Page 1246 – RTO Insider

September 19, 2017

Overheard at the IPPNY Fall Conference

By Michael Kuser

SARATOGA SPRINGS, N.Y. — New York state’s ambitious renewable procurement, New York City’s carbon reduction plan and the costs of offshore wind were among the topics Thursday at the 32nd Fall Conference of the Independent Power Producers of New York. Here’s some of the highlights:

New York Officials Excited by Response to Renewable RFP

New York officials are happy about the competitiveness of the responses to their June solicitation for up to 2.5 million MWh of large-scale renewable energy, which they say is the most ambitious in the country.

(L-R) John Reese, moderator; Doreen Harris, NYSERDA; Anthony Fiore, NYC; Clint Plummer, Deepwater Wind; Michael Ferguson, Standard & Poor’s; Robert Bryce, Manhattan Institute | © *RTO Insider*

More than 4,000 MW of renewable energy capacity — the equivalent of more than 9.5 million MWh per year — qualified to submit proposals, said Alicia Barton, CEO of the New York State Energy Research and Development Authority.

That is six times the generation that was previously secured under the prior renewable portfolio standard and almost four times the amount that the state sought to procure, Barton said. “We hope that that level of competition will drive really terrific proposals and terrific prices,” she said.

A total of 88 facilities — including utility-scale solar, landfill gas, hydroelectric and wind projects — qualified for the request for proposals, which was issued by NYSERDA and the New York Power Authority.

“We were also very pleased to see that some project developers took us up on our invitation to propose projects that would also provide grid value and included storage in the proposals,” she said.

Bid proposals are due Sept. 28, and the state expects to make the selection awards in November.

NYSERDA Working with Commercial Fishermen, Feds on Offshore Wind Siting

IPPNY Board Chairman John Reese, senior vice president of Eastern Generation, moderated a panel that included Doreen Harris, director of large-scale renewables at NYSERDA. Harris manages the master plan for offshore wind that is due out by the end of the year.

The state hopes to get 2,400 MW of generation from offshore wind by 2030. Harris’ team has been working closely with residents of Long Island and other coastal areas, and particularly with commercial fishermen.

IPPNY offshore wind — Harris | © *RTO Insider*

“We’ve been spending a lot of time actually on the fishing dock, understanding how they work,” Harris said. “We’ve also undertaken over 20 different studies and surveys, which are now underway. These are desktop analyses as well as ‘boats in the water,’ so to speak.”

Siting is an important element of the master plan, and that brings in the Interior Department’s Bureau of Ocean Energy Management, which is responsible for offshore wind leasing in federal waters.

BOEM, which has identified more than 100 GW of offshore wind potential off the Atlantic coast, has issued or is preparing to issue leases off New York and seven other states. The first offshore wind lease for New York, a nearly 80,000-acre site off the Rockaways in Queens, went to Norway-based Statoil for $42.5 million last December. (See New York Seeks to Lead US in Offshore Wind.)

Only 2% of the Offshore Study Area is needed to meet New York’s goal of 2.4GW by 2030 | *NYSERDA*

“New York can make our recommendations to the federal government, but it is ultimately a federal process,” Barton said. “We are also looking at what this means for New York; specifically, what are the rules of the road to operate in New York if you’re a project developer? We intend to develop those guidelines using the information and the outreach we’ve conducted … which would set the stage for longer-term processes and considerations around transmission.”

NYC Seeks 80% GHG Cut by 2050

New York City has its own clean energy goals, including an 80% reduction in greenhouse gases by 2050, starting from a 2005 baseline.

“In the more near term, we have a goal of 35% reduction in emissions from the building sector by 2025, and that’s truly important and aggressive,” said Anthony Fiore, deputy commissioner of energy management for the city’s Department of Citywide Administrative Services. “The city consumes about 30% of the electricity that’s generated in the state and is responsible for about 40% of GHG emissions in the state.”

Mayor Bill de Blasio said Thursday that he wants to require owners of buildings with more than 25,000 square feet of space to retrofit them for energy efficiency. The plan, which de Blasio announced in Brooklyn, could affect as many as 23,000 properties.

Electricity is responsible for about 30% of citywide emissions, and 50% of the energy consumed by the city is produced by generation within it.

“That fleet of generation, 70% of it is more than 45 years old,” he said. “That is less efficient on average than the rest of the state generation, so that presents some unique risks to the city as that generation fleet continues to age. We all know the difficulty in repowering, and the city has had a strong voice and advocated strongly with [FERC] on changing some of the repowering rules, buyer-side mitigation, to help make that easier. These things are difficult, so there’s a real risk there.”

Though some may debate the effect of GHG emissions on climate change, “what is not deniable is the air quality impacts and public health outcomes from emissions,” Fiore said. “This is really important for New York City. We have large corridors of above-average asthma rates that really affect the most vulnerable populations.”

Any improvement in airborne pollutants means fewer lost workdays, fewer lost schooldays, better educational opportunities for our children, better opportunities for career development and an overall better economy, he said. “Health care dollars are real, and avoided deaths and morbidity need to be calculated and factored into the choices we make.”

Offshore Wind Overhyped?

Michael Ferguson, director of U.S. energy infrastructure at Standard & Poor’s, said his company’s focus is on risk.

“Any time you’re going from an industry that is small right now, with only 30 MW of installed capacity [Block Island], to one in which there are very grand ambitions over time … there’s going to be risk involved,” Ferguson said.

The declining levelized cost of energy for offshore wind in Europe means “that stakeholders in the financial sector are willing to take a lower return on these,” Ferguson said. “That’s indicative of the fact that the market believes there’s less risk in these projects now than there was before.”

