Page 1220 – RTO Insider

July 23, 2019March 19, 2025

NEPOOL RC/TC Briefs: July 16-17, 2019

STOWE, Vt. — Mary Bimonte of Eversource Energy on July 16 presented a joint meeting of the New England Power Pool Reliability and Transmission committees with an overview of the regional network service (RNS) rates that became effective June 1.

Bimonte, a member of the Participating Transmission Owners Administrative Committee, showed the RNS rate increased $1.51/kW-year from last year to $111.94/kW-year, with the region’s aggregate annual transmission revenue requirement (ATRR) rising $41.3 million to nearly $2.19 billion.

Eversource subsidiaries Public Service Company of New Hampshire, NSTAR West and NSTAR East accounted for much of the ATRR increase, along with Vermont Transco and Maine Electric Power.

During a presentation of the five-year RNS rate forecast, Bimonte noted this year’s increase was 67 cents/kW-year short of projections made last year for 2019.

A summary of the RNS five-year forecast from 2020 to 2023 | ISO-NE

Modifying Interconnection Procedures

ISO-NE Director of Transmission Strategy and Services Al McBride led a discussion of proposed modifications to interconnection procedures — specifically, Planning Procedure No. 10 sections 7.7 and 7.8 — to clarify adjustments to interconnection capability following partial market exits.

According to the RTO’s market procedures, “permanent and retirement delist bids can be submitted for all or just a portion of a resource’s capacity. A partial delist bid allows a resource to remove the portion of its megawatts it cannot deliver from all ISO-NE markets or only the capacity market, depending on the type of delist bid submitted.”

“When a partial retirement delist bid clears in the Forward Capacity Auction, the resource remains active and its interconnection rights are reduced to the appropriate megawatt level,” according to the RTO. “When a partial permanent delist bid clears in the FCA, the qualified capacity value for the resource is reduced.”

In February, the NEPOOL Participants Committee approved the general changes, which include methodologies to update the levels of interconnection service available for generators (and external elective transmission upgrades) after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the Forward Capacity Market.

The RC and TC will alternately discuss the specific proposed revisions ahead of a planned vote by the PC in November, with a tentative effective date of January 2020.

During the previous discussions, stakeholders identified circumstances where the winter capability of their generating facilities after a partial market exit may not be correctly calculated by the formulas currently contained in PP10, McBride said.

The RTO will propose a new section of the Tariff to capture the rules associated with the establishment and relinquishment of interconnection service amounts and plans to present the proposed revisions at the Aug. 21 TC meeting.

Operating Procedure Revisions

The RC voted to recommend that the PC support revisions to a handful of ISO-NE operating procedures slated to become effective Aug. 2, including:

Altering OP-24 to describe the confidential Appendix C as a list of transmission facilities for which transmission owners are required to report protection settings, characteristics, failures or degradation. RTO staffer Jerry Elliott presented proposed revisions reflecting that Appendix C previously included a diagram, but now includes a list. The proposed changes to OP-24 are conforming changes.
Revising OP –12 (Voltage and Reactive Control) and OP-12D (Voltage Schedule Annual Transmittal Form) to clarify local control center actions for providing voltage schedules to generators.
Revising OP-5 (Resource Maintenance and Outage Scheduling) to indicate that outage requests for import capacity resources are for notification purposes only. The motion passed with six opposed (two from the Generation Sector, two from the Supplier Sector and two from the Alternative Resource Sector) and three abstentions (one Generation Sector, one Supplier Sector and one Alternative Resource Sector).

Future Vote on OP-14E Revision

Elliott presented proposed revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E.

The RC is scheduled to vote on the revisions at its Aug. 20 meeting, and the RTO is seeking a vote by the PC at its Sept. 13 meeting.

The changes include correcting terms defined in section I.2.2 of the Tariff or ISO-NE manuals, in addition to replacing the term “nominated consumption level” with the defined term “nominated consumption limit.”

The RTO also notified the RC of revisions to OP-10 Appendix A to update the contact information for the U.S. Department of Energy in cases of reporting major system disturbance, outage or incident. The revisions took effect immediately upon the notification.

Reactive Capability Auditing Tariff Changes

The RC voted to recommend PC support for proposed revisions to section I.2.2 of the Tariff to incorporate definitions for interconnection reliability operating limit (IROL) and system operating limit (SOL).

ISO-NE lead operations analyst Kory Haag said the revisions incorporate four new defined terms in the Tariff: reactive capability audit, reactive resource, IROL and SOL.

The meeting focused on IROL and SOL, which will now be defined as the meaning specified in the g lossary of terms used in NERC reliability standards.

NERC defines IROL as “a system operating limit that, if violated, could lead to instability, uncontrolled separation or cascading outages that adversely impact the reliability of the bulk electric system.”

It defines SOL as “the value … that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria.”

The RC requested an Oct. 1 effective date for the definitions, following a vote by the PC in August.

Eversource Substation Upgrades

The RC voted to recommend that ISO-NE determine that three proposed substation upgrades by Eversource would not adversely affect the stability, reliability or operating characteristics of nearby transmission facilities.

Eversource crews work to restore power following a Jan. 20 ice storm in Connecticut. | Eversource Energy

Upgrades to the Andrew Square and Dewar Street substations in South Boston would entail the installation of two independent current differential high-speed protection groups on the K Street-to-Andrew Square 115-kV cables and the Dewar 115-kV cables to provide the selectivity to differentiate between a line fault and a transformer fault. The work will provide protection system fault clearing selectivity and design in compliance with Northeast Power Coordinating Council protection system design criteria (NPCC Directory 4 BPS). The proposed in-service date for both projects is in November 2019.

An upgrade to the Portsmouth substation in New Hampshire would entail the replacement of an existing 115/34-kV, 44.8-MVA transformer with a 62.5-MVA rated unit, the addition of a second 115/34-kV, 62.5-MVA transformer, installation of one new 115-kV bus tie circuit breaker, and installation of two new 115-kV circuit breaker disconnect switches. Eversource will also install one new 11-kV circuit switcher for high-side transformer protection and add two 7.2-MVAR capacitor banks, one on each 34-kV bus. The upgrade also will add a 34.5-kV bus tie circuit breaker, which will normally be open, with an automatic close function upon loss of a transformer. The proposed in-service date is June 1, 2020.

