Page 1324 – RTO Insider

April 24, 2017

MISO Planners Looking at 3 La. Projects, Overlay ‘Skeleton’

By Amanda Durish Cook

CARMEL, Ind. — MISO transmission planners last week outlined three possible congestion-busting projects in Louisiana and a “skeleton” of potential projects from a long-term overlay study.

The overlay study, which used the MISO Transmission Expansion Plan 2017 futures, is designed to identify long-term transmission needs under a shifting resource mix, including possible paths for a line to link MISO South and MISO Midwest.

MISO overlay study MTEP 18 futures — | *MISO*

Preliminary results using an existing fleet projection show several 345-kV line additions in MISO Midwest, a handful of 500-KV lines in — and one leading into — MISO South, and a couple of new 230-kV lines in the Dakotas. (See MISO Begins 3-Year Tx Overlay Study.)

The policy regulations future shows a few of the 230- and 500-kV lines in the existing fleet future swapped for 345-kV ratings. The accelerated alternative technologies future depicts a large network of 765-kV lines in Central, including two 765-kV paths connecting South, and a direct current line across North Dakota and Minnesota in addition to the proliferation of 345-kV lines in Midwest and 500-kV lines in South.

MISO cautioned that “no conclusion has been reached on whether or how many projects may ultimately be recommended by the 2019 targeted completion date.”

Some stakeholders asked why MISO created preliminary overlays using MTEP 17 at all, when MTEP 18 futures consensus is close. Lynn Hecker, manager of expansion planning, said the RTO will begin examining MTEP 18’s distributed and emerging technology and see if the fourth future’s assumptions suggest the need for additional projects.

Louisiana Projects

Meanwhile, the RTO’s MTEP 17 Market Congestion Planning has produced three possible projects in MISO South: one market efficiency project and two economic projects.

All three project candidates are near the West of the Atchafalaya Basin (WOTAB) load pocket in southwest Louisiana and MISO’s control area in eastern Texas. No other areas in the RTO’s South met the RTO’s criteria for a possible project; the annual congestion planning study focused exclusively on South this year.

The projects are:

A new $122.7 million, 500-kV line from Hartburg to Sabine in southeastern Texas with a 500-kV substation and new 500/230-kV transformer at Sabine. The lone market efficiency project candidate has a 1.28 benefit-to-cost ratio;
A $2.8 million uprate of the Sam Rayburn-Fort Creek-Turkey Creek-Doucett 138-kV line in southeastern Texas with a 7.45 B/C ratio; and
A half-million-dollar upgrade of terminal equipment at southwestern Louisiana’s Carlyss substation that would increase the current 230/138-kV autotransformer capacity to 300 MVA at a 15.97 B/C ratio.

Arash Ghodsian, MISO manager of economic studies, said project candidates should be finalized by July.

Footprint Diversity Study

On the other hand, the RTO’s footprint diversity study, specifically designed to identify transmission for transfers between MISO Midwest and MISO South, will spend extra time in the suggestion-gathering step.

Ghodsian said 26 of the 32 stakeholder-submitted ideas involved connecting South and Midwest through coordination with neighboring regions.

He said MISO is seeking more projects that it can implement alone, asking stakeholders to focus only on suggestions that would connect one substation to another.

“Maybe let’s take it a notch higher and look for more technical discussion,” Ghodsian said.

MTEP 18 Futures

MISO said the four MTEP 18 futures generally received stakeholder support.

The RTO revealed proposed futures in early April, introducing a distributed and emerging technology 15-year future that captures more localized siting and storage. (See MISO Introduces Distributed Energy Future for 2018 Tx Planning.)

MISO has not studied anything like this future before. It envisions new renewables largely serving their local resource zones while rising storage capability — hitting 2 GW by 2032 — is placed near buses and two-thirds of all solar additions are distributed energy resources. The RTO usually assumes one-third of all new solar additions are distributed for planning purposes.

Policy studies engineer Matt Ellis admitted that the RTO isn’t modeling all combinations of possibilities and said nine stakeholders submitted about 13 suggested futures themselves, but he added that MISO’s proposed four futures “capture the highest and lowest bookends” and said stakeholders have indicated support.

“We do agree with stakeholders that we’re not studying all combinations, but we want this to be feasible. How many can we actually study and do the in-depth sensitivities on?” he said at the April 19 Planning Advisory Committee meeting.

Stakeholders also asked if MISO would change any of its nuclear assumptions given the recent bankruptcy filing by Westinghouse Electric, which has threatened the completion of new nuclear plants in Georgia and South Carolina. All MTEP 18 futures assume zero nuclear retirements.

“All [existing nuclear plants] have licenses through the study period. So that’s where we landed at, but we’re open to revising that,” Ellis said.

MISO will hold a more in-depth conversation at the July PAC meeting, he said.

April 24, 2017

NYPSC Order Seeks to Refine, Standardize DR Programs

By Michael Kuser

The New York Public Service Commission voted Thursday to maintain current incentive payment rates for utilities’ dynamic load management (DLM) programs through 2017 while ordering the companies to standardize their enrollment processes and approving other changes that the commission said would “ease DLM program enrollment and participation.”

incentive payment rates NYPSC — | *NYISO*

Approved in 2014, New York’s DLM initiatives include:

A peak load-shaving commercial system relief program (CSRP), which is called 21 hours in advance of a need for load relief, as determined by day-ahead load forecasts;
A distribution load relief program (DLRP) to support local reliability, called two hours in advance during contingencies and system emergencies; and
A direct load control (DLC) program, which allows utilities to cycle residential and small commercial customers’ air conditioning and other controllable loads.

In their December 2016 annual reports on the programs, Central Hudson Gas & Electric, Niagara Mohawk Power and Orange and Rockland Utilities proposed changes. New York State Electric and Gas and Rochester Gas and Electric did not seek changes.

Before calling a vote on the order, which was included in the consent agenda, Interim Commission Chair Gregg Sayres asked for any comments. Only one other commissioner remains on the PSC following the March resignation of Chairman Audrey Zibelman and the retirement of Commissioner Patricia Acampora: Commissioner Diane Burman, who spoke up.

