Page 1108 – RTO Insider

October 16, 2018

Aggregation Rising, Retail Competition at Risk in Mass.

By Rich Heidorn Jr.

BOSTON — Municipal aggregation is becoming a potent tool for cutting electric prices and greenhouse gas emissions, while some believe retail choice has failed to live up to its promise for residential customers, speakers told Raab Associates’ New England Electricity Restructuring Roundtable on Friday.

Regulators from Massachusetts, Connecticut, New Hampshire and Rhode Island, at table, listen to a question from the audience at the New England Electricity Restructuring Roundtable at the offices of law firm Foley Hoag in Boston. | © *RTO Insider*

The roundtable featured a panel of state regulators on grid modernization and a second on the future of residential retail choice, where Rebecca Tepper, chief of the Massachusetts attorney general’s Energy and Telecommunications Division, reiterated the AG’s call for a ban on competitive suppliers signing up new individual residential customers. The AG’s office initially made the proposal in March, when it released a report concluding that electric retailers were overcharging residential customers and preying on the poor.

Tepper said the AG estimates retailers overcharged Massachusetts residential consumers $253 million in the three years ending June 2018. The study found that low-income customers were twice as likely as others to choose a competitive supplier and that they paid a half-cent more per kilowatt-hour on average than other competitive shoppers.

This is not a case of a “few bad apples,” Tepper said, citing findings that 10 retailers, who held 63% of residential accounts, were responsible for 75% of the overcharges.

About 55% of households in the state receive basic (default) service from their electric distribution company, while 20% purchase from a competitive supplier and 24% via municipal aggregation — up from 19% a year earlier. The aggregation numbers are likely to grow further as the state’s two largest cities, Boston and Worcester, consider joining in.

Credibility Problem

Tepper said residential customers are being exploited because of their lack of knowledge and inability to negotiate contract terms. The state does not believe it can fix the problem through less severe rule changes, she said. Connecticut consumers overpaid by $46 million even after banning variable rates, she said, and efforts in Pennsylvania and New York to tighten rules resulted in three years of litigation.

Rebecca Tepper, energy chief for the Massachusetts Attorney General’s Office, listens skeptically as Chris Kallaher, senior director of government and regulatory affairs for Direct Energy, defends retail electric providers. | © *RTO Insider*

“Restructuring has worked for lots of entities. It’s worked for commercial and industrial customers; it’s worked for municipal aggregation. It’s working to lower wholesale prices. But after 20 years of restructuring, now is the time to look back and say where is it working and where is it not working. And this — that 20% [purchasing direct from competitive suppliers] — is where it’s not working.

Chris Kallaher, senior director of government and regulatory affairs for retailer Direct Energy, acknowledged, “We admit that [competitive suppliers] have a credibility problem.”

But Kallaher said the AG’s office is using the wrong yardstick in measuring what residential customers are paying competitive suppliers against default service, which he said is below market because of cross subsidies. Kallaher said default service has no customer acquisition costs because new and moving customers are assigned to it automatically unless they opt for a competitor. Direct Energy said the AG’s pricing comparison did not account “for all of the types of products offered by the competitive supplier” versus the plain-vanilla standard offer.

“There’s a ton of retail costs that are not in the default service rate,” he said. “Costs which should be subject to competitive pressures: billing, customer service, collections, facilities. Everything else — everything we have to pay for — remains embedded in distribution rates and not subject to competitive pressures.”

Direct Energy was one of 12 suppliers identified by the Connecticut Office of Consumer Counsel (OCC) as charging at least 20% of their customers 50% or more than the standard offer. The OCC said the company overcharged almost 38% of its Eversource Energy customers and 42% of its United Illuminating customers.

Kallaher said he was unable to explain why the AG’s office found low-income customers paying more than others for competitive service. “We need to find out what’s going on. If suppliers are discriminating on the basis of low-income status, that clearly needs to stop,” he said. “All these other things are easily addressed.”

He said the state should remove remaining barriers to customers switching and get the distribution utilities out of electricity sales altogether.

Janet Gail Besser, executive vice president of the Northeast Clean Energy Council (NECEC), suggested low-income customers are more likely to be lured by competitive suppliers’ promised savings because the electric bill is a larger share of their household budget.

She also opposed the AG’s call for eliminating residential choice. “Yank the licenses of these suppliers [preying on the poor]. Make the penalty really drastic if they are doing this kind of thing. But don’t throw the baby out with the bathwater,” she said.

She disagreed with Tepper’s contention that residential retail competition had produced no innovation, citing community solar and residential solar leases for those unable to purchase solar panels. “That access to residential customers is absolutely critical to providing these services and to continue to have companies thinking of new ways to deliver services.”

Municipal Aggregation

Paul Gromer, CEO of Peregrine Energy Group, also supported a more targeted response, calling abuses of low-income customers “a discrete problem that can probably be addressed on its own.”

But he also touted municipal aggregation, which he said provides the benefits of competition while avoiding many of the risks because the municipality vets retailers’ savings and environmental claims. About 125 communities are participating in municipal aggregation in the state, some of them using it to provide funding for local renewable energy projects.

“It’s probably the most powerful tool a community has to meet its climate goals,” Gromer said. “A lot of communities in the state have very ambitious goals. As communities, they want to do more than the federal government is doing. They want to do more than the state is doing. But they’ve got limited tools with which to accomplish those goals. They don’t regulate the power plants. They don’t regulate the utilities. They don’t run the [Massachusetts Bay Transportation Authority]. They can’t tell people what kind of a car to drive. They can put solar on municipal rooftops and they can run programs like Solarize — all of which are great but have a small impact. Aggregation, on the other hand, can have a very big impact.”

Lexington, Mass., for example, is reducing community-wide GHG emissions from electricity by 20%. “Communities have no other tool that has that kind of impact,” he said. “Lexington decides to launch a program; 10,000 households and businesses are on a green-power product overnight. Cambridge launches its program: Another 40,000 are on green power.”

Tepper said if the Massachusetts legislature doesn’t ban residential retail choice, her office would like to see smaller fixes addressing low-income residents, auto-renewal practices and fixed teaser rates followed by higher variable rates.

Kallaher disagreed with all but the need for protections for low-income customers. Banning variable prices and auto-renewals and subsidizing default service “are things we think are just killing the market without actually addressing the underlying problems,” he said.