4 20-MW Solar Projects by FPS Approved

The RC voted to recommend that ISO-NE determine that implementation of four separate 20-MW solar projects proposed by Freepoint Commodities (FPS) would not adversely affect the grid.

None of the projects include energy storage, and each comprises 10 2-MW arrays.

Solar panels in Vermont like the 20-MW projects approved by the NEPOOL RC on July 16 | Green Mountain Power

SGC Engineering’s Jeff Fenn presented the separate project overviews, showing the solar farm in Plainfield, Conn., interconnecting to the 23-kV bus at the Fry Brook substation and with a proposed in-service date of December 2022.

The firm’s project in Fair Haven, Vt., will interconnect to the 46-kV line between the Green Mountain Power Fair Haven and Carver Falls substations, while the project in Shaftsbury, Vt., will interconnect to the 46-kV line between the GMP South Shaftsbury tap and East Arlington substation, both with a proposed in-service date of July 1, 2022. The project in Claremont, N.H., has the same in-service date.

Enhancing Competitive Tx RFP

ISO-NE Transmission Planning Director Brent Oberlin led a discussion of competitive transmission solicitation enhancements that included proposed clarifications to Attachment K of section II of the Tariff, the draft selected qualified transmission project sponsor (SQTPS) agreement, and to sections I.2.2 and I.3.9 of the Tariff associated with preparing for competitive transmission solicitations under FERC Order 1000.

Based on the results of the 2028 Boston Needs Assessment, which were presented to the ISO-NE Planning Advisory Committee in April, the RTO plans to issue its first request for proposals for a competitively developed transmission solution in December 2019. (See ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)

Tx Cost Allocation Revisions

The RC voted to recommend that ISO-NE approve pool-supported costs for two projects by Avangrid’s United Illuminating subsidiary in Connecticut, including $11.24 million for work associated with the East Shore 345-kV circuit switcher replacement and $8.17 million to replace line optical ground wire and related fiber optic equipment on the 115-kV 1130 Line between the Pequonnock and Sasco Creek substations.

UIL determined that none of the costs associated with either upgrade can be considered localized.

Capacity Cost Compensation

The RC voted to recommend that ISO-NE designate PSEG Power’s Bridgeport Harbor gas-fired plant and the Wheelabrator North Andover waste-to-energy plant as dynamic reactive resources meeting the RTO’s capacity cost compensation program eligibility requirements.

The committee recommended the facilities be eligible for compensation associated with a qualified reactive resource designation effective Aug. 1.

RC Consent Agenda

The RC approved a consent agenda that included seven proposed plan application (PPA) notifications for Massachusetts solar generation totaling nearly 27.5 MW.

The list includes five projects being interconnected through Eversource:

Borrego Solar’s 3.75-MW project in Plymouth, interconnecting to the Valley substation, with a proposed in-service date of Dec. 31.
Borrego’s 4.999-MW project in Freetown, interconnecting to the Bell Rock substation, with a proposed in-service date of May 1, 2020.
CVE North America’s 2.5-MW/1.262-MW Wing Lane solar and battery project in Acushnet, interconnecting to the Wing Lane substation with a proposed in-service date of Oct. 31.
SunRaise Development’s 2.5-MW Cranberry Highway project in Wareham, interconnecting to the Tremont substation with a proposed in-service date of Dec. 1.
Syncarpha’s 4.99-MW Chester Road solar and battery project in Blandford, interconnecting to the Blandford substation with a proposed in-service date of Nov. 18.

Two projects will interconnect through New England Power:

Ameresco’s 2.5-MW Otter River Road project in Gardner, interconnecting to the Crystal Lake Substation with a proposed in-service date of Sept. 1, 2020.
NSTAR Electric’s 4.99-MW Denslow Road project in East Longmeadow, interconnecting to the East Longmeadow substation with a proposed in-service date of Nov. 15, 2020.

The consent agenda also included one PPA non-solar notification, the 1.5-MW Madison Business Park battery energy storage facility in Madison, Maine, which New England Battery Storage will interconnect to the Jones Street substation with a proposed in-service date of Jan. 1, 2020.

The agenda also included three Level I (for information only) transmission PPA notifications:

New England Power is updating the summer normal and revised winter line ratings to reflect current cable design on a new 345-kV underground line from the Wakefield Junction substation to the company’s border with Eversource at the Wakefield/Stoneham, Mass., town line; two new circuit breakers at the Wakefield Junction substation; and a new 345-kV variable shunt reactor. The proposed in-service date is in May 2021.
Eversource is updating the summer normal and revised winter line ratings to reflect current cable design on the installation of a new 8-mile, 345-kV underground cable circuit from the Woburn substation in Massachusetts to National Grid’s Wakefield Junction substation, in Wakefield, including 160-MVAR variable shunt reactors at each terminal. The work will expand the 345-kV switchyard at Woburn to be a breaker-and-a-half substation with four bays. The proposed in-service date is in May 2021.
Eversource is also rebuilding the existing 69-kV 667 Line from the Salisbury substation in Salisbury, Conn., to the Falls Village substation because of asset conditions. The proposed in-service date is Dec. 31.

— Michael Kuser

July 23, 2019

Stakeholder Soapbox: PJM’s Market Hurting Clean Energy

By Miles Farmer and Amanda Levin

PJM is lagging other regions in addressing carbon emissions and has added significantly more fossil generation than any other grid operator in the U.S. In a recent analysis, we argued that PJM’s market design plays an important role in the build-out of fossil-fueled power plants, and market reform is needed for the cleaner energy future that states and customers in the RTO demand.

Steve Huntoon’s response (See Counterflow: Scary Wrong.) is a collection of distractions from our central concern: PJM’s gas boom will break the “carbon budget” for the region, making it impossible to reach emissions goals. Market structures are a significant factor in determining the energy mix and investments made in a region. PJM’s capacity market, in particular, is built around the characteristics of fossil-fired plants, procures too much capacity and blunts market signals that could drive the expansion of clean energy resources such as wind and solar.

