Page 1227 – RTO Insider

June 30, 2019

ERCOT Real-time Co-optimization Falls into Place

By Tom Kleckner

Real-time co-optimization (RTC) in ERCOT took another step toward become reality last week following a discussion between Texas regulators and grid operator staff.

Kenan Ögelman, ERCOT’s vice president of commercial operations, told the Public Utility Commission on Thursday that he has his marching orders, thanks to a memo from PUC Chair DeAnn Walker.

“The memo allows us to get started on the key things. We do want a set of principles done by end of the year, if possible,” Ögelman said during the PUC’s regular open meeting.

RTC is a market tool that procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.

In her memo, Walker’s suggested initial values for the RTC market’s systemwide offer cap ($2,000/MWh) and the value of lost load ($9,000/MWh). She also agreed with staff recommendations to maintain the current market’s low systemwide offer cap at $2,000/MWh and that the ancillary service (AS) demand curves replicate the operating reserve demand curve’s pricing outcomes.

Walker suggested that further information be gathered for the PUC’s July 18 meeting, noting that ERCOT stakeholders commenting in the docket (48540) have advocated for changes to the day-ahead market when RTC is implemented.

The only sticking point appears to be staff’s recommendation that the current prohibition against withholding in the energy market be applied to the AS market.

Walker said her understanding is that ERCOT plans to address stakeholder concerns by allowing resources to indicate whether they can provide AS “over the full range of their output.” She said the commission did not need to address the issue because ERCOT stakeholders would fill in the details as they debate a requirement that resources provide a capacity offer curve that is qualified, online and capable of providing AS.

“I don’t think we can sit here today and make those decisions,” Walker said. “I was trying to set a basic framework. … We have to start building the system, but we don’t have to paint it right now and decide what color to paint it.”

PUC staffer Mark Bryant urged the commission to make clear that withholding resources “would constitute an anticompetitive behavior and would not be permitted.” Beth Garza, director of the ERCOT Independent Market Monitor, sided with Bryant.

“As we tie ancillary services and energy together, the ability to withhold on AS becomes a much bigger lever that can be played out in energy prices,” Garza said. She said exempting market participants with less than 5% of the market’s resources “could give free rein to small parties to economically withhold ancillary services in a way that it has a great effect on energy prices.”

“If your unit is available and capable of providing a service, there should be an offer,” Garza said. “If you don’t have an offer, one will be provided for you. There’s still some work at the commission level to set that expectation and policy.”

“The IMM’s job is to make sure [anticompetitive behavior] doesn’t happen, but we can’t establish the rules so tight … that it chokes the market,” Walker said.

In the end, staff promised to provide a proposal on how to address the smaller resources.

ERCOT has said it will take four or five years and at least $40 million to implement RTC, but that timeline could slip as the project’s scope widens.

Commission OKs AEP Renewables’ Investment

In other actions, the PUC cleared AEP Renewables’ purchase of a 75% interest in Invenergy’s Santa Rita East Wind project, a 302-MW facility currently under construction west of San Angelo. When the transaction closes, AEP will own and control 976 MW of the capacity that will be installed within the next 12 months in ERCOT (49252).

The commission also approved three settlement agreements that levied $170,000 in administrative penalties on ERCOT market participants:

Stream SPE, a retail electric provider, was assessed $85,000 for improperly applied customer switch-holds (49472).
NRG Texas Power (49221) and Golden Spread Electric Cooperative (49476) were assessed $60,000 and $25,000, respectively, for failing to adequately respond to non-spinning reserve service deployments.

June 30, 2019

Overheard at MACRUC 2019: The Carbon-free Future

By Christen Smith

HOT SPRINGS, Va. — Regulators from NYISO and PJM descended upon the historic Omni Homestead Resort last week for the 24th annual Mid-Atlantic Conference of Regulatory Utilities Commissioners (MACRUC) Education Conference to discuss how states and industry can work together to usher in new resource technologies and grid innovations.

“We must embrace the future,” Dallas Winslow, chairman of the Delaware Public Service Commission and outgoing MACRUC president, said during his opening remarks. “By being prepared and embracing the future, we will succeed in meeting the challenges of a changing utility landscape.”

Green transformation in the utility sector dominated conversation — from how to align clean energy with customer demand, to ensuring equal access to electricity, to defining which generators belong in a net-zero-carbon grid. Most presenters agreed there’s no reason to wait on the transportation or agriculture industries to reduce emissions and reverse climate change — the utility sector must forge ahead.

“These efforts will have a cost,” Bruce Burcat, executive director of the Mid-Atlantic Renewable Energy Coalition, said while moderating a breakout panel about the Green New Deal. “But the possibility of not doing enough about climate change will have a higher cost.”

The Green New Deal, a Democrat-backed proposal to address both income inequality and climate change, sets broad targets for clean energy investment, weatherization projects and infrastructure upgrades. But MACRUC panelists said its lofty ambitions don’t translate into any sort of attainable plan.

“I think we have to act quickly,” Burcat said. “I do think the problem is clear. We need to come up with a plan that really deals with this. We are facing a really serious problem in 20 years from now when climate gets really out of control. To sit on our hands and wait is really not a good solution.”

Burcat argued renewables hold the key to decarbonizing the electricity sector but admitted the “aggressive” goals of the Green New Deal seem “unrealistic, cost-prohibitive and unachievable.” Instead, he called or a “rational” cost for carbon reduction.

“What is the goal? Is it to reduce carbon? Renewables is one way, but it’s not the only way,” said Marji Philips, director of RTO and federal services for Direct Energy. “We need to find a lot of ways to do it.”

