Page 1293 – RTO Insider

May 16, 2017

NECA 2017: Embrace Disruption for Reliable New England Grid

By Michael Kuser

GROTON, Conn. — The best strategy to deal with change in the energy sector is to embrace it. So said some of the more than 250 participants at the Northeast Energy and Commerce Association and Connecticut Power and Energy Society’s 24th New England Energy Conference last week.

NECA President Tina Bennett, a principal consultant with Daymark Energy Advisors, said that the electric markets should “accept disruption” from new technologies by creating a new regulatory landscape.

NECA electric vehicles — Bennett | © *RTO Insider*

“The model today is not really conducive for where we want to go in the future,” Bennett said, citing the growing impact of distributed energy resources. “What are the things we can do today from a regulatory perspective and from a business model perspective that can open up possibilities for the disruption to happen?”

Former Massachusetts Undersecretary of Energy Barbara Kates-Garnick, now a professor of practice at Tufts University, agreed.

“We are going to have to accept disruption, but that is something that we as the energy industry haven’t been easily able to accept,” she said. “The future is not linear, it’s not a straight line, and we’re going to have to design processes that have off ramps and that also enable rewards for those people and those entities that take risk.”

Angela M. O’Connor, chairman of the Massachusetts Department of Public Utilities, said her state is “at a crossroads. We’re number one in the nation in energy efficiency, but our programs are also the most expensive in the country. When lighting requirements change, what will the next programs and the benefits look like?”

DERs’ Impact

RTOs are trying to automate their grids, but high penetration of distributed energy resources means they have to operate their feeders with less flexibility at times depending on renewable penetration levels, or “hosting capacity,” said Scott Higgins, director of distributed energy and microgrids for Schneider Electric.

The job of managing the grid is complicated by different market participants — independent power producers, utilities and behind-the-meter “energy prosumers” — each having different goals, contracts and control systems.

To illustrate the challenge, Higgins mentioned the use of battery storage to shave a “prosumer’s” peak in the middle of the day. “But we also have a demand response event coming up later in the afternoon and the control system will need to recharge the battery for that. The DR event benefits the prosumer, but it is initiated by the utility, so at some point the control algorithm decides to stop peak shaving and to charge the battery. What if the prosumer has an economic interest in peak shaving longer and foregoing the demand response event that day? Contracts and control systems both have to draw the line at some point between serving one customer constituent and another.”

With the huge investments needed in upgrading transmission and developing renewables, “we can make use of that grid; we don’t need to be trying to escape the grid,” said Jeffrey Roark of the Electric Power Research Institute.

Alan Trotta, director of wholesale power contracts for United Illuminating, offered some statistics illustrating the growth of DER. “In 2011 we had fewer than 100 requests for interconnection with distributed generation units,” he said. In 2016 “there were over 3,000 requests and over 2,300 new behind-the-meter generators interconnected.”

For maximum cost-effectiveness of decarbonization of the grid, go big, said Trotta, referring to the difference in customer costs between grid-scale renewables and DERs. “The economies of scale are real and we see it in actual procurement results.” Speaking about the evolving role of the grid, Trotta said, “The grid is changing because the needs of the users are changing, and by users, I mean customers, generators, potential storage developers [and] people in the transportation sector.”

Electric Vehicles

Many in the industry are confident that electric vehicles will cause an increase in loads after years of flat or declining power demand. Martin Stahl, managing director of Germany-based Stahl Automotive Consultants, forecast that EV sales in the U.S. will increase seven-fold to nearly 1.4 million by 2025. The main constraint on EVs, he said, is a lack of charging infrastructure.

Stahl said utilities are committed to building an EV charging infrastructure in Germany, where the decision to give up nuclear power increased renewable commitments and added stress to the grid.

Well-placed chargers are essential to avoiding excessive spending on public and private charging infrastructure, Stahl said. “But more important is the demand response function, either regulated or behind-the-meter,” he said. Fast-charging equipment is expensive and needs to be connected to higher voltage lines, while at-home charging is almost invisible to utilities. “We are exploring with clients how to ensure that emerging load can be put to a good time of the day,” he said.

For example, he estimated that with good location planning and optimization, EV charging could decrease the average residential ratepayer bill by nearly 10%, versus a 1.5% increase with no optimization.

Timing

Timing is crucial to those who seek to introduce change, Stahl said. “The ones who do that too early are also on the wrong side of the game. We saw that especially with electric vehicles, where the early players did not make it.”

ENGIE North America CEO Frank Demaille said his company and Axium Infrastructure US recently signed a $1.2 billion 50-year contract with Ohio State University to map and implement the school’s energy sustainability strategy. One initial goal is to reduce energy consumption at the 485-building campus by 25% within 10 years. A contract with such a long lifespan means “you can really build something with a strong partner,” Demaille said.

New Rate Designs

Decoupling revenues from sales is a good start to make utilities “indifferent to increasing energy efficiency on their system,” Trotta said. Referring to the expansion of net metering, however, Trotta said, “We may need to see new rate structures in the future that send the appropriate economic signals to all of the users of the grid.”

There’s no doubt that the market structure and the rate design need to change, O’Connor said. “We want utilities to do much more now under the same rate structure from 20 years ago.”

States, RTOs in Conflict?

On whether RTOs’ focus on reliability conflicts with the environmental goals of states, Macky McCleary of the Rhode Island Division of Public Utilities and Carriers said he preferred to acknowledge tension, rather than conflict. “It’s a shared concern, and the ISO can help make it cheaper to achieve those environmental goals,” he said.

“The only resources left to rely on the existing wholesale markets in New England are natural gas generators and old nukes,” said Susan Tierney, senior adviser with The Analysis Group. “Policymakers in the states are making a big bet that those markets will remain sustainable.”

May 16, 2017

Cuomo – NYISO Tensions on Display at IPPNY Conference

By Rich Heidorn Jr.

ALBANY, N.Y. — At FERC’s technical conference May 1 and 2, several commenters observed that it is easier to coordinate state policy with wholesale markets when the market is a single state, as in NYISO.

But there was no groupthink on display at the Independent Power Producers of New York’s 31st Annual Spring Conference last week, where industry stakeholders and state and ISO officials debated carbon policy, zero-emission credits for nuclear plants, the closure of the Indian Point nuclear plant and the Champlain-Hudson transmission line.

In particular, the conference highlighted the differences between the administration of Democratic Gov. Andrew Cuomo and the Republican-controlled State Senate, the ISO and IPPNY itself.

Arguably, no state officials are pushing more ambitious changes for the electric industry than New York’s — with the Reforming the Energy Vision initiative — for transitioning to a less centralized, more renewable-based future.

