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May 17, 2018

MISO Proposal Aims to Speed Up Queue Process

By Amanda Durish Cook

CARMEL, Ind. — MISO is proposing near-term changes designed to speed up its interconnection queue as it confronts its largest-ever influx of potential generation projects.

The RTO plans to reduce the number of project studies occurring in the first phase of the definitive planning phase (DPP) of the queue and require customers to demonstrate ownership, lease interest or land rights on a project’s site before entering the queue, stakeholders learned during a May 15 Interconnection Process Task Force (IPTF) meeting.

MISO Site Control Interconnection Queue — | *MISO*

MISO Director of Interconnection Planning Vikram Godbole said the proposal constituted “a small set of changes that will be very beneficial to the queue” and that the RTO began working on improvements to the queue last year after FERC accepted its redesign proposal. He said MISO and several customers have been meeting for months to discuss ways to expedite the RTO’s packed pipeline of potential projects.

Godbole said the changes are designed not to harm any existing interconnection customers. They come a month after FERC declined to order MISO to redesign aspects of its relatively new queue process but reminded the RTO of its duty to make a good faith effort to address a worsening backlog of projects. (See FERC Sides with MISO in Queue Design Dispute.)

100% Site Control

MISO is proposing to require interconnection customers to demonstrate 100% site control to the point of interconnection before entering the queue, scrapping the existing option that allows them to submit a $100,000 deposit in lieu of proof of site control. Just 25% of the projects entering the DPP in the April 2018 cycle demonstrated site control, with the rest electing to make the deposit.

The RTO currently requires a customer to demonstrate 75% of site control prior to entering the third — and final — phase of the DPP.

Godbole said the more stringent requirement should prevent unready projects from prematurely entering the first phase of the DPP. It would also prevent customers from submitting multiple, overlapping projects at the same development site, a recurring issue in the current queue, although Godbole declined to identify any specific instances.

“That is just not right, and we need to fix that,” Godbole said.

MISO’s interconnection queue currently contains 554 projects totaling 92.5 GW, including 239 additions last month representing 40.7 GW.

“With 93 GW, everyone needs to have a very realistic expectation of when these projects are going to be able to connect,” Godbole said. “Some of these projects are not going to get built, but how many is anyone’s guess. So MISO … needs to find ways to expedite the process.”

After looking into other RTOs’ practices, MISO found that ERCOT, ISO-NE, NYISO, PJM and SPP require 100% of site control either at entry or before the start of the system impact study, Godbole said.

“We said OK, if interconnection customers in other RTOs are OK with that, they should be OK with that in” MISO’s, he said. “We’ve looked at this from all angles.”

Some stakeholders said that state regulatory requirements can sometimes prevent customers from acquiring site control so early in the process. Godbole responded that in those cases customers would have to provide evidence that regulators are obstructing site control.

Godbole proposed a phased-in approach to requiring site control, with projects already in the queue but not yet studied required to secure 100% of site control requirements by the first decision point in the first phase of the DPP. All other projects would be required to demonstrate an increasing percentage of site control based on their progress.

Studies Reduction

To further accelerate the queue process, MISO is also proposing to eliminate its transient-stability, short-circuit and affected-system studies from the first phase of the DPP.

Removing the early, more uncertain iterations of those studies will result in quicker turnaround times for the first phase of DPP analysis, Godbole said.

In response to the concerns of some stakeholders that affected-system and transient-stability analyses were necessary earlier in the queue to determine the viability of a project, Godbole said that customers could hire an external consultant to conduct first versions of the analyses and pointed out that all three studies will still occur in the DPP’s second and third phases.

Godbole noted that MISO is currently holding monthly meetings with SPP and PJM to improve the affected-system study process, but he added that by removing the first affected-system study, MISO planners will have more time to devote to the more significant second and third studies.

“It’s not SPP, PJM or MISO’s fault. What’s happening is we have entities with three cycles that are just bombarding our affected systems with analyses,” Godbole said. “There are so many studies happening at the same time. If we keep requesting studies, we’re never going to finish. It’s going to be really tough to get those projects interconnected.”

Removing affected-system studies from the first phase of the DPP will reduce the potential for overlap among studies and eliminate at least 10 early affected-system studies in the next 12 months.

MISO said its West region — covering Iowa, Minnesota, part of Wisconsin and the Dakotas — has experienced one to two months of delays alone from conducting phase 1 affected-system studies.

“Look at the West region. It’s almost 200 projects alone,” Godbole said.

miso interconnection queue site control — | *MISO*

He asked stakeholders to submit feedback about the proposals by May 30, before MISO moves the recommendations to the June 13 Planning Advisory Committee meeting for an additional month of discussion. RTO staff hope to file Tariff changes with FERC by July or August.

While MISO is not seeking consensus to move forward, it will consider comments that could improve the proposal, Godbole said.

“Believe me, my phone does not stop ringing with customers concerned that they won’t get [production tax credits] in time. Something has got to give. And these are the … things that we think can have the most impact in a short amount of time. But it’s doesn’t stop here. We’re going to keep working [on the queue],” he said.

He added that future queue changes may entail moving milestone payments to a cash-only system, removing the option for customers provide a letter of credit. While MISO is not ready to propose the change, Godbole said the multimillion dollar companies that enter the queue should have no trouble providing milestone fees in cash. Some stakeholders said that although the monetary risk was the same, it’s more difficult going through the process of getting cash.

EDF Renewable Energy, which had petitioned FERC to order MISO to redesign the three-stage queue, said it supported the changes and expected them to help reduce delays, but the company thinks more needs to be done, including increasing milestone payments to deter speculative projects.

2 Projects, 1 POI

The IPTF is also collecting stakeholder feedback on a possible plan to loosen MISO’s one project/one point of interconnection policy in order to allow two projects with separate owners to connect at the same point of interconnection.

MISO manager Arash Ghodsian said the RTO would only move ahead with proposing the change if it doesn’t threaten reliability or present new delays in the interconnection queue.

Ghodsian said MISO has recently experienced an uptick in interest from customers wishing to connect multiple projects at a single point of interconnection.

Northern Indiana Public Service Co.’s Brett Furuness said he would appreciate future discussion on the topic because NIPSCO fields multiple interconnection requests at a single substation.