She said tax credits, cap-and-trade programs and carbon pricing appear to be the most efficient ways to encourage decarbonization, but she argued the influx of subsidies, limitations of storage technology and existing PJM market construct issues — such as the cost of interconnecting renewables and unreliable pricing models — will prove challenging.

“The reality of decarbonization is its expensive,” she said. “It’s achievable, but it depends on how flexible you want to make your system.”

Philips said injecting more money into the market — instead of subsidies for struggling nuclear reactors, for example — would allow cleaner, more efficient resources to come in while still preserving profitable nuclear units.

“The markets have been really great at incenting entry and pretty lousy at exiting, and that’s partly the regulators fault,” she said.

Dana Horton, director of RTO regulatory affairs for American Electric Power, and Brooks McCabe, chairman of the West Virginia Public Service Commission and incoming MACRUC president, said states flush with fossil fuels in the western half of PJM don’t see a way to protect their ratepayers from the effects of a carbon tax — despite optimism from stakeholders in the east who think avenues exist to prevent emissions and economic leakage.

“Without a regional or national adder approach, it’s just not feasible,” Horton said during a panel about PJM’s new effort to explore carbon pricing mechanisms in the RTO. “The more adders you put into the equation, the more complicated it is [and] the more potential for unintended consequence. Forcing a solution before we are ready is a mistake.” (See “PJM Offers Peek at Carbon Pricing Study,” PJM MIC Briefs: May 15, 2019.)

“Maryland and West Virginia have very different views of the world,” McCabe said. “When you put a piece of the equation on the side and try to make a decision based on that isolated aspect, that’s getting into dangerous territory.”

Chatterjee ‘Bullish’

FERC Chairman Neil Chatterjee sounded far more optimistic about the proliferation of natural gas across the world and the rise of renewable resources.

“I’m very, very bullish about the future of renewables,” he said. “There is a very strong business case to be made for renewables. … If you have a source that has no fuel cost, that source is going to prevail over time.”

Chatterjee was criticized in June for tweeting the hashtag “freedom gas” after Energy Secretary Rick Perry coined the term to describe U.S. LNG displacing Russian gas in Europe. Some said his comment broke FERC’s fuel-neutral policy.

The chairman was unfazed.

“You can’t ignore the geopolitical impacts of the U.S. being a net exporter in this industry,” he said. “That’s a very, very exciting thing.”

He also described Order 841-A, which denied rehearing of FERC’s 2018 order removing barriers to energy storage, as one of the commission’s most important rulings. the commission issued this year. “I think we may look back a decade from now and say that Order 841 was one of the most significant federal actions we took to reduce carbon emissions,” he said. (See FERC Upholds Electric Storage Order.)

FERC Commissioner Bernard McNamee told attendees he doesn’t know what the future holds, but he assured regulators the commission is trying its best to translate federal policy into actionable regulations.

“When policy comes out from Congress, it’s a broad statement,” he said. “Very often we have to translate it to something very specific. You’re [state regulators] the ones that have to make it work.

“We are trying to give orders that make a little bit more sense in your states,” he continued. “Doesn’t mean that it’s perfect, but we try very hard to make the orders that come out FERC useful to you all.”

June 30, 2019

CAISO OKs EIM Governance Review

By Hudson Sangree

Leaders of CAISO and its Western Energy Imbalance Market established a panel last week to update the EIM’s governance as the real-time market grows and likely adds day-ahead bidding in the next few years.

The mission of the new Governance Review Committee (GRC) is to go through a stakeholder process, draft proposals and offer the EIM Governing Body and the CAISO Board of Governors a set of recommendations in less than a year.

The committee members must still be selected. Once that happens, “we expect that the committee will get started right away, and we hope to have a work product completed within the next six to 12 months,” CAISO Regional Affairs Manager Peter Colussy told Friday’s joint meeting of the ISO and EIM boards in Salt Lake City.

EIM — The Western Energy Imbalnace Market currently includes eight entities in eight Western states, with more set to join. | *CAISO*

The committee will disband once it completes its work, Colussy said.

The EIM began operations in 2014. It allows wholesale energy transfers across state lines to balance supply and demand in the Western Interconnection, saving its participants more than $650 million so far, according to CAISO.

The market’s charter requires a governance review to be initiated by September 2020 “to account for accumulated experience and changed circumstances over time” in the relatively new market, Colussy said. “The committee’s form and purpose will be similar to that of the transitional committee that formed the initial EIM governance structure just a few short years ago.”

Candidates for the 11 to 13 positions on the GRC will be nominated and ranked by current EIM participants, entities that intend to join, transmission owners, public utilities, generators and consumer advocates. Then CAISO and EIM board officials will select those to serve. It’s largely the same process used to select Governing Body members, Colussy said.

The committee will have one nonvoting member from the EIM body or the ISO board, and one voting member from the EIM Body of State Regulators (BOSR), each selected by their respective groups.

The GRC is expected to represent the geographic diversity of the EIM, Colussy said. The market currently includes eight entities from eight Western states, with more expected to join in the next three years.

“We’re not asking the members of the committee to represent the interests of the stakeholder sectors that nominated them,” he said. “Members are going to be asked to work collaboratively on this process to develop a proposal that will be widely accepted by stakeholders.”

The EIM Governing Body began talking with stakeholders and figuring out the review process late last year. (See Western EIM Looks to Expand its Authority.)

Those addressing the CAISO-EIM meeting Friday generally expressed support for the governance review, with some concerns.