NYISO IPPNY Indian Point nuclear power plant — Kauffman | © *RTO Insider*

Richard Kauffman, chairman of the New York State Energy Research and Development Authority and Cuomo’s top energy official, began his speech to IPPNY by acknowledging the tensions.

“That was quite a pointed introduction,” he joked when IPPNY CEO Gavin Donohue welcomed him to the podium after laying out the organization’s complaints over the state’s “out-of-market” policies.

‘Love Letter’ to ISO

Kauffman also acknowledged that “It’s no secret that we haven’t been in very good alignment with the NYISO.”

“I’m sure that Brad Jones keeps a copy of my love letter to him on his dartboard,” he said, referring to the missive he sent last July in response to comments the ISO filed with the Public Service Commission on the state’s Clean Energy Standard.

The letter dismissed NYISO’s filing as “misleading, incomplete and grossly inaccurate” and lectured the ISO on the need to combat climate change. Kauffman also accused the ISO of being “held captive” by stakeholders representing “status quo interest that are threatened by the renewable future” — singling out IPPNY by name.

At the conference, Kauffman declined to offer an opinion on the ISO’s carbon adder plan, saying officials of NYSERDA and the Department of Public Service had just begun to review it. (See related story, NYISO Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)

But he made it clear any ISO plan would have to “harmonize” with REV and insisted the state’s actions were justified responses to market imperfections.

“We recognize the valuable role the federal wholesale markets can play,” he said. “But the truth is in our view those wholesale markets are not living up to their potential because of a failure to effectively harmonize with the states’ public policy. … Given the uncertainty in Washington, the state will not cede what it considers its role in energy and environmental policy.”

REV’s Objective

He said REV’s objective is to provide market-based incentives for private capital to build “the 21st century grid” with “a mix of central station production and distribution with distributed nodes; where supply and demand are dynamic and electrons can flow in more than one direction.”

The new grid must be “both more energy and capital efficient,” he said. “Fifty-four percent average capacity utilization — which is what our entire system is in New York state, a number which is declining — is a low number in terms of capital efficiency.

“We can’t achieve the governor’s mandate of 50% renewables by 2030 by doing things the same way. … We’ve been bolting things onto a system that it wasn’t designed for. Those things include renewables and [distributed energy resources]. … And the same way we’ve been physically bolting renewables and DER onto the grid never intended for these resources, we’ve recognized that we can’t keep bolting on policies onto a policy regime that was not intended for that purpose either.”

Kauffman said he would not answer questions about ZECs because of the suit filed by IPPNY members Dynegy, Eastern Generation and NRG Energy claiming the ZECs intrude on FERC’s jurisdiction. He said only that “the governor did not want to lose ground in carbon emissions by the upstate plants closing.” (See Federal Suit Challenges NY Nuclear Subsidies.)

Donohue concluded Kauffman’s session by imploring him, Jones and Scott Weiner, the DPS’ deputy for markets and innovation, to “keep working to come up with this market fix so that Chairwoman [Cheryl] LaFleur … can help us implement something to save our markets in New York.”

Cuomo vs. Legislature

The Cuomo administration’s differences with the State Legislature were also on display as State Sen. Joseph Griffo (R), chairman of the Senate Committee on Energy and Telecommunications, told the conference that the Senate will “carefully vet” Cuomo’s nominees to the PSC. “It’s not going to be a pro forma type of submission,” he said. (See related story, Cuomo Names NYSERDA CEO as PSC Chair.)

New York State Assemblywoman Amy Paulin (D), chair of the Committee on Energy, outlined her objections to the statewide cost allocation of the ZEC subsidies, saying the costs for the upstate generators should not be imposed on her Westchester County constituents. Assembly members were left fuming in March when the PSC and NYSERDA declined to send witnesses to a hearing on the program and Exelon sent no senior executive with knowledge of the subsidy negotiations. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.)

Indian Point

Some legislators are also upset with Cuomo’s deal to shut down the Indian Point nuclear plant by 2021. The governor has long opposed the plant because of its proximity to New York City.

In March, ISO and PSC officials told a joint hearing chaired by Paulin and Griffo that they are not concerned about replacing the capacity of the 2,069-MW plant, saying energy efficiency, transmission upgrades and the ISO’s wholesale market will ensure reliability.

IPPNY Chair John Reese, senior vice president of Eastern Generation, indicated in remarks to the conference that he is not satisfied with those assurances. “What does the future look like? We have no idea,” he said.

Reese said the ISO should begin an impact study on the retirement immediately rather than waiting for a formal retirement notice, which might not come until 2020 or later. “It takes a minimum of four to six years to build infrastructure in N.Y. If Indian Point presents an issue on [power] supply, we need to know now.”

Champlain-Hudson Transmission Line

“What should definitely be off the table [among potential Indian Point replacements] is the remarkably uneconomic Champlain-Hudson [Power] Express transmission line,” Donohue said.

nyiso ippny indian point — Paulin | © *RTO Insider*

Earlier this year, Paulin and Griffo introduced what Paulin called an IPPNY “priority bill” that would prohibit the New York Power Authority from purchasing energy from the proposed line (A07685, S05126.)

IPPNY claims the project — which would transmit 1,000 MW of Canadian hydropower to the New York metro area — could not be built without direct or indirect subsidies, such as “extra-market contracts” with a state entity. The project was proposed by Transmission Developers Inc., which claims the $2.2 billion project would be one of the largest investments in New York state history.

“The state’s view has not changed,” Kauffman said. “TDI is a merchant line. This means a customer or customers need to sign up for the power. … The cost of the transmission line will not be passed along to any ratepayers.”

May 16, 2017

LaFleur Braces for ‘FERC 2.0’ Under Trump

Since she was appointed to FERC in 2010, acting Chair Cheryl LaFleur has served with seven commissioners and two chairmen, Jon Wellinghoff and Norman Bay.

Cheryl LaFleur Trump IPPNY — LaFleur | © *RTO Insider*

Now, after operating without a quorum since February, she is about to be joined by as many as four new commissioners appointed by President Trump. It will be the biggest turnover at the commission since at least 1993 — a transition she has come to call “FERC 2.0.” (See Trump Nominates Republicans Powelson, Chatterjee to FERC; No 2nd Term for FERC’s Colette Honorable.)

The chairman sat down for an interview last week with RTO Insider editor Rich Heidorn Jr., a former FERC staffer, about whether the commission can maintain its reputation for nonpartisanship, her reflections on the commission’s May 1-2 technical conference on tensions between state policies and wholesale markets, and the grid security study ordered by Energy Secretary Rick Perry. The transcript below has been edited for clarity and length.

RTO Insider: So first off, a week after the technical conference, are you more or less optimistic about the future of the wholesale markets than you were before?