She said she voted no on some aspects of the demand response cases last year out of “a concern that the commission take a more holistic approach.”

However, Burman said there was a need to act now to set the DR rules for the summer 2017 capability period, which runs from May 1 through Sept. 30. “There needs to be regulatory certainty,” she said. “If we delayed action here it could mean changes being made mid-period or not at all.”

Incentive Changes Deferred to 2018

While maintaining the current incentive payments for 2017, the commission said it will consider changes for 2018 based on the results of marginal cost of service (MCOS) studies and the Value of Distributed Energy Resources proceeding initiated in March. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)

“Avoided [transmission and distribution] infrastructure costs constitute the majority of the benefits applicable to DLM programs,” the commission said. “DLM program incentive payment rates are directly influenced by the [benefit-cost analysis] relying on those benefits, and the MCOS studies used by the utilities to determine the per-kilowatt cost of avoided T&D for use in the BCA. Therefore, the MCOS studies are critical to determining if the DLM programs are being administered in a cost-effective manner, and if changes to such program incentive payment rates are justified.”

The commission said the MCOS studies are being reviewed and may be changed as part of the Value of DER proceeding.

Central Hudson

In addition to rejecting Central Hudson’s request to significantly lower CSRP incentive rates, the commission also rejected its proposal to eliminate its DLC program, which the company said has no participants (15-E-0186).

As it had in 2016, the commission also rebuffed Central Hudson’s request to remove the month of May from the capability period. The company said curtailments are unlikely during May, noting that the maximum demand experienced during the month has not exceeded 88% of the annual peak demand for the last decade. But the commission said “a lack of historic peak load conditions does not preclude future heat waves in May,” and that a change “would detract from tariff uniformity.”

The regulators approved the company’s proposal to increase the trigger for calling CSRP events to 97% of the summer peak forecast load from the current 92%.

The company said that the large number of events called in its service territory using the 92% threshold “led to less than optimal participant performance” in 2016, the commission noted. The 97% trigger would capture the top 10 load hours during the summer and would result in about three events each summer, the company said.

“Although the commission established a consistent 92% CSRP dispatch threshold for all of the utilities in the 2016 DLM order, experience during the 2016 summer capability period suggests that a standard statewide threshold may not result in optimal program performance,” the PSC said. “This is evidenced by the fact that, despite each utility having the same 92% threshold, CSRP planned events were called many more times in utilities with smaller service territories compared to those with a larger footprint. For example, there were 13 CSRP planned events called by RG&E, and nine by Central Hudson, but only four, two and one event called by Niagara Mohawk, NYSEG and O&R, respectively.

“Instead of maintaining a consistent 92% threshold across all utilities, the utilities should design CSRP thresholds that both recognize the unique features of their service territories and seek to balance the interests of CSRP participants and of other customers.”

Niagara Mohawk

While rejecting Niagara Mohawk’s proposal to modify CSRP, DLRP and DLC incentive rates, the PSC approved its proposed expansion of the DLRP to up to eight additional areas of its service territory in 2017 (15-E-0189).

“In only offering the DLRP in certain areas where there are specific T&D infrastructure projects [that] can be avoided, Niagara Mohawk is using the DLRP as a non-wire alternative (NWA) demand response program instead of as a generalized program to support distribution system reliability,” the commission said.

“While Niagara Mohawk will be allowed to continue to operate its DLRP in this manner for the 2017 summer capability period, the commission expects Niagara Mohawk to expand the DLRP to its entire service territory for 2018. Instead of limiting the DLRP only to specific NWA areas, Niagara Mohawk should offer different values in NWA areas for both the CSRP and the DLRP, depending upon whether the need for the NWA is based on load growth, reliability issues or both.”

Orange and Rockland

O&R’s proposed modification to its DLRP incentive payment rates was rejected while its proposed addition of CSRP notices was approved (15-E-0191).

The utility proposed adding a 21-hour advance advisory notice, with intraday two-hour minimum advance notification of confirmation or cancellation of a planned CSRP event. The advisory notice would be triggered when its day-ahead forecasted load is 92% or more of the forecasted summer systemwide peak.

The company said that under the current notification rules, it is unable to cancel a planned event even if conditions change, eliminating the need for load relief.

The commission approved the proposal while also directing Central Hudson, Niagara Mohawk, NYSEG and RG&E to propose similar notifications for 2018. The PSC had permitted an identical modification to Consolidated Edison’s CSRP in December.

Also approved was O&R’s proposal to allow direct participants and aggregators to increase their kilowatt pledge between capability periods and plan for easing the generator emissions and permitting process. As with the notice rule, the commission ordered the other utilities to make similar changes.

Under prodding by the Advanced Energy Management Association, NRG Energy and Direct Energy, the PSC ordered the utilities to standardize their DLM enrollment and settlement processes for 2017 and allow batch enrollments by 2018.

Pre-REV DR

“For me, these demand response programs fit into a specific bucket,” Burman said. “They’ve been in place in New York City for many years, pre-[Reforming the Energy Vision], and should be expanded statewide. They are intended to be cost-effective programs that produce real peak load reductions at critical periods in the summer.”

While last week’s order addresses inter-day reliability problems, Burman said other issues remain unresolved under REV, including utility earnings adjustment mechanisms and setting a “Value D” — the PSC’s plan to calculating the value of distributed energy resources by adding a distribution component (“D”) to wholesale LMP pricing. (See NYPSC Outlines Reforming the Energy Vision Changes.)

“But here, this action is really targeted to those demand response programs,” said Burman. “It does not have a fatal impact on the utility … and all the other proceedings.”

Ravenswood Sale Approved

In a separate electric power case, the PSC approved a petition for the expedited sale of TransCanada’s 2,400-MW Ravenswood generating facility in Queens, N.Y. to Helix Generation for $2.5 billion — with Burman voting to approve a one-commissioner order issued to that effect by Interim Chairman Sayres the previous day.