New Technologies

Besser said it is “tremendously ironic that we’re having this discussion about ending residential retail choice just as new technologies are becoming available to make it work better.”

She cited Sense, a monitor that can be connected to a home’s electrical panel to track energy use by individual devices.

“If Massachusetts and the New England states don’t figure out how to have the utilities deploying advanced metering, then we may see the utilities jumped over, because the competitive market will figure out ways to provide a shadow service or virtually the same service,” Besser said.

Advanced metering and other aspects of grid modernization were the subjects of the first panel of Friday’s roundtable, where Connecticut Public Utilities Regulatory Authority Chair Katie Dykes also endorsed Sense. “It’s great data for marital disputes,” she joked.

The session also featured Angela M. O’Connor, chair of the Massachusetts Department of Public Utilities; Martin Honigberg, chair of the New Hampshire Public Utilities Commission; and Rhode Island Public Utilities Commissioner Abigail Anthony.

O’Connor explained Massachusetts regulators’ approval of $220 million in spending for three electric distribution companies’ grid modernization investments. The investments include distribution management systems with advanced sensing and load flow analytics to improve EDCs’ visibility of the grid; volt-var optimization and distribution automation; and spending to help EDCs integrate distributed energy resources.

The Massachusetts DPU, however, rejected utility proposals for smart meter deployments, saying the customer benefits were uncertain and could result in high stranded costs if existing interval automatic meter reading (AMR) meters are replaced prematurely. Advanced meters will not optimize system demand without time-varying rates, O’Connor said.

Dykes outlined PURA’s initiatives in EDCs’ distribution system planning, distributed generation tariffs and pilot programs for grid-side system enhancements.

Honigberg said the New Hampshire commission’s staff will be issuing a report soon with recommendations for future actions, based on stakeholder suggestions and its research of other states’ efforts.

Anthony said the Rhode Island commission’s August approval of a modified settlement with National Grid included funding for a system data portal, upgrades to the company’s geographic information system and a program to separate distribution remote terminal units (RTUs) from transmission RTUs for the first year of the three-year rate plan. It also directed the utility and stakeholders to develop a long-term grid modernization plan and a business case for advanced metering functionality.

October 14, 2018

Q&A: PJM’s Ott Still Looking West

By Robert Mullin

In addressing last week’s annual meeting of the Northwest & Intermountain Power Producers Coalition (NIPPC), PJM CEO Andy Ott made clear his RTO is still in the running to provide wholesale market services to the Western Interconnection, despite the dissolution of its partnership with Peak Reliability. (See related story, Western Regionalization ‘No-brainer,’ PJM CEO Says.)

PJM andy ott western market — PJM CEO Andy Ott | © *RTO Insider*

After his speech before attendees, Ott sat down with RTO Insider for the second time this year to discuss PJM’s perspective on a Western market, this time in the aftermath of Peak’s decision to wind down its operations next year. (See PJM Chief Confident on Western Market Proposal.)

The interview has been edited for clarity.

RTO Insider: In a press conference last month, NERC CEO Jim Robb said he had heard Peak Reliability’s effort to develop a Western market characterized as a kind of a Hail Mary pass intended to maintain their financial viability. Would you agree with that assessment?

Ott: From what I understood from my conversations [with Peak CEO Marie Jordan], they were getting feedback that their costs for reliability services were above what others like [CAISO] or SPP felt they needed to charge. So I think Peak’s approach was if they were going to provide high-quality reliability services, they had to find a better way to pay for the other infrastructure needed to provide those services. Their constituency was saying if you would like to provide market services like others do, you may be a viable alternative. So [Jordan] was actually getting asked that question.

They were facing a cost structure that people were telling them was unsustainable, so their answer could’ve been, ‘We either fold the tent and more or less do the wind-down, or do something else.’ From a [different] point of view, some people thought it was a Hail Mary pass because it came so late in the discussion. The notion of bringing in someone like us who does markets, it was certainly doable, but for them, they couldn’t sustain that project for any length of time because they were facing cost pressures.

How unexpected was it that things fell apart as rapidly as they did after Peak made the announcement to pursue a market? Did that take you by surprise?

No. From our perspective, they’re going to have regional markets in the West. It’s just a matter of time and how they evolve. The thing we didn’t have in the West was the relationships with people, and we also didn’t have a real-time model that could be stood up fairly quickly. Peak brought both. We had the market expertise, but we didn’t have that, so it was a pretty easy decision for us to pair up with them. That said, once [Peak] introduced us, we were able to build our own relationships. And then the real-time model, based on my understanding, is going to become available to everybody, so I don’t see that as being a real challenge.

If all you provide is reliability services, there’s a certain overhead that’s required to do market operations, grid operations and reliability services. That infrastructure needs to be in place to do any of those three. If you build the infrastructure to do more than one of the three, then the costs for each one of those services per unit goes down. So what we’re saying is that we can’t be competitive in providing just reliability services, but if we could provide RC [reliability coordinator] services plus grid operations plus markets or some combination of those so that lowers the rate — because that’s essentially what [CAISO] is doing.

Does the balkanization of RC services in the West complicate things for PJM?

If you’ve talked to Jim Robb, I’m sure he’s told you this: Most folks on the reliability side preferred a single RC in the West. But it was obvious 18 months ago that Peak was saying, ‘I’ve got California and I’ve got Mountain West both telling us it’s too expensive,’ it was already going to be balkanized. I think the attitude in the West is that it’s too expensive to maintain the West-wide [RC] model because other folks want to do their own thing, so as you pull larger regions of the West out, the costs for everybody else goes up. So I think it’s inevitable that it becomes more regionalized. So for us, I don’t think it’s something we’re causing, we’re just observing it’s going to happen. It’s a fait accompli at this point. It obviously helps us because if people want to look at alternatives, then they will look at us.

You mentioned in your [NIPPC] speech that there’s interest [regarding PJM] in the Southwest, not so much in the Northwest. What entities in the Northwest have you approached?

If I’ve had conversations with folks, I’d rather not talk about that. I don’t feel comfortable. Suffice it to say, there weren’t many people in the Northwest that wanted to have conversations because they thought they already had a path forward. Hopefully that will change.