Matt Lecar, a principal with Pacific Gas and Electric, said the utility supports the GRC. He thanked staff members for clarifying that “the scope of the committee would not be unduly constrained to look at just the existing governance model.”

“With the potential extension of the EIM from a real-time market to a day-ahead market, we believe that the both the volume of transactions and the scope of policy issues that will need to be addressed are considerably weightier, and that a degree of authority and oversight will be necessary that exceeds what we see in the EIM today,” Lecar said.

“It’s very important that participants across the region have trust in the institutions and the governance that we create,” he said.

New EIM Chair and Vice Chair

Following the joint session, the EIM Governing Body met for its general session and elected a new chair and vice chair, as it does each year.

Valerie Fong’s term as chair ended Sunday. Vice Chair Carl Linvill was named by his colleagues as the EIM’s chair starting Monday, and John Prescott was named vice chair.

“It has been an honor to be the chair of this body. It’s a great learning experience. It’s a lot of fun. And we try not to blow anything,” Fong said.

She nominated Linvill to take her place and nominated Prescott to fill Linvill’s position.

The board currently only has four of its five allotted members. Former member Kristine Schmidt resigned in April to join embattled PG&E Corp.’s board of directors. (See PG&E Departure Leaves EIM Vacancy.)

June 30, 2019

FERC Rejects PJM Rule Change on Price Responsive Demand

By Rich Heidorn Jr.

FERC on Thursday rejected a PJM proposal to reduce load-serving entities’ savings from price-responsive demand (PRD) programs (ER19-1012).

PJM had proposed changing the calculation of the “nominal PRD value,” used for determining the PRD credit, from the reduction in load during the RTO’s annual peak to the lesser of summer and winter load reductions. The rule change was approved by stakeholders in December. (See “PRD Review for Capacity Performance Requirements,” PJM MRC/MC Briefs: Dec. 6, 2018.)

The RTO said it was attempting to correct disparities between PRD and Capacity Performance resources. It said that although PRD is not required to perform annually, it can displace an annual CP resource in the capacity auction. It also said the trigger for nonperformance charges for PRD is a maximum generation emergency, a less frequent occurrence than an emergency action, the trigger for CP resources.

Under price-responsive demand, load-serving entities automatically reduce consumption in response to high energy prices. | *PJM*

Exelon and the PJM Power Providers Group filed comments supporting the change.

But the commission sided with protests by the Independent Market Monitor and environmental organizations, who said the rules for PRD must be consistent with how LSEs are billed for capacity service — based on demand during PJM’s annual peak — because PRD is not a supply resource. State and consumer representatives had earlier questioned the changes. (See PJM Grilled on Price-Responsive Demand Rule Changes.)

The commission noted that PRD is limited to customers using dynamic retail rates, advanced metering and supervisory control to ensure the committed demand reductions are achieved.

“LSEs participating in PRD receive no energy payment other than reduced energy bills,” the commission said. “Similarly, LSEs receive a capacity service bill credit (the PRD credit) … based on nominal PRD value, which reflects the reduction in the LSE’s demand during PJM’s annual peak.”

The environmental organizations — the Natural Resources Defense Council’s Sustainable FERC Project, Earthjustice, Sierra Club and the Union of Concerned Scientists — offered an example to make their case: a PRD location with 100-MW peak summer load without PRD, a 75-MW summer load with PRD and an 85-MW peak winter load.

The location would get credit for reducing capacity needs by only 10 MW under PJM’s proposal, based on the lower winter load (85-75 MW), rather than the full 25-MW reduction.

“We find that PJM has not shown that it is just and reasonable to calculate the nominal PRD value and associated PRD credit based on the lesser of summer and winter load reductions,” the commission said. “We agree with the IMM and [environmental organizations] that PJM’s proposed approach would limit the amount of megawatts that PRD can commit and thereby inaccurately reflect PRD’s load-reduction capabilities.

“In light of our finding that it is unjust and unreasonable to calculate the nominal PRD value in a manner inconsistent with how an LSE’s capacity obligation is determined, we do not find it necessary to address the need for consistency between the PRD requirements and the requirements for capacity resources,” the commission added.

Tom Rutigliano, senior advocate for the Sustainable FERC Project, praised the ruling.

“A kilowatt of electricity saved is a kilowatt of dirty fossil-fuel energy not burned,” he said. “PJM has been trying to deny that demand response is a substitute for power plants, and the FERC decision today puts that wrongheaded argument to rest. FERC’s action keeps summer demand response in and removes the sword that’s been hanging over the market for this zero-emissions product.”

PJM spokesman Jeff Shields said the RTO is evaluating the order to determine its next steps. “PJM believes that consumers have benefited greatly from competition facilitated through its wholesale markets, and that all resources should compete on a level playing field,” he said. “This means that all resources competing in the market must provide the desired product on a comparable basis. PJM’s proposal would have leveled the playing field with respect to PRD as compared to demand response and generation resources.”

June 30, 2019

Minnesota Approves Huntley-Wilmarth Line

By Amanda Durish Cook

The Minnesota Public Utilities Commission on Thursday approved a proposal by ITC Midwest and Xcel Energy to build the Huntley-Wilmarth transmission project in the state’s south.

The project consists of a nearly 50-mile 345-kV line connecting Xcel’s Wilmarth substation and ITC’s Huntley substation in south-central Minnesota near the Iowa border (17-184 and 17-1 85).

Huntley-Wilmarth transmission line map — Huntley-Wilmarth project map | *Xcel Energy*

Estimated costs for the project, which will include substation upgrades, range from $88 million to $108 million, more than MISO’s original $81 million estimate.