Burman noted that the order is clear in deferring to NYISO and “FERC on matters that deal with the market power and other pending matters dealing with AC transmission and western New York.”

Noting policymakers’ concerns over market power and state resource planning, Burman said she is looking forward to FERC’s technical conference on May 1-2, “where many of these issues will be fleshed out.” The conference will focus on tensions between state public policies and wholesale markets in NYISO, ISO-NE and PJM (AD17-11).

April 24, 2017

PJM Reliability Conference Raises Questions; Solutions Elusive

By Rory D. Sweeney

PHILADELPHIA — More than 200 stakeholders met at the Philadelphia Airport Marriott on Wednesday and others listened in on the webcast to discuss the meaning of resiliency and reliability on the electricity grid and how to incentivize enhancement of it through PJM’s electricity markets.

PJM Grid 20/20: Focus on Resilience included 16 speakers and featured three panels that slowly built toward a discussion of solutions with the final speakers. However, clear solutions seemed to remain elusive.

“The only way we can properly design the market, the only way we can ensure reliability is through conversations like this: What’s happening, how do we need to change, how do we need to adapt and are we comfortable with where things are going?” said Bill Berg, Exelon Generation’s eastern RTO director. “I said, ‘that was my only firm, concrete solution.’”

Grid 20/20 Panel left to right: Foster, Mroz, Bowring, Berg and Novotny | © *RTO Insider*

Independent Market Monitor Joe Bowring moved the ball forward by suggesting what those conversations should entail.

“We need to define analytically the detailed meaning of resilience,” he said. “What are the metrics?”

Beyond that, speakers largely identified issues and what shouldn’t be done.

“Here’s what we shouldn’t do,” Bowring said. “We shouldn’t pick winning technologies; we shouldn’t provide nonmarket competition for preferred technologies; we shouldn’t make fundamental changes to the market to accommodate preferred answers.”

His answer touched on a consistent battleground during the discussions about whether noneconomic baseload generators should be retained if they provide other benefits. The issue is particularly timely given the zero-emissions credit subsidies approved in Illinois and New York to preserve in-state nuclear plants.

Berg, whose company’s nuclear units are the beneficiary of both of those subsidies, urged stakeholders to consider whether the markets are designed correctly if such out-of-market measures are necessary to preserve the grid’s nuclear fleet. Supporters have argued that ZECs would not be necessary if the markets incorporated the cost of carbon emissions from fossil fuel plants.

“While it’s simple to say, ‘Let’s just rely on markets,’ there’s a reality that we need to recognize as part of the conversation as we transition to a fully competitive market,” he said. “We’re not there yet.”

Bowring argued that the purpose of the markets is to determine whether such plants are indeed desirable.

“The term baseload, think about it: What does that mean?” he said. “A baseload unit was a unit that used to be economic and isn’t anymore, but we still want it to be so let’s make it economic by giving it subsidies.”

Other speakers urged cooperation among all stakeholders to solve the issues.

“This is not an issue that is just left in each of the silos, whether it’s PJM, or it’s a state regulator, or it’s the industry or if it’s one of you companies to try and find solutions,” said Richard Mroz, president of both the New Jersey Board of Public Utilities and the Organization of PJM States Inc. “It is really incumbent upon all of us to do it. … State regulators don’t have the answers. People think we do. We don’t even have a real semblance of that ability as we did to deal with integrated resource plans.”

Joining Bowring, Mroz and Berg on the final panel was Calpine’s Andrew Novotny, who reminded the audience that out-of-market subsidies have impacts that can hurt the market’s overall purpose.

“If we do use state subsidies in order to preserve nuclear plants when they become uneconomic, it’s critical that PJM protects the capacity market and has a price that is protected from what that impact would be,” he said. “There will be a consequence if that’s not done. … We rely on the Capacity Performance product in order to provide revenues that we desperately need to maintain our fuel-oil backup.”

Calpine has oil backup for about 5,000 MW of its natural gas-fired generation to address its CP responsibilities, he said.

Direct Energy’s Marji Philips asked the panelists why proposed solutions continue to cling to previous market structures.

“Everybody’s talking about the past, and putting Band-Aids on the past, instead of looking [at] what’s going to be a very radical future that we can’t imagine today,” she said.

Bowring said the purpose of markets is to define needs and incentivize creative solutions.

“I would say there is no defined market-design problem that requires subsidies as a solution, particularly for specific uneconomic resources,” he said. “One of the things that underlies this whole discussion is an underlying tension between the exogenous requirement to be reliable, NERC-imposed, FERC-imposed and the existence of markets. Markets have successfully met the reliability standards so far, and my point is I think they can continue to do that, but there is that tension. There has always been that tension. The fact that we’re talking about resilience doesn’t make that tension new. It simply makes the challenges more difficult. We need to now think in even more detail about what reliability really means when we include resilience in the definition.”

Mroz warned that state regulators can’t be left to define needs for the market either. For example, he said the BPU is sometimes the last to know about distributed energy resources interconnecting to the grid.

“We don’t have the tools anymore at the state level to identify where all those resources are,” he said. “Something that I have been very vocal about is to ask PJM to ask the industry to be mindful that in the context of meeting these challenges, we’re also mindful at the end of the day of the cost impact that ultimately has to be borne by the consumer.”

April 24, 2017

Offshore Wind Industry Looks for Next Gust of Support

By Jason Fordney

ANNAPOLIS, Md. — A senior federal official told offshore wind energy developers last week that the Trump administration supports their cause as the industry looks to build momentum after putting the first U.S. project into service last year.

“I can attest to the fact that offshore wind is very much a part of the portfolio of energy that [new Department of Interior leaders] have come on board to promote,” Bureau of Ocean Energy Management Acting Director Walter Cruickshank told dozens of attendees April 20 at the 2017 International Offshore Wind Partnering Forum. “So, we can put that question behind us and talk about the future.”

The Obama administration ended its last term with two landmarks in the development of the nascent resource. In December, Deepwater Wind’s 30-MW Block Island Wind Farm off Rhode Island became the first offshore facility to deliver electricity to the U.S. grid, days before developer Statoil Wind US agreed to pay BOEM a record $42.5 million to lease a parcel off New York.