May 17, 2018

PJM Board Elects New Chair, Welcomes New Member

NATIONAL HARBOR, Md. — The PJM Board of Managers on Wednesday elected Ake Almgren as chairman and new member Neil H. Smith, the former CEO of generation developer InterGen.

Re-elected to three-year terms were John McNeely Foster, who joined the board in 2003, and Sarah Rogers, who began in 2012.

Almgren, a Ph.D. engineer, succeeds former Chairman Howard Schneider, who retired after 21 years on the board. Smith will fill the vacancy created by Schneider’s retirement. (See Retiring PJM Chair Schneider Reflects on 21 Years at the Helm.)

Ake Almgren Neil Smith PJM Board — Schneider | *PJM*

“Howard Schneider has led the PJM board by example, with a focus on integrity and the highest ethical standards,” PJM CEO Andy Ott said in a statement. “He has served on the board during a time of tremendous growth for PJM and unprecedented change in the industry.”

Almgren, who joined the board in 2003, is the former president of ABB Power T&D, former CEO of Capstone Turbine Corp. and a former member of the Department of Energy’s Electricity Advisory Council. He is the owner of Orkas Inc., which provides consulting in electric transmission and distribution, distributed resources, renewable energy and hybrid electric vehicles.

Smith retired as InterGen’s CEO in 2016 after 25 years with the company. He also is a former board member for The Wood Group, which provides project, engineering and technical services to energy and industrial clients.

Foster, a certified public accountant, is a former member of the Financial Accounting Standards Board and former vice president, treasurer and principal accounting officer of Compaq.

Rogers, an electrical engineer, served as CEO of the Florida Reliability Coordinating Council from 2007 until 2012. Between 1984 and 2007, she worked in a variety of positions at Progress Energy and its predecessors, including vice president of transmission.

— Rich Heidorn Jr.

May 17, 2018

FERC: MISO External Capacity Zone Plan Deficient

By Amanda Durish Cook

MISO’s plan to create external resource zones in its annual capacity auction isn’t detailed enough on several fronts, FERC told the RTO on Wednesday.

Commission staff issued MISO a deficiency notice explaining the proposal lacks sufficient detail about the reliability concerns that spurred it, the concept of border external resources, and how pseudo-tied resources and coordinating members’ resources will factor into the proposal (ER18-1173).

MISO FERC External Resource Zones — MISO Resource Adequacy Subcommittee in 2017 | © *RTO Insider*

MISO filed the plan in late March after three years of stakeholder meetings in its Resource Adequacy Subcommittee. It would create external resource zones by 2019 for MISO’s annual capacity auction, based on existing neighboring balancing authority area boundaries. External zones would not have capacity import limits, planning reserve margin requirements or local clearing requirements.

Resources in BAAs that border either MISO Midwest or South would clear at two different prices based on subregional unconstrained auction clearing prices, while those in BAAs that border both MISO areas — including Tennessee Valley Authority, SPP, Associated Electric Cooperative Inc. and Southwestern Power Administration — would receive a blended price.

In cases of auction price separation, the RTO would distribute historical supply arrangement credits from excess auction revenues as a refund to external resources with long-term and consistently used historical supply agreements. The proposal would also establish new zonal capacity export limits in time for the 2019/20 planning year auction. (See MISO Closing in on External Capacity Zones.)

In its deficiency letter, FERC asked MISO, among other questions:

Why it thinks that its current practice of giving external resources capacity credit in the local resource zone where its firm transmission service crosses into the footprint has the potential to cause reliability concerns;
How it will reconcile its current Tariff definition of local clearing requirement — defined as the minimum amount of unforced capacity physically located with a local zone — with its proposal to allow certain external resources to contribute to a local resource zone’s local clearing requirement;
If it will count pseudo-tied resources as external resources;
How it differentiates a “border external resource” — defined in the proposal as resources with direct electrical connections to the RTO but located in another BAA — from all other external resources;
How border external resources and coordinating owner external resources can be used to alleviate transmission constraints and address other reliability concerns for local resource zones;
How it plans to model external resources and how coordinating owner and border external resources will impact capacity import and export limits;
What physical and operational standards a coordinating owner external resource must meet to qualify for capacity credit in a local resource zone. FERC also asked MISO to identify any other coordinating members besides Manitoba Hydro, its sole listed coordinating owner;
If its proposed historical supply arrangement credits will be distributed to resources offered into the Planning Resource Auction, resources included in a fixed resource adequacy plan or both; and
How much estimated capacity would qualify for historical supply arrangement credits. FERC also asked MISO to describe scenarios in which the credits might not be fully funded.

FERC also ordered MISO to list all resources that would receive border external resource designation, their unforced capacity values and the local resource zones they border. The RTO previously said it identified about 3.8 GW of capacity from potential border external resources.

Finally, the commission said MISO must compare in writing the operational control it has over Manitoba Hydro’s resources versus other external resources, including Exelon’s Byron Generating Station, Duke Energy Indiana’s Madison Generating Station, WPPI Energy’s Nelson Energy Center and any resources with firm transmission service over a direct current line, such as the Grain Belt Express Clean Line.

May 17, 2018

FERC Pushes NERC Further on GMD Rules

By Rich Heidorn Jr.

FERC took another step Thursday in its efforts to protect the grid from geomagnetic disturbance events (GMDs), proposing to approve a revised reliability standard but directing NERC to also require mitigation of vulnerabilities to localized events (RM18-8).

The commission’s Notice of Proposed Rulemaking would approve reliability standard TPL-007-2 (Transmission System Planned Performance During Geomagnetic Disturbances), which revises the definition of GMDs, requires grid operators to collect certain data and imposes deadlines for corrective actions, as the commission directed in Order 830 in 2016. (See FERC Approves GMD Reliability Standard.)

GMDs occur when the sun ejects charged particles that cause changes in the earth’s magnetic fields, potentially causing geomagnetically induced currents that can cause voltage instability or collapse and damage connected equipment.

The rule would require planning coordinators and transmission planners to conduct supplemental GMD vulnerability and thermal impact assessments that go beyond NERC’s original “benchmark” GMD event definition that is based on spatially averaged data.

NERC defined the “supplemental” GMD event using individual station measurements rather than spatially averaged measurements, acknowledging that geomagnetic fields during severe GMD events can be “spatially non‐uniform” with localized peaks that could affect reliability.