Huntley-Wilmarth was part of MISO’s 2016 Transmission Expansion Plan, meeting criteria to qualify as a market efficiency project. As such, it would have been open to competitive bidding if not for Minnesota’s right-of-first-refusal law.

At the time, MISO respected the ROFR and declined to open the project to competitive bidding. (See Courts Uphold Minn. ROFR, MISO Cost Allocation.)

Xcel and ITC plan to start construction next year, with the line expected to be in service by the end of 2021. The utilities submitted applications for permitting to the Minnesota PUC in January 2018.

Xcel Energy-Minnesota President Chris Clark said the line will help facilitate Xcel’s goal to reduce carbon emissions 80% by 2030 and produce only carbon-free energy by 2050.

“The Huntley-Wilmarth project will provide several local and regional benefits including relieving congestion on the transmission grid, delivering clean, affordable energy to customers and increasing property tax revenues to local governments,” Xcel Senior Vice President of Transmission Michael Lamb said in a release.

In May, Administrative Law Judge Barbara Case found that “no more reasonable and prudent alternative has been identified to alleviate current and potential future transmission congestion in Southern Minnesota.” Case said the project will strengthen the area’s reliability, allow Minnesotans access to lower-cost energy and will lower emissions by tapping into renewable generation, allowing area coal plants to retire.

June 30, 2019

OMS Outlines Long-term Tx Planning Principles

By Amanda Durish Cook

The Organization of MISO States last week issued a set of principles intended to guide the RTO’s approach to long-term transmission planning.

The release of the document comes as MISO and its stakeholders are debating whether the RTO should launch a second regional transmission package similar to 2011’s multi-value project (MVP) portfolio. (See MISO Stakeholders: New Blueprint Needed for Tx Planning.)

“Considering the timeline associated with infrastructure planning and development, it’s important to get started now to ensure the grid we need in the future will be there to maintain reliability and support the evolving resource mix,” Minnesota Public Utilities Commissioner and OMS Vice President Matt Schuerger said in a statement.

OMS approved the eight basic principles in mid-June as part of a position statement, with support from 12 of its 17 regulator members.

Among the precepts laid out in the document, OMS states that MISO’s long-term planning must account for the changing resource mix based on “robust input from the states.” The group also wants the RTO to consider reliability requirements when planning transmission and to test transmission proposals “under a variety of system conditions and scenarios.”

OMS also asked for an exhaustive and transparent stakeholder process should MISO develop a new cost allocation for a long-term plan. It also said the RTO should move quickly to assess system needs if it’s planning on a new long-term transmission package “given the long time frames expected for infrastructure planning and development.”

Other principles for MISO to follow include:

Producing cost-effective solutions to “known physical and contractual system constraints.” Here, OMS specifically called out the MISO Midwest-to-South regional transfer limit.
Evaluating multiple transmission and non-transmission alternatives on a “level playing field.”
Publishing the cost impacts to subregions, including the costs of both moving ahead with or delaying transmission plans.
Ensuring that any state in the MISO footprint is not negatively impacted by a long-term transmission plan.

MISO executives at the Board Week meetings in June said the region must invest significantly in transmission investment to accommodate all the projects in the current 100-GW interconnection queue; however, RTO staff also expect several unprepared generation projects to drop out.

Opposition

Two MISO South states and the city of New Orleans came out in opposition to the principles, calling them “vague and overly broad” and lacking a “clear goal.”

“No one has demonstrated that these changes are needed or that MISO’s current long-range transmission planning process is unjust or unreasonable,” the Louisiana Public Service Commission, the Mississippi Public Service Commission and the New Orleans City Council wrote in a minority dissent.

They also said the principles won’t provide additional guidance because MISO already employs such principles in its long-term transmission planning.

“These principles are unnecessary and open to endless interpretation. To the extent MISO’s existing long-range transmission planning processes are unable to address a specific planning goal or object, interested stakeholders should raise those concerns within the MISO stakeholder process,” the opponents said.

The Illinois Commerce Commission chose not to take a stance on the document, and the Manitoba Public Utilities Board did not participate in crafting the principles.

At an Advisory Committee meeting June 19, Schuerger said the “common sense” principals were settled on after many months and the document represented “broad support” for “key positions and policies.”

“It was not a unanimous vote; not everyone agreed,” Schuerger said, but he noted that most states came together in agreement.

“We are working continually to bring all of our states together,” he added.

Study Scoped for MISO-SPP Seams

In a separate development related to transmission planning, Independent Market Monitor David Patton last week revealed the scope of the joint analysis on seams issues requested by OMS and the SPP Regional State Committee. (See RSC, OMS Approve Monitors’ Seams Study.) Patton called MISO-SPP market-to-market coordination was his “No. 1 priority.”

The study scope focuses on eight areas for improvement: market‐to‐market coordination; possible creation of targeted market efficiency projects like those between MISO and PJM; more efficient interface pricing; optimization of interchange transactions across the RTOs’ interface; better management of the regional directional transfer limit; outage scheduling and day‐ahead coordination; elimination of rate pancaking; and possible joint dispatch.

“Some of these issues we’ve raised in our reports, and some the SPP Monitor has raised,” Patton said during a call hosted by the Board of Directors’ Markets Committee on Wednesday.

Patton said he thought analyses on rate pancaking and joint dispatch would be the least beneficial, the former because it would not reduce production costs, and the latter because it might require some merging of the RTOs.

“That one confuses me,” he said of joint dispatch.