During his campaign, President Trump promised to revitalize the fossil fuel industry and to renege on the carbon emissions cuts promised in the Paris Agreement on climate change, creating concern that his appointees might curtail federal support of renewable energy.

But Cruickshank, a long-time Interior Department official who was deputy director of BOEM at its inception in 2011, noted that the agency completed its seventh competitive lease sale for offshore wind in March. Avangrid Renewables presented the high bid of about $9 million to develop a 122,000-acre wind energy area off Kitty Hawk, N.C., a deal that Interior Secretary Ryan Zinke called a “big win.”

Cruickshank said the agency hopes to identify sites for development off the California shore by June. The seabeds near Massachusetts, New York/New Jersey, the Delmarva Peninsula, the Carolinas, Oregon and Hawaii are also being eyed for development, he said.

At the three-day Annapolis forum, sponsored by the Business Network for Offshore Wind, offshore developers described the unique technical and regulatory requirements for bringing their projects to fruition. Design challenges are highly complex, and the scale of equipment and logistics is huge, while much of the required knowledge and experience is in its infancy in the U.S., relative to Europe.

“This industry does not exist in the U.S. — it is nascent,” said Paul Rich, director of policy development for offshore developer US Wind. The company is vying with Deepwater Wind to be the first to build off the coast of Maryland.

Rich told the forum that it is critical that they collaborate, and told them to be “bold” and to “go big, go large.”

US Wind’s proposed wind farm on an 80,000-acre site 17 miles off Ocean City, Md., would have 187 turbines producing 750 MW. The company won its BOEM lease in August 2014 for $8.7 million and has already invested more than $20 million in its project. The wind farm, which still needs federal permits to move ahead, has a total price tag of $2.5 billion.

The Maryland Public Service Commission is due to decide by May 17 whether US Wind or Deepwater subsidiary Skipjack Offshore Energy will receive offshore renewable energy credits to help fund their proposed projects. The credits, a subsidy that will later be transferred to electricity suppliers to meet renewable energy requirements, spring from 2013 legislation that created a carve-out for offshore wind in Maryland’s renewable portfolio standard. The legislation directs that projects must be 10 to 30 miles off the coast, able to connect to the PJM grid and approved by the state commission.

Skipjack has a much more modest plan for a 120-MW wind farm. The company argues for a more measured approach to development and says its site — 26 miles from the Ocean City Pier and 19.5 miles from its closest point in Maryland — would have much less visual impact.

About 72% of Maryland voters support offshore wind, according to a poll by Annapolis-based marketing analysis firm Opinionworks conducted in 2013. But siting the projects is difficult because of the massive infrastructure and environmental footprints involved. The costs of building offshore are almost three times that of onshore wind according to the U.S. Energy Information Administration’s levelized cost of energy calculations, although offshore turbines are larger and have substantially higher capacity factors.

In addition, even a small visual presence of turbines peeking above the horizon can create complaints in coastal areas. Ocean City officials raised concerns about the visual impact of the proposed US Wind turbines and their possible effect on tourism. The company this month offered to move the project from 12 to 17 miles offshore, adding millions of dollars in costs.

Developers must also deal with the lengthy and costly generator interconnection process faced by land-based generation.

But after setbacks to projects planned off of Atlantic City, N.J., and Martha’s Vineyard, Mass., the industry has reason for optimism. Last August, the Massachusetts legislature approved legislation ordering procurement of 1,600 MW of offshore wind by 2027. (See Cuomo Proposes 2,400 MW of Offshore Wind by 2030.)

Liz Burdock, executive director of the Business Network for Offshore Wind, says there is a “4.25-GW pipeline” of offshore wind projects in the U.S., large enough to spark a supply chain similar to that in Europe, which has been building utility-scale offshore wind for more than 15 years. The continent boasts 12.6 GW from nearly 4,000 turbines in 10 countries, according to industry group WindEurope.

U.S. developers are looking to utilize the expertise of European offshore wind developers — as well as companies that service U.S. offshore oil and gas drilling — to build capabilities here.

Last week’s forum attracted more than 200 companies and labor unions that would like to be part of that supply chain, in addition to university and government researchers and others.

April 24, 2017

Heated Start for CAISO CRR Reform Initiative

By Robert Mullin

Financial traders made clear last week that they won’t give up CAISO’s congestion revenue rights (CRR) auctions without a fight, sparring with the ISO’s internal Market Monitor at the first meeting to discuss the auctions’ revenue shortfalls.

At a contentious meeting of the Congestion Revenue Rights Analysis Working Group on April 18, the CAISO Department of Market Monitoring was unyielding in its position that the auctions should be scrapped and replaced with a bilateral swap market that doesn’t burden California ratepayers. The department said ratepayers have paid more than $560 million since 2012 to cover the shortfalls, receiving only 49 cents of every dollar paid out.

CAISO launched the congestion revenue rights auction reform initiative at the request of its internal Market Monitor, which wants to discontinue the auctions in the face of revenue shortfalls that leave ratepayers footing the bill to pay rights holders. | *CAISO*

Opponents of the initiative complained in January that it lacks widespread stakeholder support. (See CRR Initiative Elicits Mixed Reviews from CAISO Participants.) In comments filed with the ISO earlier this year, the Western Power Trading Forum (WPTF) criticized it as the Monitor’s “pet project.”

Who Owns the Transmission System?

The Monitor has argued that the main beneficiaries of the existing auction structure are financial speculators rather than load-serving entities or generators. Its objective is “to not have ratepayers offer financial swaps at a zero-dollar reservation price,” said Ryan Kurlinski, manager of the department’s analysis and mitigation group.

“If there were no CRRs, no auction, no allocation, who would get the [congestion] rent? Transmission ratepayers,” said Roger Avalos, a lead analyst with the Monitor. “Who would get the auction revenues? Ratepayers.”