The supplemental GMD event is defined by a “reference peak geoelectric field amplitude” of 12 V/km versus the 8 V/km used in the original spatially averaged definition. Both are intended to reflect a one-in-100-year occurrence and use scaling factors to account for local geomagnetic latitudes and earth conductivity. They also employ a “locally enhanced reference geomagnetic field time series or waveform” to analyze the impact of the GMD on equipment.

Mitigation Directive

NERC’s standard requires mitigation of vulnerabilities to the benchmark event, setting a one-year deadline for the completion of corrective action plans and two- and four-year deadlines to complete mitigation actions involving non-hardware and hardware mitigation, respectively.

But NERC rebuffed FERC’s call for mitigation of risks from supplemental events. NERC’s proposed standard would only require applicable entities to make “an evaluation of possible actions designed to reduce the likelihood or mitigate the consequences and adverse impacts of the event(s)” if a supplemental GMD event is assessed to result in cascading outages.

NERC told FERC that its standard drafting team determined that requiring corrective action plans in response to supplemental GMD event vulnerabilities was premature because the supplemental definition is based on small number of observed events “that provide only general insight into the geographic size of localized events during severe solar storms.” NERC also said current tools are inadequate to realistically model localized events.

But the commission said NERC’s position ignored its directives in 2013’s Order 779, which were reiterated in Order 830.

“NERC’s proposal to modify the benchmark, but then allow applicable entities the discretion to take corrective action based solely on the results of the spatially averaged benchmark analysis while taking under advisement (‘an evaluation of possible actions’) the results of the supplemental assessment, does not satisfy the clear intent of the commission’s directive. …

“We are not persuaded by NERC’s reasoning that … existing technical limitations, specifically the limited number of observations used to define the supplemental GMD event and the availability of modeling tools to assist entities in assessing vulnerabilities, make requiring mitigation premature at this time.”

Deadline Extensions

NERC also diverted from Order 830’s directive that it consider extensions of the corrective action deadlines on a case-by-case basis.

Instead, NERC would allow entities to unilaterally revise their corrective action plan if events beyond its control — such as delays from regulatory and stakeholder processes, equipment lead times or inability to acquire rights of way — prevent implementation within the original timetable.

“Given the complexities and potential novelty of steps applicable entities may take to mitigate the risks of GMDs, we agree with NERC that there should be a mechanism for allowing extensions of corrective action plan implementation deadlines,” FERC said. “However, we would like to avoid unnecessary delay in implementing protection against GMD threats.”

The NOPR seeks comment on whether the standard should permit these “self-declared extensions” or be revised to require NERC’s case-by-case approval. “Under either option, the commission proposes to direct NERC to submit a report regarding how often and why applicable entities are exceeding corrective action plan deadlines,” FERC said.

May 16, 2018

Retiring PJM Chair Schneider Reflects on 21 Years at the Helm

By Rory D. Sweeney

National Harbor, Md. — If, in the coming years, Howard Schneider feels an inexplicable urge to be at the Chase Center in Wilmington, Del., on Thursdays late in the month, he can be forgiven. PJM’s monthly Markets and Reliability/Members committee meetings have been part of his life for the past 21 years.

Schneider on Tuesday morning at this year’s PJM annual meeting | © *RTO Insider*

The first and only nonexecutive chairman of PJM’s Board of Managers retires Wednesday, having reached the limit on terms an individual can serve on the board. It’s a day for which he has had years to prepare, and yet he’s resigned to the fact that he may never be fully ready to let go. (See related story, PJM Board Elects New Chair, Welcomes New Member.)

“[It] is going to be a melancholy day,” Schneider said during an interview Tuesday at PJM’s annual meeting at the Gaylord National Resort & Convention Center on the Potomac River outside D.C. He was only half joking.

And why not? Schneider has been on the board since its inception in 1997 when, PJM — formed as a power pool run by Philadelphia Electric Co. and others in 1927 — completed its transition to an independent organization and became the nation’s first fully functioning independent system operator. He became the board’s first nonexecutive chairman in 2007.

Schneider was there as PJM became the nation’s first fully functioning RTO in 2002 and worked through many market changes since then. He has overseen two transitions of the executive team, from Phil Harris to Terry Boston in 2007 and from Boston to Andy Ott, PJM’s current president and CEO, in 2015.

Howard Schneider PJM Board of Managers — PJM Board Chairman Howard Schneider and CEO Andy Ott listen to consumer and public advocates at last year’s PJM annual meeting. | © *RTO Insider*

“Phil was an innovator, very talented, a futuristic thinker,” Schneider said. “Terry was a practical guy who implemented well and had terrific relationships with outside constituencies. I think Andy is a thinker, an innovator also, and I think he tries to find solutions and implement them. I’ve been very, very pleased with Andy’s CEO status. The board was looking for somebody who could carry the PJM flag, and I think Andy does it exceptionally well.”

The More Things Change…

Prior to joining the board, Schneider knew little about the power industry, though he was highly experienced in Wall Street’s exchanges for commodities, securities, futures and other markets. He was the general counsel for the Commodity Futures Trading Commission from 1975 to 1977. That understanding of “pure” markets has informed his appreciation for the challenges of PJM’s administrative markets.

“We were just starting to put LMP into effect. … Capacity markets came on right around that time. It was all sort of new. I don’t really know what it was like before, but you can envision the utilities in effect having vertical dominance over the markets and operating in their own little spheres,” Schneider said. “It’s incredible because [RTO markets], they’re make-believe markets. Every time something goes wrong, there’s another bell that [gets added] on, another whistle that goes on. … There’s always a revision to an artificial market. … as something develops in a marketplace, they make the change that’s necessary to cure that particular thing, which then leads to another change, which leads to another change. So, they’re always evolving markets; they’re never rigid.”

The concept has been evolving since PJM opened its first bid-based energy market in 1997, and Schneider doesn’t expect that to change.

“When you have a [Market Monitor] and a senior staff as innovative as they are, I think you’re going to see change,” he said. “Frankly, I’d like — the stakeholders would like — to see less change so that it stabilizes. … But it’s just the way the world it is. It just changes.”

But some of the foundational pieces, like the capacity market, are likely to remain constant, Schneider insists.

“The sine qua non of PJM has been the capacity market,” he said. “It’s hard to think about … PJM without a capacity market, and it’s served a very useful purpose.”