Patton said the RTOs could see more economic benefits from optimizing their interchanges and better coordinating their market-to-market process. But overall, he praised the work between the MISO and SPP states.

“I actually think there are some issues on here where the states can help the RTOs come to a consensus, an agreement,” Patton said.

He said the goal is to complete the analyses before 2020. MISO executives said they may have to adjust their 2019 budget in order to compensate the Monitor and his staff for the extra work. Patton said he would come up with a statement of work soon.

The Markets Committee also addressed the study in closed session immediately following the meeting.

June 30, 2019

Carbon Pricing Study Navigates Shifting NY Landscape

By Michael Kuser

RENSSELAER, N.Y. — If you’ve ever seen a circus performer riding two horses around the ring, one foot on each, you have a good idea of the balancing act Analysis Group’s Sue Tierney had to execute in detailing the preliminary results of her firm’s carbon pricing study for NYISO.

Tierney’s performance came just days after the New York legislature passed the Climate Leadership and Community Protection Act (A8429), a development that could further complicate NYISO’s carbon pricing effort as it moves to a conclusion. (See “New Energy Law Could Affect CO2 Market Design,” NYISO Business Issues Committee Briefs: June 20, 2019.)

“We are looking at the carbon proposal as proposed by NYISO last December, although we are now revising our work to take into account the implications of shifting public policies in New York,” Tierney told NYISO’s Installed Capacity/Market Issues Working Group (ICAP/MIWG) on June 24.

The third-party study examining the impacts of pricing carbon into NYISO’s wholesale electricity markets is intended to augment the Brattle Group report process that concluded in December, and is underway just as the new bill makes statutory many of Gov. Andrew Cuomo’s environmental targets, such as requiring 70% of the state’s electricity to be generated by renewable resources by 2030.

“We are not going to advocate for one particular action or another, though our point of view may be obvious from our analysis,” Tierney said. The final results are expected to be previewed with stakeholders ahead of the ISO posting the technical report and a separate summary for policy makers.

The new law would nearly quadruple the state’s offshore wind energy goal to 9 GW by 2035 and target making the electric system carbon-neutral by 2040. The bill also doubles distributed solar generation to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030.

After presenting information about changes in NOx emissions that could be anticipated with a carbon price in the NYISO energy market, Tierney said such outcomes are important, “even with the peaker rule in New York City,” referring to the state Department of Environmental Conservation’s proposal to revise its Clean Air Act regulations. The changes to lower allowable NOx emissions from simple cycle and regenerative combustion turbines during the ozone season would go into effect May 1, 2023, with generator compliance plans due by March 2, 2020. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

In contrast, the new climate bill will take effect once it’s signed by Cuomo, expected soon. The bill will assign the responsibility of adopting and enumerating the new standards to the DEC; establish an environmental justice advisory group; and create a 22-member “New York state climate action council” that “shall consult with the climate justice working group … the Department of State Utility Intervention Unit and the federally designated electric bulk system operator.”

Price Signals

“The 70% renewables target in the new bill is consistent with what the governor has been saying about the electric sector since January,” Tierney said. “There’s going to be more demand for electricity because of these goals now established in the act.”

The power sector will play a key role, given the intent to convert transportation and building heating and cooling end uses to electricity, she said.

Adding that the bill will also include deeper energy efficiency measures, Tierney said the other forms of “beneficial electricity use” promoted in the statute would create pressure to increase electricity supply and demand.

“This is the yin and yang of more electricity use and better efficiency,” Tierney said. “If you go meet all these renewables goals and growing demand with long-term contracts for [renewable energy credits], it would mean an increasingly large — and potentially unsustainable — share of the NYISO market under out-of-market, [policy-driven] contracts. By contrast, a carbon price could lessen the reliance of certain renewables on out-of-market contracts.”

A carbon pricing mechanism could stimulate entry based on wholesale price signals and reduce risks associated with increasing quantities of supply under long-term contracts in FERC-regulated wholesale markets, the presentation said. It noted that by 2030, if all new renewables entered the market with long-term REC contracts, in addition to those already under contract, and if zero-emission credit contracts were extended for the FitzPatrick and Nine Mile Point 2 nuclear plants beyond 2029, roughly 50 to 60% of supply would be under contract.

Howard Fromer, director of market policy for PSEG Power New York, said, “The bill directs a significant portion of the state’s clean energy and energy efficiency dollars to environmentally disadvantaged communities … perhaps reducing the amount available for subsidizing renewable energy resources.”

“The point here is that carbon pricing complement and reduce the role of long-term or out-of-market contracts,” Tierney said. “Having as full a toolkit as possible will benefit policymakers. It could provide greater visibility in energy markets for the value of zero-carbon resources, and possibly even help the upstate nukes beyond 2029, when the ZEC program ends. I have no idea whether the nuke owners would act in response, but a price signal is better than nothing.”

The Brattle study and a separate analysis released in May by the ISO’s Market Monitor, Potomac Economics, both point to power production efficiency improvements, lower emissions (in environmentally disadvantaged communities in particular), public health improvements and reduction in overall use of natural gas, Tierney said.

Public Benefits

Regarding public health benefits and other impacts, “Brattle and the Potomac Economics study could understate some impacts … because of their underlying assumption that all of the renewables needed to meet the prior 50% target by 2030 would show up in any event in the base case at no apparent cost to consumers,” Tierney said.

She added that that level of clean power is not free: “So the question that is still unanswered is whether a carbon price would help reduce the overall cost of entry of renewables?