Talk of lower risk profiles might be fine for a banker, but for Robert Bryce, a senior fellow at the Manhattan Institute, “offshore wind has been hyped nearly as much as a Kardashian wedding.”

He cited some large projects that were announced but never built — such as the Atlantic Wind Connection by Google — and big plans by the Obama administration that never materialized, such as 10 GW by 2020 and 54 GW by 2030.

“In January, the Long Island Power Authority agreed to a $1.6 billion, 20-year power purchase deal to buy power from the South Fork Wind project from Deepwater Wind,” Bryce said. “For that project, Deepwater Wind will also collect $70 million in tax credits … the South Fork project is 90 MW. I could today build 180 MW of natural gas-fired capacity for about the same amount of money that Deepwater Wind is collecting just in tax credits.”

LIPA has agreed to pay $220/MWh for the power from South Fork, Bryce said. “How many of you in this room are getting $220/MW? None. The prevailing price last year in New York was about $34/MW. Therefore, so far what we’re seeing is that offshore wind is at least six times as expensive as conventional electricity.”

Clint Plummer, vice president of development for Deepwater Wind, responded that LIPA had determined that South Fork was the most cost-effective way of serving eastern Long Island. “Yes, you may be able to build a natural gas-fired plant in the middle of Texas for less, but if you want to build something to supply East Hampton, N.Y., you can’t,” he said.

“Three dollars per dekatherm may be the cost of natural gas delivered to Henry Hub in Louisiana, but it does not reflect the cost of natural gas delivered over a bulk transmission system and then through a distribution system to a local power plant, and it doesn’t reflect the heat rate when you run through an existing or even a new natural gas-fired power plant. So, it’s a false comparison.”

September 19, 2017

ISO-NE Forecast Sees Flat Loads, More Solar, No Congestion

By Rich Heidorn Jr.

BOSTON — ISO-NE expects growing energy efficiency and behind-the-meter solar generation to more than cancel out load growth over the next 10 years.

ISO-NE NERC energy efficiency Coal-Fired Generation — Audience at last week’s ISO-NE 2017 Regional System Plan Presentation | © *RTO Insider*

RTO officials outlined their forecasts at a public forum on their draft 2017 Regional System Plan on Thursday.

The forum’s 150 attendees were mostly industry stakeholders, regulators and RTO officials. But there was also a three-woman contingent from Mothers Out Front, a climate change activist group, who pressed RTO planners on the region’s continued reliance on fossil-fueled generation. Carol Chamberlain, of Arlington, Mass., raised concerns about methane leaks in the natural gas supply chain. Randi Soltysiak, of Somerville, Mass., criticized the RTO’s plan for not shifting more heavily to carbon-free sources.

“To me, forming a new 10-year plan around increasing fossil fuels in 2017 is not only irresponsible, but it’s morally unconscionable in the face of the climate destruction that we’re seeing,” she said. “We need to do better. This is New England. They’re [setting 100% renewable goals] in Australia and they’re doing it in California.”

Others in the audience questioned transmission spending and the dearth of storage in the region. The RTO got its first grid-scale battery, a 16-MW facility at Yarmouth Station, last year.

Passive demand resources and energy efficiency are expected to more than double over 10 years to 4,475 MW in 2026. Solar PV, including BTM generation and resources participating in ISO-NE wholesale markets, also is expected to more than double over the planning horizon, from 1,918 MW (nameplate) in 2016 to 4,733 MW by 2026. BTM PV will reduce summer peak loads by 1,035 MW in 2026.

But the RTO expects natural gas to comprise 56% of its capacity by 2026, up from 44% now, said Michael Henderson, the RTO’s director of regional planning and coordination, who gave a presentation on the plan.

Declining Net Loads

Although planners expect the gross peak summer load to grow 1% over the 10-year planning horizon, they forecast net load — including energy efficiency and solar generation — to drop 0.6% per year, from almost 126,800 GWh in 2017 to less than 120,000 GWh in 2026.

The 50/50 net summer peak forecast for 2026 is about 26,300 MW, down 0.6% from 2017. The 90/10 net summer peak forecast, however, rises by 0.5% to more than 29,000 MW in 2026.

Energy efficiency — supported by more than $1 billion in spending annually by the New England states — is expected to reduce the 90/10 net winter peak load from almost 21,900 MW to 20,600 MW, easing concerns over having sufficient natural gas for power generation during the heating season.

Resources

Despite declining net loads, the RTO says its net installed capacity requirement will grow from 34,300 MW in 2022 to 35,700 MW in 2026. Barring retirements, New England’s resources would exceed the ICR by at least 1,700 MW throughout the planning horizon.

“However, the region will likely still need to rely on operating procedures that provide load and capacity relief every season from 2018 through 2026, especially under extremely hot and humid conditions, severe winter weather, and during infrastructure-outage conditions of both electric power and natural gas facilities,” the report says. “The region also will likely face additional retirements of aging oil and coal-fired generation.”

The RTO’s interconnection queue has 76 active projects totaling almost 13,000 MW, including 6,400 MW of natural gas, 5,400 MW of wind generation and 77 MW of batteries.

Almost all the proposed natural gas generation is in Connecticut, Massachusetts and Rhode Island, consistent with the plan’s conclusion that “the most reliable and economic place for resource development” remains near load centers in southern New England. About 80% of the RTO’s load is south of Massachusetts’ northern border, Henderson said.

Two-thirds of the wind capacity would be added in Maine, with the remainder mostly offshore projects off the southeast coast of Massachusetts.

Transmission Needs

The report notes changes in the criteria and inputs used in assessing system needs, including the adoption of NERC transmission planning standards. The RTO also is using a new probabilistic methodology to determine the amount of generation assumed out of service in its base case analyses.

