Page 1022 – RTO Insider

July 2, 2019April 22, 2024

Overheard at TREIA GridNEXT 2019

SAN ANTONIO — Grid safety and security were the focus of the Texas Renewable Energy Industries Alliance’s (TREIA) annual GridNEXT conference last week.

Speakers during the event Thursday addressed a variety of related topics, from protecting critical assets and safeguarding vital data, to the role renewables and microgrids will play in ensuring a more reliable and resilient grid.

TREIA board member Ingmar Sterzing, a vice president with renewable developer OnPeak Power, put things into perspective when he asked his panel, “Are you prepared to operate your business without electricity and cellphones?”

“You need a responsible plan for cybersecurity. You plan to have that event actually happen. You don’t plan for it not to happen,” Mike Allgeier, ERCOT’s director of critical infrastructure security, told attendees gathered at The International Center. “Prepare for the worst. If you don’t prepare for the worst, when the worst happens, it’ll be pretty bad. Plan for what you think is the worst, then double it.”

Allgeier warned that the “bad actors,” or hackers, operating online today are not to be underestimated.

“They’ve been around a while,” he said. “Typically, they’re dedicated and well-trained to do their job. It’s not the 15-year-old kid in the basement. They have goals and they’re measured. They have quotas.

“They’re not only looking at the big guys. They understand that if they can control a wide swath of resources, that can be just as damaging as getting into one large resource,” Allgeier said.

Speaking on the same panel, ABZ’s Trey Kirkpatrick emphasized the importance of raising awareness of cybersecurity issues among employees. He used Berkshire Hathaway’s three-strikes-and-you’re-out approach to phishing emails as an example.

“Their policy is if someone clicks on a phishing email three times, they’re gone. You don’t see that in every organization,” Kirkpatrick said.

Both Allgeier and Kirkpatrick bemoaned the difficulty of finding and retaining cybersecurity subject matter experts, with Kirkpatrick calling it “the biggest risk.”

“The consultants are getting busy; they’re highly paid, and they’re moving around,” Kirkpatrick said. “I know companies that can’t even find a cybersecurity manager, even with the money they are offering.”

Allgeier said he typically fills his cybersecurity staff with personnel that have financial and military backgrounds.

“From the financial side, because they’ve been doing this for a long time; and from the military sector, because they have been trained to fight our online enemies,” he said. “I can’t always compete with salaries the high-tech or financial firms can offer, so we try to keep them with competitive benefits and the collaborative nature of work, building the esprit de corps.”

Place for Storage, New Technologies

Panelists discussing the ability of renewable energy and smart technology to make the grid more secure and reliable suggested looking away from California, where mid-day solar energy peaks reduce demand for other sources, resulting in a “duck curve.” (See Report: Calif. ‘Duck Curve’ Growing Faster than Expected.)

“California has kind of become the sacrificial lamb,” Energy Storage Consultants CEO Judy McElroy said. “Storage is a good answer to that, but just throwing storage on your grid doesn’t make it more reliable.”

“As we integrate [battery storage and other technologies], we can make them more reliable, but there’s a cost,” said Dean Tuel, global vice president of microgrid and storage solutions sales for Aggreko. “We have a diverse portfolio of technologies we can provide at a cost the customer is willing to accept. We can accommodate this with today’s technology and reach a level of renewable penetration that gets us to the … reliability the customer is looking for.”

TREIA on Track for 50% by 2030 Goal

Buoyed by the large amount of wind and solar projects in ERCOT’s interconnection queue, Sterzing said TREIA’s goal of achieving 50% renewable energy in Texas by 2030 is coming into clearer focus.

Sterzing pointed to the 35.7 GW of wind projects and 58.6 GW of solar projects in the queue as of May as reason for hope. Only 14.3 GW and 7.6 GW of the respective wind and solar projects have signed connection agreements.

“Will it all be built? Hard to say, but that’s a huge industry movement either way,” he said. “There’s a lot of development coming into Texas. There’s certainly a lot more we can do as a state, with this kind of investment, to make Texas an energy center for the country.”

Sterzing noted Texas that has seen a “steady trajectory” over the last five years in renewable energy’s share of the fuel mix. Wind and solar energy accounted for almost 20% of ERCOT’s production in 2018. At the current rate of growth in the state, Sterzing estimated an additional 18 GW of wind energy and 39 GW of solar would help “maintain a reasonable mix and achieve the 50% goal.”