“A carbon price would affect the dispatch of fossil units, and that will reduce local air emissions, as well as carbon emissions,” Tierney said. “We wouldn’t have protests about power plants if there were no benefit in removing them.”

Mark Reeder, representing the Alliance for Clean Energy New York, said, “There are a number of benefits of carbon pricing that Brattle said will occur but which Brattle said were too hard to quantify, so [they] are set to zero … like the benefits of increasing the likelihood of life extensions of existing hydro, the financial benefit to [the New York Power Authority], etc.”

On the Market Monitoring Unit’s analysis of the impacts of carbon pricing, which for consumer price impacts considered the two scenarios of base case and repowering, Reeder pointed out that the first three years of a carbon charge would cost consumers, but the following seven years would save them money, and he asked why not average the effect.

Erin Hogan, representing the UIU, said it would be better not to average, that “people don’t dismiss three years of pain so easily. If any report should be balanced, this is the one.”

June 30, 2019

Utilities Warn of Encroachment on Communications Band

By Rich Heidorn Jr.

WASHINGTON — Utilities asked FERC on Thursday to lobby against a Federal Communications Commission proposal that the companies say could disrupt their mission-critical wireless communications.

Speaking on the final panel of the commission’s annual technical conference on reliability, representatives of the Edison Electric Institute and the Utilities Technology Council (UTC) urged FERC to oppose the FCC’s proposal to require utilities to share the 6-GHz wireless spectrum with unlicensed users, saying they fear it could cause interference with their communications. But wireless companies told FERC the utilities’ fears are unfounded.

Electric utilities use the spectrum (5,925 to 7,125 MHz) for point-to-point microwave links providing communications with substations, fault sensors, two-way meters and service crews. It is also used to provide situational awareness in rural areas where wireline networks are not available.

The UTC — which represents water, gas and electric utilities that use the spectrum — joined with the Edison Electric Institute, the American Petroleum Institute, the American Public Power Association, the American Water Works Association and the National Rural Electric Cooperative Association in joint comments opposing the FCC’s proposal.

“Electric companies use the 6-GHz band for [supervisory control and data acquisition] and tele-protection systems that monitor and control the balance of power on the grid, which must operate constantly in real time with sub-second latency to avoid system instability and power disruptions,” J.P. Brummond, vice president of business planning for Alliant Energy, testified on behalf of EEI on Thursday. “EEI joins with UTC to recommend that the commission coordinate and formally engage with the FCC and other stakeholders in regular meetings.”

FCC NOPR

The FCC proposed the change in a Notice of Proposed Rulemaking last October, saying it was in response to growing demand for access and a congressional directive to identify additional spectra for wireless broadband (18-295, 17-183).

“Unlicensed devices that employ Wi-Fi and other unlicensed standards have become indispensable for providing low-cost wireless connectivity in countless products used by American consumers,” the NOPR said. “The broad spectrum swaths that we propose making available in this frequency band could promote new technology and services that will advance the commission’s efforts to make broadband connectivity available to all Americans, especially those in rural and underserved areas.”

The commission cited estimates that North American mobile traffic, including unlicensed Wi-Fi devices, grew 44% in 2016 and is projected to grow nearly 35% annually through 2021.

The FCC’s proposal is based on existing rules on Unlicensed National Information Infrastructure (U-NII) devices that have been operating for years in the 5-GHz band, including Wi-Fi and Bluetooth technology used by smartphones, streaming video, cordless phones, security systems, garage door openers and baby monitors.

Communications Utility — The density of assignments in the 6-GHz wireless spectrum (excluding fixed-satellite service) | *FCC*

The commission said unlicensed use of the new spectrum is a “natural fit” for Internet of things (IoT) devices, which some project will grow to 15 billion by 2022.

The FCC began considering opening the 6-GHz band with a 2017 Notice of Inquiry. “Filers representing incumbent interests uniformly emphasized the need to protect those incumbent operations, with individual filers expressing differing levels of optimism as to whether successful sharing mechanisms could be established.”

Some companies that originally supported unlicensed use throughout the band without restriction, including Apple, Cisco Systems, Google and Qualcomm, now support requiring automated frequency coordination (AFC) for all outdoor and some indoor devices. AFC relies on a “database lookup scheme” to ensure that unlicensed users are not encroaching on an existing user’s priority access to the frequency in a specific area.

In response, a group representing fixed microwave incumbents, the Fixed Wireless Communications Coalition (FWCC), “appears to be more open to the possibility of finding successful shared use mechanisms in the band than it had been,” the FCC said.

Widely Used

Fixed point-to-point wireless in the 6-GHz spectrum is used by a range of critical services in addition to electric utilities, including police and fire dispatch, railroads, natural gas and oil pipelines, and long-distance phone service.

Alliant’s Brummond told FERC that the importance of his company’s wireless communications was illustrated in its response to a 2018 tornado in Marshalltown, Iowa. “The radios that our crews used during the recovery efforts were invaluable since public networks were overloaded right after the tornado hit,” he said.

Alliant’s Iowa generation and dispatch operations use the 6-GHz band “in support of bids” into MISO’s markets, Brummond said. Interference could also harm the company’s ability to control its generators and calculate accurate system load, he added.

The 6-GHz spectrum is currently available only to licensed operators that UTC said “undergo a rigorous process of frequency coordination” to prevent interference.

While interference can occur under current rules, the UTC said, the other entities in the band are known, allowing for arrangements to eliminate conflicts.

Under the FCC’s proposal, utilities would not easily know who is causing interference, UTC said. “Instead, they would need to track down interference all over their 6-GHz network and make any necessary adjustments for an event that may never occur again. This is a highly technical and time-consuming proposition without any guarantee that the interference mitigation efforts would be successful,” it said.