Compared with CAISO, most RTOs appear to have a different model of stakeholder engagement, with CAISO probably being the most staff-driven, and MISO and PJM, for example, being more stakeholder-driven. What advantages do you see in the latter model?

I think certainly in a Western context … who better to decide what the rules of the road should be than the actual stakeholders of the market? And I am a bit biased because that’s where I come from, but my people aren’t wise enough to drive. I mean we can provide services, we can consult, we can give them the analytics, but at the end of the day, the RTO is more or less a service provider, an information provider to stakeholders who make decisions with that independent information. I just think it’s a better model because it’s more transparent.

Occasionally we have to step in and do something controversial because our mandate is to have nondiscriminatory results, but I think 90% of the issues are resolved through that consensus, and I think it’s more healthy. And out here [in the West], if people feel they’re not being fairly treated and they don’t have any other option, how sustainable is that?

You talked in your speech about the relationship [between a new market] and the Energy Imbalance Market. What kind of complications would there be in having an overlay with that market?

This goes back to the mindset of folks saying, ‘Either I do EIM or I have to do this regional market, and I have to choose between them.’ And that was my point [in the NIPPC speech] — you don’t.

I mean, the only difference is whether you are participating in the EIM as a group or individually. If you’re participating as a group, then maybe you’ll have a say in how prices are formed, where today you don’t have a say.

If the California legislature won’t give up control [of CAISO’s governance], well then you’re having a peer-to-peer discussion and that goes to FERC. So the point is, if [CAISO] won’t change its price formation, then the entities outside will say, ‘We got together and we decided we’re going to price ramping this way, and we’re going to price hydro this way,’ and then you have to make those interact at the border. And so when we’re selling to you, you’ll pay our price, and when you’re selling to us, we’ll pay your price, and that’s interregional coordination.

The whole point is that market-to-market coordination creates huge efficiencies. In fact, you’d have higher levels of trade than you would with the EIM, because EIM is individual, so if one person creates a constraint on another person’s system, you have to stop. If you combine them together and say we’ll manage constraints together, we’ll have more throughput. So the whole notion out here that they have to make this choice between EIM or not is just fiction.

I hope they’ll go back and think about this notion of participating as a team or a group, banding together and then participating in the EIM, and then you can have a conversation about, ‘Well it doesn’t matter what California says about price formation, we have an opinion too. And if there’s a conflict, we’ll resolve it at FERC.’ And I know that scares some people, but my point is, who [is CAISO] going to trade with?

So it would be something like a joint operating agreement? That would be the relationship?

Yeah, it’s a market-to-market coordination joint operating agreement. There would be an agreement approved by FERC. This is not unheard of. This is the way everybody else does it. We have them with New York, MISO, [the Tennessee Valley Authority], with Duke [Energy], so it’s pretty standard.

I’ve talked with some in the Northwest who say the idea of applying the standard market design is outdated and not really applicable to the region. What do you think about that?

This is key: The market design has to adapt to the region, not the region to the design. So the whole mindset back in the day that you have a standard market design and we have to adapt to it was never going to work. In fact, we don’t even have that. There’s differences between MISO’s design and PJM’s design because of the regional structure.

But for the West, we’re not saying you have to take our design. Now there’s stuff we’ve learned where every place in the world there are certain key things — like economic dispatch — that are always going to work. But as far as hydro coordination out here, it’s a huge deal, so the market side has to adapt and let hydro coordination be a primary design criteria.

Is there a timeline you’re operating on in the West?

No, it really depends on the folks here. There originally was a timeline because Peak had a certain burn and had to have an answer by a certain date. But once Peak and PJM dissolved their relationship, there’s no timeline on our side. It’s what the region wants. And this is why we considerably slowed down and we’re talking to people at a more casual pace. My opinion is, the quicker the better for them.

October 14, 2018

Northwest Ponders RTO with Mix of Hope and Skepticism

By Robert Mullin

UNION, Wash. — The California State Assembly bill intended to set CAISO’s regionalization in motion may have died in committee this past summer, but talk of an organized market for the broader Western Interconnection lived on last week during the annual meeting of the Northwest & Intermountain Power Producers Coalition (NIPPC).

NIPPC’s annual meeting | © *RTO Insider*

That talk was tinged with a mixture of resignation, skepticism and optimism — and humor.

“For the moment, it appears to me regionalization in the West is dead, at least from the CAISO perspective,” said Steve Rodgers, director of FERC’s Division of Electric Power Regulation-West.

“There’s not going to be regionalization anytime soon, it appears. Some states perceive that California has a desire to export its policies to other states. I’m sure nothing like that would ever happen,” Rodgers joked.

Rodgers noted that some California groups opposed to regionalization fear it will allow “free riders” in the rest of the West to take advantage of infrastructure paid for by California ratepayers, while some in other parts of the West worry about increased costs for their ratepayers.

“I had one experience back in the spring where in consecutive weeks I had two of these diverse groups come to meet with my staff to express their concerns,” he said. “I felt like saying, ‘You guys should get together, because some of these fears are not adding up.’”

Rodgers said that while FERC was closely monitoring developments around regionalization, it would not put pressure on any of the region’s players because “that surely would be the kiss of death” for the effort.

caiso regionalization western rto nippc — Richard Glick | © *RTO Insider*

FERC Commissioner Richard Glick said that some California opponents of regionalization have argued that an “evil FERC is going to come in and they’re going to reverse California’s greenhouse gas emissions program.”

“First of all, at least with regard to the California ISO, we already do have a significant amount of authority. If we wanted to engage or use certain words that could inhibit California policy, I think we could do that, but I’m not saying we’re going to do that and we certainly shouldn’t do that,” Glick said. “And secondly, I think the evidence is out there already if you look at the other regions with RTOs that the commission is generally pretty deferential in terms of regional preferences.”

“We need a big bipartisan win, and I don’t think we’ll get it on carbon tax in the short term, but I’ll tell you a place where we can get it. We can get it on enhanced regional grid integration,” said Ralph Cavanagh, co-director of the energy program at the Natural Resources Defense Council.

Cavanagh recounted this summer sitting before the California Senate Judiciary Committee (which was pondering the regionalization bill), bracketed by the “extreme” left and right.