Gas Won’t Save Us

Huntoon suggests that coal-to-gas switching must continue. This is not a climate solution for the region: Retiring coal must be replaced with zero-emission energy sources. Simply replacing remaining coal with gas will not extend the emission reductions PJM has achieved in the past decade. Even as coal-fired power continued to decline last year, carbon pollution in the region (and nationwide) increased year over year in 2018 as natural gas consumption and generation reached new highs. This is projected to continue in the U.S. government’s own most recent energy outlooks. (See the Energy Information Administration’s 2019 Annual Energy Outlook.) Even as coal retires across PJM, emissions in the region will plateau in the coming years under a business-as-usual, high-natural-gas scenario.

PJM — | *Historical data from S&P Global Market Intelligence; Projections derived from U.S. EIA’s Annual Energy Outlook 2019*

This is not a climate-safe future. While the reductions PJM has achieved so far from coal-to-gas switching are roughly consistent with a 1.5 or 2-degree Celsius warming trajectory, they will not continue without focused efforts to deploy zero-carbon resources.

PJM’s market has worked well for gas but poorly for other technologies. A new formula is needed to push the region past gas and achieve reductions in line with a net-zero future.

PJM’s Capacity Market is Flawed

Many factors influence a region’s energy mix, including market rules, as well as state policies and renewable resource potential (i.e. how strong the winds are or how often and powerful the sun shines). We agree with Huntoon that other RTOs, like ERCOT in Texas, were dealt a better hand to play than PJM when it comes to renewable resource quality. Even so, it is clear that PJM’s capacity market design over-procures fossil capacity and blunts clean energy investment.

As we explained in our article, PJM is procuring vastly more capacity than reliability regulators have deemed necessary to keep the lights on.

| *PJM Base Residual Auction & Reserve Requirement Study Reports*

One reason for this is that PJM has failed to implement a seasonal market and thereby fails to fully leverage resources like demand response, solar and wind. Aggregation fails to address the real issue that the region has different needs in summer and winter.

Huntoon contends that prices would be the same in any case, as “there is no free lunch.” But PJM’s current construct essentially forces all customers to buy a heaping dinner portion even at breakfast time, when they aren’t very hungry, and makes it very costly for chefs to include any menu options other than foods that can be served for both meals. The Brattle Group estimated that separate procurement periods would push costs down by roughly $100 million to $600 million per year.

In addressing our point that PJM’s over-procurement has been costly to customers, Huntoon proposes his own free lunch, contending that our simple intuition that buying more stuff costs more money “profoundly misunderstands” the capacity market. His logic on this point is circular. Huntoon explains that if capacity suppliers had offered higher prices (high enough that PJM wouldn’t want to over-procure supply), costs would have been higher.

This is a faulty counterfactual. If PJM were to just procure the capacity necessary to serve a lower reserve margin (and then stop procuring additional “low-cost” capacity that has bid in), the market would actually see lower clearing prices. Our point is not that PJM should switch to a vertical demand curve (which has other downsides), but rather that after procuring significantly more than its target year after year after year, it is clear that PJM has based its demand curve on erroneous inputs and the overall market construct needs to be reassessed.

In Huntoon’s calculation, he assumed supply bid prices were high enough that PJM would not procure beyond the target reserve (red dot). However, if PJM were to just procure the capacity necessary to serve the target reserve margin (and not procure additional “low-cost” capacity), the market would actually see lower clearing prices (green dot).

PJM’s unwillingness to leverage seasonal resources and persistent over-procurement mean more money is gained from the region’s capacity markets, distorting energy and ancillary markets. Unlike in the rest of the country, renewable resources are largely excluded from resource adequacy planning and are left to compete against heavily subsidized fossil fuel plants in energy markets. In contrast to PJM’s capacity market, wind and solar resources compete in the energy and ancillary services markets on equal footing, as those markets are not defined by administrative criteria.

PJM Can Change Course

Fighting climate change will not be easy. Large, integrated, efficient markets are an essential tool in this fight. But those markets must not create barriers to clean resources or climate policy. Critically, those markets must not be dominated by administrative constructs where incumbent market participants fight over hidden subsidies and create barriers to competition.

Highlighting the consequences of overbuilding gas does not ignore that the region has not been blessed with the same renewable resources as other areas of the country. PJM’s rules play an important role in determining the future resource mix. The recent leadership change at PJM provides the grid operator with an ideal opportunity to shift course, allowing them to better respond to the demands of customers and states, reverse its trend of capacity over-procurement, and better integrating state clean energy policies into a reliable and clean energy future for the region.

Miles Farmer is a senior attorney and Amanda Levin is a policy analyst in the Climate & Clean Energy Program of the Natural Resources Defense Council.

July 23, 2019

MISO, SPP States Ponder Look at Interregional Planning

By Amanda Durish Cook

INDIANAPOLIS — State regulators in the MISO and SPP footprints are considering an independent analysis of the interregional planning process to supplement the seams coordination analysis already underway by the two RTOs’ market monitors.

The Organization of MISO States and the SPP Regional State Committee’s Seams Liaison Committee agreed unanimously at a July 21 meeting to scope an independent analysis that would examine whether the RTOs are leaving efficiencies and benefits on the table in their interregional transmission planning.

The joint committee will allot 30 days for stakeholder suggestions on how the analysis might look and what questions it will probe.

“We don’t know at this juncture what the analysis will be,” OMS President and Missouri Public Service Commissioner Daniel Hall told fellow regulators.

The regulators’ plans reflect frustration over the inability of the RTOs to find beneficial projects across their seams.

Missouri Public Service Commission economist Adam McKinnie | © *RTO Insider*

Missouri PSC economist Adam McKinnie said recently approved improvements to the MISO-SPP interregional planning process may or may not lead to their first-ever project. He agreed with other regulators that interregional project construction is not necessarily an indicator of the health of the MISO-SPP planning process.

“If there’s a good opportunity and a project, let’s do it, but I don’t want to add work. I don’t want to dig ditches for fun,” McKinnie said.

“If there are [economic] benefits and we’re not capturing them with projects, then we have a problem,” Arkansas Public Service Commissioner Ted Thomas added.

Earlier this month, FERC OKs Changes to MISO-SPP Joint Study Process.)

MISO and SPP completed two 18-month studies beginning in 2014 and 2016. They began another Coordinated System Plan earlier this year, skipping a 2018 start date in favor of trying to improve their interregional planning processes. However, early indications are that the newest study may not yield a project either. (See “Revised Seams Study with MISO yet to Bear Fruit,” SPP Seams Steering Committee Briefs: July 10, 2019.) The RTOs will report conclusive CSP results at an Aug. 19 Interregional Planning Stakeholder Advisory Committee meeting.