“You’re making that as a conditional statement upon this alternate universe you’ve created, but you don’t know that’s actually what would happen through the course of policy decisions,” countered Seth Cochran, manager of market affairs and origination at DC Energy, which trades CRRs and other financial instruments tied to the power and natural gas markets.

Neil Huber, an energy trader with XO Energy, took issue with the fact that the Monitor was using the terms LSEs and ratepayers “interchangeably.” He contended that “we would all agree that the LSE may be paying for the underfunding” of the auctions, but that use of the term “ratepayer” seemed “politicized” within the context.

Kurlinski explained that transmission developers recover their capital costs through CAISO’s transmission access charge, which is charged to metered load — a cost that LSEs pass directly to their customers.

“So that’s where we’re getting to the concept of ratepayers ultimately paying for this physical transmission, and therefore they have the rights to revenues generated from those assets in the day-ahead market — which are the congestion rents,” Kurlinski said.

“Everything in the [auction] balancing account is passed to ratepayers, not the shareholders of LSEs,” Avalos added.

Michael Rosenberg, principal trader with ETRACOM, questioned the assumption that the transmission system is effectively owned by ratepayers.

“Right now, it’s not clear to me, after all this discussion, why that transmission congestion revenue belongs to — quote-unquote — transmission ratepayers or ratepayers, and why the current market mechanism is inferior,” Rosenberg said.

CRRs Benefits to Ratepayers

In a presentation to the group, Abram Klein of Appian Way Energy Partners said that “CRRs are not bad for consumers — it’s really the opposite.”

“And what matters for consumers is not how much money they’re getting from the CRRs, but what’s the premium and the cost to certain load in the competitive wholesale market,” Klein said.

In a well-designed market, he said, CRRs actually lower risk premiums for serving wholesale load, which brings down forward prices. The upshot: Consumer costs are ultimately reduced by the increased transparency and liquidity provided by CRR auctions, he said.

Klein said the auctions will become increasingly important as California moves toward more retail choice through the growth of community choice aggregators, which will rely on CRRs to keep their forward prices in check.

Doug Boccignone, a consultant representing Silicon Valley Power, the CCA for Santa Clara, noted that CCAs are eligible to participate in the ISO’s CRR allocations after effectively taking over the role of their host utilities. “They have all the rights and obligations that any other LSE has,” he said.

Boccignone added that LSEs appear to be participating in the auctions to unwind their own allocation positions rather than to acquire more CRRs.

Other Markets for Hedges?

Klein said that although congestion costs are relatively small — representing just 2% of the cost of serving load — the CRRs are “a crucial piece because they are really embedded in the LMP market design.” Eliminating the CRR auction would remove “one of the pillars” of the market, he said.

Ellen Wolfe, a consultant speaking for the WPTF, said that LSEs indirectly benefit from the CRR auctions through deals made “more efficient” by access to CRRs outside the allocations.

“A seller cannot necessarily transact with a buyer well unless there is some way to hedge, and those deals become more efficient with the ability to hedge well, and the CRRs in a nodal market allow that process,” Wolfe said. Without the auction, there’s no way for third parties to get hedges, she said.

“I don’t think that we’re in any way talking about eliminating all markets for these kind of financial hedges,” Kurlinski said. “I think the purpose of this initiative is, ‘What are the options for replacing the current CRR auction? Does it have to be this CRR construct? Does it have to be the ISO deciding how many of these financial swaps to offer up?’”

“Another market can evolve if there’s actually demand for these hedges,” Kurlinski said. He said such a market wouldn’t be liquid today because the ISO is selling a “huge quantity” of what are effectively financial swaps at a zero-dollar reservation price.

“Nobody else is going to be able to come in and compete with that,” Kurlinski said.

Need for Root Cause Analysis

Wolfe said the Monitor seems to be concerned that when revenues are sold for below-market value that “there’s some kind of transfer of wealth” and that there’s no remedy available to address that.

“Along the way, there’s been no real explicit investigation of the root causes of why those CRR clearing prices are less than day-ahead congestion and what’s driving” the discrepancy between auction revenues and CRR payouts, Wolfe said.

Kolby Kettler of energy and commodities trader Vitol encouraged market participants to consider the “intangible” transparency benefits of the CRR auctions. The transparency behind auctioned CRRs is used by lenders to price their financing to energy project developers, Kettler contended.

“Do they pull up the CRR price and use that as it is? Maybe not,” Kettler said. “But it goes into consideration and it reduces the premiums back to load based on this information. So that’s something we need to take into consideration. It’s very hard to quantify some of those things.”

The intangible benefits do exist, agreed Alan Wecker, market design analyst at Pacific Gas and Electric. But he offered a significant qualification.

“It’s just that the magnitude of the loss is so large that it causes me to want to have a better way to make those intangible benefits tangible,” Wecker said. “Without that, it’s so ethereal that it’s really hard for us to agree that no change needs to be made or that the changes don’t need to be that massive.”

April 24, 2017

PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:20)

Members will be asked to endorse the following proposed manual changes:

A. Manual 14B: PJM Regional Transmission Planning. Revisions developed in response to a change to the NERC glossary of terms to change all occurrences of “special protection system” to “remedial action scheme” and correct wording in the baseline thermal analysis section to match analytical procedures.

3. Energy Market Uplift Senior Task Force (EMUSTF) (9:20-9:40)

Members will be asked to endorse the proposed Phase 3 solution endorsed by the EMUSTF, which would limit increment offers and decrement bids to trading hubs and locations where the settlement of physical energy occurs. It would also limit up-to-congestion trades to zones, hubs and interfaces. (See UTC Trader Displeased with PJM’s Handling of Uplift Rule Changes.)

4. Regulation Market Issues Senior Task Force (RMISTF) (9:40-10:00)

Members will be asked to endorse the proposed regulation market changes endorsed by the RMISTF. The package, proposed by PJM and the Independent Market Monitor, would change rules regarding performance scores, clearing, and settlements.

5. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (10:00-10:10)

Members will be asked to endorse the draft charter for the CCPPSTF. (See PJM Capacity Task Force Considering 60+ ‘Design Concepts’.)

