Square.

“The community solar programs in New York were slow to start, much slower than we originally anticipated because the market signals weren’t quite there for a while,” said Cynthia Christensen of Namaste Solar, an employee-owned cooperative with headquarters in Boulder, Colo., and an office in New Paltz, N.Y. “Investors always like certainty. Good, bad or indifferent, give them certainty.”

Panel moderator Valessa Souter-Kline, policy coordinator for the New York Solar Energy Industries Association said, “Community solar is still fairly new. The order authorizing it [Reforming the Energy Vision (14-M-0101)] came out in 2015, and it’s had a slow start because when the CDG [community-distributed generation] order came out, the state also started digging into some other policy issues, including the value of DER. So there has been some policy and regulatory uncertainty.”

The Value Stack

The state’s Public Service Commission in March issued a Value of Distributed Energy Resources (VDER) order (15-E-0751) that began the transition away from net energy metering and toward an approach that aggregates specific value components. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)

Drew Warshaw, vice president of community solar for NRG Energy, said that the VDER order differed significantly from its draft form.

“As a result, the slow ramp-up that we’ve had is going to continue unless some of the economics around that problem change. In terms of the governor’s and the administration’s goal of 325 MW of community solar — we don’t see that happening without significant changes around the program economics,” Warshaw said.

To incent community solar, “there are any number of levers on the revenue side that the state can pull,” Warshaw said. “I think the [New York State Energy Research and Development Authority] block program is certainly one — and the market transition credit, which is one of the pieces in the value stack of the VDER order.”

City Goals

Mayor Bill de Blasio in 2015 launched the OneNYC climate change program, which aims to lower the city’s greenhouse gas emissions to 80% below their 2005 levels by 2050, achieve the best air quality of any large U.S. city and send no waste to landfills by 2030.

Benjamin Mandel, renewable energy policy adviser with the mayor’s Office of Sustainability, said the city is working to ensure that as the market moves beyond net metering, it “has the right kind of signals both in terms of where it benefits utilities and also where does policy benefit and where we want to see DER projects going, including community solar.”

In terms of the installed capacity needed to meet its greenhouse gas mitigation goal, the mayor’s office estimated it would need 7 GW of solar citywide, which is “our entire technical potential,” Mandel said. “For reference, we’ve probably got between 110 and 120 MW installed citywide right now … a stretch goal is to reach 1,000 MW of installed solar capacity citywide by 2030.”

The mayor’s office works with Sustainable CUNY and the NYC Economic Development Corporation to expand access to the benefits of solar energy and other forms of renewable energy. Programs include Solarize NYC — for community group purchasing — and a related program called Shared Solar NYC.

Since 2006, the NYC Solar Partnership program has connected government and industry with oversight agencies that permit rooftop solar projects and with the interconnecting utility, Consolidated Edison. This “has greased the skids” and allowed the city to narrow the disparities in solar adoption between the five boroughs and less dense areas like Westchester or Long Island, Mandel said.

Jung (left) and Christensen | © *RTO Insider*

And the city has its own large constituents. Bomee Jung, vice president of energy and sustainability for the New York City Housing Authority, said, “If NYCHA doesn’t meet its goals, it’s not likely that the city’s going to get there without us.”

The housing authority serves about 400,000 people in 176,000 apartments and another 200,000 people through its voucher program, the largest numbers of any city in the country.

Near Future

“You’re going to have a fairly limited market here in the near future for a few reasons,” said Tom Hunt, vice president of corporate development for Clean Energy Collective, which licenses community solar software to developers and utilities.

The community solar panel at Infocast’s NY REV Summit (L-R): Tom Hunt, Clean Energy Collective; Drew Warshaw, NRG Energy: Benjamin Mandel, NYC Mayor’s Office of Sustainability; Bomee Jung, NYC Housing Authority; Cynthia Christensen, Namaste Solar; and moderator Valessa Souter-Kline, NYSEIA | © *RTO Insider*

“You have economics under Phase One [of New York’s Clean Energy Standard] that probably don’t work in at least a few different load zones … and in those load zones where the economics do work, you’re going to have some pretty significant interconnection issues, or siting issues for here in the city,” Hunt said.

“The math will work, the economics will work in Con Edison Zone J [NYC], but the challenge there is siting,” Warshaw said. “We have a service area that produces an amount of community solar at scale that’s really going to make an impact. So that’s the challenge that a company like NRG sees, which is very focused on building out community solar, has the money to invest in New York and feels like a lot of positive things are happening in New York in terms of the climate, the horsepower and the brain power in Albany focused and wanting to do this.”

Some solar developers claim that there’s going to be 2 GW of community solar built in the next 12 months in load zones A through C, but Hunt is doubtful.