McKinnie said MISO and SPP’s regional economic planning models still differ on assumptions like load, fuel mix and where new resources will be sited.

FERC Commissioner Cheryl LaFleur, who attended the meeting, reminded liaison committee members that MISO and PJM’s level of seams coordination was not always held up as the standard it is now.

“There were six stormy years — maybe not all of them stormy — that it took to get there,” LaFleur said.

LaFleur also said she was working during her short time left on the commission to get her colleagues to devote attention to MISO-SPP seams issues.

Meanwhile, work continues on MISO and SPP’s market monitors’ seams study. Hall said both SPP and MISO market monitors are still open to modifications to the study’s work plan. (See RSC, OMS Approve Mo n itors’ Seams Study.)

MISO is paying Potomac Economics $250,000 to complete the first phase of the study. SPP has an in-house Market Monitoring Unit and has not disclosed a special budget item.

“We’re ready to go; we’re ready to work with you; and we think it’s time,” Hall said of the study in remarks before the MISO Board of Directors in June.

OMS and the RSC expect the first phase of the monitors’ study results to be released in September. The first phase of the study focuses on market-to-market coordination, rate pancaking and joint dispatch. A second phase of the study will concentrate on interface pricing, interchange optimization and regional directional transfer limits.

July 23, 2019

Study: Carbon Adder Supports NY Clean Energy Goals

By Michael Kuser

NYISO’s effort to price carbon into its wholesale markets could help New York achieve its ambitious clean energy goals, but the policy would benefit from a boost in the social cost of carbon (SCC) or additional programs, according to a s t udy released Tuesday.

The study by the nonprofit Resources for the Future (RFF) indicates a $63/ton carbon price could drive clean energy penetration to as high as 64% of the state’s resource mix by 2025, “well on the way” to the 70% requirement for 2030. The SCC is currently estimated at $40/ton.

The target of 70% renewable generation by 2030 implies an increase in the share of non-emitting generation from its current level of approximately 60% (46% not including Indian Point, which is slated to retire in 2021) to roughly 88% in 2030 (for load-serving entities under the jurisdiction of the New York Public Service Commission) and 100% by 2040, according to the study.

“This analysis suggests pricing carbon within New York electricity markets could help to advance the adoption of clean energy, but a higher carbon price, additional companion policies or different policies will likely be necessary to hit the clean energy goals New York state has set for 2030.”

The think tank used its own Engineering, Economic and Environmental Electricity Simulation Tool (E4ST) to model the impact of carbon pricing on emissions and prices in New York and throughout the Eastern Interconnection based on expectations for 2025.

The study, “Benefits and Costs of Power Plant Carbon Emissions Pricing in New York,” was co-authored by RFF’s Daniel Shawhan and incorporates key assumption changes from an earlier version of the analysis presented last September to the Integrating Public Policy Task Force (IPPTF), a joint effort between the ISO and the PSC. (See ‘Negative Leakage’ from NY Carbon Charge, Study Shows.)

The ISO’s Market Issues Working Group (MIWG) took over in January from the task force, which over nearly a year and a half had developed the carbon pricing proposa l released last December.

“The most influential change was that we used what I consider to be better projections of the costs of solar and wind technology,” Shawhan told RTO Insider.

“The ones we used before were from the [U.S. Energy Information Administration’s] Annual Energy Outlook, and they’re just simply out of date,” Shawhan said. “So we used better assumptions … the medium cost projections from the National Renewable Energy Laboratory annual technology baseline. The effect of that change was to lower the projected cost of solar and wind, and, as a result, we get considerably more emissions reductions and we get a low projected cost to electricity users, lower than some of our prior projections.”

Clean Energy Legislation

NYISO market participants have been debating how the state’s newly enacted Climate Leadership and Community Protection Act (A8 4 29) and its mandated influx of renewables would affect the effort to price carbon. (See “New Energy Law Could Affect CO2 Market Design,” NYISO Business Issues Committee Briefs: June 20, 2 0 19.)

Along with the 70-by-2030 renewables target, the new law nearly quadruples the state’s offshore wind energy goal to 9 GW by 2035 and requires the economy to be carbon-neutral by 2040. It also doubles the distributed solar generation goal to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030.

Gov. Andrew Cuomo signed the bill July 18, the same day he announced the state was awarding a combined total of 1,700 MW in offshore wind contracts to Equinor’s Empire Wind project and to Sunrise Wind, a joint venture of Ørsted and Eversource Energy.

In addition, the state Department of Environmental Conservation is revising its Clean Air Act regul a tions to lower allowable NO_x emissions from simple cycle and regenerative combustion turbines during the ozone season, effective May 1, 2023, with generator compliance plans due by March 2, 2020. (See NY DEC Kicks off Peaker Emissions Limits Heari n gs.)

According to the RFF simulation results, New York electricity users in in 2025 would pay the equivalent of between 0.1 and 1.1% of the retail electricity rate for the carbon adder, while the net benefit to society as of that year would be between $108 million and $691 million per year, in 2013 dollars.

The analysis found a carbon adder drives New York renewable energy credit and zero-emission credit prices to zero, incentivizing renewables investment and the maintenance of upstate nuclear generation in the energy markets. It also found the carbon policy increases zonal average wholesale electricity prices in New York by $20 to $24, but with revenue rebated to end users, and other charges reduced, the average cost to end users is 9 cents to $1.21/MWh.

In addition, the study found the Regional Greenhouse Gas Initiative’s Emissions Containment Reserve, due to be introduced in 2021, will provide a mechanism for reducing the emissions cap if the RGGI allowance price falls to the reserve trigger price, resulting in lower total power sector emissions from the RGGI states taken together.

July 23, 2019February 19, 2025

Ohio Approves Nuke Subsidy

By Christen Smith

Ohio legislators approved a controversial bill Tuesday to subsidize FirstEnergy Solutions’ nuclear reactors on Lake Erie, making it the third state to provide a financial lifeline to the nuclear industry in PJM.

The Ohio House of Representatives voted 51-38 in favor of the $170 million Ohio Clean Air Act (HB 6). Republican Gov. Mike DeWine quickly signed the bill later that day, officially curtailing the state’s current renewable portfolio standards and tacking on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills for the Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects in rural areas of the state.