6. Seasonal Capacity (10:10-10:30)

Members will be presented with a final report of the Seasonal Capacity Resources Senior Task Force, asked to approve sunsetting the task force and endorse proposed revisions to Manual 18: PJM Capacity Market. The manual changes are intended to conform to FERC’s March 21 order approving PJM’s plan for easing the aggregation of seasonal resources so that they can qualify under Capacity Performance rules (ER17-367). (See PJM Outlines Aggregation Rules for Upcoming Capacity Auction.)

Members Committee

Consent Agenda (1:20-1:25)

B. Members will be asked to endorse a proposed shortage pricing/operating reserve demand curve solution and associated Operating Agreement and Tariff revisions. The changes, to comply with FERC Order 825’s directive to allow transient shortages, will add a permanent second step on the demand curve. (See “Shortage Rule Takes Effect amid FERC Silence,” PJM Market Implementation Committee Briefs.)

1. Manual 15 – Fuel Cost Policies (1:25-1:45)

Members will be asked to endorse proposed revisions to Manual 15: Cost Development Guidelines related to fuel cost policies. (See PJM Fuel-Cost Policy Changes to Take Effect in May.)

– Rory D. Sweeney

April 24, 2017

MISO Planning Advisory Committee Briefs

CARMEL, Ind. — MISO is planning to eliminate temporary suspensions of generating resources, a move the RTO says will provide resource owners more flexibility.

The existing Attachment Y suspension status requires that owners supply MISO with a return date. Under the new rules, the status would be reduced to a binary option: on or off.

MISO attachment Y — Reddoch | © *RTO Insider*

Fewer options actually translate into greater flexibility for resource owners, MISO adviser Joe Reddoch told stakeholders at the April 19 Planning Advisory Committee meeting. He said generation owners will now be able to enter a catch-all “economic shutdown” period using an Attachment Y, giving them time to evaluate options over a planning year before rendering a final decision to retire.

The decision point will align with the Planning Resource Auction, with interconnection service intact for a full planning year after a notice to go offline is submitted. If approved by FERC, the new process will be added to MISO’s Tariff.

The same planning yearlong rescission period will apply to system support resources whose status has been lifted by MISO.

“Once a generator submits an Attachment Y retirement notice, they cannot change their minds. If they do, they have to re-enter the interconnection queue,” Reddoch said of MISO’s current process.

Reddoch added that MISO’s current six-month suspension timeline is “a bit cumbersome” with multiple filing deadlines. He also said that suspension notices can sometimes “mask” lost megawatts because MISO assumes suspended resources will eventually come back online.

The changes stem from the Independent Market Monitor’s 2013 State of Market Report recommendation that MISO improve alignment between its Attachment Y process and the PRA timeline. The Monitor said that an Attachment Y unit that participates and clears in the PRA should be allowed to “defer the effective date of retirement.” (See “Aligning Attachment Y Process with PRA,” MISO South-to-Midwest Transfer Limit Upped for 2017/18 PRA.)

Once an Attachment Y request is submitted, MISO will carry out an Attachment Y retirement reliability study as usual, but with one added feature: Upon completion of the study, MISO will publicly post study results. Some stakeholders expressed concern at the heightened transparency.

Indianapolis Power and Light’s Lin Franks said publicly posting the results might inadvertently create a panic in some companies that have not publicly announced plans to retire.

“You may understand that you’re trying to take a middle ground, but the guy at the plant [losing his job] doesn’t understand that,” Franks said.

“That’s fair enough,” Reddoch replied.

Other stakeholders asked MISO to consider deferring public results of Attachment Y until the new decision point deadline, but Reddoch said early warning is key when planning for retirements.

“When you keep things confidential, it’s hard to talk about upgrades or projects that are needed when we can’t talk about why those projects might be needed,” Reddoch said. “If you don’t start on upgrades early enough, and a plant does retire, you might have reliability issues. Our thinking is you want to get started early on the timeline if these things require a number of years to complete.”

WPPI Energy’s Steve Leovy suggested that Franks’ company could initiate MISO’s optional nonbinding Attachment Y study. Franks said IPL had gone through the “horrible” process and does not want to repeat it. “Okay, that sounds like another issue,” Leovy said.

The Environmental Law & Policy Center’s Justin Vickers said his firm supported MISO’s stepped-up transparency, saying that posting study results would assist in preparations and be “good for the footprint.”

MISO will take stakeholder feedback on proposed Tariff changes through May 10.

48 Competitive Tx Contenders in 2017/18

MISO is reviewing qualifications of 48 transmission developers that submitted documentation to become or renew their status as competitive developers for this year’s planning cycle, the same number as last year. The exercise is likely to be moot, however, as MISO is not expected to announce a competitive project this year.

— Amanda Durish Cook

April 24, 2017

NYISO, PJM Discuss PARs’ Benefits, Cost Allocation

By Michael Kuser

RENSSELAER, N.Y. — Lots has changed since 1993, when members of the New York Power Pool and several transmission owners in PJM agreed to split the cost on two phase angle regulators (PARs) at Consolidated Edison’s Ramapo substation.

PJM NYISO cost allocation pars — ConEd PAR | *ConEd*

The power pool was succeeded by NYISO, PJM grew west to Chicago and FERC issued Order 1000, which set new cost allocation rules.

Those changes are now complicating efforts by the ISO and PJM to come up with a new cost-sharing agreement for the PARs, which control flows on the 500-kV Branchburg-Ramapo 5018 transmission line between New York and PJM.

On Tuesday, staff and stakeholders from both grid operators met at NYISO’s headquarters for a nearly daylong meeting to discuss ways to evaluate the value of the PARs and who should pay for them. The grid operators said they were pleased with the discussion and will meet again at PJM headquarters May 24 to continue talks.

And Then There was One

The need for better interface management originated in the great Northeast blackout of November 1965, which left 30 million people without power. Con Ed installed two PARs at Ramapo in 1988 and only five years later did the New York grid operator and PJM agree to split the entire costs 50/50 — purchase, installation and operation.

