Page 1137 – RTO Insider

August 20, 2018

Canadians Seek Inclusion in Cybersecurity Meetings

By Tom Kleckner

CALGARY, Alberta — Canadian Electricity Association CEO Sergio Marchi took advantage of several opportunities during last week’s NERC Board of Trustees meeting to complain that he and other Canadian stakeholders have been excluded from Department of Homeland Security cybersecurity briefings.

Canadian Electricity Association’s Sergio Marchi | © *RTO Insider*

“We’re forbidden to participate because we are considered, quote unquote, foreigners,” said Marchi, whose association represents integrated utilities, independent power producers, transmission and distribution companies, power marketers and industry suppliers. “The irony is most of our CEO representatives happen to be American citizens.”

Marchi said that over the last year, he and the two Canadian CEOs on the Electricity Subsector Coordinating Council (ESCC), ENMAX’s Gianna Manes and Hydro One’s Mayo Schmidt, have been shut out of the classified briefings.

NERC responded that the Canadians have been excluded because they don’t have the proper security clearance. It added that it is working with industry and government partners to increase the functionality of the Electricity Information Sharing and Analysis Center (E-ISAC) portal, which gathers, analyzes and shares security data across the North American grid.

“NERC as a private company does not have authority to grant or sponsor clearances or to provide access to classified briefings in the United States or in Canada,” CEO Jim Robb said in a statement provided to RTO Insider. “However, NERC will ensure that all NERC events are inclusive of all our North American stakeholders. Simply getting information is only piece of the security pie, and the E-ISAC is in a unique place to analyze and triangulate information to identify threats and mitigation actions to share information that North American stakeholders need to protect their systems.”

Marchi told RTO Insider that the exclusion from the ESCC briefings has become more of an issue under the Trump administration.

“It’s frustrating, and whether it’s NERC or Bruce Walker [the Department of Energy’s NERC representative], they haven’t been able to pinpoint who is blocking us and why,” he said. “This is an example, where everyone says we should be in the meeting, but we don’t know who [is preventing us] and why we are kept out of the meeting. We’re hopeful we can make progress, and the next time the council meets, we can be on the same team.”

Robb acknowledged the issue while briefing trustees on the ESCC’s recent discussions. He said improving information sharing with Canadian industry members is “complicated territory.”

Marchi said the CEA was willing to give Robb a “proper runway” to improve the process.

A former member of the Canadian Parliament and cabinet minister, Marchi also objected to what he said was a 25% budget increase for the E-ISAC as part of NERC’s overall 9.5% budget increase.

“Our Canadian utilities receive the same information from Canadian sources, but it’s quicker and of higher quality,” Marchi said. “Why should we pay twice for information that is of less quality, and that is late on arrival?”

In his statement, Robb pointed out that Canadian stakeholders were able to file comments on the 2019 budget and business plan as part of NERC’s “open and transparent” budget process. He said the organization takes their concerns seriously.

“[We] had multiple meetings, phones calls and written exchanges with [Canadian stakeholders] to discuss the 9.5% increase,” Robb said. “While we acknowledge [their] concerns, we believe the budget approved by the NERC Board of Trustees is the right answer for industry based on all feedback we received.”

Robb acknowledged that the Canadian government has, at times, “authorized release of information to Canadian industry sooner than the U.S. government.” He said NERC recently executed a memorandum of understanding with the Canadian Cyber Incident Response Centre to help improve E-ISAC access to the Canadian government’s security information.

Marchi said the CEA will monitor the next budget cycle and “consider our options” at that time. He said the E-ISAC’s relationship with U.S. security organizations is “an important piece of that puzzle.”

“It’s very important those relationships are picture perfect, if a new investment to the E-ISAC will create the outcomes they’re intended to,” he said. “We need to continue to work closely as our industry evolves at a rapid pace and cyberattacks continue at a great pace. This work must be done in a cost-effective and efficient manner, because both regulators and customers demand and expect it.”

NERC Board Chair Roy Thilly said improving the involvement of Canadian utilities in the E-ISAC “is a very high priority” for the trustees. “We ask the Canadian utilities to work with us to help you provide that value.”

Earlier in the week, the NERC board and Canadian regulators held their annual meeting. NERC said Canadian regulators were briefed on cybersecurity, including the E-ISAC long-term strategic plan and the organization’s reliability assessment and performance analysis capabilities.