“I’m trying to get them to vote for a fully independent board for the California ISO, and there were howls of anguish from the extreme left in California on this because of a perception this was going to turn California over to the tender mercies of what is called the Trump FERC, without recognizing that the California ISO is fully regulated by the Trump FERC today,” Cavanagh said.

Cavanagh noted the bill passed the committee with Republican votes, which would have been key to passing it if it had gone to the State Senate floor.

“And I really hope to see that. I really hope to see Democratic and Republican majorities on a tough issue. It’s been controversial, and collectively the will of this room must be ‘We will not give up on this,’” Cavanagh said, addressing his NIPPC audience.

“I tend to agree that that is ideally a place where bipartisan agreement will emerge,” said Montana Public Service Commission Vice Chair Travis Kavulla, who noted he sits on the Western Energy Imbalance Market Governing Body.

“Even in the absence of a kind of fully packaged regionalization of an ISO, which would be ideal, I think you can incrementally build on the regional efforts that are currently underway,” Kavulla said. “Right now, you’ve kind of got a toolbox with only a Phillips-head screwdriver in it, but it would be nice to add some additional tools into the Western regional market.”

Kavulla said he was disappointed to see the tenor of the California debate over regionalization, but that it was “hilarious” to see the NRDC’s Cavanagh associated with regionalization proponent PacifiCorp.

“But, fundamentally, as a non-California Westerner, it’s simply inconceivable that you’d have a workable and productive market for electricity in this region in the absence of a jurisdiction that has half of its load,” Kavulla said.

Lauren McCloy, senior policy adviser to Washington Gov. Jay Inslee, noted the governor supported passage of California’s failed regionalization bill and understands that CAISO and regional stakeholders continue to work on enhancements to the EIM that “could pave the way for a more dynamic regional market in the future.”

“The governor also continues to advocate for resolutions to the two biggest issues for Washington stakeholders participating in these discussions: governance and fair valuation for hydroelectricity,” McCloy said. “In order for Northwest entities to join the regional market, they will have to have a decision-making role in how that market is run.”

McCloy reminded conference participants that Washington produces about a quarter of U.S. hydropower. In establishing a fair value for the resource, a market operator would need to recognize that hydropower “is not only emissions-free, but it’s also flexible and can be coordinated to complement other variable renewable resources such as solar and wind.”

FERC’s Rodgers said the EIM has been a “great success so far.”

“First of all, there’s been great benefits to date of over $400 million. Not only is that a large number, but that number is getting larger all the time as more and more entities join the EIM. The boundaries of the EIM are growing each year,” he said.

Rodgers also pointed out that the possible extension of CAISO’s day-ahead market could increase the benefits of the EIM, but that some observers are concerned it could prevent full regionalization.

NIPPC Executive Director Robert Kahn wrapped up the meeting with a healthy dose of skepticism on the issue: “NIPPC has been working to create an RTO/ISO since 2000, and we will continue to do so, but we’re not holding our breath.”

October 14, 2018

NYISO Business Issues Committee Briefs: Oct. 10, 2018

NYISO and PJM last month jointly filed a request with FERC for a waiver of their joint operating agreement (ER18-2442), Rana Mukerji, ISO senior vice president for market structures, told the Business Issues Committee on Wednesday while presenting the monthly Broader Regional Markets report.

The waiver would permit the two grid operators to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. If granted, it will enable PJM to conduct redispatch operations to control flows to the more restrictive rating on the New York side of the line without violating the PJM Tariff for a limited time while the RTO and NYISO work to develop a permanent solution.

NYISO and PJM have jointly filed a request with FERC to waive a portion of their JOA to allow the East Towanda-Hillside tie line to be added as a market flowgate. | *NYISO*

Mukerji also highlighted efforts to clarify the minimum deliverability requirements for external capacity from PJM into NYISO’s Installed Capacity (ICAP) market. The ISO will continue discussions of this topic with stakeholders at the Installed Capacity/Market Issues Working Group meeting this month, he said.

In August, the ISO briefed the BIC on proposed market design changes to improve the supplemental resource evaluation process for external capacity resources.

Improving Public Policy Tx Planning

The BIC approved revisions to improve the efficiency of the Comprehensive System Planning Process in the short term, including eliminating the requirement that the New York Public Service Commission issue an order before NYISO begins evaluating transmission solutions. Under the proposal, the PSC retains the ability to cancel or modify identified public policy transmission needs (PPTNs) prior to the ISO’s selection of the more efficient or cost-effective solution, which would halt the evaluation or result in an out-of-cycle process to address the modified need.

In one case, NYISO had to wait about five months before evaluating and selecting Western New York PPTNs, according to a report by Yachi Lin, senior transmission planning manager. Under the new process, the ISO would begin the process following completion of a viability and sufficiency assessment and if developers meet the necessary requirements to proceed.

NYISO has proposed related Tariff amendments and will seek approval from the Operating and Management committees this month before seeking board approval in November.

In addition, the ISO will clarify in the Tariff that the project description in the transmission interconnection application or interconnection request must match the description in the PPTN proposal or face rejection.

Technical Details

Within 60 days after a formal solicitation from NYISO, interested developers must submit both redacted and unredacted versions of their complete project proposal to satisfy the PPTN, submit identical proposals in the interconnection process and provide a nonrefundable $10,000 deposit and a $100,000 study deposit for each project.

NYISO will then post a brief description of the project proposals within five business days after the solicitation window closes.

The ISO will file the final viability and sufficiency report at the PSC, and within 15 days of the filing, each developer must confirm that it intends to proceed and agree to a system impact study.

Long Term

NYISO will present a long-term process design concept to stakeholders by the end of 2018 to improve its Local Transmission Owner Planning Process (LTPP); Reliability Planning Process (RPP); Congestion Assessment and Resource Integration Studies (CARIS); and Public Policy Transmission Planning Process (PPTPP).

Under the proposal, prior to issuing a formal solicitation, the ISO will hold a technical conference to get input from developers and interested parties on the application of selection metrics to the PPTN.

LBMPs Up 31% Year-on-Year

NYISO locational-based marginal prices averaged $38.70/MWh in September, down from $42.56/MWh in August but up 31% from the same month a year ago, driven by four days in early September in which the peak load topped 28 GW compared with no such days in September 2017, Mukerji said in his monthly operations report.