Ratepayers will also notice a $1.50 charge to supplement two Ohio Valley Electric Corp. (OVEC) coal plants — a House-crafted addition meant to attract support from electric distribution utilities, according to some critics. (See Ohio Nuke Bill: A Worthwhile Tradeoff?)

Davis-Besse Nuclear Power Plant

“We are very pleased that Gov. Mike DeWine signed HB 6 following its successful bipartisan passage in the General Assembly,” said John W. Judge, CEO of FirstEnergy Solutions. “We’re also thankful for the support and commitment by Speaker [Larry] Householder and Senate President [Larry] Obhof, who understood the importance of protecting 90% of the state’s zero-emissions electricity, substantial employment and the need to provide affordable rates from a diverse portfolio of generation sources for Ohioans.”

Judge confirmed that FES will rescind deactivation orders for both plants and prepare for necessary refueling in the spring.

With DeWine’s signature, Ohio joins New Jersey and Illinois as the only states in PJM to subsidize nuclear generation — a policy reaction to the economic impact of cheap, natural gas-fired generation setting prices in the wholesale markets. Supporters insist the support is justified because the RTO’s market structure doesn’t appropriately value the reliability and carbon-free emissions provided by nuclear power. Without them, proponents say states can’t achieve aggressive clean energy targets because renewables are intermittent. (See Nuclear, Gas Seen as Crucial to PJM’s Renewables Gro w th.)

Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE), characterized the plan as a “bailout” — echoing the sentiments of critics in both the clean energy and natural gas sectors who argue the subsidies will distort the wholesale energy market and spike electricity prices.

“At a time when the nation is accelerating its transition to affordable, pollution-free renewable power, this legislation goes in precisely the wrong direction with a bailout of aging and uneconomic coal and nuclear plants and a weakening of the state’s renewable portfolio standard,” he said.

“House Bill 6 is just the latest, though maybe the worst, of the retreats from the legislature’s brave stand for utility consumers through power plant competition in 1999,” said Bruce Weston, counsel for the Ohio Consumers’ Counsel (OCC). “Power companies have too much influence in Ohio, and that should be reformed.”

AARP joined ACORE, the OCC and the Ohio Manufacturers’ Association in calli n g on the governor to veto the bill, to no avail.

Todd Snitchler, CEO of the Electric Power Supply Association, said the bill “unfairly punishes competitive generators who are the largest power producers in Ohio. This bailout jeopardizes competitors’ investments and risks local tax revenues and jobs in the communities hosting competitive coal and natural gas plants that generate thousands of megawatts for Ohio and the PJM region.

“Passage of yet another nuclear bailout makes it more urgent than ever for the Federal Energy Regulatory Commission to swiftly implement effective measures to protect the integrity of PJM’s energy and capacity markets,” he added.

The House vote came six days after the Senate approved the bill, capping off months of hearings that debated the merits of saving the plants at the expense of RPS goals. (See Ohio Senate Clears Nu k e Rescue.) Householder (R) had reportedly worked behind the scenes to secure bipartisan support in his chamber by pushing the fees for OVEC, and slashing the RPS mandates long unpopular among state Republicans.

“We are reducing consumers’ bills, repealing wasteful government mandates and keeping good-paying jobs here in Ohio,” Householder said Tuesday. “This is legislation that makes sense for the ratepayers of Ohio.”

Under the plan, the nuclear charges would sunset in 2027, and the Public Utilities Commission would audit the facilities each year between 2022 and 2026 to determine if the subsidies are still needed — an attempt to placate critics who insist the plants aren’t losing money at all.

The RPS — the law determining how much electricity electric distribution utilities procure from renewable resources — will drop from 12.5% by 2027 to 8.5% until 2025, with no continuation of the mandate thereafter.

Opponents have vowed to seek a referendum opposing the bill on the November 2020 election ballot. ClearView Energy Partners said opponents have 90 days after July 23 to collect the necessary 265,774 signatures needed to get it on the ballot. The success of such a measure depends largely on the way election officials word the referendum, ClearView said.

July 23, 2019

FERC Upholds Fuel Cost Penalties Against CPV Plant

By Christen Smith

FERC on Monday upheld penalties levied against a New Jersey power plant for violating its fuel cost policy, saying the company acted in bad faith and ignored advice from PJM staff and its Market Monitor (ER19-1083).

Competitive Power Ventures (CPV) requested two waivers regarding its decision to bid its Woodbridge Energy Center, a 725-MW combined cycle plant in Middlesex County, into the energy market on Jan. 5, 2018, using its revised — but not yet approved — fuel cost policy. The company wanted FERC to waive the rules and reverse the penalty, given what it called the rare circumstances that led to the changes, or retroactively approve its revised policy.

During a discussion one week prior to the January auction, PJM and the Independent Market Monitor told CPV to submit energy offers based on its existing policy until its revisions were approved — which didn’t happen until Jan. 29.

CPV — Competitive Power Ventures’ Woodbridge Energy Center | *Competitive Power Ventures*

The company said it ignored the recommendation because it “does not believe it would have been selected to operate given the overall unit offers.” CPV said it was faced with the choice of making a cost-based offer using its approved policy, which no longer reflected its true costs, or using the unapproved but more accurate policy reflecting “in some cases lower” costs.

“CPV argues the purpose of imposing a penalty for submitting an offer inconsistent with an approved fuel cost policy is to prevent the ‘deliberate misrepresentation of fuel costs,’ and CPV had no intent to misrepresent its fuel costs,” the company wrote. ” … This situation will not repeat itself because CPV’s revised fuel cost policy is now approved, and the unique circumstances are unlikely to arise again.”

The Monitor argued granting either of the waivers would undermine the enforcement of fuel cost policies, market power mitigation and customers’ confidence.

“It would undermine the entire process of ensuring accurate cost-based offers and would provide precedent for requests for any participant that wanted to modify its fuel cost policy after-the-fact,” the IMM wrote. “CPV’s waiver requests represent a broad attack on the approved rules that ensure fuel cost policies are verifiable and systematic.”

The commission said it rejected the waiver because CPV failed to show it had acted in good faith.