Cheryl LaFleur: I would say that the conference met our expectations, which I think were difficult to fulfill. We wanted to have all the different views represented and aired in a very transparent way to try to frame the issues and I think that happened. We wanted to get a better sense of what the consequences were of the different potential solutions, and I think to a large measure, that happened. And we wanted to create a sense of momentum behind the issue without having the ability to vote out anything to create a sense of momentum, and I think we did create a sense of momentum that we are now trying to sustain.

RTO Insider: In your opening remarks May 1, you talked about feeling like you had been punched in the gut when you read Sue Tierney’s words from the 2013 capacity market technical conference. In retrospect, do you feel like the 2013 conference was a missed opportunity? Or do you not have time for regrets about that? (See Power Markets at Risk from State Actions, Speakers Tell FERC; Capacity Market Attracts Praise, Criticism at FERC.)

Cheryl LaFleur: Well, I don’t think this particular issue of state policies and the markets was really fully framed in 2013. Although I do clearly … Dr. Tierney did allude to it, and I remember at that 2013 conference, her distinctly talking about the Clean Power Plan and so forth, which nobody else was talking about then. I think actually, in my opinion, quite a lot came out of the 2013 tech conference. As part in response to conversations at that tech conference, we saw a settlement achieved in New England, which led to the sloped demand curve and the renewables exemption, which was very clearly discussed at the conference. And in some ways the Capacity Performance, Pay-for-Performance proposals that we saw come out of [PJM and] New England in some ways were generated by things at that conference so I thought that was one of our more productive conferences.

I said at the time of the 2013 conference and it’s still true, that there’s two competing things we hear all the time. The first is: Stop making changes in the capacity markets. And the second is: Make my change please. And I think the concept that when we’ve had a successful tech conference, it’ll be when nothing changes anymore because the world is going to be, as it is may be, illusory. Because I think the issues that are framed now in the 2017 tech conference have evolved.

RTO Insider: So, there was a reference earlier today to the Rick Perry comments and this need to study grid reliability. Isn’t that kind of a slap in the face to what you guys at FERC have been doing for the last couple of years?

Cheryl LaFleur: Well, FERC and DOE we have always worked in parallel or in a complementary way. I mean, they made [us] aware they were putting out the memo. Presumably they’re going to do this study. I don’t remember when the 60 days run out, but it’s relatively soon and it’ll be a piece that’s part of the conversation.

RTO Insider: So, would it surprise you if they came up with anything you haven’t already talked about?

Cheryl LaFleur: I can’t surmise that. I mean, there’s always new things under the sun.

RTO Insider: So let’s talk about the quorum news. How well do you know Powelson and Chatterjee?

Cheryl LaFleur: I know both of them. In general, I’m saying I’m very happy that we got the news. I appreciate the White House making the announcement. I appreciate Sen. [Lisa] Murkowski [R-Alaska, chair of the Senate Energy and Natural Resources Committee] saying she was going to act on them quickly. I tried to sort of in general not comment on individuals. But I do know these gentlemen. I’m very happy to see this news this week.

RTO Insider: And do you have any sense of when the player to be named later [third Republican nominee] may be named?

Cheryl LaFleur: I read in the press soon, but hopefully soon.

RTO Insider: What came out of the conference that perhaps most surprised you?

Cheryl LaFleur: Nothing was really surprising, but I think it was very important and informative to hear the different views of the different states, and we only saw [a] microcosm. I believe we had three of the PJM states there, and it was interesting to see where they were coming from I thought. Hearing the New England states — their representatives were very honest about some of the things they would and would not accept. I think that in itself, if that’s all we got out of the day, that would’ve had value. Because I mean they chose to come into a forum that was a FERC forum and express those views and that was very important.

RTO Insider: How does that play out when, let’s say, you get that filing from ISO New England for this two-tier capacity auction? Does having heard from the states give you some sense of, well here’s what the political realities are and we have to kind of take that into account?

Cheryl LaFleur: Well I would first of all hope that in the process that’s going to ensue between now and whenever any filing is made that there would be a discourse with the states as they go along. I feel like I’m on a little bit of a tour now because I’m in New York, doing PJM in a few weeks and then I’m going to [the New England Conference of Public Utilities Commissioners’ Annual Symposium]. And I know between the NECPUC meeting and then the [New England Power Pool] summer meeting, ISO New England will be talking a lot to the states. Certainly here in New York, one state, one ISO, so I would hope a lot of that would happen as they go along and it wouldn’t be a case of picking up a filing and finding out a state was unhappy that I didn’t know before.

RTO Insider: In other words, them filing an intervention.

Cheryl LaFleur: Or I mean I would hope that we would’ve known where the states were on the issues as we went along. Because really, as I said at the conference, the regional markets exist because of changes in state policy that gave rise to them. And they exist with the support of the states so they’re very important constituencies.

RTO Insider: If in fact the capacity market becomes less central to, let’s say operations in PJM, because public power persuades the commission that they should have more latitude, is that necessarily a failure of the markets? Or would you say that the capacity markets have always been kind of a Rube Goldbergian device, and so it’s to be expected some people may want to opt out of it?

Cheryl LaFleur: There are different ways you can do resource adequacy, and a spectrum of different ways you can do resource adequacy, and I try to have an open mind about the ways that the regions do it. If you look at the way the Southwest Power Pool does resource advocacy versus California versus New England, there’s different models.

I feel the only failure would be if we didn’t plan for resource adequacy and stumbled into something. Or if something fell between the cracks in the federal government and the state government. But different systems that different states come up with, I have an open mind.

RTO Insider: How, if at all, do you expect the new commissioners to change the dynamics on the commission? As long as I’ve been following the commission — back to when I worked there under Pat Wood — what I’ve always been impressed by in the FERC building, as opposed to much of the rest of Washington, is the lack of partisanship. We rarely mention commissioners’ party affiliations because you don’t really see that playing out in how they vote. Any reason to think that might change under the new regime?

Cheryl LaFleur: Well I think FERC does have the strong tradition of bipartisanship and making decisions based on the facts and the law, and I certainly hope that we’ll continue and that the new commissioners, as they’re sworn in, will continue in that tradition. I think in terms of the dynamics — not partisanship, just the dynamics in general — we’ll see a change in the commission the likes of which we haven’t seen since 1993, maybe even more. Because generally, you have one commissioner at a time come on, you have the four who were there and one individual comes on. And every time a new person comes, it changes the shape of the whole. But to have up to four come on at a time — including a chairman — that’s a big turnover. In 1993, four came at once, but the chairman was there already. So, that’s a big turnover. But I believe the tradition of — or more than a tradition — the expectation of making decisions by the record and bipartisanship will continue.

RTO Insider: Somebody had floated the notion that the president is not actually required to appoint two Democrats to the other seats. He can appoint three Republicans, but he can appoint independents or what have you. Have you heard anything about that — that there is going to be any change in the way they handle that?