The report includes about $4 billion in proposed, planned and under-construction transmission upgrades. Since 2002, the RTO has spent $12.4 billion to add 714 transmission project components. “With these system upgrades in place, combined with the changes in assumptions to needs assessments … the need for additional reliability-based transmission upgrades, as shown by the steady-state studies of peak load, is expected to decline over the planning horizon. Conversely, generation retirements and studies reviewing system performance, accounting for the integration of nonsynchronous resources and improved load modeling, may drive the need for some additional reliability-based transmission upgrades.”

Future drivers of transmission include integration of large-scale renewable resources and distributed resources, aging infrastructure, adding interchange capability with neighboring systems, and complying with new NERC standards, the report says.

“The overall need for major additional reliability-based transmission projects is expected to decline over the planning horizon. The low growth of net peak load means it no longer is a major driver of the need for new reliability-based transmission projects,” it continues. “The development of [Forward Capacity Market] resources in favorable system locations also defers the need for major new projects.”

The RTO has yet to identify the need for market-efficiency transmission upgrades (METUs), because reliability upgrades have reduced system production costs, particularly out-of-merit operating costs. New economic and fast-start resources also have helped eliminate congestion and uplift costs.

While the study projects sufficient capacity and transmission to meet reliability criteria, it says the limited natural gas pipeline system is a fuel-security risk, especially in winter.

Panel Discussion

In addition to the presentation on the system plan and a keynote speech by former EPA Administrator Gina McCarthy, the forum included a panel discussion on planning for the “hybrid” grid. (See related story, Ex-EPA Chief Angry but Optimistic Over Climate Change.)

Outgoing ISO-NE Board Chair Paul Levy moderated the discussion, which focused on integrating renewables, storage and other distributed energy resources.

Chris Root, chief operating officer for Vermont Electric Power Co., said his state is showing where the region is headed.

About one-quarter of its typical peak load of 1,000 MW is provided by solar on sunny days. More than 35% of its needs come from in-state run-of-river hydro and hydro imports from Canada and New York. It also has 120 MW of wind, with an additional 30 MW under construction.

“Ninety percent of the time, there is not a single carbon-producing generator running in the state of Vermont,” he said.

But wind output must be curtailed during heavy hydro runoff periods because of insufficient transmission, he said. “There hasn’t been a public policy transmission project yet. Everyone’s scared to be No. 1 on that,” he said.

Stephen Pike, CEO of the Massachusetts Clean Energy Center, said he would like to see “a truly educated and engaged customer base.”

He said that when his organization offered businesses a free feasibility study on adding solar or storage, it could find only 30 takers, well below the 50 it sought. “It’s extremely frustrating,” he said. “Frankly I thought we’d be overwhelmed with requests for assistance.”

Root agreed with the need for more customer education, saying few people know that it takes about 6 acres of PV panels to generate 1 MW. People say, “‘I have six panels on my roof.’ [I say,] ‘Great — you can run a hairdryer.’ A typical women’s hairdryer is 1,500 W. That’s [the capacity of] all the panels on the roof during that time you’re running it.”

Ed McNamara, regional policy director for the Vermont Department of Public Service, predicted consumers will become more educated about the varying cost of power as electric vehicles become more popular.

“Think of how many people you know who know exactly which gas station has the cheapest gas,” he said. “If you’re now moving into electric vehicles, people are going to care about what their rates are.”

Nicholas Miller, senior technical director for GE Energy’s consulting business, said even industry professionals in the U.S. aren’t as informed as they should be. While European engineers have become increasingly comfortable with high renewable penetration rates, in the U.S. “lots and lots of PV starts to get really scary.”

“There are many distribution systems in northern Germany that regularly run at 300% instantaneous [solar] penetration — that is 3 MW of solar for one 1 MW of load. The distribution system looks like a spread-out power plant pushing power onto the grid,” he said. “That makes utility distribution people in the U.S. — including in New England — hair catch on fire. We’ve got a ways to go.”

September 19, 2017

NYPSC Limits ESCO Service, Sets New DER Compensation

By Michael Kuser

The New York Public Service Commission last week issued a procedural order to begin implementing its 2016 ruling prohibiting energy service companies (ESCOs) from enrolling new low-income customers and requiring them to unenroll existing ones.

NYPSC energy service companies ESCO — PSC Meeting underway

While litigation had delayed execution of the December order, the state’s Appellate Division this month lifted a temporary restraining order and denied a stay on implementation sought by the National Energy Marketers Association, clearing the way for the commission to act.

The December order included 11 clauses establishing implementation deadlines and a waiver process for ESCOs seeking to offer low-income customers a guaranteed savings product. The more recent order revised the deadlines to account for time lost under the temporary restraining order. (See Court Blocks NYPSC Order Barring ESCO Contracts.)

“I think this order is extremely useful, it addresses any possibility for confusion and it brings clarity to the implementation and to the timing,” PSC Chair John Rhodes said during a Sept. 14 commission meeting. He was supported by commissioners Diane Burman, Gregg Sayre and James S. Alesi.

The commission’s general counsel, Paul Agresta, testified that the new order does not affect ESCOs that had filed for waivers consistent with the December order. “Those ESCOs do not need to de-enroll customers from their guaranteed savings products until the waivers are acted upon by the commission,” he said.

One Waiver Granted

Immediately after issuing the procedural order, the commission approved a petition for waiver from one ESCO (Ambit Energy), while denying two others (Drift Marketplace and M&R Energy Resources).

A petition must demonstrate the ESCO’s ability to calculate “what the customer would have paid the utility and to ensure that customers would be paying no more than they would have paid the utility, and appropriate reporting to demonstrate compliance with these assurances,” Bruce Alch, of the Department of Public Service (DPS) Office of Consumer Services, told the commission.