The original PARs both had a life expectancy of 40 years, but one was replaced after failing in 2013. The second original unit was destroyed in a substation fire last June. (See PAR Wars: A Struggle for Power.)

Con Ed is willing to purchase the replacement PAR but wants to be assured of repayment. Both sides estimate that it costs about $200,000 per month to run the two PARs.

Two-Track Approach by NYISO

“It all keeps coming back to the criteria” for determining benefits, Wes Yeomans, the ISO’s vice president for operations, said at the discussion April 18.

NYISO is taking a two-track approach: It is preparing to file a proposed Tariff revision with FERC to allocate the costs among all its load-serving entities and, at the same time, discussing with PJM how to share the costs.

The plan would promise to reimburse New York LSEs found to have overpaid their shares when the interregional cost allocation issues are resolved.

“Delay in reaching agreement on interregional cost allocation should not be permitted to indefinitely delay the installation of a second PAR at Ramapo,” the ISO said.

PJM says, however, that “cost allocation will only apply to transmission facilities that are approved in writing by all parties in advance of installation.”

Brian Wilkie, counsel for the New York Power Authority, suggested that “this discussion might be easier if PJM adopted NYISO’s practice of applying costs across all LSEs.”

Stan Williams, PJM director of performance compliance and market settlements, said, “I agree, but a lot of this is holdover from the 1993 JOA, which predates a lot of us, which is part and parcel of why we’re here.”

The 1993 Ramapo PAR agreement allocated 50% of the costs to the NYPP and 50% to the PJM group — which included only TOs in PJM’s Mid-Atlantic control zone.

Measuring the PARs’ Benefits

Any cost-sharing arrangement between NYISO and PJM will have to abide by FERC Order 1000’s guiding principle that transmission upgrades be “allocated in a way that is roughly commensurate with benefits.”

PJM and NYISO have yet to determine what reliability and economic criteria to use in their analysis. For example, are the effects on production costs more important than implications for reliability?

NYISO evaluates transmission upgrades under three separate planning processes: reliability, public policy and economic.

The ISO says the PARs provide reliability benefits during extreme contingencies or restoration following outages.

They also have market efficiency benefits: Without the PARs, NYISO’s ability to import lower-cost power from PJM is reduced. Those imports also have allowed the ISO to operate with smaller installed reserve margins and locational capacity requirements.

The ISO can import 1,700 MW from PJM in summer with both PARs and 1,400 MW with one. With neither PAR, the summer import limit drops to 1,000 MW.

Yeomans estimated the installed capacity benefits are about $75 million but would not elaborate on how he got that number, saying it came from two separate analyses, both made under non-disclosure agreements with third parties.

PJM’s list of suggested planning criteria included the impact of a second Ramapo PAR on revenue for holders of financial transmission rights — called “transmission congestion contracts” in NYISO. But Jane Quin, director of energy policy and regulatory affairs for Con Ed, objected to including such revenues as evaluation criteria, saying “that’s not how we treat” other similar facilities in NYISO.

DFAX Methodology

She also said Con Ed would opposed use of the distribution factor (DFAX) cost allocation method, as proposed by Public Service Enterprise Group, for evaluating benefits provided by the PAR.

Con Ed’s complaint over its $91 million bill for PSEG’s Bergen-Linden Corridor upgrade in North Jersey was one of the factors that led the utility to cancel use of the Con Ed-PSEG wheel.

The DFAX method also has been a flashpoint on the Artificial Island stability project in South Jersey. PJM has said that DFAX works well in many cases but can result in anomalous allocations. (See Board Restarts Artificial Island Tx Project; Seeks Cost Allocation Fix.)

Stan Williams, PJM director of compliance and settlements, said that “the PJM-MISO interface is a lot more complicated than [PJM-NYISO], with lots of nodes and contact points, whereas the major part in the NYISO interface is in the extreme Northeast, around New York City.” He added that the Ramapo PARs also play a wider role in the region, for example, contributing significantly to mitigating Lake Erie loop flows on the Michigan/Ontario interface.

PJM’s Chuck Liebold said that while PJM had reached no conclusions, when jointly planning the two grid operators normally look to the Northeast Protocol — the three-party agreement of NYISO, PJM and ISO-NE. Liebold suggested two options: They could establish a new type of interregional transmission project under the Northeast Protocol, or establish new planning provisions under their joint operating agreement.

Howard Fromer, director of market policy at PSEG Power New York, said, “If we’re devoting more money to this issue with the people in the room now than the cost of the project, we should develop a process applicable to many issues.” He added that the quantifiable benefits should include effects on emissions.

Timeline

New York’s timeline calls for May votes in the Business Issues and Management Committees on the changes, June approval by the NYISO Board, FERC filing immediately thereafter and Con Ed installing the second PAR in Fall 2017. The group hopes to have a proposal for PJM Markets and Reliability Committee to review in July.

Officials asked stakeholders to provide written comments to PJM and NYISO on the options by May 12.

April 24, 2017

Avangrid Renewables CEO Steps Down to Take NW Natural Role

By Robert Mullin

PORTLAND — Avangrid Renewables CEO Frank Burkhartsmeyer is resigning to take over as chief financial officer for Oregon-based natural gas service provider NW Natural.

Laura Beane, currently vice president of operations and management services at the renewables company, will take over the top spot once Burkhartsmeyer departs May 17.

In an internal memo to company employees, Avangrid CEO Jim Torgerson expressed “regret” over Burkhartsmeyer’s departure from the renewable energy company. Headquartered in Portland, Avangrid Renewables is a division of Connecticut-based Avangrid, the North American subsidiary of Spanish energy giant Iberdrola.

“Avangrid Renewables has grown under his leadership as CEO since 2015,” Torgerson said. Burkhartsmeyer, who has been with Avangrid and its previous affiliates for 20 years, was promoted to CEO after serving as the company’s senior vice president of finance. At NW Natural, Burkhartsmeyer will oversee the $3.1 billion company’s treasury, accounting, financial reporting, budgeting and forecasting, financial analysis, investor relations, business development, and supply chain activities.