Cheryl LaFleur: No I believe the law says only three of the president’s party. I have heard no changes.

RTO Insider: So you don’t anticipate that’s likely to happen.

Cheryl LaFleur: The White House has not shared with me their plans. I’ve said all along my hope is that they appoint people who are experienced in energy, and so far, they have.

RTO Insider: And along the lines of that, have you been given any indication whether they might continue you in an interim position as chair for a while after the new commissioners are sworn in?

Cheryl LaFleur: No.

RTO Insider: Okay. We’ll all have to wait to find out.

Cheryl LaFleur: I mean there’s so many different ways this can go. I think a lot also is riding on when the third nomination comes, and how these nominations proceed. But, regardless of how long I’m chairman, my focus right now is on getting the backlog and the issues that are pending before us framed in the best way we can to help the onboarding commissioners come up to speed, and helping the work of the commission to move forward. I intend to stay afterward as a commissioner so I’ll be there for the transition. But even if I weren’t, the FERC staff will be there, and many of them have been there through several chairmen.

RTO Insider: Is there anything that I haven’t asked you about that you want to put out there as your message coming out of either the tech conference, or just kind of the state of play right now?

Cheryl LaFleur: Well I guess I would just say on the tech conference, we have not yet issued, I don’t believe, our request for comments, but we hope to hear from voices beyond the ones who spoke at the tech conference. We know there were people who volunteered to speak, and others who might not have volunteered, but have something to say, and we hope to hear from them.

The only other thing you haven’t asked about is Commissioner [Colette] Honorable, which is also, it was only a couple weeks ago that happened. I was very sorry to hear her plans, although it’s obviously up to her. But she’s been a wonderful colleague and a great addition to the commission.

RTO Insider: Well we kind of assumed that prior to Commissioner Bay leaving, that her position would go to a Republican to make the balance. Once he left, in theory she could have stuck around. Do you know if she had an indication from the White House that she would not be reappointed?

Cheryl LaFleur: I don’t know any of that, and it’s not my place to say. While we’re talking about the new guys, she was great. She is great; she’s still there.

RTO Insider: And let me ask you one last question about the criticism of the public interest groups who claim they were not allowed to testify at the conference, and also about a lack of transparency in the RTOs. [See Public Interest Groups Cry Foul over Technical Conference, RTO Transparency.] I just wondered if you had any response on that, any comment on that.

Cheryl LaFleur: Well we tried to balance the panels and have a consumer viewpoint on every one of the panels, and I think we did, but as I said, we’re going to be putting out a request for comments and we certainly hope to hear from others as well.

RTO Insider: Are you happy with the level of transparency in the RTOs?

Cheryl LaFleur: I really don’t have any comment on that. We have an obligation to oversee their stakeholder processes and the way they decide things, and I asked a question about that at the tech conference in fact.

RTO Insider: I must have missed that.

Cheryl LaFleur: I don’t want to prejudge the … I don’t really have any comment. No, I think I picked up on one of the [witnesses] that said something about the stakeholder processes.

RTO Insider: Well thank you very much for your time, appreciate it.

Cheryl LaFleur: Thanks a lot.

May 16, 2017

MISO Market Subcommittee Briefs

CARMEL, Ind. — MISO last month called on load-modifying resources for the first time in 10 years after it declared an unusual mid-spring maximum generation emergency in the southern part of its footprint.

Unseasonably high loads coupled with a large number of generation and transmission outages precipitated the April 4 event in MISO South, RTO officials said in an emergency review.

The region lost almost 1,500 MW of generation just after midnight when a large unit unexpectedly went down. MISO issued a maximum generation alert around 8 a.m., and by 1 p.m., all resources were in use, with LMRs called up about two hours later. To compound conditions, temperatures topped 80 degrees Fahrenheit, exceeding April averages by about 8 degrees and driving unexpectedly high load.

MISO Market Subcommittee cost recovery gap — Benbow | © *RTO Insider*

“What we saw is temperatures that were more typical for May,” Rob Benbow, senior director of systemwide operations, said at a May 11 Market Subcommittee meeting.

Transmission outages were also higher than normal, with some lines down from earlier severe weather and seasonal maintenance, stranding generation in some cases. Spring maintenance season also sidelined a large number of generators.

All told, MISO called up about 730 MW of LMRs in MISO South to cover a projected 447-MW energy shortfall, marking the first time the RTO has relied on the resources since 2007.

“It’s the first time we’ve deployed load-modifying resources in quite some time,” Benbow said. “This isn’t unusual where you’ve got a lot of maintenance outages and high load in shoulder times.”

MISO forecasts a 79.3% probability that it will again call up LMRs this summer. (See MISO Slims Summer Reserve Prediction.)

Benbow said MISO’s new emergency pricing floors were initiated during the event and worked as intended. By about 9:30 p.m., emergency operations were lifted.

“I fully support overdoing it,” ITC’s Ray Kershaw said. “When you hit the button, you’re not sure how many peakers are going to show up. … You did your job, that’s for sure.”

MISO is still collecting meter data from the event and will evaluate the performance of the LMRs, Benbow said. Stakeholders asked whether operators of those resources are required to respond to run requests from MISO outside of summer peak conditions, an issue RTO staff said they would investigate.

Benbow credited successful management of the emergency event to MISO’s extensive drills. “You only get this through training,” he said.

MISO Officially Expands ELMP

MISO this month expanded its extended locational marginal pricing (ELMP) program to allow online units with one-hour start-up times to set prices.

The program — now entering its second phase — was previously available only to 10-minute fast-start resources.

The move means that 58% of MISO’s capacity is eligible to qualify as peaking resources, compared with 8% beforehand.

FERC accepted MISO’s filing to expand ELMP in an April 20 letter order (ER17-1081).

Twelve newly eligible resources participated in ELMP price-setting during the first day of implementation, said Concong Wang, MISO market design engineer.

MISO’s second phase of ELMP fell short of its Independent Market Monitor’s recommendation that price-setting be extended to all resources with a two-hour minimum run time. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)

Wang said MISO will present a post-implementation analysis at the December MSC meeting, after collection of about six months’ worth of data.

Additionally, the RTO is planning to discuss a potential new trading hub in Mississippi at the June 8 MSC meeting, Director of Forward Operations Planning Kevin Sherd said.

Proposal Would Address Cost Recovery Gap

MISO will revise its Tariff to address two possible gaps in cost recovery when units are manually redispatched offline.

The new language will allow generators to recover start-up costs and day-ahead margin assistance payments during required minimum down times following an RTO-ordered decommittment.

“We currently don’t allow for recovery of start-up costs when a resource is taken offline,” said MISO Market Quality Manager Jason Howard.