Year-to-date monthly energy prices averaged $45.75/MWh in September, a 29% increase from a year ago. September’s average sendout was 458 GWh/day, lower than 537 GWh/day in August and 437 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $2.75/MMBtu, down about 8.3% from August and up 21.5% from a year earlier. Distillate prices climbed slightly compared to the previous month but were up 23.3% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $16.21/MMBtu and $16.08/MMBtu, respectively.

Total uplift costs and uplift per megawatt-hour came in lower than August, with the ISO’s 37-cent/MWh local reliability share in September down from 59 cents the previous month, while the statewide share climbed from -61 cents/MWh to -48 cents. Uplift, excluding the ISO’s cost of operations, was -11 cents/MWh, lower than -2 cents in August.

The Thunderstorm Alert (TSA) cost in New York City was 33 cents/MWh, more than double the 14 cents in August.

— Michael Kuser

October 14, 2018

MISO Market Subcommittee Briefs: Oct. 11, 2018

CARMEL, Ind. — MISO’s Independent Market Monitor last week pointed to other RTOs to illustrate the ineffectiveness of the coordinated transaction scheduling (CTS) between MISO and PJM.

Market Monitor David Patton at MISO Board Week in September | © *RTO Insider*

Monitor David Patton told the Market Subcommittee on Thursday that the CTS between ISO-NE and NYISO includes an explicit waiver of uplift and transmission charges between them. As a result, the process last year yielded bids and offers of 700 MW in one direction and 400 MW in the other.

Patton has recommended that MISO remove transmission charges from CTS with PJM. MISO currently applies transmission charges to these transactions when they are offered, not just when they are scheduled, which the Monitor said discourage CTS offers and subsequent savings. (See 7 New Recommendations from MISO IMM.)

Patton admitted that the New England numbers weren’t as high as he’d like, but that it’s important that the coordination is used.

“CTS has basically completely failed between PJM and MISO. Quantities have fallen to essentially zero,” Patton said.

MISO and PJM launched CTS a year ago to allow market participants to schedule economic transmission transactions based on forecasted energy prices in the two RTOs. While CTS should have lowered the cost of serving load in both regions, it has not been used since mid-February because of the double transmission charges.

MISO will respond to the recommendation later this month, when it releases its formal response to the Monitor’s State of the Market Report.

Dynamic Line Ratings

The Monitor is also renewing calls for MISO to adopt dynamic line ratings that are adjusted based on weather conditions, opening up transmission lines for more capacity when temperatures are cooler.

“The hotter the temperature, the less electricity you want through the conductor,” Patton said. “Transmission owners have long recognized that there are benefits to different ratings. … Every additional megawatt you can flow over the line can help you ramp down a higher-cost generator and ramp up a lower-cost generator.”

Transmission lines are rated based on seasonal ambient temperature and wind speeds. Patton said that of MISO’s TOs, “almost none” submit upratings beyond seasonal limits.

Customized Energy Solutions’ Ginger Hodge asked the Monitor how MISO might incentivize TOs to offer dynamic ratings. “I think there are few that offer dynamic ratings because they introduce risk to their system,” she said.

Patton said TOs themselves can benefit from higher ratings. “This capability is valuable, and they should see an economic value from providing it,” he said.

— Amanda Durish Cook

October 14, 2018

NY Carbon Task Force Looks at REC, EAS Impacts

By Michael Kuser

NYISO on Thursday recommended steps to prevent certain wholesale market suppliers, designated as carbon-free in the New York Clean Energy Standard (CES), from collecting double payments for carbon-emission reductions that have already been captured by renewable energy credit contracts.

“The idea is to prevent these resources from benefiting from a change in [locational-based marginal prices] resulting from a carbon price,” said Michael DeSocio, the ISO’s senior manager for market design. DeSocio presented a report on the treatment of REC contracts to the state’s Integrating Public Policy Task Force (IPPTF), which met by teleconference.

NYISO proposes applying a carbon charge to wholesale market suppliers with active, fixed-price REC contracts with the New York State Energy Research and Development Authority that are based on a REC solicitation that began or was completed prior to the carbon pricing rules taking effect.

At the July 16 IPPTF meeting, the ISO said it was considering options to reduce or eliminate the potential for such double payments. (See NY Sets Carbon Pricing Timeline, Reviews Progress.)

NYSERDA Only

“I want to remind everybody that NYISO is not a party to any of these agreements, and we’re aware of resources only because NYSERDA has made us aware of them,” DeSocio said.

The proposal is limited to NYSERDA contracts because the ISO believes it has no authority to put conditions on out-of-state REC contracts, DeSocio said.

Wholesale market suppliers with such NYSERDA REC contracts are initially settled at the LBMP, including the carbon component. NYISO will then deduct the carbon charge from the supplier’s settlement based on the social cost of carbon and the real-time marginal emission rate for the supplier’s zone.

Marginal emissions rate by month for Load Zones F, G, J and K. | *NYISO*

“This carbon charge will be applied to the actual output of the resource based on the proportion of the REC contract to the nameplate capacity,” DeSocio said.

Generators designated as carbon-free under the CES, and whose NYSERDA REC contract has expired, will settle at the LBMP including the carbon component — and not be subject to a carbon charge. Zero-emission credits and offshore wind RECs are not included, as they have an option to adjust to changes in market conditions, he said.

‘Hard Squeeze’

Seth Kaplan of EDP Renewables said, “NYSERDA has entered into REC contracts for virtually all of the output of the facilities they contract with — that’s just what they do.” He suggested that NYISO check with NYSERDA about how much of the output it buys from projects.

Kaplan said the ISO “is assuming that RECs are carbon payments and that therefore there is a problem to be solved.” He referred to an updated Brattle Group analysis showing a minimal effect of carbon pricing on pre-2020 RECs, with actual customer costs of 4 cents/MWh in 2020 and 2 cents/MWh in both 2025 and 2030.

“It raises a very serious question of whether the hard squeeze that you’re putting on companies that have taken risk and moved forward under REC contracts is worth the juice that comes out of the bottom of the orange, [and] of whether this is an enormous effort that would produce, as I believe [Brattle’s Sam] Newell said, nearly invisible impact, and whether this is really worth the trouble,” Kaplan said.