“That’s a huge, huge target, and enough to keep us all busy,” he said.

Energy Industry, Military Collaborate on Grid Security

A panel focused on defense and grid security stressed the importance of the energy industry working closely with the military.

Melissa Miller, Avangrid Renewables’ regional development manager for the central U.S., said technological improvements have led to the construction of wind farms in areas they could not have previously been built. That has only increased the conflicts seen across the country between wind facilities — which are increasingly taller — and military flight paths.

“We’re more successful with wind almost everywhere, but all of a sudden, that creates an impact with military operations,” Miller said. “It’s really important we learn about their missions and what their objectives are, especially in the lower air space. The need to collaborate is so important.”

Shanna Ramirez, CPS Energy’s chief integrated security officer, said the San Antonio utility has long enjoyed a collaborative relationship with the military, which has four major installations and 250,000 retirees in the city. Ergo, the city’s trademarked nickname, “Military City USA.”

“We’ve been really successful about keeping the military aware of how we secure our mutual facilities,” Ramirez said. “We have more people at the table, we keep buying a bigger table.”

“There’s an acknowledgement we will not solve problems alone,” said Christian Delarosa, deputy base civil engineer for Joint Base San Antonio. JBSA is composed of the Army’s Fort Sam Houston and the Lackland and Randolph Air Force bases.

“The Air Force wants to keep focus on resiliency and low costs,” Delarosa said. “We’re still interested in saving energy, but we’re now focused on resiliency and grid operations. It’s going to take industry experts and academia to look at this problem and develop solutions.”

Renewables Enjoy Positive Legislative Session

Attorney Chris Reeder, a partner at Husch Blackwell, reviewed the recent 86th Texas Legislature, painting it as a success for the renewable energy industry despite the efforts of the conservative Texas Public Policy Foundation (TPPF).

Reeder said the TPPF was at the forefront of a “sustained and aggressive and hostile campaign” against renewable energy during the recent session, which ended in May.

“They’ve made it a centerpiece of their political strategy to oppose renewable energy,” he said. “When they say, ‘Level the playing field,’ others would call that a rollback. They have been very vocal and aggressive in shooting down our success to the economy of Texas.

“Any legislation with renewable energy attached to it automatically draws some level of opposition in our state House and state Senate,” Reeder said. “That tends to misread the true situation, in which there’s much more support out there than makes its way into the chatter you see in The Dallas Morning News or the trades.”

July 2, 2019

Exelon: PJM ‘Buried the Lede’ on Nuke Study

By Christen Smith

WILMINGTON, Del. — Exelon told PJM’s Markets and Reliability Committee on Thursday that the RTO “buried the lede” in its analysis of nuclear plant retirements in Ohio and Pennsylvania, suggesting instead that results prove the reactors offer value worth saving.

“We think the results show it makes sense to preserve zero-carbon sources and replace retiring coal units with gas units,” said Jason Barker, director of wholesale market development for Exelon. “The data shows better results than the response that PJM promoted. Frankly, it sort of buried the lede.”

Exelon manages the largest nuclear portfolio in the country, including the decommissioned Three Mile Island near Harrisburg, Pa. (See Exelon to Close Three Mile Island.)

The PJM study, published June 7, concluded emissions will drop regardless of whether FirstEnergy’s Perry and Davis-Besse facilities in Ohio and its Beaver Valley plant in Pennsylvania close or stay open — though the reduction would be significantly greater if the plants stay online. (See PJM: Nukes Keep Energy Costs Down, in Theory.)

Comparison of cost savings and emissions reductions in PJM’s first simulation, which preserves all three FirstEnergy nuclear plants | *Exelon*

Regulators in both states asked PJM to simulate the impact of losing the plants on the power grid and greenhouse gas emissions as subsidy plans pend in each legislature. Staff obliged the requests by creating five scenarios against which to compare what the RTO considers its base case: all three plants retire, and scheduled gas and renewable generators with an in-service date in 2023 come online, reducing net-load payments by $1.6 billion. Carbon dioxide emissions would likewise decrease by 4.3 million tons, while nitrogen oxide and sulfur dioxide emissions would fall by 37,900 tons and 18,200 tons, respectively, the analysis concluded.