When MISO decommits a day-ahead resource, the day-ahead margin assurance payment does reimburse the resource for minimum down times or start-up costs. (See “Potential Cost Recovery Gap in Manual Redispatch,” MISO Market Subcommittee Briefs.)

MISO will file the language by the end of May and seek a next-day effective date, Howard said.

He also said he would have to follow up on a question by Customized Energy Solutions’ Ted Kuhn, who asked if MISO enforces any limits on a resource’s minimum downtime.

MISO, PJM in ‘General’ Agreement over Pseudo-Tie Congestion Remedy

MISO and PJM are in “general” agreement about using an interim rebate program to handle their overlapping pseudo-tie congestion charges, according to MISO Director of Forward Operations Planning Kevin Vannoy.

Vannoy said PJM is still reviewing a slight modification to the original agreement: that the RTOs exchange information about firm flow entitlements a day before a flow date to better predict the effect of congestion on pricing.

The RTOs proposed the rebate solution in early March as a stopgap. A longer-term solution will involve scheduling pseudo-ties in the day-ahead process. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.) They have postponed their ambitious June 1 implementation date for the program to early September. Staff from both will review the solution again at the May 23 Joint and Common Market Initiative meeting held at MISO’s Carmel, Ind., headquarters.

— Amanda Durish Cook

May 16, 2017

Overheard at the IPPNY Annual Spring Conference

ALBANY, N.Y. — About 200 industry stakeholders and state and NYISO officials discussed carbon policy, zero-emission credits, and other pressing and contentious issues at the Independent Power Producers of New York’s 31st Annual Spring Conference last week. Here’s some of what we heard.

The Independent Power Producers of New York’s 31st Annual Spring Conference was held at the new Albany Capital Center, where the IPPNY logo was displayed in lights in the ceiling. | © *RTO Insider*

New Venue, Tighter Security

IPPNY demand curve carbon policy — Donohue | © *RTO Insider*

This year’s conference was held at the new Albany Capital Center. IPPNY CEO Gavin Donohue is chairman of the Albany Convention Center Authority, which built the $78 million project a block from the state capitol.

Event organizers ordered tighter security than in years past. No one without a registration badge was allowed near the event.

“You know what happened at the last conference,” recounted Donohue, referring to the May 2016 event at the Desmond Hotel, when anti-pipeline protesters took over the stage as then-FERC Chair Norman Bay was speaking.

Energy Policy Under Trump

In a panel on energy policy under President Trump, attorney Steven Croley, a partner with Latham & Watkins who served as general counsel for the Department of Energy under President Barack Obama, led the audience in a “thought experiment” comparing Trump’s energy policy with that of a fictional third Obama term.

Croley said Trump will have a smaller impact than some critics fear, calling the policy differences between the two administrations “susceptible to exaggeration,” Croley said.

For example, he said the scale of LNG exports will be driven by world demand, not any new federal policy.

Neither Trump nor Obama would back federal funding of utility-scale solar projects. The Obama administration funded five such projects, but the falling prices of solar technology made additional federal support unnecessary, he said.

Croley acknowledged that Trump has substantial discretion over how aggressively to enforce existing environmental rules but said that states or environmental groups will likely sue if they believe Trump’s EPA is ignoring major violations.

“[Non-governmental organizations], states [and] state regulators are all important drivers of national policy too. They will fill what is perceived to be a regulatory gap or regulatory inaction to some extent,” he said. “Every White House will create its antibodies. Believe me, that’s how it works.”

Indeed, Kit Kennedy, director of the energy and transportation program for the Natural Resources Defense Council, said her organization has increased its litigation team, which has filed 10 lawsuits against Trump’s efforts to roll back environmental policies. She said the organization is also increasingly looking to state and local governments for leadership.

She was more alarmed than Croley, saying “what the president says and does really matters.”

“We’re seeing an onslaught on bedrock environmental safeguards and laws from President Trump today that we’ve never seen before,” she said. “The situation is fundamentally different” from the Reagan and Bush administrations.

Kennedy engaged in a more vigorous debate with James Taylor, an adviser to the presidential campaign of Energy Secretary Rick Perry and president of the Spark of Freedom Foundation, which promotes natural gas, hydro and nuclear power as “affordable” and “environmentally friendly” sources.

“Renewable is not synonymous with green,” Taylor said, citing the environmental impact of mining for rare earth minerals used in solar panels — which he said is worse than uranium mining.

“Wind turbines kill 1.5 million birds and bats each and every year in this country, including many endangered and protected species. It also requires hundreds of square miles of wind turbines to replace a single conventional power plant. For conservationists, that should trouble us.”

He said federal policy should be based on “full spectrum” environmental impact analyses “that [go] beyond the renewable and non-renewable definition and looks beyond carbon dioxide emissions.”

Problems with New Demand Curve

IPPNY Chair John Reese, senior vice president of Eastern Generation, celebrated the completion of NYISO’s demand curve reset but criticized FERC’s decision to not include the costs of environmental controls for the proxy upstate unit.

“It takes about two years to go through that process and lots of pain and suffering and gnashing of teeth. I think IPPNY did a great job in representing the needs of generators and what it takes to get market investment,” he said.

But he said FERC erred in its January order, which rejected requests by IPPNY and the ISO to assume selective catalytic reduction (SCR) emissions controls for the proxy unit for zones C and F.

In its prior reset, NYISO proposed that the New York Control Area peaking plant operate under an annual operating hours limit in lieu of installing SCR. FERC said that assumption still holds, despite the ISO’s contention that peakers without the controls risk not obtaining necessary air permits. FERC rejected as “speculative” IPPNY’s contention that the state’s Siting Board is likely to require tougher controls in the future. (See FERC OKs NYISO Demand Curve Reset.)

“If you’ve done business in New York — if you have developed projects — to imagine that you could build a fossil generator in upstate New York without State of New York controls is just foolishness,” Reese said. “It just cannot be done.”

IPPNY filed a rehearing request on the issue in February (ER17-386).

May 16, 2017

PJM Differs with Monitor in State of the Market Response

By Rory D. Sweeney

While PJM and its Independent Market Monitor agree that its markets “work” and are competitive, they disagree on what might make them better.

Those differences were highlighted last week when the Monitor released its first quarterly State of the Market report of the year, followed by the RTO’s response to the Monitor’s 2016 report.

The quarterly update revised just two of the Monitor’s existing recommendations for Incremental Auctions. It added a proposal that PJM should hold only one IA annually, three months prior to the start of the delivery year.

It also recommended that the RTO release cleared capacity at those auctions “only in cases where the combination of quantities released and associated prices would increase the welfare of capacity market resource owners and load” with consideration for both capacity and energy market benefits.