Robb Reflects on Cross-border Interconnections

Robb noted several significant milestones during his president’s report, pointing to NERC’s 50th anniversary and the 15th anniversary of the 2003 blackout in the Northeast. As Robb put it, a vegetation contact in Ohio led to power failures in Ontario and “returned the favor” for 1965, when a transmission line tripped in the Canadian province and blacked out Manhattan.

“These anniversaries and our meeting in Canada have given me a chance to reflect on the interconnected nature of our grid and the importance of our international collaboration,” he said. “The Electric Reliability Organization [ERO] is an agency for driving a common approach to reliability and security. We have a tremendous amount of work to do together, and it is a high priority for all of us.”

In addition to establishing reliability coordination services in the West, Robb listed as top issues security, integrating new technology, and a changing resource mix that could halve the U.S.’ coal fleet by 2030. (See related story, Sept. 4 Key Date for Potential Western RC Providers.)

Robb said the early returns on NERC’s six-month-old, five-year strategic plan have been “very positive,” but that there is a “tremendous amount of work to do.”

“It’s a very complex system to defend,” he said of the grid.

The continuing retirements of coal- and nuclear-fired generation, combined with the rapid deployment of variable resources and natural gas plants, is a problem “no one agency or individual forum can solve,” Robb said.

He said NERC has started work on a guideline to bring “greater clarity” regarding what kind of contingencies need to be studied.

“There are serious issues in the Northeast and desert areas of the Southwest,” Robb said. “We need to move along very quickly on this.”

CEO: AESO’s Challenges Same as Everyone Else’s

The Alberta Electric System Operator (AESO) faces steep challenges in meeting legislative mandates to phase out its coal-fired generation — which accounts for 40% of its installed capacity — and produce 30% of its energy from renewables by 2030. Adding to the challenge, it has very little hydro and no nuclear power in its generation mix.

But that’s no different than the challenges facing other jurisdictions, CEO David Erickson said.

AESO CEO Dave Erickson (left) and DOE’s Catherine Jereza | © *RTO Insider*

“With the integrated nature of the grid in North America, working together to solve those problems is important,” he said. “That’s the only way to get through this transformation, with the increasing penetration rate of renewables, cyber threats and changing generation mix. Those are real challenges we need to work together to solve. The ISO/RTO community has a big role.

“That said, NERC has an enormous role to get through this. I encourage the industry, I encourage NERC to work together. Whether we like it or not, we’re in this together. There’s a better path that’s more efficient and a lot more effective, if we do this together.”

August 19, 2018

Sept. 4 Key Date for Potential Western RC Providers

By Tom Kleckner

CALGARY, Alberta — Where once there was one, there will now be several players offering reliability coordinator (RC) services for most of the Western Interconnection.

How many RCs there will be, and who they are, should come into better focus on Sept. 4. That’s the unofficial deadline NERC and the Western Electricity Coordinating Council (WECC) have placed on Western balancing authorities and transmission owners to declare their RC.

The only certainty is that it won’t be Peak Reliability, which has been providing the RC function for the entire interconnection except Alberta since WECC was bifurcated in 2014, with WECC retaining Regional Entity functions. Peak announced last month that it will wind down its services by the end of 2019, having determined it will be financially unable to compete with CAISO’s and SPP’s RC services.

“Things have been moving quickly,” WECC CEO Melanie Frye told NERC’s Board of Trustees last week. “We’re hoping to get a bit more clarity on where everybody is looking to go, and whether they’re intending to go with [CAISO] or SPP, or whether some other option will emerge.

“That will allow us to see where the seams start to emerge and whether it will result in swiss cheese, where you have a small BA choosing one RC provider, but everyone else around them choosing another,” she said during the board’s Aug. 16 meeting.

Both CAISO and SPP have been aggressively pursuing potential members. CAISO said in January it will become its own RC and offer that function to other Western entities. SPP, which still hopes to integrate some of the Mountain West Transmission Group into its RTO, has filed a request with WECC to provide RC services to two Western Area Power Administration companies and says it has received interest from 26 other parties. (See WAPA Formally Requests SPP’s RC Services.)

North of the border, the Alberta Electric System Operator (AESO) already handles its own RC services, while BC Hydro is “leaning to forming” its own RC in British Columbia, Frye said.