“CPV does not dispute this timeline and admits it knowingly offered pursuant to the pending revised fuel cost policy, as opposed to its then-effective initial fuel cost policy as required by the Operating Agreement,” the commission wrote, noting CPV never explained why it waited until January to revise its policy or why it took nearly a month to provide a copy of its fuel supply agreement when the Operating Agreement allows just five business days to pass. “We find that these facts do not support a finding that CPV acted in good faith, and its waiver request fails.”

The amount of the penalty assessed on CPV was not disclosed.

A PJM stakeholder-crafted package pending before the Market Implementation Committee would create a “safe harbor” provision for sellers who violate their fuel-cost policies for unforeseen reasons. (See PJM Stakeho l ders Still Divided on Fuel-cost Policies.)

July 22, 2019

High Temps Put Con Ed on the Hot Seat Again

By Rich Heidorn Jr.

Temperatures finally receded Monday after a three-day heat wave that broiled cities from Oklahoma City to Boston. But Consolidated Edison remained on the hot seat after power outages hit 50,000 customers in New York City and Westchester County on Sunday night.

That included 30,000 customers in Brooklyn whose service was cut Sunday to prevent equipment damage. As of 3 p.m. Monday, the company was reporting almost 12,000 customers still without service.

The outage came just a week after a blackout attributed to failed relay systems that darkened part of Manhattan. (See Con Ed: Failed Relay Protections Caused NYC Blackout.)

An angry New York City Mayor Bill de Blasio said Monday he had lost faith in the utility, echoing Gov. Andrew Cuomo’s suggestion after the July 13 outages that it could be replaced.

“I spoke to Con Ed’s president last night. I spoke to him this morning,” de Blasio told reporters Monday. “No answers whatsoever as to why this happened and what is being done to ensure it will not happen again. This was obviously a predicable situation and therefore preventable.

“It’s very clear we have to question whether Con Ed as it’s structured now can do the job going forward or whether we need to go to an entirely different approach. So, I’m calling for a full investigation and [an inquiry into] whether we need a new entity to handle this situation going forward, because at this point, I do not have faith in Con Edison.”

Cuomo repeated his criticism in a tweet in which he announced he had deployed 200 State Police officers, 100 generators and 50 light towers to Brooklyn. “We’ve been through this situation with Con Ed time and again, and they should have been better prepared — period,” he said.

Con Ed’s stock closed Monday at $86.82/share, down more than $2 (2.4%) from its close before the two blackouts on July 12.

The company said Monday its actions were needed to prevent more severe outages.

“We are completely focused on getting customers back in service, and we regret the distress they are under,” it said in a statement. “The actions we took were necessary to prevent longer outages to the impacted customers that would have occurred as a result of additional equipment damage. Customer service representatives are in southeast Brooklyn providing assistance as crews work to restore the remaining customers in that area, as well as other parts of our service area.”

Con Ed earlier reduced voltage by 8% in some areas to maintain service. The company distributed dry ice to residents during the outage.

Company spokesmen told The New York Times that the outages were ordered to prevent damage to overhead lines at risk of overloading due to the heat. “It is the third day of the heat wave, so the system is really baking at this point,” one representative said.

Con Ed wasn’t the only utility that faced challenges in the heat. PSEG Long Island had about 6,000 customers without power Sunday evening, Newsday reported.

Other utilities scrambled to restore power after strong thunderstorms brought down lines. DTE Energy reported that 600,000 customers in southeast Michigan suffered outages as a result of the region’s largest storm in years. Consumers Energy said about 220,000 customers lost service as storms downed more than 2,600 wires.

Weather-related outages also were reported in New Jersey and Wisconsin.

July 22, 2019

Comments due July 26 on Revised Inverter Standard

By Rich Heidorn Jr.

NERC stakeholders have until 8 p.m. ET Friday to weigh in on proposed changes to reliability standard PRC-024-2 concerning inverter-based generation resources.

The proposal is intended to ensure that generator owners (GOs), operators, developers and equipment manufacturers understand how their plants are expected to respond to grid disturbances. It was based on disturbance analyses and the Inverter-Based Resource Performance Task Force’s PRC-024-2 Gaps Whitepaper. (See NERC to Try Again on Invert e r Rules.)

One of the most significant changes is in section 4.1.2., in which NERC proposes expanding applicability to include transmission owners “that own a bulk electric system generator step-up (GSU) transformer or collector transformer.”

It also requires inverters not to trip or “enter momentary cessation” — an interruption in their injection of current into the grid — within the “no trip zone,” except for “documented and communicated regulatory or equipment limitations.”

Revised Inverter Standard — Most solar PV generation is below the 75-MW threshold requiring registration with NERC. | *NERC*

The unofficial comment form references two issues that the standard drafting team (SDT) said must be addressed to ensure the reliability intent of the PRC-024 is achieved.

It notes that the existing standard refers only to “generator protective relaying,” which suggests the setting of voltage and frequency protection relays on the GSU transformers on synchronous generators are excluded.

“Because the GSU and the generator are connected to the same bus and have the same source (the generator), they see the same voltage (and frequency). Consequently, the voltage and frequency protection settings applied to the relays on the GSU must be included in the standard as the operation of those relays would result in tripping the generator, thus defeating the reliability intent of the standard,” it said.

Another issue identified by the SDT is that the standard applies only to GOs, excluding TOs that own GSUs or collector transformer and associated voltage and frequency protective relays.

However, none of those who had filed comments as of Monday said they knew of any GSU owners that were registered as a TO but not as a GO.

Commenters should use the Standards Balloting and Commenting System to submit feedback.

July 22, 2019April 14, 2025

ERO Budget Nears OK Despite Canada’s Concerns

By Rich Heidorn Jr.

The Electric Reliability Organization’s proposed $207 million budget appears headed for approval, but NERC’s increased spending to develop its cybersecurity capability is facing some pushback from Canadian utilities.

The Canadian Electricity Association and Ontario’s Independent Electricity System Operator questioned the 13.3% spending increase on the Electricity Information Sharing and Analysis Center (E-ISAC), part of a five-year strategic plan. The E-ISAC will account for about 27% of NERC’s budget next year.

NERC is boosting 2020 assessments by 4.5% overall, but Canada (+7.2% to $0.013/MWh) and Mexico (+6.0% to $0.016/MWh) face bigger increases than the U.S. (+4.3% to $0.016/MWh).