In helping to set the waiver procedures, the DPS Utility Intervention Unit (UIU) recommended that the commission deny any petitions that failed to meet that criteria and impose strict reporting requirements on any ESCO granted a waiver. Alch said the attorney general’s office and the Public Utility Law Project, a consumer advocacy group, both agreed with the UIU’s comments.

DPS staff recommended that the commission approve the petition for Ambit Energy to continue to serve low-income customers.

“Unlike the other ESCOs, the only product Ambit sells in New York state is a guaranteed savings product,” Alch said. “In support of its petition, Ambit provided models which replicate the utility tariffs and enable it to closely bill the customer what the utility would have billed the customer.”

Rhodes noted that “with this order, we also begin to lay out the standards for what it means to definitively establish the ability to provide guaranteed savings. That clarity is important, it’s helpful to the industry and it’s helpful to customers.”

PSC NYPSC CILs FERC Order 1000 — PSC Commissioner Diane Burman

Burman cast the only ‘no’ vote on all three waiver petitions, urging that the commission “take a step back.”

“The process has been confusing,” she said.

The commission directed ESCOs to block the enrollment of any new low-income customers on or before Sept. 22 and to unenroll customers within 30 days of receiving customer lists from the utilities.

NEMA on Friday filed comments protesting the PSC’s claim that ESCOs overcharge customers and cited data showing that they have saved New Yorkers more than $10 billion since 2002.

New VDER Compensation System

The commission last week also issued an order establishing a “value of distributed energy resources” (VDER) compensation system as a first step in moving beyond net energy metering. The new order grandfathers solar and other distributed energy systems installed before March 9, 2017, into the existing compensation scheme for the life of their operation.

Homeowners and small commercial customers that install solar or other small distributed systems between March 9, 2017, and Jan. 1, 2020, will be compensated through net metering for 20 years. All other systems installed after March 9 will be placed onto the new VDER compensation system after the utilities file final calculations and tariffs, which will take effect Nov. 1.

The commission in March adopted a new “value stack” pricing mechanism for solar and other DER, along with issuing two other orders to transition utilities into “distributed system platforms” and align their incentives with DER providers (Case 15-E-0751). The transition away from net metering will increasingly aggregate specific value components to raise the granularity and accuracy of the valuation. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)

“This is a concrete first step that creates more active and more value-reflective pricing to spur development of those projects that are most valuable to the grid,” Rhodes said.

Last week’s order raises the maximum size of solar projects (from 2 MW to 5 MW) in order to decrease development costs and increase the competitiveness of the community solar market. It also establishes the first compensation values for energy storage systems when combined with eligible forms of DER and requires utilities to work with the state to integrate storage into the electric grid.

The commission anticipates considering final action early next year, following further analysis by utilities, stakeholders and DPS staff.

September 19, 2017

PJM PC/TEAC Briefs: Sept. 14, 2017

VALLEY FORGE, Pa. — PJM has reduced its installed reserve margin (IRM), largely because of a drop in the equivalent forced outage rate (EFORd), stakeholders learned at last week’s Planning Committee meeting. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)

The IRM dropped nearly 1 percentage point from 16.6% to 15.8% for delivery year 2021-2022, thanks to an anticipated fleet-wide EFORd reduction from 6.59% to 5.89%. PJM calculated EFORd — which measures the probability a generator will fail completely or in part when needed — for the existing generation fleet and the fleet expected in future study years.

PJM’s Tom Falin said the reduction is mostly because of the retirement of old coal and nuclear units, which have higher EFORds, and the increase in new gas-fired units, which have lower failure rates. The IRM is developed from the past five years of NERC’s Generating Availability Data System (GADS) data, so the 2011 data rolled off as the 2016 data was added.

However, the reductions will have little effect on prices, Falin said, because the updated forecast pool requirement (FPR), which impacts the Reliability Pricing Model, increased just .0006 to 1.0898. The FPR is calculated by multiplying 1 plus the IRM by 1 minus the average EFORd.

Cleared PRD Forces Manual Revisions

PJM’s John Reynolds presented proposed Manual 19 revisions that have become necessary, in part, because of price-responsive demand (PRD). The changes align the method to forecast PRD with the method for forecasting demand response.

“Some of these changes are predicated on the fact that, after being around for about eight years, we finally have some cleared price-responsive demand,” Reynolds said. “Because we haven’t had any price-responsive demand, we don’t have a history of the cleared [megawatts] becoming committed.”

While DR customers can receive payments for reducing their energy use, PRD customers save money by cutting or shifting their electricity use in response to dynamic prices.

The DR forecast is based on auction results, influenced by a historical analysis of how many megawatts that cleared were eventually committed in the delivery year. PJM will use limited historical data for the analysis until PRD has been around long enough to mirror the DR process. Reynolds said the forecast method was revised to reflect the observation that fewer resources were registering as DR in the delivery year than had cleared in the delivery year’s Base Residual Auction — the result of market participants buying out of the commitment in one of the three Incremental Auctions (IAs) between the BRA and the delivery year.

Esam Khadr of Public Service Electric and Gas questioned whether too much emphasis was being placed on an untested product at the expense of capital-intensive generation “you know that … is going to be here for 40 or 50 years.”

“We’re planning the system for many years to come on something that may or may not exist two or three years from now,” he said.

PJM IRM EFORd forced outage — Farber | © *RTO Insider*

“I think it should also be recognized that the revenue requirements for those 40 or 50 years are also there, regardless of whether that capacity is needed by customers for 40 or 50 years or not,” responded John Farber of the Delaware Public Service Commission. “Whereas demand response having a much shorter planning horizon would not have that type of revenue requirement.”