John Marinho, vice president of cybersecurity and technology for CTIA, which represents the U.S. wireless communications industry, told FERC that the FCC should continue its “flexible-use policies” to respond to spectrum demand while requiring AFC to prevent interference.

John Kuzin, regulatory counsel for Qualcomm, told FERC much the same. “We would not be supporting allowing unlicensed use of this band if it could not be done without protecting the current incumbent users. Because the point-to-point incumbent links are fixed and their operational parameters are in an FCC database, protecting them from unlicensed operations is straightforward. The 6-GHz band presents a great opportunity for new unlicensed technologies to support new devices, services and applications for these incumbent industries, as well as millions of American consumers.”

UTC said it is not convinced that AFC will protect its members, calling the technology “untested, unproven and hypothetical.”

Adrianne Collins, vice president of power delivery for Southern Company Services, filed written testimony with FERC also expressing doubts. “Southern Co. does not agree the 6-GHz band is the right band to implement unproven sharing technologies,” she wrote. “Given its extensive service territory in both urban and rural areas, the 6-GHz band is the only suitable band that can accommodate the bandwidth and performance objectives over very long microwave paths.”

UTC acknowledged that interference in the 6-GHz band “is unlikely to have a cascading impact on electric reliability.”

But it said its members have invested millions in 6-GHz systems. “If we can no longer rely on 6 GHz to provide these services, we will essentially be forced out of the band to seek alternatives, and there are few, if any, spectrum bands with the same qualities as 6 GHz, which provides wireless transmissions across longer geographic areas (propagation) very quickly (low latency),” UTC said. “Even for those who do have alternatives, redesigning and re-engineering their communications systems, we have been told, will be a lengthy and highly technical process, taking perhaps up to 10 years in certain instances.”

June 29, 2019

Panelists Seek FERC OK to Move to Cloud

By Rich Heidorn Jr.

WASHINGTON — Registered entities asked FERC on Thursday to clear the way for their use of cloud computing, which they said could improve system visibility, security and availability while saving money.

Speaking at FERC’s annual reliability technical conference, representatives of the American Public Power Association, MISO, Berkshire Hathaway Energy and PPL all said registered entities should be able to use cloud service providers (CSPs) and virtualization for some functions subject to NERC reliability standards.

“Current NERC rules of procedure and NERC critical infrastructure protection standards do not explicitly address the use of cloud services and virtualization, leaving the industry uncertain as to how to approach related security and compliance risks as they explore the use of these technologies,” said Antiwon Jacobs, chief information security officer for the Sacramento Municipal Utility District (SMUD), who testified on behalf of APPA and the Large Public Power Council (LPPC).

From left: Ashley Mahan, FedRAMP; Antiwon Jacobs, Sacramento Municipal Utility District; David Rosenthal, MISO; Michael Ball, Berkshire Hathaway Energy; Brenda Truhe, PPL; and Michael South, Amazon Web Services. | © *ERO Insider*

MISO is piloting some cloud services, though not for operations or NERC CIP functions. Current CIP standards “were not developed with cloud services in mind, and they offer no guidance as to whether and how cloud services may be NERC CIP compliant,” said David Rosenthal, MISO’s director of incident response and systems recovery.

“It is no longer a question of whether cloud services have a place in our industry,” Rosenthal said. “Rather, it is a question of when, what and how cloud services will work in our industry. Major software vendors have moved quickly from a ‘cloud first’ to a ‘cloud only’ mindset, and that tells us that older, non-cloud technologies will not be supported indefinitely.”

Brenda Truhe, NERC CIP senior manager for PPL, said her chief information officer recently attended an all-CIO meeting where “he was one of the few who did not have his main applications in the cloud. He was talking to the financial industry and they said, ‘We do trillions of dollars in banking every day in the cloud. You can make it work.’”

“We’re seeing all critical infrastructures use the cloud in some way shape or form,” said Michael South, Amazon Web Services’ Americas regional leader for public sector security and compliance. “In my experience, the financial sector is probably the most mature and advanced.”

Benefits

In April, a NERC standards drafting team (Project 2016-02) released a draft white paper that it called “the case for change.” The team said virtualization offers the kind of benefits for computing infrastructure that the interconnected power grid does for bulk electric system reliability.

“As individual utilities interconnected their power systems to form a power grid to share spare capacity for meeting demand peaks and surviving contingencies such as generating unit and transmission line outages, so virtualization connects processors, networks and storage into ‘computing grids’ that allow our vital systems and applications to meet peak demands and survive outages of individual components,” they wrote.

MISO said cloud services can provide redundant and resilient data and systems and potential cost savings compared to the legacy practices of procuring and supporting hardware.

“It takes quite a long time to provision servers and get them ready for use. One of the things that virtualization does is it allows us to build from templates — pre-hardened — that are ready to go immediately,” Rosenthal said. “When you want to do a recovery, it makes it very simple and very quick. … When we had to recover our physical servers, it took a significant amount of time, and sometimes we failed.”

Truhe said cloud services also help registered entities deal with the shortage of qualified IT candidates, who may find working for AWS or Google more attractive than working for a utility.

Current Rules

Jacobs said NERC CIP standards “do not address the concept of virtual infrastructure” and that registered entities need “a signal or some form of endorsement from NERC and FERC” to provide them regulatory certainty.

He also requested FERC and NERC endorse external accreditations of CSPs, such as those provided by the Federal Risk and Authorization Management Program (FedRAMP), to address entities’ compliance risk.