“Canadians have voiced concern regarding the overall value proposition of the E-ISAC, especially given substantial increases in the value of cyber-related services and cybersecurity investments by Canadian government partners,” the CEA said, adding that its member utilities have “limited ability … to flow through NERC costs to ratepayers.”

It said the E-ISAC should take advantage of “capabilities already available from other agencies or partners (such as the Canadian Cyber Centre) to avoid unnecessarily fully building out its own capabilities.”

IESO noted that concern over rising electricity costs has led the Ontario government to promise a 12% rate reduction. “A rise in regulatory fees beyond the rate of inflation forces the IESO to adjust our budget in areas that may negatively affect our ability to execute on our strategic priorities,” it said.

The CEA and IESO were among six entities that filed comments on NERC’s initial budget proposal. (See ERO Budgets up 3.8%; Assessments up 2.9%.) NERC’s second draft budget, released July 15, adds $500,000 for modifications to its Atlanta headquarters to provide more meeting space.

Other Commenters

Other commenters on the initial draft were generally supportive of the expansion of the E-ISAC, although the Bonneville Power Administration called for more “transparency” on its programs and benefits. BPA noted that the E-ISAC and the Cybersecurity Risk Information Sharing Program (CRISP) are more than 30% of the NERC budget, saying it “would like assurance that as resources are transferred from other programs such as event analysis to E-ISAC that those programs will still be viable to the industry.”

The Edison Electric Institute expressed no misgivings over the expansion, saying “the execution of the E-ISAC’s long-term strategic plan for building a world-class ISAC is critical for providing timely sharing of security threat information.”

The ISO /RTO Counc i l (IRC) Standards Review Committee said NERC should “ensure the E-ISAC is able to provide the most relevant and timely actions in response to bulk power system threats and vulnerabilities.”

NERC respon ded to the comments by detailing the E-ISAC’s programs and touting its access to the intelligence community. It said industry participation with the office has increased, noting 25 Canadian asset owners and operators had established user accounts since late 2018.

Personnel Costs

EEI and the IRC did question NERC’s personnel costs.

The IRC suggested NERC should cut spending in reliability standards and compliance programs to reflect reduced compliance requirements as a result of its Standards Efficiency Review. In May, the Board of Trustees approved the elimination of 84 reliability requirements. (See “Standards Efficiency Review Retirements OK’d,” NERC Standards News Briefs: May 8-9, 2019.)

The council also said that while risk-based monitoring has introduced some efficiencies in the compliance program, “the enforcement program continues to follow a lengthy process.”

“The 2018 average processing age for the entire ERO Enterprise inventory was almost a year, with 37% between one and two years old and 7% over two years old. Developing a quicker path to resolve issues of noncompliance, particularly those that pose minimal risk to the reliability or security of the BPS could affect personnel and future budget dollars,” it said.

EEI sought information on NERC’s salary increases and urged the organization to seek ways to reduce medical expenses, which are budgeted to increase by 13%. NERC said its budget includes a 3% increase over base salaries for “merit adjustments” and “up to 0.5% for equity and market adjustments” that was requested by its board.

The institute said NERC should continue seeking ways to minimize operational costs “and focus resources on activities that are aligned with NERC’s performance objectives and [Reliability Issues Steering Committee] priorities. If new risks are identified, NERC should re-evaluate and prioritize activities, including deferring certain work to efficiently manage resources.”

NERC said its salaries are based on guidelines from the board’s Corporate Governance and Human Resources Committee and market compensation and benefit studies. “NERC is committed to building and maintaining top talent with the required specialized expertise necessary to fulfill the ERO Enterprise’s mission-critical roles,” it said.

The organization said it also benchmarks benefit costs and that increases to its medical insurance plan were “below market for several years.”

“The past two years have shown higher increases due to recent loss experience and fewer medical insurance provider options in the state of Georgia,” it said. “NERC continues to negotiate these premiums and will have final amounts for 2020 at the end of 2019.”

The National Rural Electric Cooperative Association offered brief comments urging the ERO to continue its efficiency efforts, saying it “should be a long-term focus for NERC.”

$500K Increase

NERC presented its revised budget at the board’s Finance and Audit Committee (FAC) conference call Thursday. Interim CFO Andy Sharp said the additional spending, which was revealed in the second draft of the budget, will save money on catering and travel costs.

The additional spending boosts NERC’s 2020 budget to $83.4 million, a 4.5% increase over 2019, compared to 3.8% in the first draft. The office improvements will be funded through reserves, so the NERC assessment will not increase from the original draft.

In addition to the spending on the office, the second draft adds two employees converted from contractors, which it said will result in a slight savings.

The regional entities also presented their 2020 budgets at the meeting, none of which changed materially from the first drafts. All told, NERC and the REs are proposing about $207.3 million in spending in 2020, a 4.1% increase. Total assessments are projected to increase by 2.9%.

Approval Schedule

Written comments on the final budget draft, which are due by July 31, should be sent to Erika Chanzes, manager of business planning and regional relations (erika.chanzes@nerc.net).

The Member Representatives Committee will hold a call to receive input on Aug. 2. The FAC will meet Aug. 14 to recommend approval of final budgets, followed by board approval on Aug. 15 and a FERC filing Aug. 26, with subsequent filings to Canadian authorities.

July 21, 2019

US House Takes on Grid Security

By Rich Heidorn Jr.

Grid modernization and security were the focus of two U.S. House of Representatives committees last week as four bipartisan bills cleared the Energy and Commerce Committee and a second panel held hearings on two other legislative proposals.

Grid Security — The House SST Committee’s Energy Subcommittee held hearings on grid modernization and cybersecurity last week.

On Wednesday, the Energy and Commerce Committee passed the following bills by voice votes, moving them to consideration by the full House:

The Enhancing Grid Security through Public-Private Partnerships Act (H.R. 359), introduced by Reps. Jerry McNerney (D-Calif.) and Bob Latta (R-Ohio), would direct the Department of Energy to encourage public-private partnerships to mitigate electric utilities’ physical and cybersecurity risks. The effort, in consultation with state regulators, industry and the Electric Reliability Organization, would promote the use of maturity models, self-assessments and auditing methods for measuring security, provide training to address supply chain risks, and encourage sharing of best practices and data collection.
The Cyber Sense Act of 2019 (H.R. 360), also introduced by Latta and McNerney, would require the secretary of energy to establish a program to identify cybersecure products for use in the bulk power system.
The Pipeline and LNG Facility Cybersecurity Preparedness Act (H.R. 370), introduced by Rep. Fred Upton (R-Mich.) — ranking member of the E&C Committee’s Energy Subcommittee — and Rep. David Loebsack (D-Iowa), would establish a program at DOE to improve the physical security, cybersecurity and resilience of natural gas transmission and distribution pipelines and LNG facilities.