In response to a question from Calpine’s David “Scarp” Scarpignato, Reynolds explained that PJM performed “due diligence” to determine that the PRD resources that cleared had transitioned from being DR resources. The distinction affects forecasting.

Budget Unveiled

PJM’s Jim Snow presented the RTO’s preliminary 2018 budget. The $42 million in planned capital expenditures is dominated by technology upgrades and replacements.

“Really what this is doing is allowing us to maintain those systems that we built during the AC2 era,” Snow said, referring the more than $50 million spent at the beginning of the decade to build a backup control room.

RTEP Window Results

PJM’s Mark Sims reviewed results from the first proposal window of the 2017 Regional Transmission Expansion Plan, which closed on Aug. 25. PJM, which had requested proposals to correct 40 reliability violation flowgates, received 51 proposals from 10 entities addressing nine target zones. The RTO defines a flowgate as an overloaded facility in its models paired with a contingency violation. There were 29 greenfield projects and 22 transmission owner upgrades.

PJM’s reliability analysis for 2022 identified five additional “immediate need” baseline upgrades that will be performed by incumbent TOs. Four of the upgrades are in PSE&G’s zone and one is Pennsylvania Electric. Another project was identified to address high-voltage issues at the Davis-Besse nuclear power plant in the ATSI zone.

Two other projects were included because they met Dominion’s “end of life” criteria. Additionally, two supplemental projects in the American Electric Power zone and three in Dominion were approved, along with a rebuild and upgrade of PSE&G’s Mason substation, which was damaged in Superstorm Sandy.

Sims said PJM plans to present all of the projects to the Board of Managers in October and recommended them for inclusion in the RTEP.

— Rory D. Sweeney

September 19, 2017

Power Restored for 97% of Customers in Irma’s Wake

About 97% of customers who lost power during Hurricane Irma have had their service restored, utilities and regulators reported Monday.

Parts of Alabama, North Carolina, South Carolina and every county in Florida and Georgia were impacted by Irma, which prompted what Tom Bossert, President Trump’s homeland security and counterterrorism adviser, called the “largest ever mobilization of line restoration workers” in U.S. history.

FPL Florida hurricane irma — A crew from Joplin, Mo. receive their safety orientation at Tampa Electric’s staging area in Plant City. | *Tampa Electric*

More than 60,000 utility workers deployed from more than 30 states and Canada. Dozens of utilities — including Atlantic City Electric, AEP Ohio, Avista, Black Hills Energy, Consumers Energy, Consolidated Edison, Dayton Power & Light, Delmarva Power, Dominion Energy, Duquesne Light, Entergy, Eversource Energy, FirstEnergy, Green Mountain Power, Hydro-Quebec, Indiana Michigan Power, Jersey Central Power & Light, Kansas City Power & Light, Liberty Utilities, National Grid, Pepco, Northern Indiana Public Service Co., Pacific Gas and Electric, Texas-New Mexico Power, Toronto Hydro, and Wisconsin Public Service — reported sending crews.

As of Monday, they had eliminated significant outages everywhere except Florida.

The Florida Public Service Commission said almost 312,000 customers, 3% of the state’s total, were still without power as of 6 p.m. Monday. Florida Power & Light had about 160,000 customers still out, down from 4.45 million. Duke Energy had almost 94,000 out, 5% of its total. Georgia Power reported 171 customers still dark as of Monday evening.

At Irma’s peak on Sept. 11, more than 7.8 million customers were without power.

The Edison Electric Institute said work had been slowed by debris, fallen trees and downed power lines. But FPL spokesman Bryan Garner told the Palm Beach Post that the restoration was four times faster than it was following Hurricane Wilma in 2005, thanks to $3 billion in grid-hardening investments since then.

The effort included strengthening 600 transmission lines, placing more than 450 lines underground and clearing vegetation from more than 135,000 miles of wires. More than 1.2 million poles have been inspected and upgraded or replaced. Also speeding the recovery was the installation of millions of smart meters and grid devices that help detect problems. FPL deployed almost 50 drones to assess the damage.

But not all the investments worked out. About 40% of FPL’s system is underground, but uprooted trees damaged some underground lines in Homestead, south of Miami.

“One of the things you are seeing in particular with FPL’s investment in hardening their system is not that it prevented outages, but that it allowed for the restoration process to be a lot quicker and a lot safer,” EEI Executive Director Scott Aaronson told the Post.

Even if customers paid $1,000/kWh, Aaronson said, “I still cannot guarantee that there are not going to be outages. There is no such thing as risk elimination. It is really about risk management.”

— Rich Heidorn Jr.

September 19, 2017

Senate Panel Clears McIntyre, Glick for FERC

The Senate Energy and Natural Resources Committee this morning approved FERC nominees Kevin McIntyre and Richard Glick, sending them to a confirmation vote by the full Senate.

FERC REV Senate Energy and Natural Resources Committee Richard Glick — McIntyre | © *RTO Insider*

The committee voted unanimously in favor of McIntyre, a Republican tapped by President Trump to be FERC chairman, and Glick, a Democrat. The two testified before the committee Sept. 7. (See McIntyre to Senate: ‘FERC does not Pick Fuels’.)

Their confirmation would restore the commission to its full five members for the first time since October 2015, when Republican Phil Moeller left the commission. FERC was without a quorum between February, when former Chairman Norman Bay resigned, and August, when Republicans Neil Chatterjee and Robert Powelson joined Commissioner Cheryl LaFleur on the commission. (See FERC Quorum Restored as Powelson, Chatterjee Confirmed.)

On Wednesday, the commission is scheduled to have its first open meeting since January. (The meeting was moved from its normal Thursday schedule because of Rosh Hashanah.)