In response to the Monitor’s original recommendations, PJM agreed “that the structure and format of Incremental Auctions should be reviewed” and pointed to the recently created Incremental Auction Senior Task Force to address those concerns.

But the RTO disagreed with many of the Monitor’s other recommendations, including how to handle demand response resources and uplift. PJM said the EPSA v. FERC Supreme Court case ruled that DR should receive full LMP payments and — despite the Monitor’s recommendation that “any generation component of their retail rate” be subtracted from DR payments — doesn’t plan to challenge the ruling.

PJM state of the market report — | *PJM*

On uplift, PJM said many of the Monitor’s recommendations were considered by the Energy Market Uplift Senior Task Force, which debated the issue for several years before coming to a consensus on a three-phase plan that was endorsed by members — despite ongoing controversy — during April’s Markets and Reliability Committee meeting. PJM is waiting to submit the plan for FERC approval until the commission has a quorum. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)

The largest rift between the Monitor and PJM seems to be whether to allow inflexible units to set LMPs. The Monitor opposes the idea, but PJM argued that “allowing inflexible units to set [LMP] would create an outcome in which [LMP] increases more consistently as load increases.”

PJM believes that — along with the addition of a load-following product — allowing inflexible resources to set LMP would reduce uplift, increase system flexibility and promote enhanced gas-electric coordination.

The changes would also benefit what appears to be PJM’s goal of increasing its energy market prices. In its response, the RTO raised concerns about steadily declining prices thanks to cheap, efficient gas units, increasing renewables and stagnant demand growth partially attributable to energy-efficiency improvements.

Recent low prices, combined with hesitancy to invest in the market and public-policy actions in order to address socioeconomic concerns, “test market price formation and long-term viability,” PJM said.

The effects of units not properly incentivized to follow PJM’s dispatch signals, along with an increasing role for the capacity market in resource entry/exit decisions, “accumulate over the longer term to create unintended bias toward low capital-cost resources with high operating costs,” it said.

Low prices have created a recent rush to subsidize unprofitable generation, such as through the creation of zero-emission credits in New York and Illinois. PJM and the Monitor agree that’s ill-advised.

“Although some state subsidies may intend to address the financial problems that some generators face due to declining energy prices, paradoxically, the subsidies actually may make the problem worse because they further depress market prices, causing needs for more subsidies,” PJM said. “As the 2016 State of the Market Report indicates, however, subsidies are contagious and could spread. If subsidies do become more widespread, they could deter new entry while the suppressed price could artificially raise demand, causing supply shortages in the long term.”

Instead, PJM suggests pricing carbon at the state level if necessary, or implementing its “capacity market repricing” proposal that would allow subsidized resources to be counted toward PJM’s installed reserve margin without impacting the capacity clearing price.

While PJM and the Monitor remain at odds on the role of inflexible units in the market, the RTO is working toward some of the Monitor’s recommendations. The RTO will bring a problem statement to the Market Implementation Committee or the MRC to create comparable flexibility of the operating parameters in the cost-based offer and price-based parameter limited schedule (PLS) with the non-PLS price-based offer. It will also address the Monitor’s recommendation that market participants have at least one cost schedule with the same fuel type and parameters as that of their offered price schedule.

May 16, 2017

Stakeholder Soapbox: Organized Markets for the Future

By Rob Gramlich

As soon as new commissioners are seated at FERC, they will have fundamental and controversial market design questions to resolve.

mandatory capacity obligations FERC technical conference — Gramlich

Some of those questions will be decided in states in terms of the benefits of those policies to those states, and some will be decided by courts in terms of their legality. For their part, the new commissioners will need to choose sides in the never-ending supplier vs. customer debate on capacity obligations and markets.

Or will they?

The Great Divide

The FERC technical conference on potential conflicts between state policy and RTOs/ISOs on May 1 and 2 revealed the same splits as in 2013 and previous commission reviews of capacity markets. Suppliers believe prices should be higher to attract and retain needed resources, while wholesale customers believe capacity markets fail to serve their needs. The main outcome of the 2013 review, which was to improve price formation, has helped a little, and more can still be done there to reflect scarcity in prices.

Carbon pricing was endorsed by many participants as the best economic policy solution for current market challenges, but that doesn’t seem to be a silver bullet either, as putting it in FERC-jurisdictional tariffs was not widely embraced by states. Searching for a third way, ISO-NE and PJM introduced proposals to raise capacity market prices. But explicitly discriminating between supply sources in terms of eligibility and pricing based on someone’s determination of what is “subsidized” and by how much seems hardly like a way to reduce litigation. The higher capacity prices will also lead to further unneeded entry on top of today’s generation surplus that customers will not be happy about paying for.

So this customer-supplier divide remains. And PJM’s recent Capacity Performance changes, now in litigation, created more capacity market enemies by preventing renewable energy resources from selling their capacity value. No wonder there was so much frustration at the conference.

What if we re-evaluate the fundamental objectives of capacity obligations? Do some of the debates become moot?

Mandatory Capacity Obligations No Longer Necessary?

When FERC reluctantly accepted mandatory capacity obligations on load-serving entities in the early 2000s, it was for three reasons that may no longer exist: 1) “resources take years to develop,” 2) “spot prices that are subject to mitigation measures may not produce an adequate level of … investment” and 3) “regional resources are made available to all regional load-serving entities” with no ability to curtail those customers who failed to procure enough.^[1]

Point 1 is no longer true, with demand response and batteries now able to enter markets and provide peak energy within six months. Point 2 can be fixed with scarcity pricing and raising offer caps. Point 3 may not be true any longer either, with improvements in metering, control and scarcity pricing. So maybe capacity markets are only fighting the last battle and failing to solve future challenges.

Resource Adequacy Responsibility in the Future

The commission appropriately wants to make sure someone is responsible for generation meeting load at all times. As with any market in any sector, primary responsibility should be put on customers to procure the supply they need. Wholesale customers today have a range of preferences in terms of resource types, fuel price risk management and environmental attributes.

Some LSEs will be guided or required by states in their resource planning. Either way, their resource choices should be respected and supported to do most of the resource planning work. They have newfound abilities to cover themselves now that batteries can be deployed in six months with exactly as much as is needed, along with DR, in contrast to the past when they had to plan three or more years ahead for lumpy generation assets.

Reliability when Scarcity Conditions Arise

When it comes down to real time, and scarcity exists, RTOs and FERC still need to make sure the system can be balanced. Scarcity conditions may occur at very different times of day and year than in the past, as we are seeing in California and other markets, given different load and supply stack shapes. Reliability during these scarcity conditions can be satisfied if either a) pricing prevents LSEs from demanding more power than is available, or b) the system operator can physically curtail loads that caused the shortage.