Should all three nuclear plants stay operational and new generation enters the market as planned, net-load payments would decrease by an additional $474 million from the base case. In Pennsylvania, emissions of CO2, NOx and SO2 would decrease from the base case by 4.7 million tons, 5,000 tons and 3,300 tons, respectively. In Ohio, the additional emission reductions total 3.7 million tons, 2,400 tons and 3,500 tons, respectively.

The results are similar — net-load savings increase and greenhouse gas emissions decrease — when either just Beaver Valley or the Ohio plants stay online, PJM found.

“The data really reveals here the benefits” of keeping the plants open, Barker said. “The base case demonstrates coal to gas switching, and we think that will occur regardless of the fates of the nuclear plants. Simulation 1 is the real story … which is what are the impacts of maintaining these units.”

Critics have argued that PJM’s other simulations that reduce the number of gas units scheduled to come online by 50% as “more realistic” than the first scenario — a result of nuclear subsidies that could come to fruition and discourage market entry.

Barker argues that those scenarios “aren’t very credible” because PJM made no consideration of how many projects already had interconnection study agreements, where these projects were located or how committed developers were to completing them.

Exelon’s analysis of PJM’s data purports that even if developers canceled 4.6 GW of scheduled gas units, the combined impact of coal retirements, preserved reactors and renewable penetration would still reduce carbon emissions by 16.8 million tons and reduce energy costs $1.7 billion.

“PJM answers the wrong question,” Barker said. “The story is really in the difference between the base case and the simulation. We just unmasked the data.”

Stu Bresler, PJM’s senior vice president of operations and markets, said the RTO stands by its analysis.

“We think subsidization of significant generation of any type would lead to long-term reduction in entry,” he said. “Our intent was to throw it all out there … to let stakeholders apply whichever subsidy level they think is most appropriate.”

June 30, 2019

FirstEnergy Extends Clock on Ohio Nuke Plan

By Christen Smith

FirstEnergy Solutions said Monday it will extend the deadline for Ohio lawmakers to rescue its nuclear power plants along Lake Erie, after a late-stage concession to renewable supporters failed to win immediate support among state senators over the weekend.

Bankrupt FES said it was optimistic the state Senate will approve subsidies for the Davis-Besse and Perry nuclear facilities at its next session, scheduled for July 17.

The company said last August it needed a promise of state subsidies by “mid-2019, when FES must either purchase the fuel required for Davis-Besse’s next refueling or proceed with the shutdown.”

But FES spokesman Tom Becker said Monday that the company will bear the “financial burden” of missing a June 30 fuel purchasing deadline “given the expectation that the legislation will be passed in the coming weeks.”

“The company appreciates the hard work, support and commitment of House Speaker [Larry] Householder, Senate President [Larry] Obhof and Governor [Mike] DeWine to work toward final passage of HB 6 on July 17,” he said. “While FES is optimistic about the outcome for HB 6, the company remains unable to purchase the fuel required for Davis-Besse’s next refueling cycle without the certainty of critical legislative support. We remain on path for a safe deactivation and decommissioning. Should we receive the long-term certainty that comes with an affirmative vote within this time frame, we will immediately re-evaluate our options.”

Ohio — Perry Nuclear Power Plant, located about 40 miles northwest of Cleveland.

The Senate Energy and Public Utilities Committee on Wednesday unveiled a modified House Bill 6 that would subsidize both nuclear and renewable energy generation, walking back House-approved language that gutted Ohio’s renewable portfolio standard and replaced it with fees for FirstEnergy’s nuclear facilities and two Ohio Valley Electric Corp. coal plants. Committee Chairman Steve Wilson (R) arranged for testimony on the revised bill over the weekend, but senators never took a vote.

Wilson told RTO Insider last month he was working to give FES an answer by Sunday. According to tweets about Saturday’s hearing, however, Wilson said he’d rather get the bill right than stick to the company’s timeline.

Dan Lushcek, a Senate staffer, told RTO Insider on Monday that the committee will consider a slew of other amendments to the bill before taking a vote.

“I know it’s Sen. Wilson’s intention to work on the plan and meet before the scheduled session on July 17,” he said. “Whether it’s just more hearings or an actual vote, I can’t say for sure.”

Some opponents of the subsidies contend the reactors are profitable and in no danger of retiring early, despite the company’s deadline for legislative action.