Expansion

Schneider remains particularly proud of PJM’s expansion during his tenure, both geographically — in reaching out to Commonwealth Edison’s territory in Chicago — and structurally in the size and variety of its markets. The desire for growth has meant challenges, though.

“There was a time when we were talking about merging New England ISO, NYISO and PJM, and that turned out to be a terribly divisive issue,” Schneider said. “I advocated for it because I thought it would solidify the same concept of expansion out to the west, to the north. … It divided the board a little bit at the time, and I don’t think our friends in New York or New England particularly copped to it, so it was something I think I regret in retrospect.”

Still, Schneider believes that PJM has room to grow.

“The only place you can go is basically to the south, and that’s always a possibility, but it’s nothing that PJM is actively seeking, nor should it. If the opportunity presents itself, it’s certainly a discussion item,” he said.

On market efficiency, he argued they’ve become “almost too successful, in that the prices are so low that resources are finding it hard to make sufficient money to be effective.”

Schneider said he is strongly opposed to anything that might suffocate the market, such as Energy Secretary Rick Perry’s efforts to subsidize coal and nuclear generators.

“I personally believe that this whole business with the Department of Energy and the threat that that creates for markets is an existential threat to PJM itself, it’s very existence, because if you foul up these markets — which is what I think the DOE proposal would do — then you’ve in effect taken away what is PJM’s great strength and characteristic, which is its ability to have functioning markets that have performed so well,” Schneider said. “It’s been an unbridled success, and I don’t want to see that go away.”

He said PJM’s current analysis into the grid’s resilience should determine which way to go.

“I think you have to look at resilience in a very holistic way, and you have to look at it some years down the road,” Schneider said. “Reliability is not a problem. Whether the fuel system is secure five years out, 10 years out, is a question that I think needs to be examined … and we’ll see where that leads. It may lead to something that says, ‘Things are fine; leave it alone’ — although you have a government that’s trying to push in a different direction — or one that says maybe we need to tweak this or tweak that and give a value to some resiliency characteristic that we hadn’t given a value to before.”

The resilience challenge differs from the Capacity Performance changes implemented after the 2014 polar vortex, Schneider argued.

“The point of CP was really to have a system in which outages were very limited to a real inability to perform because of something that was more like an act of god than just because it hadn’t been dealt with in a significant way. … It incentivized generator performance,” Schneider said. “Now you’re in another world of resilience that takes on different characteristics and may lead to something like a significant Capacity Performance-type fix, or it may not.”

He found it hard to identify the most difficult issue PJM faced during his tenure.

“Each problem that you tackle has a problem to it. When we put in Capacity Performance, for example, everybody was complaining, ‘You’re going too fast.’ And, on the other hand, if you didn’t go fast you’d miss the next year, and the thought of generators [having a] 20% outage [rate] or anything like the polar vortex was just [very bad] so we had to move,” Schneider said. “You’re not going to satisfy every constituency. Sometimes the way you know you’ve done something right, is everybody’s mad at you.”

Polar Vortex

Schneider insists he never worried the lights would go out during the 2014 scare.

“We came close to having to pull back and blackout, so it wasn’t fun. Everybody was worried about that, but we pulled through,” he said of the incident. “I’m never nervous. I have tremendous faith in the management team at PJM. I always have from the very first inception, and you could see they were very talented people who thought things through and came to reasoned conclusions, which I think is all you can ask of people.”

Board Stuff

Schneider hedged when asked whether his time on the board matched what he had envisioned, saying it worked out “a little of both” — unexpected and how he had planned. He said he spoke with Ott weekly to determine if anything needed to be reported to the board. “Over 21 years, as you can imagine, there are have been plenty of issues du jour,” he said.

He transitioned quickly to praise his colleagues on the board.

“I think it’s been a very responsible and responsive board, and I think that has contributed to PJM’s success in a great measure. We’ve been fortunate. There are diverse people who come on that board, and I can’t say there’s been a clunker among them. That’s a very pleasant thing,” Schneider said. “We were going to be a true corporate board. We weren’t going to be a stakeholder board or any of the other variants that are around in the ISO community. To me, that principle of being a true corporate board was essential to the success of PJM.”

Schneider emphasized PJM’s “very good relationships with most of the ISOs” and the board’s “deep sense of fiduciary responsibility” to states, the Market Monitor, stakeholders and consumers.

Even with very diverse backgrounds, board members come to consensus, he said. “It is a very, very rare time that we come away with a divided board,” he said.

Future Plans

Going forward, Schneider said he’ll only attend the monthly MRC meetings as a hired consultant advocating for a client. He has been a senior consultant at Charles River Associates since 2010 but “studiously avoided the energy field” because of potential conflicts of interest. Now that those conflicts no longer exist, he’s ready to step into the energy field.

“I loved it,” he said of his run. “It’s been a great experience with some really extraordinary people. I’ve been very pleased by it. … I sure as hell enjoyed it. It’s been great fun.”

May 16, 2018

NYISO Floats Carbon Pricing Straw Proposal

By Michael Kuser

NYISO is floating a proposal that would incorporate the cost of carbon into the ISO’s wholesale market by debiting each energy supplier a uniform carbon emissions charge as part of its settlement, eschewing an alternative approach that would levy region-specific charges for imports.

Social Cost of Carbon Carbon Pricing NYISO — DeSocio | © *RTO Insider*

“The process we envision is very similar to how we handle invoicing today, where load-serving entities (LSEs) are debited the locational-based marginal price (LBMP), and now the LBMP will have a carbon price effect,” Michael DeSocio, the ISO’s senior manager for market design, told New York’s Integrating Public Policy Task Force (IPPTF) Monday.

The May 14 discussions were part of issue “Track 1” in the group’s five-track effort to price carbon emissions, which required development of the straw pro p osal.

The ISO’s proposal relies on a “status quo” carbon pricing approach (referred to as Option 1) that would not consider the specific carbon content in energy trades from out of state. A second option under consideration would’ve evaluated marginal emissions rates from out-of-state imports.

Both options appeared in a Brattle Group presentat i on to the task force last month, with Brattle favoring Option 2’s more aggressive approach to external transactions. But DeSocio said choosing the second option of “color-coding megawatts” outside New York would be too complicated. (See NY Carbon Task Force Discusse s Seams, ‘Leakage’.)