“We are thrilled to have someone with Frank’s impressive experience on our officer team,” NW Natural CEO David Anderson said in a statement.

Beane joined Avangrid Renewables in 2007 after the company acquired PPM from Scottish Power. She had worked for 10 years at PPM under its previous parent, PacifiCorp.

“We are delighted to add Laura’s breadth of experience, knowledge and enthusiasm to the Avangrid Management Committee,” Torgerson said.

Avangrid Renewables has more than $10 billion in operating assets, representing more than 6,000 MW of capacity in 20 U.S. states.

April 21, 2017

Westar Shares Fall as Kansas Regulators Block Great Plains Deal

By Rich Heidorn Jr. and Amanda Durish Cook

Shares of Westar Energy fell 8% Thursday after Kansas regulators rejected as too risky and too expensive the company’s planned sale to Great Plains Energy.

The Kansas Corporation Commission voted 3-0 to reject the $12.2 billion deal, announcing it at the end of the day Wednesday.

Westar shares, which had ended Wednesday at $55.11, dropped $4.24 to $50.87 Thursday. Shares of Great Plains, the parent company of Kansas City Power and Light, were virtually unchanged, rising 4 cents to $29.55.

Price Too High

“The commission is not opposed to mergers as evidenced by its approval of two acquisitions within the past six months,” the commission’s order said. “As one of the intervenors notes, in many ways a merger between GPE and Westar makes sense, but for one insurmountable obstacle — the purchase price is simply too high.”

The commission said that based on their complementary service territories, a merger of the two companies could make sense. But it said the price was excessive and would force Great Plains to take on too much debt, noting the $4.9 billion acquisition premium exceeds Great Plains’ market capitalization by $100 million.

The commission also said that Great Plains’ winning bid of $60/share was $4 higher than that of the next highest offer. “Evidence suggests the $60/share purchase price exceeded the expectations of both Goldman Sachs and Guggenheim,” who validated the purchase price for Great Plains and Westar, respectively. Great Plains’ own analysis showed a “mid-fifties price point as the high end of a reasonable purchase price,” the commission said.

“Unfortunately, the transaction was presented to the commission as a take-it-or-leave-it proposal. Repeatedly, the joint applicants advised the commission that any significant safeguards that would protect consumers, such as maintaining a separate, independent Westar board of directors, would halt the transaction. Therefore, the proposed transaction could not be salvaged and the commission is left with no choice but to reject” it, the commission said.

The deal, announced last May, would have given Great Plains 1.5 million customers in a service territory covering the eastern one-third of Kansas, much of the Kansas City metropolitan area and a large portion of northwest Missouri. Great Plains said the merger would have increased its operating scale, resulting in efficiencies that would benefit ratepayers. (See Great Plains Asks Missouri PSC’s OK on Westar Deal.)

Debt Burden

Great Plains would have assumed $3.6 billion of Westar’s debt. It planned to finance the $8.6 billion purchase of outstanding Westar common stock with a package of 50% equity and 50% debt, including $4.4 billion in new debt. The company issued $4.3 billion in debt financing in March, the order noted.

“Since GPE has already completed both the equity and debt portions of the financing, it argues its ability to accomplish the financial steps necessary to close and support the transaction is no longer a concern. But the issue facing the commission in evaluating the transaction … is not whether GPE could obtain financing, but whether post-transaction, the resulting entity would be financially stronger than the stand-alone entities would be absent the transaction.”

The commission noted that Great Plains acknowledged that it expected Moody’s to downgrade its senior unsecured debt rating from Baa2 to Baa3, the lowest investment grade credit rating.

The commission cited the testimony of Great Plains CFO Kevin Bryant, who said that the company hopes to pay off $300 million to $500 million of debt within three to five years, but that it has no written plan to do so.

“Since GPE has failed to formulate any written plan to pay down the debt, the commission has nothing to review and cannot assume GPE will be able to rapidly deleverage. Therefore, the commission must review the joint application under the assumption that a post-transaction GPE will have substantial debt that will likely result in downgrades to its credit rating.

“The commission shares the concerns voiced by [the Kansas Board of Public Utilities] and [the Citizens’ Utility Ratepayer Board] that if the transaction is approved, GPE has little financial flexibility and very little margin of error to keep its investment grade rating. … The evidence is overwhelming that the rating agencies believe … GPE will be a riskier investment if the transaction goes through.”

The commission also noted Great Plains and Westar’s claims that applying a consolidated capital structure that included Great Plains’ transaction-related debt would halt the merger, saying such assertions were “a tacit admission that the joint applicants’ ability to complete the deal is entirely dependent on its ability to use the operating utilities’ higher rates of return to finance the transaction.”

Savings in Question

The commission also cast doubt on Great Plains and Westar’s estimated savings from the early retirement of five KCP&L generating units and five Westar units, calling them “too speculative to be reliable.”

Great Plains and Westar “support their application with little more than preliminary estimates, developed in only three weeks and without full access to Westar’s books or personnel,” the commission said of Great Plains’ savings analysis.

The commission also said Great Plains and Westar’s commitment to not seek recovery of the acquisition premium from ratepayers was flimsy at best. It pointed out that an exception to acquisition financing can be triggered if a “single intervenor simply proposes to use a different capital structure, regardless of whether the commission adopts the intervenor’s proposal.”

With 22 parties intervening in Westar’s last rate case and nine parties intervening in KCP&L’s, the commission said Great Plains and Westar would quickly lose control of the proposal, and promises to not charge ratepayers could be broken, the commission said. “Allowing the joint applicants to seek recovery of the acquisition premium if any party in any future Westar or KCP&L rate case proposes a different capital structure renders the … promise not to seek the acquisition premium from ratepayers hollow. An exception that is so easily triggered is an empty commitment,” the commission decided. “The exception is so open-ended as to render the joint applicants’ commitment not to seek recovery of the acquisition premium meaningless.”

The commission, which ruled after taking seven days of testimony, noted that of the 28 parties that intervened, all but the applicants opposed the merger.

Great Plains and Westar officials said they were reviewing the order to consider their next steps.