Kathy Slusher, director of energy procurement and utility regulatory affairs for the State University of New York, said the university system has a campus that will put a bid request out for 150,000 RECs, representing 150,000 MWh of energy in a “ready commodity market.”

“However this is going in NYISO would interrupt that market and would really throw everything for renewables in New York up in the air because none of us could sign a [power purchase agreement] because we don’t know if we’re going to get RECs, what value they would have, or if they’d be able to be sold,” Slusher said. “Sorry … but I think NYSERDA punted this over to [NYISO] and it doesn’t belong in your court.”

To the extent that there’s a secondary market for RECS, the ISO doesn’t know about it or seek to administer some clawback, DeSocio said.

Weird Dynamic

Anne Reynolds, executive director of the Alliance for Clean Energy New York, said that not considering REC sales elsewhere “does raise a weird dynamic.”

“If you’re saying the generators can’t sell their RECs to NYSERDA and still realize the carbon charge revenue increment, but they can sell them to someone else … there’s no logical reason for that, and it illustrates again that a REC payment and a social cost of carbon are not the same thing,” she said.

Reynolds also spoke of the perception among some industry participants that the Public Service Commission addressed the grid operator’s responsibility regarding RECs in a state proceeding, “but the fact is that petition [Case No. 15-E-0302] has never been answered by the commission; it’s an open petition. In the offshore wind order [Case No. 18-E-0071], there was discussion of the issue, and one sentence that said, ‘it might be more appropriate for the ISO to take on this issue’ or something like that, but there was no ordering clause from the commission telling the ISO to solve this problem.”

She also said the utilities are acquiring RECs through value of distributed energy resources (VDER) payments and that VDER projects are getting LBMPs that include the carbon charge increment. She noted that some VDERs qualify as Tier I renewables (for example, a community solar project getting the value stack and exporting to the grid) and utilities can use those RECs to meet their Tier I obligations.

Warren Myers, Department of Public Service director of market and regulatory economics, said the utilities can use such RECs for compliance: “They’re not tradeable RECs, but they can use them to satisfy their Tier I REC requirements.”

ICAP Demand Curve and Net EAS Revenues

Ryan Patterson, NYISO associate for capacity market design, presented a report recommending that any carbon charge in the wholesale market should be rolled into net energy and ancillary services (EAS) revenue estimates through the existing annual update process.

Carbon pricing impacts the capacity market through the ICAP demand curves. | *NYISO*

The ISO analyzed the impacts of carbon pricing on the installed capacity (ICAP) demand curves to illustrate how the annual update process could affect future capacity market clearing prices, finding that net EAS revenue will be impacted by a carbon charge.

Increasing carbon prices and LBMPs will likely impact both cost and revenue, Patterson said. The net EAS revenue offset values and the reference point have an inverse relationship: as net EAS revenue increases, the reference point decreases, and vice versa.

In the last ICAP demand curve reset process, the ISO moved to a historic model that averages projected net EAS revenue over a three-year period preceding the new ICAP demand curves taking effect. The study period ran from Sept. 1 of Year 1 through Aug. 31 of Year 3, using actual historic data such as LBMPs and fuel and emission costs.

The 2017/18 ICAP demand curves used net EAS revenue offset values measured from Sept. 1, 2013, to Aug. 31, 2016, and the ISO implemented an annual update process that allows for specific variables used in calculating the reference point to be recalculated each year between the quadrennial resets.

Changes to the reset process implemented in 2016 were intended to allow for the ICAP demand curves to capture changes in market conditions over time, including the impacts of changes to market rules. Adjustments to the net EAS model to allow for incorporation of a carbon charge will be evaluated as part of the upcoming reset process, Patterson said.

Two datasets were used to run several scenarios, Patterson continued. The first was 2015 and 2016 marginal emissions rates (MER) prepared by Brattle, under which the LBMP was increased by $50/MWh and, to account for the carbon price change, the Regional Greenhouse Gas Initiative price was increased by $50 for hours that LBMPs were adjusted for carbon pricing.

The second dataset was derived from modeling and pricing software (MAPS) runs for 2020, 2025 and 2030, in which LBMPs were output for carbon and no carbon base cases, and then fed into the net EAS model along with projected fuel costs used in each respective MAPS run. As with the previous dataset, the RGGI price was increased by $50 for the carbon cases.

No stakeholder asked questions about the net EAS revenue impact analysis, but Brett Kruse of Calpine said he would like to make a presentation to the IPPTF on Oct. 22 on the issue of how a carbon charge might affect hedges on transmission congestion contracts.

IPPTF Chair Nicole Bouchez, the ISO’s principal economist, shared a revised schedule that foresees the task force meeting on the remaining Mondays this month, collecting stakeholder feedback in November and presenting a formal proposal on carbon pricing Dec. 17.

RTO Insider will have coverage later this week of the task force’s Monday meeting at NYISO headquarters.

October 14, 2018

SPP Briefs: Week of Oct. 8, 2018

FERC last week approved SPP’s first seams project with a neighboring utility when it accepted Tariff revisions incorporating a cost-sharing and usage agreement with Associated Electric Cooperative Inc. (AECI).

The Oct. 10 letter order allows SPP and AECI, a Missouri-based collection of six generation and transmission cooperatives, to proceed with the Morgan transformer project. It was the entities’ second attempt to gain FERC approval (ER18-2243, ER18-2245).

SPP says the project is the most efficient, cost-effective solution to economic and reliability issues identified in two separate studies. It also said the project will reduce day-ahead market uplift costs and avoid the cost of a more expensive regional solution, resulting in a regionwide load-ratio-share benefit of more than $17 million.

The RTO included both arguments in its revised filing, after its first attempt failed in 2017. (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)

SPP has proposed to regionally fund the project, as it will solve congestion issues on its side of the seam. The RTO will cover 82.91% of the $13.75 million engineering and construction cost, while AECI will cover the remainder and is responsible for the project’s construction, operations and maintenance.

SPP FERC m2m settlements aeci — David Kelley | © *RTO Insider*

David Kelley, the RTO’s director of seams and market design, told RTO Insider that FERC’s approval “is evidence it’s possible to share both costs and benefits of new transmission projects across regions.”

“We continue to work with all of our seams partners to enhance our processes to identify and approve mutually beneficial transmission projects,” Kelley said.