DeSocio said the ISO is not aware of all supply positions outside the New York Control Area and whether there are offtake positions from one external generator to some external load. That means the energy from a source external to NYISO could be coming from a coal plant in Michigan, for example.

“I don’t have the tools to guarantee that what I’m getting is getting the right attributes assigned to it,” he said.

Rather than try to develop all those tools, which would cost time and money, the ISO is attempting to keep market participants on an even playing field to avoid making a trade into or out of New York harder, or create a bigger barrier to entry, DeSocio said.

Imports will add the charge to their offers, in effect competing with internal resources on a “status quo basis” with the same relative costs as if no carbon charges applied to anyone. Exports are similar but with a credit.

“We think Option 1 does a nice job of keeping the carbon price self-contained and easy to manage,” said DeSocio. “We think it’s a reasonable approach that offers a lot of the same benefits without a lot of the complexity.”

Allocating Residuals

The straw proposal foresees LSEs being debited the LBMPs, “but then the LSEs would be credited all of the collections that we refer to as the carbon charge residuals from the suppliers that are emitting,” said DeSocio. “So, there’s a debit, and a credit, but at the end of the day on the invoice there’s only one charge, and that is the net of the two. That’s the concept.”

In allocating carbon charge residuals, the ISO chose to levelize the net impact so that customers across the state would end up paying the same rate, consistent with carbon affecting everyone and also with how other decarbonization policies are applied to rates, he said.

“There is an externality to the wholesale competitive market,” said DeSocio. “That externality has to do with environmental attributes, including the cost of carbon. There’s money being spent outside of the competitive market to try to deal with decarbonization. So, the goal of the carbon price would be to incorporate that externality to the maximum extent possible into the competitive market as directly as possible.”

Howard Fromer, director of market policy for PSEG Power New York, said that with the increasing number and scale of state solicitations for clean energy, offshore wind and energy storage, state agencies and regulators should make their contract language capable of accommodating a possible carbon charge.

“The numbers are mounting quickly, so if you don’t do something soon to avoid double-dipping, you’ll run into problems,” Fromer said.

Social Cost of Carbon

The straw proposal says the New York Public Service Commission (PSC) would set the gross social cost of carbon (SCC) in dollars per ton of CO₂ emissions “pursuant to the appropriate regulatory process.” (See NY Looks at Social Cos t of Carbon, Modeling.)

Representing a coalition of large industrial, commercial and institutional energy customers called the Multiple Intervenors, Couch White attorney Michael Mager said, “If carbon pricing were to be implemented under the straw proposal, one of Multiple Intervenors’ concerns would be how the social cost of carbon (SCC) gets set and updated.”

Mager said his clients could not accept the SCC being subject “to update and modification at any time by the PSC in its discretion.”

“It’s one thing if there’s something that’s set by schedule or set by certain parameters, like the annual demand curve update where it’s a formula, everyone knows it, it’s set in advance, and it gets changed in a non-controversial manner,” Mager said.

“This is a little bit of public policy and a little bit of wholesale market, which is territory that we haven’t dealt with too often,” said DeSocio.

DeSocio suggested the ISO’s public policy transmission process could offer guidance on how to proceed.

“It will be helpful to have more of an understanding of what any process would look like for setting [SCC], especially if we were to consider moving forward with including the cost of carbon in the wholesale market,” said DeSocio.

David Clarke, director of wholesale market policy for Power Supply Long Island, asked what would happen if FER C or the federal government decides a lower cost of carbon is appropriate and asserts authority over the rate used under the Tariff.

“We’re kicking around a sixty some-odd dollar per ton number, but what if FERC comes back and says the number’s twenty bucks, or FERC comes back and says the number is three dollars?” said Clarke.

“Certainly, if FERC [were] to develop some policy regarding how to value the cost of carbon in a wholesale market, we would need to take a step back and think about that,” DeSocio said. “At the moment, we’re unaware of any such policy.”

He added that in using a state-supported SCC, the ISO wants to make sure its “incorporation is stable and provides robust market signals” for investment decisions.

The task force had its own charter on the agenda Monday but deferred serious discussion of it until the stage of discussing next steps — around July 9, when the path forward should be clearer. The overall study results are scheduled to be presented in September.

The task force next meets May 21 at NYISO headquarters to address issue “Track 5” assumptions and scenarios on customer impacts, including wholesale customers.

May 15, 2018

SPP’s Tariff Team Begins Carving up the Elephant

By Tom Kleckner

KANSAS CITY, Mo. — As chairman of SPP’s Holistic Integrated Tariff Team (HITT), Tom Kent has been asked to lead a team responsible for addressing “the many issues challenging” the region.

spp hitt cost allocation — HITT Chair Tom Kent | © *RTO Insider*

Simple things, like cost allocation and transmission zones, Z2 credits, the planning and study process, and what to do with 60 GW of wind in the planning queue — issues that have vexed staff and members for the past several years.

“There are some pretty meaty topics,” admitted Kent, Nebraska Public Power District’s COO.

The 17-person team includes state regulators, SPP directors and key member representatives, all of whom also have day jobs. So how do you keep everyone on track?

“We have to come together on how we want to eat the elephant, so to speak, right?” Kent said before the team’s April kickoff. “It’s a pretty big topic, and you’ve got to take it one bite at a time. We’re going to spend a lot of our time kind of understanding what the elephant is, and what the scope is, and how big the elephant is. Hopefully, we’ll get to the point where we’re able to start prioritizing which bites we want to take off and go after.”

Fortunately, Kent has plenty of experience in meeting management and team dynamics.

“It’s nothing new. It’s a broader group with different perspectives, but the dynamics of leading a team or a group are very similar,” he said. “You’ve got to get everyone to start working together and understand how we’re going to function as a group. Keep the group focused on the priorities that we’re working on — and there are going to be lots of things to work on.

“It’s just typical team dynamics, right?”

HITT Squad

The “HITT squad,” as it is called informally, encountered some early turbulence when several stakeholders complained about the secrecy under which it was created in March. SPP’s Board of Directors approved the team’s formation during a closed-door meeting. (See SPP Questioned on Secrecy over Tariff Team.)