We should allow for the possibility that efficient real-time energy markets with today’s pricing and control systems will do the job. RTOs could define short-term products purely according to system requirements and allow all sources to compete on a level playing field. Technology neutrality would help attract batteries, different demand sources and other new technologies to enter to serve system needs. ERCOT is closest to this market vision at this point, though it isn’t fully there.

Completing the Transition

With primary reliance on bilateral contracting for resource adequacy and RTOs focused on their core mission of bid-based security-constrained economic dispatch in real time as a backstop, we can take the competition training wheels off and support a bright, clean, efficient and reliable future power system. We can accommodate rather than work against state policies. We can pull back on RTO mission creep and thereby encourage greater participation in the efficient regional energy markets that are needed for clean energy development in the non-RTO parts of the country. Let’s see if we’re ready to move past the old debates and design the RTO markets of the future.

Rob Gramlich, founder of Grid Strategies LLC, was Economic Advisor to FERC Chairman Pat Wood III in 2001-2005 and Senior Economist in the PJM Market Monitoring Unit covering capacity markets in 1999. Most recently, he was Senior VP for Government and Public Affairs for the American Wind Energy Association.

^[1]SMD NOPR, July 2002, par.461, citing Power System Economics by Steven Stoft.

May 16, 2017

Hydro, Solar Boost CAISO Summer Outlook; Aliso Concerns Remain

By Robert Mullin

CAISO should have sufficient generation to meet peak demand this summer, although questions still linger about the adequacy of Southern California natural gas supplies in the face of a heat wave.

The ISO’s 2017 Summer Loads and Resources Assessment, which describes the grid operator’s preparedness for California’s season of peak electricity usage, paints a generally promising picture. Under “normal” summer conditions, operating reserve margins will average 19.5%, compared with the 15% required by the Public Utilities Commission.

hydropower aliso canyon natural gas — The continued closure of the Aliso Canyon natural gas storage facility remains an issue for the summer readiness of the Southern California grid.

About 52,785 MW of capacity is expected to be on hand to meet this summer’s predicted peak load of 46,877 MW, which would be 0.6% more than the weather normalized peak for 2016.

“The slight overall demand increase is a result of projected modest economic and demographic growth over 2016, tempered by utility projections of new behind-the-meter solar installations over the past year,” the report said.

Summer peak demand could spike to 48,845 MW under conditions that occur only once every 10 years, CAISO said.

The ISO expects 3,090 MW of new generation will have entered commercial operation during the 12 months leading up to this June, 2,566 MW of which is in the southern part of the system — service territories controlled by Southern California Edison and San Diego Gas and Electric.

Nearly three-quarters of the new resources consist of solar (74%), followed by natural gas (23%), storage batteries (3%) and a fraction of a percent each for hydro and biofuel.

California’s hydro conditions have “vastly improved” over last year, the ISO noted. On April 28, statewide snow water content stood at 158% of normal for April 1, typically the peak date for Sierra Nevada snowpack. The state is also experiencing a near record year for precipitation.

“This abundance of rain has nearly all reservoirs near capacity and needing to spill water to make room for spring snow runoff,” CAISO said.

But uncertainty still looms over the outlook for Southern California, where gas-fired generators confront a second summer of fuel supply restrictions stemming from the closure of the Aliso Canyon storage facility. (See Aliso Canyon Gas Restrictions Cloud Summer Outlook.)

The ISO pointed out that its analysis is a “system level” assessment and does not account for gas curtailment risks associated with emergency restrictions on the pipeline system operated by Southern California Gas, owner of the facility north of Los Angeles.

“There are limitations in attempting to shift power supply from resources affected by Aliso Canyon to resources that are not affected because of certain factors such as local generation requirements, transmission constraints and other resource availability issues,” CAISO said in its report.

A joint agency report to be released later this month will address the ongoing risks to the grid posed by continued prohibition on gas injections into Aliso Canyon. The report’s authors include CAISO, the PUC, the California Energy Commission and the Los Angeles Department of Water and Power.

Mild conditions and a series of temporary ISO market measures helped the region’s grid to weather last summer without any major incidents related to constrained gas supplies. FERC last December approved an ISO proposal to extend those measures through November 2017. (See FERC OKs One-Year Extension for CAISO’s Aliso Canyon Gas Rules.)

The ISO last winter also said it would adopt a recently approved West-wide reliability measure to help ensure that it has sufficient capability to transmit power into Southern California via the Path 26 transmission line when needed. The new measure approved by Peak Reliability — the West’s reliability coordinator — allows a system operator to selectively relax a transmission network’s seasonal performance standards in response to “credible multiple contingences” under emergency conditions. (See CAISO to Rely on New Emergency Measure to East Path 26 Transfers.)

May 16, 2017

SPP Members Again Struggle with Solutions to Z2 Credits

By Tom Kleckner

SPP stakeholders’ effort to simplify the RTO’s complicated crediting system for transmission upgrades continues to spin its wheels.

Members once again discussed alternatives to SPP’s cumbersome Z2 process during an all-day meeting in Kansas City on Wednesday, but they adjourned without reaching any major decisions. (See SPP Z2 Panel Sees ILTCRs as Cure to ‘Mess of Complexity’.)

SPP z2 credits — Buffington | © *RTO Insider*

“It feels like we’re going over the same material every time,” said the group’s chair, Kansas City Power & Light’s Denise Buffington. “At some point, we have to get to where we can make a decision. We have to pull the trigger eventually, and it’s clear to me we’re not ready.”

The group did agree to schedule two additional meetings next month to improve its chances of presenting a recommendation in July to the Strategic Planning and Markets and Operations Policy committees.

The task force rehashed the pros and cons of two of the alternatives they have settled on: staff recommendations to replace Z2 credits with incremental long-term congestion rights (ILTCRs) or credit payment obligations (CPOs) under a Tariff schedule. Westar Energy’s Grant Wilkerson has proposed a third alternative, in which only upgrades that create transfer capability would receive credits under the Tariff.

Under Attachment Z2 of SPP’s Tariff, members are assigned financial credits and obligations for sponsored upgrades. The task force is trying to simplify the process while still meeting FERC requirements.

Several stakeholders raised concerns over using ILTCRs to replace Z2 credits, arguing that SPP’s transmission congestion rights (TCR) market is not yet fully functioning. Charles Cates, the RTO’s manager of transmission services, disputed that perception, saying the market is “working very well.”

“Seventy-eight percent of the load entities are fully hedged,” Cates said. “It’s a perception I do not agree with.”

“That’s not a perception OGE shares,” said Oklahoma Gas and Electric’s Greg McAuley, expressing a different viewpoint. “If you dilute a TCR market that’s not fully functional because you’ve never really used an ILTCR yet … I don’t know why you would do that intentionally.