McIntyre (left) and Glick chat before the hearing. | © *RTO Insider*

Also approved by the Senate committee today were Ryan Nelson, nominated for solicitor of the Interior Department; Joseph Balash, to be Interior assistant secretary for land and minerals management; and David Jonas, for general counsel of the Department of Energy. Sen. Al Franken (D-Minn.) opposed Balash. Jonas was approved 14-9 on a largely party line vote.

— Rich Heidorn Jr.

September 18, 2017

NYISO Business Issues Committee Briefs: Sept. 12, 2017

RENSSELAER, N.Y. — Members of NYISO’s Business Issues Committee last week discussed a recent Brattle Group report on pricing the social cost of carbon into the wholesale electricity market with the report’s principal author, Sam Newell.

Because most meeting participants had attended a public comment session on the topic during the previous week, Newell presented a summary of the report as well as a spreadsheet of modeling assumptions for a more detailed discussion. He explained that Brattle had used load-weighted average locational based marginal pricing (LBMP), proportional to state load patterns. (See NYISO Stakeholders Talk Details of Carbon Charge.)

Several people wondered whether the carbon charge would incentivize construction of fossil fuel generators — or whether the study assumed too much capacity being built in the form of gas-fired turbines.

“I don’t care what the demand reset curve says,” Newell said during the Sept. 12 meeting. “Look at what people are building: a lot of combined-cycle generators.”

Erin Hogan of the New York Department of State Utility Intervention Unit asked whether the study incorporated the effects of offshore wind on wholesale prices. Yes, was the answer, but not by 2025. One participant asked whether increased energy prices stemming from the charge might prompt large industrial users to leave the state. Although Newell was reluctant to speculate, he said an industrial user might see higher energy costs but a lower overall bill.

NYISO carbon charge transmission constraint pricing — | *The Brattle Group*

“This is the crystal ball stuff,” Newell said. “We assume a third of New York State load is the biggest industrial users with sophisticated rate design capabilities and a greater ability to respond to price signals. … We can’t imagine all the ways the market might respond.”

Still, the study did not consider how increased wholesale prices might provoke industrial users to relocate.

“There’s a lot of freedom in how you allocate [carbon charge] revenues,” Newell said. “You could let the big users see the LBMP and just write them a check” to cover their increased costs from the charge. He added that the proposed $40/ton charge on carbon emissions was based on “nothing to do with electricity” but on the “worldwide harms from carbon.”

When asked why the modeled offset from renewable energy credits (RECs) was greater than that for zero-emission credits (ZECs), Newell said the ZECs can drop only by $5 and cannot go below zero, while RECs can go below zero and thus can be modeled to drop $15.

Newell thanked participants for their input and asked them also to look into the unintended consequences of a carbon charge.

LBMPs Down 29% from a Year Ago

NYISO Senior Vice President for Market Structures Rana Mukerji reported that the ISO’s August 2017 average year-to-date monthly energy cost of $35.80/MWh marked a 4% increase from a year earlier. LBMPs last month averaged $30.57/MWh, down 15% from July and 29% from August 2016.

The grid operator’s average daily sendout was 477 GWh/day in August, compared with 498 GWh/day in July and 548 GWh/day in August 2016.

August natural gas prices were lower while distillate prices were higher compared with those of the previous month. Gas prices on the Transco Z6 pipeline serving New York City averaged $2.16/MMBtu, down from $2.44/MMBtu in July but up 7.4% from a year earlier.

Distillate prices were up 17.6% year-on-year, with Jet Kerosene Gulf Coast averaging $11.53/MMBtu (up 10% from July) and Ultra Low Sulfur No. 2 Diesel NY Harbor averaging $11.65/MMBtu (up 7%).

The local reliability share was $0.12/MWh, slightly higher than $0.11/MWh in July, while the statewide share was $0.31/MWh, compared with $0.54/MWh in July. Total uplift costs, with Schedule 1 components including NYISO cost of operations, were higher than those in July.

Mukerji highlighted a section of his Broader Regional Market report, showing steps NYISO has taken to reduce the impact of potential ISO-NE policy changes on New York’s capacity market. The New England grid operator has proposed to revise the requirements for enabling “import capacity resources” to participate in ISO-NE’s Reconfiguration Auctions and bilateral transactions, a move that could increase New York capacity prices and create inefficient price signals.

NYISO last year filed proposed Tariff revisions with FERC to set the Locality Exchange Factor for capacity exports from Zone G-J generators into ISO-NE at 80% from June 2017 through May 2018, rather than use existing Tariff methodology and inputs. While FERC accepted the new methodology in January, it rejected a one-year transitional mechanism. NYISO followed up in June by filing an informational report concerning potential modifications to its rules-governing capacity exports from certain localities but does not now intend to pursue changes to the currently effective Locality Exchange Factor calculation methodology.

Updates to Tx Constraint Pricing Manuals

The BIC also approved revisions to the Transmission Constraint Pricing Manual, which will be presented to the Operations Committee for approval on Sept. 15.

NYISO transmission constraint pricing carbon charge — | *Potomac Economics*

NYISO Associate Energy Market Design Specialist Jennifer Boyle proposed the changes to update the ancillary services, day-ahead scheduling and the transmission and dispatching operations manuals. Section 6.8.2 of the ancillary services manual would no longer refer to a “transmission demand curve.”

The updated day-ahead scheduling manual would include a new section (4.3.5) describing the ISO’s transmission constraint pricing logic, with sub-sections detailing the constraint reliability margin and its application to transmission facilities and the pricing logic. It also provides a table of the pricing values used.

The transmission and dispatching operations manual would see a section renamed to “ancillary service demandcurves,” with transmission demand curve references removed from the section description and table. A new Section 6.3.7 would include new sub-sections describing the same subjects being proposed for the day-ahead scheduling manual.