The Morgan project comprises a new 345/161-kV transformer at AECI’s Morgan substation and an uprated 161-kV line, both near Springfield, Mo. It was identified during an SPP-AECI 2016 study as outlined by the entities’ joint operating agreement and by the RTO’s 2017 10-year assessment.

“It’s important to SPP and our industry to continue to provide affordable and reliable electricity to our customers, and our success in doing so will depend more and more on our ability to work across regional boundaries to create win-win scenarios,” Kelley said.

SPP said stakeholders, its Board of Directors and state regulators have consistently recommended regionwide cost allocation for the Morgan project.

FERC last year rejected SPP’s first attempt to allocate the project’s costs, ruling it had not shown that the proposed allocation on a regionwide, load-ratio-share basis was “roughly commensurate” with the project’s benefits.

The commission in 2015 also rejected SPP efforts to create a new class of seams transmission projects, saying its plan to identify projects outside the Order 1000 interregional planning process was “too broadly drawn” (ER15-2705). FERC did allow SPP to make filings on a project-by-project basis for non-Order 1000 facilities. (See FERC Rejects SPP Proposal for Seams Transmission Projects.)

FERC does not comment beyond an order’s language. A spokesperson would not confirm whether this was the first interregional project the commission has approved on a case-by-case basis.

August M2M Payments Again in MISO’s Favor

Replicating an outcome last seen two years ago, the market-to-market (M2M) process between SPP and MISO resulted in the latter receiving more than $531,000 in payments for August.

MISO last received back-to-back payments in July and August 2016, the beginning of the only three straight months the RTO has seen M2M payments in its favor. SPP has been on the right side of the ledger 19 of the 21 ensuing months.

Temporary flowgates were binding for 327 hours in August, resulting in $788,835.60 in M2M payments to MISO. That was reduced by $257,098.85 for permanent flowgates binding for 127 hours in SPP’s favor.

SPP still has as healthy balance of almost $51.4 million in M2M payments since the process began in March 2015.

— Tom Kleckner

October 14, 2018

ERCOT ‘more than Sufficient’ on Reserves

ERCOT’s current market design “will support more than sufficient reserve margins,” according to a draft report the grid operator filed on Friday with the Texas Public Utility Commission.

The report by The Brattle Group estimates a market equilibrium reserve margin (MERM) of 10.25% under projected 2022 market conditions.

ERCOT puct brattle group reserve margins — PUC Commissioners (left to right) Shelly Botkin, DeAnn Walker and Arthur D’Andrea | *ERCOT*

“This estimate should not be interpreted as a precise forecast for 2022 or any other particular year, but as a reasonable expectation around which actual reserve margins may vary as market conditions fluctuate,” Brattle said. “Low reserve margins cause high energy and ancillary service prices and attract investment in new resources, and investment will continue until high reserve margins result in prices too low to support further investment.

“This is much lower than historical reserve margins, but close to the reserve margins from ERCOT’s latest resource adequacy reports,” the report added. ERCOT’s reserve margin was 10.9% for summer 2018 and is projected at 11% for 2019.

Brattle also calculated a 9% economically optimal reserve margin (EORM), the point at which the marginal costs and marginal benefits of adding capacity are in balance. “The economic optimum occurs at the reserve margin that minimizes societal costs net of all supply costs and the lost value from any disruptions in electric service,” Brattle explained.

The report was submitted as part of the PUC’s review of ERCOT’s reliability standard (Project No. 42302) and its performance during the summer’s tight conditions (Project No. 48551).

The report notes MERM is a relevant measure because ERCOT does not have a resource adequacy reliability standard or reserve margin requirement, unlike other systems in North America. ERCOT’s reserve margin is “ultimately determined by suppliers’ costs and willingness to invest based on market prices, where prices are determined by market fundamentals and by the administratively-determined operating reserve demand curve [ORDC] during tight market conditions,” the report’s authors said.

Brattle worked with Astrapé Consulting to model ERCOT’s wholesale market design and projected system conditions for 2022, simulating “a range of possible reserve margins under a range of weather and other conditions.”

The report noted that the market equilibrium of 10.25% is greater than the economically optimal level by 1.25%. “Based on these results, we conclude that the current market design will support more than sufficient reserve margins from an economic perspective,” Brattle said. “The market equilibrium is higher than the economic optimum because the ORDC as currently designed sets prices higher than the marginal value of energy during scarcity conditions.”

The authors cautioned that “an important uncertainty” in the study is the likelihood of extreme weather. The base case gave all 38 years of historical weather an equal probability of occurring for the 2022 simulation. Assigning 10% weight to each of the last 10 weather years and ignoring the other 28 years would increase the equilibrium reserve level by 1.5% “due to the higher energy prices in these years,” Brattle said. “However, it would increase the number of scarcity events, resulting in similar reliability.”

The report’s results for both the market equilibrium and economically optimal reserve margins were 1.25% lower than found in a 2014 study. Brattle said low gas prices, higher renewable penetration and updated assumptions on generators’ forced outages and weather contributed to the change.

Brattle will present its study results during ERCOT’s Supply Analysis Working Group meeting on Oct. 19. The report will also likely be used in an Oct. 25 PUC workshop on the grid operator’s summer performance.

ERCOT will accept stakeholder comments on the report through Nov. 26.

WETT Faces Full Rate Case

During an abbreviated open meeting Oct. 12, the PUC moved to open a rate case for Wind Energy Transmission Texas (WETT), which staff said earned an excess $16.4 million last year.

The commission’s action gives the company 120 days to file revised rates, although staff is hopeful a settlement agreement can be reached before then (Project 48158).

WETT had a 12.43% return on equity in 2017, above staff’s estimate of 9.60%. WETT reported a year-end 2017 capital structure of 53% debt and 47% equity, while the PUC said a 60/40 mix is appropriate for transmission-only utilities. “If WETT’s actual capital structure were instead 60% debt and 40% equity, its reported level of 2017 return dollars would have generated an even higher ROE of approximately 14.1%,” staff said in a memo.

PUC Approves Cleco Acquisition of Gas Unit

The PUC’s consent agenda included approval of Cleco Cajun’s acquisition of NRG South Central Generating’s 100% interest in Cottonwood Energy. Cottonwood owns a 1,263-MW gas-fired generation facility, interconnected with MISO, along the Louisiana border in Southeast Texas (Docket No. 48266).