“I don’t know that there’s 20 MW within all that that have figured out how you deliver a full program in terms of bringing customers in and billing them, invoicing them, let alone getting utilities on your side so you can bill credits,” Hunt said. “While we’re certainly optimistic about the order and what it means, there’s a lot of work left to be done, and which we think needs to be done in order to make this market sustainable.”

August 15, 2017

PJM OC Briefs: Aug. 8, 2017

VALLEY FORGE, Pa. — Unpredictable rainstorms throughout PJM in the middle of July resulted in overestimated load forecasts last month, the RTO’s Chris Pilong told members during an Aug. 8 Operating Committee meeting.

PJM operating committee load forecasting — Pilong | © *RTO Insider*

“Just about every afternoon, we had rainstorms that were possible … and just about every day, those storms did hit,” he said, noting that they reduced temperatures and caused daily forecasts to exceed actual load by as much as 6,000 MW.

One example: While the RTO forecast peak demand of approximately 150,000 MW on July 20, early afternoon storms capped load at about 145,000, Pilong said. That allowed the summer peak so far to remain the previous day, July 19, when demand hit 146,635 MW, he said.

PJM’s peak load forecasting error for the month was 4.58%, 0.79 percentage points above July 2016, PJM’s Joe Ciabattoni said. The overall forecasting error was 3.13%, just above PJM’s 3% target. Ciabattoni attributed the deviation to the “pop-up storms” on the western side of the footprint. The errors were highest in the distribution territories of Dayton Power & Light, Duquesne Light, FirstEnergy’s American Transmission Systems Inc. and Duke Energy Ohio/Kentucky.

The monthly balancing authority area control error limit, which measures how well the RTO maintains constant frequency control, was 99.9%, with total excursions and excursion minutes at their lowest levels in at least the past year.

The Anatomy of a LMP Spike

LMPs jumped to about $900/MWh around 10:30 a.m. on July 27, Pilong said. An outage the previous evening on the Black Oak-Hatfield 500-kV line created increased flow on the Conastone-Peach Bottom 500-kV line. PJM had been controlling flow over the latter segment to roughly 93% of its limit, but flow levels on the line can be volatile, as they are sensitive to load or generation movements. Moves from hydro units and shifting load increased flow over the line by about 5%, Pilong said.

Operators directed PJM’s security-constrained economic dispatch (SCED) engine to reduce flow over the line by 6%, but the demand was too great and sent the engine into a “relaxation mode” in which it doesn’t attempt to control the flow. Pilong said that in those instances, SCED just fails to solve the case and moves on to resolve the rest of the system.

Operators reduced their request to 2%, which SCED could perform but only by raising the LMP to about $900/MWh. The price spike caused generation to respond, which reduced the strain on the line and allowed SCED to realign prices.

GT Power Group’s Dave Pratzon asked if such short-term and unexpected fluctuations were caused by PJM’s move from 15-minute to 10-minute dispatch settlements. He also questioned whether generators will be expected to follow PJM’s dispatch signals during those periods and how signal deviations will be handled.

GT Power Group’s Pratzon (left) and Hyzinski | © *RTO Insider*

Pilong said that with the shorter lookaheads, larger transmission changes will create greater price separation. Part of the issue, he said, is the response time of low-cost resources.

“If the low-cost generation isn’t able to move as rapidly as we need it to, we may need to reach out to more costly resources for a short period time,” he said.

Reserve Differences Explained

In response to a stakeholder data request, PJM’s Lisa Morelli explained why the real-time SCED engine has not priced for shortages that stakeholders have observed in published data.

The public data come from PJM’s emergency management system (EMS), Morelli said, which has more conservative estimates than SCED. The most significant difference for this was a 2% “back off” in which the EMS system assumes resources will only achieve 98% of their stated capability. This assumption was removed in changes made on July 11, Morelli said, and immediately resulted in a 300-MW increase in the EMS synch reserve.

There are also differences between real-time SCED’s 10-minute lookahead and EMS’ real-time data. Additionally, real-time SCED uses units’ SpinMax (the reserve maximum) to estimate reserves, while the EMS uses the lesser of the SpinMax or the EcoMax (the economic maximum).

Exelon’s Sharon Midgley noted that the data request also asked for all of the unapproved real-time SCED cases, which she said would provide more clarity on whether PJM operators are being presented with real-time SCED cases that include shortages but are declining to select them.

Midgley and Old Dominion Electric Cooperative’s Adrien Ford said they had not been aware of the removal of the 2% back off and asked that PJM be more communicative with such changes in the future.

Morelli said there has been a 12% improvement in the alignment between the two measurements since PJM moved to the 10-minute settlement.

— Rory D. Sweeney

August 15, 2017

PJM PC/TEAC Briefs: Aug. 10, 2017

VALLEY FORGE, Pa. — PJM’s Michael Herman told members at last week’s Planning Committee meeting that proposed Manual 14B updates to incorporate modeling changes reflecting the cancellation of the Con Ed-PSEG “wheel” would include reductions in emergency transmission limits.