— Michael Kuser

September 18, 2017

MISO Members Seek Delay on Five-Minute Settlements

By Amanda Durish Cook

CARMEL, Ind. — MISO officials said last week they will consider stakeholders’ request that it seek a second extension on FERC’s deadline for introducing five-minute market settlements.

The RTO is about three months behind schedule on creating a market program to achieve five-minute settlement intervals under FERC Order 825, Chris Delk, MISO manager of market settlements, said during a Sept. 14 Market Subcommittee meeting.

Delk said implementation is delayed because needed software code cannot be written until MISO completes replacement of its settlements computer system in the fourth quarter. The RTO was slated to begin stakeholder testing of the program at the end of the year, but it is now unclear whether it will meet that deadline. MISO will release software components as soon as it can, he said.

Last month, several stakeholders asked the RTO to consider delaying five-minute settlements to give members more time to develop and test their own software changes. (See “Five-Minute Settlements Delayed?” MISO Market Subcommittee Briefs: Aug. 10, 2017.)

MISO officials responded then that FERC had already granted MISO a March 1, 2018, deadline — seven weeks later than the order’s required date — to allow time for deploying the new settlements system (ER17-778). MISO’s real-time settlements are currently based on an hourly average price, while real-time operating reserve settlements are conducted on a five-minute basis already.

MISO FERC five-minute settlements MISO Annual Stakeholders' Meeting — SeDoris | © *RTO Insider*

On Thursday, MSC attendees voted 30-1 to urge MISO to request an additional extension from FERC. The stakeholder motion asks for the release of final business practice manuals at least four months ahead of parallel operations testing of the new settlements system. It also requests at least 12 weeks of testing before a go-live date.

“Our intent here is to gain that three-month delay back for our stakeholders,” said Northern Indiana Public Service Co.’s Bill SeDoris, who introduced the motion.

Because the RTO’s new settlement system is taking longer to go live than originally intended, SeDoris said, MISO members need time to review and adapt to the settlement rules, seek vendors to update related software and finish new coding.

Bladen said meeting those demands could delay the implementation date of five-minute settlements until next summer.

“It puts us at risk for FERC to deny a delay. The response we’ve [gotten] from FERC [thus far] is that a motion for delay is not off the table, but an unreasonably long motion of delay would be unwelcome,” Bladen said.

Bladen nonetheless agreed to take the stakeholder request to MISO management. FERC might be more amenable to MISO filing closer to the standing deadline with the explanation that it is still working on implementation, he said.

September 18, 2017

Hurricanes Steal ‘Baseload’ Thunder at Grid Resilience Hearing

By Tom Kleckner

Hurricanes Harvey and Irma were very much on the minds of lawmakers and electric industry regulators last week during a House Energy and Commerce subcommittee hearing on the grid’s reliability and resilience.

The subcommittee’s Sept. 14 hearing, “Defining Reliability in a Transforming Electricity Industry,” was delayed two days following Irma’s landfall in Florida and then shortened to 45 minutes so members — who had recently approved a hurricane aid package — could take a series of roll-call votes.

Harvey Irma Grid Resilience climate change — FERC’s Neil Chatterjee

FERC acting Chairman Neil Chatterjee and his fellow witnesses, NERC CEO Gerry Cauley and Patricia Hoffman, the Department of Energy’s acting assistant secretary for the Office of Electricity, used their opening comments to detail the steps their organizations have taken in the restoration efforts in Texas, Florida and other southern states.

“It’s times like these that … remind us how important the reliability and resilience of the electric grid is in our lives,” said Chatterjee. “Rebuilding from these storms is going to take time. It’s important as we confront these storms and the impact they’ve had on the grid that we ensure … we can bounce back from these types of events.”

‘Modern, Dramatic Response’

While the subcommittee’s Republicans focused their questions on threats to reliability they said were posed by the changing generation mix, Florida Democrat Kathy Castor challenged her colleagues and the industry to respond to the threats posed by “the changing climate.”

Castor said a “modern, dramatic response” was needed in the face of increasingly large and violent weather events.

“These disasters are very expensive, and it is time to make a dramatic investment in a modern grid, something that is more resilient and preserves the needs of our citizens in a better way,” she said. “We have some of the brightest minds in America, and we need to put them to work, and we need to put the technology to work, whether that’s burying lines we haven’t invested in before or a greater distributed energy grid or building renewables over time.”

Castor questioned DOE’s Hoffman regarding how the agency could invest in a modern grid under significant budget cuts. The department submitted a fiscal year 2018 request of $28 billion in funding, 5.4% below its FY16 levels — including a 42% cut to the Office of Electricity Delivery and Energy Reliability.

“We simply can’t cut our way and think we can address these costs and the challenges ahead,” Castor said. “I hear the [DOE] wants to be proactive on this, but I don’t know how we are going to do that when we see such tremendous cuts by the Trump administration in resilience, in research. We have to re-think that.”

“The administration has focused its FY18 budget on early research,” Hoffman responded. “We are concentrating on maximizing the effectiveness of work at the Department of Energy. We did provide a budget to Congress for FY18. We look forward to what Congress will provide back on what the department will implement as part of our FY18 appropriations.”

“You’re right. It’s back on Congress … and I hope [Congress is] listening and understanding the huge cost if we do not address this,” Castor shot back. “Look at what we’re facing already … emergency aid packages, flood insurance, rising property insurance, rising local taxes because local governments are having to raise taxes to harden [infrastructure], the loss of life. Let’s do more working together.”

Castor found a friendlier ear in Cauley, who said the 50 largest events to affect the grid over the last six years have all been weather related. That has led NERC to “focus on resiliency as a priority going forward,” he said.