The acquisition is part of Cleco’s $1 billion acquisition of NRG’s eight power plants (3,555 MW) and contracts to provide wholesale power to nine Louisiana cooperatives, five municipalities in Arkansas, Louisiana and Texas, and one investor-owned utility. (See NRG Selling Renewables, Other Assets for $2.8 Billion.)

Louisiana-based Cleco would own the Cottonwood facility, but the project will be leased back to NRG, which will have full operational control until May 2025.

Commission to Intervene in MISO FERC Docket

The commissioners agreed during their closed session to intervene in a FERC docket involving MISO’s cost allocation methodology for targeted market efficiency projects with PJM (EL18-2514). (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)

The PUC also agreed to have Executive Director J.P. Urban coordinate with the Texas Commission on Environmental Quality in providing comments on EPA’s Affordable Clean Energy rulemaking (EPA-HQ-OAR-2017-0355), its proposal to replace the Obama administration’s Clean Power Plan.

Commissioner Arthur D’Andrea drew laughs when, referring to the EPA’s naming convention, he said, “We should adopt a system like that.”

— Tom Kleckner

October 12, 2018

ERCOT Board Approves $53.3M Economic Tx Project

ERCOT’s Board of Directors on Tuesday unanimously approved the grid operator’s first economic project in three years, a $53.3 million transmission upgrade in West Texas, despite concerns it doesn’t address reliability issues.

ercot bearkat transmission upgrade — Bearkat Area Transmission | *ERCOT*

Staff recommended Wind Energy Transmission Texas’ (WETT) Bearkat area project as the “most cost-effective solution” to address congestion near Odessa. The region’s wind generation has been bottled up by a lack of adequate transmission, resulting in congestion more than half the time, staff said.

Director Clifton Karnei, who represents the cooperative market segment, referenced the state’s Competitive Renewable Energy Zones (CREZ) initiative in expressing his unease about the board making “mini-CREZ” decisions. CREZ resulted in the construction of 2,800 miles of new transmission facilities, delivering West Texas wind energy to the state’s urban centers at a cost of $7 billion.

“We built all the CREZ lines that raised transmission costs. People are concerned about transmission costs being high, yet here, we’re adding another transmission project that’s not needed for reliability,” Karnei said. “We’re doing it because we have all this wind in a constrained area that is being derated. So when we run the production cost model, that’s when it shows the net societal impact. It makes me feel very uncomfortable.”

ERCOT’s analysis found the Bearkat project would produce $400 million in 30-year net savings, based on its economic planning criteria. Staff evaluated nine upgrade alternatives, all of which passed the criteria.

Asked whether the area would require a reliability project in 10 years should the board reject staff’s recommendation, Fred Huang, ERCOT manager of regional planning, said it’s difficult to project future load reliability without doing a study.

“Without this project, we expect to continue to see congestion in this area,” he said. The Bearkat area has 1.5 GW of wind energy already in operation or planned.

Unaffiliated Director Peter Cramton pointed out that building transmission for only reliability reasons would forego potential economic gain.

“It seems like this makes sense for reliability and social economic benefits to be included as a reason to do transmission projects. There aren’t going to be the private incentives for somebody to build this,” he said. “In a first best world, the private incentives would be aligned with the social incentives, and we would just let the market work, but it seems transmission is an area where we can’t completely rely on the market.”

Karnei was able to find comfort in ERCOT’s Protocols and their reliability and economic criteria.

“If we are to follow Protocols, it appears to me we need to endorse this project,” he said.

“This analysis supports the consistent regulatory framework we have in place,” ERCOT Legal Counsel Chad Seely said, reinforcing Karnei’s statement.

ERCOT updated its economic planning criteria in 2012, following the Texas Public Utility Commission’s removal of a consumer benefit test from its economic criteria for certificates of convenience and necessity.

The Bearkat project comprises two new 345-kV bays and a 27-mile, 345-kV single-circuit line on double-circuit-capable structures. ERCOT’s Technical Advisory Committee endorsed the project last month. (See “TAC Endorses $53.3M Economic Project in West Texas,” ERCOT Technical Advisory Briefs: Sept. 27, 2018.)

October 12, 2018

MISO Monitor Reiterates Call for Capacity Deliverability

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Independent Market Monitor urged the RTO and stakeholders Thursday to require that planning resources have firm transmission to ensure they can deliver their full installed capacity.

In its State of the Market report issued in June, the Monitor said that MISO’s deliverability requirements are too lenient because resources with energy resource interconnection service must only secure firm transmission for its unforced capacity values, which are about 5 to 10% less than their full installed capacity levels. (See 7 New Recommendations from MISO IMM.)

“It’s being relied on but it’s not deliverable,” Potomac Economics’ Michael Chiasson said during an Oct. 11 Resource Adequacy Subcommittee meeting. “It’s clear to us that the [loss-of-load-expectation] study is assuming resources will be deliverable to their installed capacity value.”

Chiasson said MISO’s current practice means as much as 1,400 MW procured in the 2018/19 Planning Resource Auction may not have been deliverable. He also acknowledged that some resource owners may have purchased more firm transmission service than MISO requires.

Chiasson said the rule change can be made with little economic impact to the PRA.

“The concern is more the potential reliability impacts, which could be serious,” Chiasson said.

While roughly half of the about 190 resources contributing to the possible shortfall impact 2 MW or less of capacity, 23 of the resources could each affect 20 MW or more.

Chiasson pointed out that MISO currently requires full deliverability for resources with network resource interconnection service, leading Consumers Energy’s Jeff Beattie to say the RTO was giving unequal treatment to the two groups of generators.

MISO Director of Resource Adequacy Coordination Laura Rauch said that the RTO generally agrees with the recommendation, which could result in a change to how it accredits capacity resources. The RTO is expected to formally respond to the State of the Market report by Oct. 17.

Some stakeholders said that the benefits of the more stringent requirement wouldn’t be significant enough to justify more spending on transmission rights.

But Chiasson said if planning resources decide not to pay for more transmission rights, MISO could simply disqualify the portion of their installed capacity that cannot be guaranteed deliverable.