The capacity emergency transfer limits (CETLs) would be reduced in certain load deliverability areas (LDAs), including by 500 MW in EMAAC, 1,100 MW in MAAC, 1,527 MW in PSEG and 1,309 in PS North.

At PSEG, that would put the CETL at just 574 MW above the capacity emergency transfer objective (CETO), the threshold for necessary transfer capacity to ensure reliability in an emergency. In PS North, the difference between CETL and CETO would be just 335 MW.

The modeling adjustments come in response to Consolidated Edison’s decision to end a decades-long agreement with PJM to route 1,000 MW from upstate New York to New York City through Public Service Electric and Gas’ northern New Jersey territory. The change necessitated reanalysis of regional power flows, which eventually identified that continuing an “operational base flow” of 400 MW would be the most reliable solution. (See Analysis Recommends Continuing Reduced Con Ed-PSEG ‘Wheel’ for Grid Stability.)

Reliability Pricing Model PJM — Sims | © *RTO Insider*

In the updated CETL calculations, PJM removed any non-firm energy transfers. However, it kept them in its updated capacity import limit calculations. Stakeholders questioned why non-firm was removed from the CETL.

“If it’s a non-firm product, we just can’t depend on it during these critical times,” PJM’s Mark Sims said. “There could be a time when our system is stressed, the neighboring system is stressed, and then to depend on non-firm energy to support your system … just doesn’t make sense.”

The revisions were approved by acclamation with one objection and 14 abstentions.

PJM has scheduled a webcast on Aug. 30 from 1-3 p.m. to address questions about the CETL procedural changes.

Resilience Planning to Recognize Outage Propagation Potential

Sometimes, resilience means knowing when to give up.

In analyzing its planning criteria, PJM will be considering what is likely to happen downstream when a piece of equipment fails. Sometimes, this will mean the equipment simply collapses at that point. But it could also open a pathway for cascading failures further throughout the system and a larger collapse. (See “Resilience to Become Planning Driver,” PJM PC/TEAC Briefs: July 13, 2017.)

“If you had an existing station where you improved the strength of it such that during an event, where normally it would be lost very quickly and cleanly, it’s now hanging on,” Sims said.

As a result, the grid operator could face a scenario “where the system collapsed instead of being bounded because you actually have a stronger part of the system which allows the event to propagate further and in the end the result is worse,” he said.

To prepare for such a contingency, PJM is developing appropriate metrics and criteria for factoring resilience into planning.

“These are not events that happen often. I can’t pull data on voltage collapses,” Sims said. “We have to do our best to make some valid assumptions.”

Stakeholders have previously asked how PJM plans to address the subjectivity of the topic.

“To PJM, megawatts would just be load, but to others, megawatts are customers,” said John Farber with the Delaware Public Service Commission. He asked if PJM plans on considering the amount of load that would be impacted by a piece of equipment failing.

“I don’t know if you’re suggesting that some load is perhaps more critical than others, [but] I think many people would generally agree with that,” PJM’s Paul McGlynn said.

“I salute your eagerness to swim with the alligators,” Farber replied.

Market Efficiency Analysis Ongoing

Staff have completed analysis of market efficiency projects in the Reliability Pricing Model and are nearly finished examining interregional projects, Sims told members at last week’s Transmission Expansion Advisory Committee.

The RTO is currently reviewing projects from PPL’s zone.

The analysis identified six projects to be recommended for approval by the Board of Managers, including four in Commonwealth Edison’s LDA and one in Duke Energy Ohio/Kentucky. Two of the ComEd projects were proposed by American Electric Power.

Six other proposals — two from AEP and Exelon, one from Transource Energy and three from Northeast Transmission Development — were not recommended. PJM is expecting to seek approval on recommended projects at the board’s October meeting.

Reliability Analysis for 2022 Finds 190 Violations

PJM’s reliability analysis of the Regional Transmission Expansion Plan for 2022 conditions found violations at 190 flowgates.

The majority (115) were generation delivery issues, with most of those (50) being on 138-kV lines on the western side of the RTO’s footprint. Overall, the 138-kV system had the most issues, with 77 violations identified.

The runner-up was the 345-kV system, with 46 violations identified. That system also had 35 of the 37 overall total high-voltage violations. All 35 were in the MAAC region.

Of the total 190 flowgates identified with violations, 41 will be included in the 2017 RTEP proposal window: 33 in the West region, five in the South region and three in MAAC. Generation delivery issues account for 35 of the available projects and six are N-1 thermal violations.

The remaining 149 flowgates were excluded because they were either “immediate need” projects or under 200 kV, which are expected to be addressed by the incumbent transmission owner.

— Rory D. Sweeney