Responding to a question from subcommittee ranking member Bobby Rush (D-Ill.), Cauley said climate change is “outside our organization” but agreed there appears to be “an increase in magnitude and severity of events, flooding and storms.”

“We have to think about that in designing our systems and how we prepare for more extremes than we have seen historically,” Cauley said. “Florida Power & Light invested $3 billion in hardening its infrastructure. The equipment that was hardened performed significantly better.”

Script Ripped Up

The hurricanes threatened to steal the script from those who had hoped the hearing on resilience — the fifth in the committee’s “Powering America” series — would provide support for struggling coal and nuclear generators.

When it was their turn to ask questions, North Dakota Republican Kevin Cramer drilled into what he called the importance of coal generation as baseload power, while Texas Republican Joe Barton questioned whether reliability is threatened when generation is predominately renewable.

“I think the technology is there today [to ensure reliability], but it requires a lot of coordination,” Cauley answered Barton.

Chatterjee, who reminded the legislators that FERC is fuel-neutral, referred to Democratic FERC nominee Richard Glick’s confirmation hearing testimony, in which Glick said that FERC and DOE should closely monitor retirements of coal and nuclear baseload generation. (See McIntyre to Senate: ‘FERC does not Pick Fuels’.)

“I would echo those comments,” Chatterjee told Cramer. “We are going to closely watch and monitor whether or not, in fact, transitions in the grid do lead to threats to reliability and resilience, and where we would need to take steps to make sure it is met.”

Cramer asked Chatterjee how the commission will react to Illinois and New York, which are providing subsidies to preserve struggling nuclear generators, and whether the future will be “regulation by litigation.”

“I believe in states’ rights, and it is their prerogative to determine the sources of generation in their generation mix,” Chatterjee said. “When it does affect interstate commerce and potentially does have threats to reliability, FERC does have the authority to weigh in there.”

Virginia Republican Morgan Griffith, facing a ticking clock, reserved one question for Chatterjee. Griffith asked how high a priority the commission is placing on ensuring wholesale markets properly compensate the existing baseload fleet for its reliability services.

“We can walk and chew gum at the same time,” Chatterjee assured Griffith, alluding to the backlog of orders that accumulated during FERC’s six months without a quorum. “I’d say [it’s] a high priority.”

“We face a period of rapid change in the electric industry … this transition is altering our understanding of baseload power and how generating resources are dispatched,” Cauley said, citing cheap natural gas, technological advances, public policy and customer preferences as causes.

“With the appropriate policies, careful planning and strong actions, I’m confident the electricity sector will continue to accommodate these changes and enhance reliability and resilience,” he said. “Even with the changes that are already underway, the bulk power system remains highly reliable and resilient, and shows improved performance each year.”

Cauley called for ensuring reliable gas supplies as the industry becomes “increasingly dependent on natural gas” and said all generating resources should be able to support “essential reliability services.”

“Markets should incent and require all resources … and ensure those resources will respond in both normal and extreme conditions,” he said.

September 18, 2017

MISO Invites Feedback on Plan to Curb Dispatch Deviations

By Amanda Durish Cook

CARMEL, Ind. — MISO is seeking stakeholder feedback on its proposal to use a new calculation to crack down on generators that fail to follow dispatch instructions.

MISO uninstructed deviation — Howard | © *RTO Insider*

The proposed calculation, which comes after years of debate, will impose a “failure to follow dispatch” warning when a resource fails to move at least half its offered ramp rate over four consecutive dispatch intervals, MISO Market Quality Manager Jason Howard said during a Sept. 14 Market Subcommittee meeting. Generators are currently flagged after they deviate by more than 8% from dispatch instructions over four consecutive intervals.

MISO Executive Director of Market Design Jeff Bladen emphasized that the calculation is not yet final and asked for stakeholder suggestions.

After several months of delays, MISO said in May it was still developing software to support its effort to tighten tolerance bands on uninstructed deviations. The RTO’s Market Monitor has been recommending the project for more than five years. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)

A MISO impact study using production data from May through July found that failure to follow dispatch increased from 2.4 to 6.1% under the new threshold. The study also found that the calculation reduced excessive and non-excessive energy charges by 4.4% across the MISO footprint for the three months, while Day-Ahead Margin Assistance Payment (DAMAP) disbursements decreased by 7.6% or $941,000.

MISO Market Monitor David Patton said the reduction in DAMAP payments is “huge” because it shows MISO will stop awarding make-whole payments to generators that fail to follow dispatch.

Howard said MISO now will seek feedback on the new calculation from the FERC Office of Enforcement and continue discussions with the Monitor’s staff. At an Advisory Committee meeting this spring, several stakeholders asked MISO to convene a workshop to discuss the RTO’s analysis and the possible shape of the proposal. (See “AC Prods Restart on Tighter Uninstructed Deviations,” MISO Advisory Committee Briefs.)

DTE Energy’s Nick Griffin asked if the new proposal might have “unintended consequences” by discouraging slow-ramping resources from offering in fear of being penalized.

“The goal here is to get people to offer the ramp rate that they are comfortable with and they actually can live with,” Bladen said. “We don’t want generators to offer a ramp rate that they can only meet half the time because the reality is we’re counting on the ramp. We’re counting on people to move.”

“It harms the system to provide a ramp rate that you can’t realistically meet,” Patton added. “Your offer parameters aren’t really accurate if you can’t perform to them.”

Some stakeholders expressed concern that the nearly $1 million in theoretically lost DAMAP would inordinately affect slower moving coal units.

“You’re talking about a million dollars [for] every generator [in] MISO. We’re not going to devastate anyone here,” Patton said. “There might be one or two units that are so inflexible that they might alter their offer, but that’s a good thing because we won’t be relying on flexibility that we really don’t have.”