The amendment would direct 80 cents from each residential ratepayer’s bill — down from $1 in the House version approved in May — toward keeping the generators profitable amid a flood of cheap natural gas that has dragged energy prices down.

Commercial customers would pay $11/month (down from $15), and industrial customers would pay $240/month (down from $250), while large-scale customers would pony up $2,400 (down from $2,500). (See Ohio Plan Subs Nukes, Fossil Fuels for Renewables.)

The amended bill would also preserve a scaled-back RPS, the state law that mandates how much power electric distribution utilities (EDUs) procure from renewable resources. The Senate-proposed RPS requirement dropped from 12.5% of renewables by 2027 to 8.5% until 2025, with no continuation of the mandate thereafter. Lawmakers anticipated the new formula would collect $150 million in 2020 for the nuclear plants, but then it would be up to the Public Utility Commission of Ohio to determine if FirstEnergy needed the subsidies over the following six years.

The plan also cut the $2.50 fee assessed for the continued operation of OVEC’s coal plants to $1.50 and gave PUCO authority to reduce the rate even further, if necessary.

The changes did little to appease HB 6’s biggest critics, including the Ohio chapter of the American Petroleum Institute (API) and the Ohio Environmental Council Action Fund, which characterized the plan as a corporate “bailout.”

“While Senate leadership has started an important conversation about Ohio’s energy future, they are now headed in the wrong direction,” said Chris Zeigler, executive director of API Ohio. “This bill picks winners and losers at the expense of one of the most significant contributors to Ohio’s economic growth over the past decade: natural gas.”

He said 70% of residents oppose rescuing the plants and encouraged lawmakers to stick with the competitive electricity market framework, “which has brought cleaner air and more affordable electricity to Ohioans.”

Trish Demeter, chief of staff for the Ohio Environmental Council, said other tweaks proposed in the bill — including a provision that would prevent EDUs from taking a cut of the savings customers achieve through existing energy efficiency programs — diminish EE incentives. PUCO Chairman Sam Randazzo testified earlier this month that EDUs collected more than $233 million between 2014 and 2017 via these “shared savings.” (See Ohio Nuke Bill: A Worthwhile Tradeoff?)

“While on paper the renewable portfolio standard and energy efficiency resource standard are maintained … in practice these standards will effectively fade away,” she said. “This is due to … the likelihood that utilities would no longer cut energy waste through energy efficiency rebate programs.”

Demeter said the reduced OVEC fee is a step in the right direction but that the bill still lacks enough support for renewables.

“The new version of House Bill 6 is essentially a distinction without a difference and would drive the same conclusion if enacted — higher bills, dirtier air and Ohio jobs at risk,” she said. “As a state, we should lean into clean energy, instead of significantly dialing back policies that attract more investment in Ohio, cut energy costs for Ohio families and reduce harmful air pollution.”

The Ohio Consumers’ Counsel testified on Saturday that the new plan didn’t go far enough; only stripping out the OVEC fees entirely could make it more palatable, it said.

“Given the bill’s approach of subsidies instead of competitive markets, the Ohio Consumers’ Counsel continues to oppose the bill and the utility subsidy culture that it reflects,” said Michael Haugh, an OCC consultant. “I do appreciate the Senate’s truth in ratemaking where the bill no longer describes the OVEC plants as a ‘national security resource,’ which they are not.”

Haugh said a June 19 ruling by the Ohio Supreme Court underscores the risk of allowing FirstEnergy to collect fees disguised as funding for infrastructure support and investment. The court overturned a “distribution modernization rider” that PUCO assessed on customers in 2016 to upgrade infrastructure. Opponents, including the OCC, argued it was nothing more than a sham devised for “credit support.” The company collected $168 million annually from the rider, and the court said that without legislative action to the contrary, ratepayers won’t see any refund. (See Ohio Supreme Court Overturns FirstEnergy Subsidy.)

“The connection to HB 6 is that it was a subsidy, and the subsidy was for credit support that would relate in part to the troubled finances of the ultimately bankrupt FirstEnergy Solutions,” Haugh said, urging the committee to include language in the bill that provides a refund mechanism for customers. “It should have been a good week for consumers with the end of the charge, but it was a bad week for consumers with the court’s decision that FirstEnergy can keep the improper charges without a refund of nearly a half billion dollars to Ohio families and businesses.”

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.”