“Z2 is functioning. Some people may not like it, but it’s doing the job it was designed to do. From OGE’s perspective, we’re getting credits for the upgrades that have been put in palace, and we’re also paying for upgrades that have been in place. We have a system that’s in place and working.”

“I’m hearing that we’re trading one set of problems for another set of problems,” NextEra Energy Resources’ Aundrea Williams said. “I want to make sure we don’t lose sight of the ultimate goal of simplification and transparency. I don’t want us to completely discount [that] Z2 can be improved, but the objective doesn’t have to be to get rid of it.”

Cates, who has been tasked with developing the ILTCR alternative, warned against changes to SPP’s market design, saying adding an auction revenue right mechanism connected to financial rights is a disconnect from the original purpose of the design.

“The unintended consequences of going this route could be profound — or not. It’s hard to say at this point,” he said to laughter. “If we’re not careful, the complaints I hear about the TCR market not working — which I personally don’t agree with — could get more loud.”

The moments of levity, while lightening the mood, did not diminish the difficulty of the task before the group.

“The problem I have now is every time I think I understand it, I don’t,” McAuley said. “I don’t have a problem going back to MOPC and saying this is a complicated animal. I don’t want to approve one of these [alternatives] and have a bigger mess on our hands because we didn’t understand it.”

May 16, 2017

MISO Resource Adequacy Subcommittee Briefs

CARMEL, Ind. — Capacity prices last month cleared at just $1.50/MW-day across MISO because of increased supply and low demand, John Harmon, MISO senior manager of capacity market administration, said during a post-mortem of the RTO’s April capacity auction. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.)

Coal accounted for most of the auction’s 135 GW of cleared capacity at 53,332 MW, followed by natural gas (48,784 MW) and nuclear (12,885 MW).

A key factor in depressing demand and prices: the overall rise in self-scheduled offers and fixed resource adequacy plans (FRAPs), which increased by more than 10% in zones 4 and 8.

Speaking at a May 10 meeting of the Resource Adequacy Subcommittee, Harmon said changes in offering behavior flattened the offer curve compared with last year’s auction, which saw prices clear at $2.99/MW-day in MISO South, $19.72/MW-day in Zone 1 and $72/MW-day in zones 2, 3, 4, 5, 6 and 7.

Indianapolis Power and Light’s Ted Leffler pointed out that many offers in this year’s auction came in at less than a dollar, with some entered at just a penny.

“There were no instances of mitigation for physical or economic withholding,” Harmon confirmed.

American Electric Power’s Kent Feliks wondered if MISO had to contact any resources in order to enforce a new rule that imposes a 50-MW physical withholding ceiling on affiliated market participants collectively, rather than on each affiliated company individually. The new rule won tentative FERC approval mid-March with forewarning that the rule may not be just or reasonable. (See FERC Staff OKs MISO Mitigation Changes; Refunds Possible.)

“There were a few phone calls, largely from late offers,” Harmon said, noting that some resources bid into the auction near the end of the three-day offer window.

“MISO acting as a conduit to affiliates makes us a little uneasy,” Feliks replied.

Some stakeholders have argued that FERC Order 697 already prohibits affiliates from colluding to dodge withholding mitigation and MISO and its Independent Market Monitor’s new rule is unjustified. (See MISO Plans Additional Capacity Auction Revamps for 2017.)

RASC Chair Chris Plante expressed surprise that stakeholders didn’t have more to say about the auction results, given the low clearing prices.

Stakeholders Won’t Debate Single Year of MISO-SPP Settlement

Stakeholders voted overwhelmingly to end debate about whether costs for MISO’s transmission use settlement with SPP should be allocated by capacity benefit to holders of transmission service requests above the 1,000-MW contract path linking MISO Midwest to MISO South.

Laura Rauch, MISO manager of resource adequacy coordination, said the RTO agreed that the allocation amounts in question were too small to warrant more presentations and feedback cycles.

The RTO had previously asked stakeholders about holding discussions about how to allocate costs for the 300 MW in requests for 2018/19 that exceed the current limit on the North-South interface. Staff warned that the cost split may be negligible, and the matter was put to a stakeholder vote last month via a motion prepared by the Load-Serving Entity Coalition. (See “Single Year of SPP-MISO Settlement Allocation on Ballot,” MISO Resource Adequacy Subcommittee Briefs.)

MISO to Keep Current OMS Survey Format

MISO will stick with using the existing format for its annual resource adequacy survey with the Organization of MISO States, while examining next year’s project estimate approach in light of a new interconnection queue process, RTO staff said.

Rauch said that while stakeholders had not reached consensus on how to display survey results, most believe the RTO should do more to emphasize a fuller range of capacity possibilities. Staff were considering a “floating” results format, but it failed to garner stakeholder favor. (See “MISO Still Tweaking OMS-MISO Survey Format,” MISO Resource Adequacy Subcommittee Briefs.)

MISO is still uncertain about how survey results will be affected by the roll-out of FERC-approved improvements to the interconnection queue, which could increase capacity counts through a quicker turnaround of project approvals. Rauch said it will continue to look into revising its project estimates in future surveys.

This year, MISO and OMS will count 35% of projects in the definitive planning phase of the queue toward future available capacity, in addition to the typical counting of all generation projects with signed interconnection agreements. The new approach was announced after multiple stakeholders voiced displeasure at what they saw as overly conservative results. (See OMS-MISO Survey Moves Ahead with New Calculation.)

Attorney Jim Dauphinais, speaking on behalf of Illinois Industrial Energy Consumers, said trade press and policymakers tend to take zonal capacity projections at their word and ignore the import capability of neighboring zones, which can solve capacity shortfalls.

“Those are negative amounts, and there is some concern with that, but import capability can solve that, and somehow that needs to come through so that policymakers aren’t left with the impression that this is a big problem,” Dauphinais said. “I think sometimes the press and policymakers miss” import capability. He also suggested that MISO post results by state rather than by local resource zones.

Ted Kuhn of Customized Energy Solutions said that even the scaling of the shortfalls versus surpluses on the findings graph is off, with shortfalls drawn visibly larger than their identical surplus counterparts in 2016 results. Rauch examined the graph and agreed that shortfalls were exaggerated in illustrations.

MISO and OMS will present results of the survey mid-June.

MISO to Study Effects of Extended Outages

MISO is still considering whether to bar resources on extended outages from participating in Planning Resource Auctions — or to make changes to capture the risk of such outages in its loss-of-load expectation (LOLE) analyses.

Harmon said the RTO will review its current LOLE study against actual recent outages and present results to stakeholders by mid-July.

MISO’s Tariff does not currently prohibit auction participation for resources on outages for 90 days up to the entire planning year. Staff last month asked stakeholders to suggest maximum outage lengths that would disqualify a resource from PRA participation. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)