SPP proposed that most HITT meetings be held face to face, with stakeholders “encourage[d]” to participate by dialing in, unless they are presenting to the team in person. Early discussion about the group suggested that only team members would be allowed to participate in meetings, but other stakeholders are now invited to provide information and ask questions.

The SPP HITT meets for the first time. | © *RTO Insider*

“I wouldn’t use the word ‘secret.’ It’s just new,” Kent said. “You’ve got to give everyone an understanding of how the group’s going to work, what the scope’s going to be, what the priorities are going to be. You can’t take the elephant all at once. I expect for a while, at least, the meetings will be focused on the team.”

The early focus has been on education and technical presentations. The HITT’s first meeting was spread out over two days following the April board meeting, with staff delivering detailed presentations on SPP transmission, planning and cost allocation, and markets and operations.

The team began drawing up a list of hot topics and requested feedback from stakeholders on the issues, topics and/or challenges they believe it should be addressing.

Afterward, Kent shared with the HITT a study on the market value of variable renewables and additional background materials.

“I thought we covered a lot of good information,” Kent said.

The team next meets in Dallas on May 16. On the agenda: developing a problem statement, reviewing requested information, and more technical presentations and education.

The HITT has been tasked with filing a written report by April 2019, but it can request additional time, if needed. It will report to the board’s Members Committee and provide status reports to the Regional State Committee, Markets and Operations Policy Committee and Strategic Planning Committee.

The team includes Directors Larry Altenbaumer and Graham Edwards, state commissioners Shari Feist Albrecht (Kansas Corporation Commission) and Dennis Grennan (Nebraska Power Review Board), and member representatives for the investor-owned utilities, cooperatives, independent power producers, municipalities, state agencies and independent transmission companies.

Cindy Ireland, the Arkansas Public Service Commission’s director of research and policy, has joined the team as a liaison for the Cost Allocation Working Group (CAWG). The RSC had requested a liaison, as much of the HITT’s work will touch on that of the CAWG’s.

“We don’t want to retrace ground other groups are working on,” Kent said. “That coordination and working together is going to be important for the CAWG, and it’s also going to be important for other groups, potentially.”

Taking on the Animal

The HITT has been asked to assess:

Transmission planning and study processes: generation interconnections; the interconnection queue; aggregate studies; energy resource interconnection service and network resource interconnection service; capacity requirements, including more attributes than energy; and related FERC planning requirements.
Transmission cost allocation issues: highway/byway; directly assigned costs; Attachment Z2 credits; cost allocation impacts on transmission pricing zones with large wind resources; and state-by-state supply resource mix requirements and/or goals.
Integrated Marketplace: effects related to a changing resource mix; access to lower cost generation; potential changes in production tax credits; using market-based compensation for varying attributes of different types of generators.
Disconnects or potential synergies between transmission planning and real-time reliability and economic operations.
Additional areas and/or issues as appropriate and reasonably related to its scope of work.

The team has been modeled after the Synergistic Planning Project Team (SPPT), which was formed in 2008 to suggest a process addressing deficiencies in SPP’s then-existing planning processes. In just a matter of months, it filed a report that led to the RTO’s Integrated Transmission Planning process and the highway/byway cost allocation methodology.

SPP is hopeful the HITT will be just as successful.

General Counsel Paul Suskie, who represented the Arkansas PSC on the SPPT and is the staff secretary to the HITT, said the SPPT’s work led to FERC Order 1000.

“Three of the five commissioners told me that SPP’s approach to planning is what the nation needed,” Suskie said.

Suskie also recalled conversations he had with fellow team member Barry Smitherman, then chair of Texas’ Public Utility Commission. Texas was in the midst of its Competitive Renewable Energy Zone project, which used state money to finance nearly $7 billion in transmission infrastructure to connect West Texas wind energy with cities to the east. Customers would eventually pick up the tab through CREZ fees on their bills.

The two would tease each other over the best methods to fund transmission buildouts.

“I’d always call [regional funding] socialization,” Suskie said. “Barry would tell me, ‘In ERCOT and Texas, they call it uplift.’”

Suskie is just one of three holdovers from the eight-person SPPT, which also included Dogwood Energy’s Rob Janssen, the HITT’s vice chair, and SPP COO Carl Monroe.

“That experience and that background, having gone through the process before, will be invaluable,” Kent said. “I’m excited about being able to sit down with them and take on this animal, and talk about some different issues and look for opportunities to improve things going forward.”

May 15, 2018

Overheard at EBA Annual Meeting

WASHINGTON — FERC Chairman Kevin McIntyre, the luncheon speaker on the second day of the Energy Bar Association annual meeting last week, said he’s often asked about his priorities as head of the commission. “I love this [question] because it suggests I get to pick,” he said to laughter.

ferc eba energy bar association kevin mcintyre — McIntyre | © *RTO Insider*

“We get to select some of the topics we work on but … I arrived in December and at that time, there was a faint ticking sound … on the 11th floor of the FERC — something awaiting prompt attention,” he continued. The ticking sound was the Dec. 11 deadline for responding to Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to provide price supports for coal and nuclear generation.

“And I thought, in the [tradition of the] Hippocratic Oath: First do no harm. So, my first official and brave act as FERC chairman on Dec. 7 was to humbly request more time,” McIntyre said. “I’m happy to say that such time was granted and that we beat our extended deadline by a couple of days. And we managed a five-to-nothing order taking action on the Notice of Proposed Rulemaking that was proffered to us by the secretary, deciding as a commission that we could not adopt it in the form it was presented to us.” The commission instead opened a new docket on resilience — a proceeding that prompted more than 100 comments last week. (See related story, Don’t Rush on Resilience, Commenters Urge.)

McIntyre also discussed the commission’s challenges in determining whether state subsidies for generators based on their fuel source is unduly discriminatory. “Isn’t that an unfair market advantage? These are valid questions, not crazy questions. And we have before us the work of trying to figure out answers to them, and every bit as difficult as that, trying to figure out how to implement sensible policy steps based on those answers. This plays out in a number of different ways, and I wish I had all the answers. … As lawyers we like challenges … and boy is this one. It’s a real toughie.”

With Antitrust Risks Rising, ‘Boring is Good’

Former FERC General Counsel Max Minzner said the “defensive regimes” that have shielded energy companies from antitrust liability — the state action doctrine, federal pre-emption and filed rate doctrine — are being eroded.