The panel also approved a bill (H.R. 362) that would codify the role of Karen S. Evans, who was appointed in September as assistant secretary for DOE’s Office of Cybersecurity, Energy Security and Emergency Response.

Science, Space and Technology Committee

Evans was among the witnesses who testified Wednesday before the House Science, Space and Technology Committee’s Energy Subcommittee.

Subcommittee Chair Conor Lamb (D-Pa.) opened the hearing by touting two other pieces of legislation, the Grid Modernization Research and Development Act of 2019 — which calls for research on grid resilience, emergency response, modeling and visualization — and the Grid Cybersecurity Research and Development Act of 2019 (H.R. 4120), which would authorize a research and development program by the Department of Homeland Security, the National Institute for Standards and Technology (NIST), and the National Science Foundation to harden the grid from cyberattacks. The R&D program would include technical assistance, education and workforce programs. The bills will be introduced after the August recess.

Artificial Intelligence’s Role

Evans told the committee that DOE is seeking to spur innovation in big data and artificial intelligence, saying AI has a “critical role” in improving grid resilience. “We’re talking about … software-defined networks, autonomous solutions, really analyzing the data … to remove some of what is happening at a human level now that could be done by AI, by machine learning. That is the area that we are really exploring so that we can look at higher analysis of security, and also being able to model the resilience in real time.”

McNerney asked whether adversaries could use AI to attack the grid.

“For every great new innovation that we do … we also have to evaluate what are the potential risks associated with that and then engineer preventative solutions,” she responded. “We don’t want to stifle innovation. We want to take advantage of those things.”

Juan Torres, associate laboratory director for energy systems integration at the National Renewable Energy Laboratory, agreed.

“Just about any tool … can be used for good or for bad. That’s why it’s imperative for us to maintain that leadership in the advancements of these technologies so we are the ones using these for the right purpose and can actually deter any negative use or any attacks on these systems,” said Torres, who is also co-chair of DOE’s Grid Modernization Lab Consortium.

Torres said DOE is applying AI to four “foundational areas”: understanding complex systems theory; big data analytics; optimization to ensure distributed systems work together; and non-linear controls.

“What we’re seeing is with highly distributed systems, some of the linear control concepts that are used now on the grid may not apply in a highly decentralized type of system,” he said.

Wind, Solar Cybersecurity

Torres said DOE’s solar and wind technology offices are working with industry officials to identify the industry’s cybersecurity needs and those of distributed energy systems. DOE and the International Electrotechnical Commission on Wednesday hosted a cybersecurity workshop at the National Wind Technology Center at NREL’s Flatirons Campus in Boulder, Colo. “This event is bringing key government and industry players together for the first time to add the cybersecurity needs of the growing wind power industry,” he said.

AI would build on smart grid technologies that witness Katherine Hamilton, executive director of the Advanced Energy Management Alliance, said “have allowed the grid to operate more efficiently and with greater visibility.”

“The year of detective work necessary to determine that the Northeast blackout of 2003 was caused by a branch in Cleveland would no longer be the case thanks to these technologies,” she said.

Workforce Needs

The hearing also discussed the industry’s workforce needs. According to research funded by NIST, the U.S. has almost 716,000 people in the cybersecurity workforce and almost 314,000 job openings.

Hamilton said the workforce challenges extend beyond cybersecurity, noting that about 30% of utility employees and 40% of the industry’s engineers are millennials. “Millennials tend to change jobs faster than we’re used to in the utility workforce. You would start in the utility and retire in the utility. But people change jobs a lot faster and there are more types of jobs, so we need to find out what [kinds of] training are needed. … What are some of the skills that transfer really easily?

“In California right now, there are wildfires that are potentially going to cause public safety outages of 30 days or more … and there are not enough trained tree trimmers to do the work needed on vegetation management. You can’t send a kid out with a bushwhacker. These are really trained labor. So, there are a lot of job needs and opportunities, and there are people who don’t have jobs, and we need to somehow match those. So, bringing the public sector and the private sector together on that seems to me to be a good way to think about that.”

Hamilton said encouraging interest in STEM education and cybersecurity needs to begin in elementary school.

Kelly Speakes-Backman, Energy Storage Association

Witness Kelly Speakes-Backman, CEO of the Energy Storage Association, said she was glad her twin 15-year-old daughters were in the audience hearing the discussion. “Their high school has a program that is partnered with the U.S. Naval Academy specifically on cybersecurity, and I really want them to take it,” she said.

Torres said that in addition to sparking early interest in the STEM fields, industry and government should encourage mentoring to ensure a pipeline of future teachers and professors.

Hamilton said DOE and its National Labs also should be involved in encouraging what she called the “democratization” of innovation.

“Innovations are not limited to our labs, our universities or our utilities. They are everywhere. They are kids in basements playing with their apps,” she said. “So, trying to make sure that our research programs are able to connect the dots so that we can bring entrepreneurs to test and make sure that we have proof of concept [is important]. Because no utility is going to purchase a piece of equipment that was designed in somebody’s basement. They need to know that the Department of Energy and the National Labs have given it the seal of approval … by testing it and making sure that this all works.

“While part of that is about bringing new people into the industry — because there are so many new excited young people coming in — we also need to make sure that we then connect them to the programs that are existing to enrich the programs too,” she said.

A House subcommittee meeting last week heard testimony from (from left) Karen S. Evans, DOE; Juan Torres, National Renewable Energy Laboratory; Kelly Speakes-Backman, Energy Storage Association; and Katherine Hamilton, Advanced Energy Management Alliance.

Measuring Cost-effectiveness

Speakes-Backman, a former member of the Maryland Public Service Commission, had a different ask of DOE, saying it should help states develop ways to measure the cost-effectiveness of resilience measures. “This is an issue that I personally had after the derecho in 2011. Utilities can invest in reliability and there are metrics for that, but they cannot invest in resilience because there aren’t metrics for that to prove cost-effectiveness.”