Michael Ball, chief security officer for Berkshire Hathaway Energy, agreed that third-party accreditation is “an essential foundation” for a move to the cloud.

But he said “it is not the service provider that provides the security. … It still relies on me as an entity. You know they can build the best house, the most secure doors. But when they hand me the keys, do I lock the door?”

Off Limits?

Jacobs said APPA and LPPC oppose the use of cloud-based technology for controlling energy management systems and supervisory controls and data acquisition “at this time.”

The groups also said CSPs should not result in the removal of “critical layers of defense to [physical access control systems] and [electronic access control or monitoring systems] such as operational security (physical), access points, authentication servers and key management servers.”

MISO and PPL agreed that those functions should not go to the cloud without more experience.

Truhe said the cloud could have a role in those functions in the future. “I wouldn’t want to take anything off the table at this point,” she said.

June 29, 2019

New Western RCs to FERC: All Systems Go

By Michael Brooks

WASHINGTON — CAISO, SPP and BC Hydro officials reassured FERC on Thursday that the Western Interconnection’s transition from two reliability coordinators to five is going smoothly and that everything will be ready by the time Peak Reliability closes shop Dec. 3.

“We are ready,” Dede Subakti, CAISO director of operations engineering services, told the commission at its annual technical conference on reliability. “That’s probably the reason they allowed me to go out of the office and I’m here now.”

CAISO’s new RC West, which received its NERC certification May 30, will take over providing RC services from Peak for the ISO, several California municipal utilities and a northern sliver of Baja California at the U.S.-Mexico on Monday. It will take on most of Peak’s territory elsewhere in the West on Nov. 1.

Meanwhile, BC Hydro will assume responsibility for its own footprint on Sept. 2, and SPP will take over the remainder of Peak’s territory on Dec. 3. (See New RCs Tell WECC Transition on Schedule.)

CAISO and SPP are taking over RC responsibilities in most of the West this year. | *CAISO*

Differences Add Complexity

The officials did acknowledge complications surrounding the transition. One of the primary functions of an RC is to work with other RCs to respond to threats to reliability, and each of the new providers is unique: an ISO, an Eastern Interconnection-based RTO and a Canadian provincial utility. Learning each other’s set of terms and functions has been important, they said.

“SPP is in a unique position” as an RC provider in both interconnections, said Bruce Rew, vice president of operations for the RTO. “Understanding the distinctive operation of each neighboring RC allows us to establish a framework for coordinating congestion between two or more RCs.”

The panel included officials from MISO and PJM to talk about their experiences developing the RTOs’ joint operating agreement. PJM Vice President of Operations Mike Bryson talked about the challenges of creating seams agreements with different entities — MISO, the Tennessee Valley Authority, NYISO and Southern Co. — that don’t necessarily share the same functions as his RTO. He expressed how “I love the fact that I’m the RC, the BA [balancing authority] and the TOP [transmission operator]. But I get that’s kind of unusual.”

From left to right: Dede Subakti, CAISO; Bruce Rew, SPP; Melissa Seymour, MISO; Mike Bryson, PJM; Asher Steed, BC Hydro; and Jordan White, WIRAB. | © *ERO Insider*

Commissioner Cheryl LaFleur noted that all Eastern Interconnection market operators also performed all three functions — but Rew and Melissa Seymour of MISO noted that their respective RTOs were not TOPs.

LaFleur seemed stunned. “This is how complicated this is,” she said. “This should be FERC 101.”

Commissioner Richard Glick asked if it wasn’t just simpler to have one RC. “It seems to me you’re just increasing the risk, even if you have all these seams agreements and do everything properly,” he said.

“My perspective to everything is that there is a pro and a con to it,” Rew replied. The pro of having a single RC is you don’t have to worry about seams or communication between multiple entities, he said. But “with multiple RCs, you have multiple eyes looking at” problems. “It gives you the opportunity to ask your neighbor, ‘What are you doing about this?’” He recalled as an example the Jan. 17, 2018, cold snap in the South, which led MISO to call a maximum generation alert. (See “SPP, MISO Discuss Jan. 17 ‘Big Chill,’” SPP Briefs: Week of July 9, 2018.)

“That was a wide-area issue, and it affected four RCs,” Rew said. “So we had four RCs working on that. … Just think if that was one RC, that would have been very challenging to have the resources and the ability to manage the widespread problem area.”

Common Tools

The new RCs stressed that they are using many of the same tools as Peak, which has helped in the transition.

In shadowing Peak, RC West has been able to check the accuracy of the tools, Subakti said. “We find that having two RCs in there brings us to a situation where iron sharpens iron,” he said. “We start asking ourselves, ‘Why did we do it this way?’ … It’s actually uncovered a lot of improvements.”

But Utah Public Service Commissioner Jordan White, speaking on behalf of the Western Interconnection Regional Advisory Body (WIRAB), said his organization was concerned about the potential loss of one tool he said has received little attention from the new RCs”: Peak’s performance metrics. Peak uses the metrics not only to keep itself honest, but to measure the level of information provided by the BAs and TOPs.

RC West is developing its own metrics, but WIRAB wants the commission and NERC to encourage the new providers to work together to establish consistent ones. “Consistent metrics across the RCs will not only provide the necessary data to improve reliability; they will demonstrate if reliability has diminished during this transition,” White said.

“Are Peak’s reliability metrics the absolute fundamental right way to go? Not necessarily,” he said. “We do think they’re a good starting place … but what we’re really looking for is a discussion among the RCs about what those best practices are.”