One source of the erosion is litigation, he said, referencing the Supreme Court’s 2015 ONEOK decision, which found that federal pre-emption under the Natural Gas Act does not prevent state antitrust suits over pipelines’ price manipulation.

Minzner, now a partner with Jenner & Block, also cited technology that can overcome natural monopolies and regulatory changes such as the development of federally regulated gas and power markets. “And finally, one of the areas that I find most fascinating, is erosion from legislative change. The rise of the market manipulation authority within the Energy Policy Act of 2005 has an overlay on the filed rate doctrine.”

Minzner was the moderator of a panel on antitrust trends, where panelist R. Scott Mahoney, general counsel and chief compliance officer for Avangrid, sparked a discussion on the risks of making intemperate statements in emails, text messages and internal presentations that can be obtained in discovery.

Mahoney said he urges Avangrid employees “to think about doing that in a … more precise way so that you don’t create the one email that then gets waved around” as evidence of anticompetitive behavior.

Richard M. Lorenzo, chair of Loeb & Loeb’s antitrust practice, recalled the damage done to Microsoft’s antitrust defense in 1999 after testimony that company Vice President Paul Maritz had threatened to cut off rival Netscape’s “air supply.”

He cited a 1982 phone call from American Airlines President Bob Crandall to Braniff Airways President Howard Putnam — which Putnam recorded — in which Crandall said, “Raise your goddamn fares 20%. I’ll raise mine the next morning.”

“So, what you write in memos matters. [We’re] trying to emphasize to employees at all levels of the company — especially at the management level — to tone it down. Write factually as opposed to emotionally with lots and lots of adjectives. It’s very important because this stuff comes back to bite you when there is discovery.”

“People want to make a splash. People want to be remembered, and so therefore they’re always pushing the envelope with respect to PowerPoints and other ideas [using] colorful language,” added Michael O’Connor, chief legal executive for law and human resources for the Salt River Project. “And once you have one of these cases and you put it in that light and it’s thrown up in a federal district court or all over the papers, people remember that.

“And they realize that boring is good.”

— Rich Heidorn Jr.

May 15, 2018

Former FERC Chairs Reminisce, Sound Off at EBA

By Rich Heidorn Jr.

WASHINGTON — The Energy Bar Association closed its annual meeting last week with a panel discussion with five former FERC chairs whose terms collectively spanned two decades. The former chairs offered entertaining anecdotes about the past while expressing pride over the growth of competitive markets — and frustration over forces they said threaten them.

eba energy bar association ferc order 2000 — Hoecker | © *RTO Insider*

James Hoecker (1997-2001) jokingly referred to his tenure as the “Cretaceous period of FERC regulation,” a time when he said there was less state-federal conflict but also no FERC authority to impose meaningful penalties on market manipulators. He started at FERC as a staff attorney in 1979 and left for a time before returning in 1993 as a commissioner. He cited Order 637, which revised gas pipeline rules to encourage competition, and Order 2000, which set the requirements for RTOs, among the biggest accomplishments of his tenure.

“FERC had not gotten to be so visible in the media because of its work in energy infrastructure as it’s become recently,” said Hoecker, now counsel to the trade group WIRES. “I guess I’m thankful for that.”

Pat Wood III (2001-2005) expressed regrets over not returning a phone call to Southern Co. CEO H. Allen Franklin in 2002 after announcing Standard Market Design, “which was going to solve all the problems that happened in California” during the 2000-2001 Western energy crisis.

“Maybe I’m overselling my persuasive skills and it was never meant to be, but [I wish] I could have talked them out of being so intransigent against Standard Market Design,” said Wood, now chairman of Dynegy.

He also wished he had been “more willing to accept imperfections” in the RTO applications filed by Southern and other companies in the Southeast and West.

“Accepting that could have avoided what I call the carnage that’s happened [in the Southeast] with noncompetitive generation. … But I was pretty rigid on making sure they met the criteria of Order 2000 and neither of those [regions] had” sufficient independence.

Joseph T. Kelliher (2005-2009) said his pre-commission career as a congressional aide helped him in negotiations to eliminate “hostile” anti-FERC provisions from the Energy Policy Act of 2005 shortly after becoming chair. The law gave the commission the authority to issue enhanced penalties for market manipulation and mandatory reliability rules, and deputize NERC as the Electric Reliability Organization.

“At the time, I had a lot of doubts about NERC’s capacity to discharge their responsibilities under the act,” said Kelliher, now NextEra Energy’s executive vice president for federal regulatory affairs. “And I thought it was necessary for FERC to adopt a larger role until NERC expanded its capacity, almost like a big brother throws his arm around his little brother until he gets some more muscle. … I think NERC is a much more capable institution than it was in 2005.”

Jon Wellinghoff (2009-2013) said his background as Nevada’s first consumer advocate informed his chairmanship, during which he “tried to ensure that the markets were open and fair” for technologies such as renewables and demand response.

Wellinghoff expressed special pride in Order 745, which required that RTOs pay DR resources LMPs, and Order 755, which required RTOs to compensate fast-regulation resources for speed and accuracy. He also cited Order 719, requiring RTOs to treat DR offers like generation, and Order 764, which aided the integration of variable energy resources.

“I think they’re all important to ensuring that all resources can efficiently and effectively compete in these markets. And then … in Order 1000, the transmission planning order, we tried to ensure that there was some level of competition in the planning and selection of transmission.”

Wellinghoff, who has continued to advocate for distributed energy resources as CEO of consulting firm GridPolicy, added he is “very encouraged” by actions the current commission has taken to open markets to energy storage and DERs.

“You’re seeing the distributed resource technologies just explode. You’re seeing the enabling technologies underneath them — which are really the communication and control technologies — get less and less expensive … and more available to consumers. My son is truly a computer geek. … He was cataloging our house the other day: We have 52 addressable devices in the house.”

Wellinghoff said he’d like to see more done to open competition in transmission. Without competition, he said, the industry is “going to stamp down innovation. There are many innovative technologies coming into the transmission space … that are substitutes for transmission that need to have the opportunity to compete … against the incumbents.”

Norman Bay (2015-2017) talked of the obligation he felt to live up to the legacy of his predecessors. “As I listened to their comments today, I’m struck by … the nonpartisan nature of the work that we’ve been doing. The ability of Republicans and Democrats alike to come together to get things done to further the public interest,” said Bay, now head of Willkie Farr & Gallagher’s energy regulatory and enforcement group in D.C. “I would bet that if anyone were to listen to the comments of anyone on this stage and didn’t know what political party they belonged to, they would have no idea if that person was a Republican or a Democrat. And how great is that?”

‘Crony Capitalism’

Wood and Bay debated the impact of zero-emission credits — enacted in Illinois and New York and under consideration in New Jersey — to subsidize nuclear generation.

“Are they a good idea? No. They’re crony capitalism by just a new name,” Wood said. “I do think that FERC has got to take … an informational role to let these state legislatures know … what damage these kinds of things do the operation of the competitive markets that we worked for a quarter century to set up. That’s exactly what they are. The resilience thing looks like a continuation of the same crony game,” referring to calls for subsidies for coal and nuclear plants with onsite fuel. “I just think it’s poisonous to markets.”

Bay, however, said ZECs are states’ response to the markets’ failure to price carbon emissions. “I think everyone on this panel would agree that the first best solution if you care about carbon emissions is to put a price on carbon and then harness the power of markets. That clearly has not happened.

“The second-best solution — and I would say second by a long ways — is to provide financial incentives to resources that do not produce the negative externality. And that’s essentially what states are trying to do. Running the market now without taking into account the negative externality results in an inefficient market outcome.”

“And that would be fine, I think, if all zero-emitting resources now and in the future could qualify for that,” Wood responded. “As opposed to the New York case, which is very egregious, that named plants [eligible for ZECs] and one [Indian Point] was excluded.”

Future of Capacity Markets

Wood and Wellinghoff responded to a question about the future of capacity markets.

“As one who comes from the energy-only market of Texas, it works,” said Wood, acknowledging that the market will be stressed this summer because of the reduction in ERCOT’s reserve margin. “It will be a real big test. So, ask me this question at the end of September.” (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

Wellinghoff said he has grown increasingly skeptical of capacity markets.

“Don’t tell him this, but Bill Hogan may be right,” said Wellinghoff, referring to the Harvard University professor, a prominent proponent of energy-only markets. “Ultimately, I think capacity markets are very difficult to design correctly and functionally. I’m currently working in Alberta. The ISO and the government there have committed to put a capacity market in with a balancing energy-only market. I’m working with a client there trying to help them to help the ISO come up with a design that will work for everybody. And we’re close to pulling our hair out!”

Confessions

At the end of the session, moderator and FERC Administrative Law Judge Lawrence Brenner elicited confessions from some of the panelists over “impulsive” actions they took as chair.

Bay recalled being up until 2 a.m. the night before the FERC Christmas party because he insisted on hand squeezing the 20 pounds of limes needed to make proper margaritas. “You can probably divide the world into two camps: the people who believe that a margarita can be made from a mix, and the people who realize, no, you really need to use fresh squeezed lime juice,” he said.

Kelliher recalled when vineyards near California’s Russian River petitioned him to authorize the release of water from hydro projects during a drought.

“Of course my first thought was, ‘I really like Russian River red wine.’ But my question to the staff was, ‘What legal authority do I have to do that?’ And the response was, ‘Highly questionable’ — FERC-staff speak for nonexistent.

“And I thought about it for about 10 seconds and I said, ‘Release the water!’” he said to laughter. “It felt very Christ-like. I knew it was the closest I would get to being holy. … I wasn’t turning water into wine but authorizing water. … And I thought if I go down [get overturned], I’ll get a Wine Spectator cover or something.”

May 15, 2018

SPP Average Winter Prices up 4.6% from 2017

By Tom Kleckner

SPP’s winter real-time prices increased 4.6% from the previous year, according to the Market Monitoring Unit’s latest quarterly State of the Market report.

The report said real-time prices averaged $25.69/MWh, compared with $24.57 the previous winter, when prices jumped 37.9%. Day-ahead prices this winter averaged $24.07/MWh, 7 cents shy of the 2017 average.

SPP Winter Real-Time Prices State of the Market Report — SPP’s Low Winter Prices | *SPP MMU*

The MMU reviewed the report, which covered December 2017 to February 2018, with market participants during a webinar Friday.

Also last week, the MMU released its annual State of the Market report, saying SPP’s market showed increasing flexibility and improving efficiency during 2017. The MMU had shared a draft with the RTO’s Board of Directors in April. (See “MMU Shares Draft of State of the Market Report,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)

The quarterly report noted average gas and electricity prices — which have historically been highly correlated — diverged slightly this year, with gas dropping from $3.08/MMBtu in 2017 to $2.64/MMBtu in 2018. Panhandle Eastern hub prices ranged from $2.50 to $2.80/MMBtu from February 2017 until January, when they spiked to $3.23/MMBtu during a cold snap.

SPP set three new winter peaks Jan. 16-17, topping out at nearly 43 GW. Oil-fired units set prices during the period that “routinely exceeded” $400/MWh in western Arkansas, eastern Texas and southern Missouri.

SPP and MISO were forced to use market-to-market redispatch Jan. 16-18, resulting in SPP collecting $2.66 million during that time. The Neosho-Riverton flowgate was responsible for most of the costs, as it has been since the two RTOs began the M2M process in March 2015. Congestion on the flowgate has resulted in $26.5 million in payments to SPP, more than half of the $51.4 million M2M charges MISO has incurred.

The MMU said the flowgate also caused Empire District Electric and the Missouri cities of Carthage and Springfield to see the highest winter prices in SPP’s footprint, with Carthage seeing average real-time prices of slightly more than $50/MWh.

Other highlights from the report include:

An increase in the occurrence of negative price intervals, with winter 2018 levels higher than previous years.
A nearly 7% increase in the hourly average load for winter 2018 from winter 2017. December 2017 was at a similar level to the prior year, but January and February 2018 average loads were nearly 11% higher, driven primarily by lower-than-normal temperatures.
A 7% increase in average monthly real-time generation from winter 2017 to winter 2018. Coal-fired generation its downward trend, accounting for only 46% of energy produced during the winter. Wind resources accounted for 26% of total generation.
A 36% day-ahead wind capacity factor, which increased to 46% in the real-time market. The disparity between day-ahead and real-time capacity factors contributed to the increase in negative price intervals.