“Ultimately, it will be the BAs and the transmission owners that make sure they have a certified RC,” Frye said. “I think we’re making progress there. We’ve had very good engagement with all of the potential RC providers. At a technical level, a lot of that planning is starting to take place, and that’s very healthy.”

As the RE for the Western Interconnection, WECC has hosted a series of stakeholder forums to discuss a future with multiple RCs. The agency will be responsible for ensuring the RCs are certified to perform the registered function; ensuring the BAs and TOs are aligned with a certified RC; and monitoring compliance with reliability standards. WECC has scheduled on-site certification visits with CAISO for March and SPP next summer.

The loss of a Western-wide RC has several stakeholders concerned.

RC Certification Timelines in the West | *WECC*

Utah Public Service Commissioner David Clark said it was his “personal hope” that whichever entity handles the RC function has “a governance structure that is independent and a process that’s transparent.”

“However this settles out, I hope the function will be performed in a way that is transparent … particularly to state energy advisers and state regulators and consumer advocates,” he said.

“I understand there are market considerations involved, but this has to be done very carefully,” warned NERC Trustee Dave Goulding, who chairs the organization’s Enterprise-wide Risk Committee. “As NERC, we don’t want to get into a situation where reliability is compromised.”

Not to worry, Frye said. “The focus on WECC’s work and NERC’s work will be on the intricacies of the interconnection and making sure that reliability across the seams with the RCs is maintained,” she told RTO Insider.

To that end, Frye, who is just completing her first month as WECC’s CEO, said the RE will be asking for a variance to the reliability standard that requires Western RCs to model the entire interconnection and all its remedial action schemes.

“We’ve started to engage this week at an executive level with the utilities, to ensure we have that connection-wide view,” she said.

Frye and WECC have the support of NERC and its CEO, Jim Robb, Frye’s predecessor at the RE. Robb joked that Frye is a “complete upgrade over the previous guy,” and he listed reliability coordination in the West as the second of four priorities that NERC is focused on in addressing industry risk.

“WECC and NERC are approaching this completely in lockstep around the changes that are happening in the West and [ensuring] that the resulting infrastructure works as well as possible, as with same heightened performance as a single RC,” he said. “We’re working very hard with WECC to understand the needs they have for these RCs.”

CAISO has notified WECC that it intends to seek certification as an RC. Frye said the ISO intends to go live within its BA footprint on July 1, 2019, and it will add its new members later in the fourth quarter. CAISO is meeting with Peak to coordinate data exchange and operations.

SPP also plans to go live with its RC functions in the last quarter of 2019. The RTO already has a West-wide model in its energy management system.

“SPP is proceeding along a slower timeline, but obviously, both need to be up and running before the December date Peak has announced,” Frye said.

August 19, 2018

NERC OKs Utilities’ Transfer to ReliabilityFirst

CALGARY, Alberta — The NERC Board of Trustees last week approved Wisconsin Public Service Corp.’s (WPSC) and Upper Michigan Energy Resources’ requests to move to ReliabilityFirst from Midwest Reliability Organization. NERC staff determined the transfer of the companies’ facilities would have a negligible impact on other grid users and operators, noting that the two utilities’ facilities have more geographic and electrical boundaries with RF than MRO.

Wisconsin Electric Power Co. acquired WPSC in 2015 and established UMERC as a new company in 2017. It applied for the registration transfer request in December.

The board also approved the 2019 Electric Reliability Organization enterprise business plan and budget and the budgets for the seven Regional Entities; approved a requirement that transmission and generation owners provide NERC with their geomagnetic monitoring data to support ongoing research and analysis of geomagnetic disturbance risks; and adopted three reliability standards:

— Tom Kleckner

August 17, 2018

NEPOOL Debates Fuel Security, Cost Allocation

By Michael Kuser and Rich Heidorn Jr.

The New England Power Pool Markets Committee on Tuesday debated ISO-NE’s proposals for conducting fuel security reliability reviews and allocating the costs of resources retained as a result.

The fuel security issue became a pressing matter following a July 2 FERC ruling that called the RTO’s request to waive several Tariff provisions “an inappropriate vehicle” for keeping the Mystic Generating Station running (ER18-1509). Exelon plans to retire the 2,274-MW plant when its capacity obligations expire in May 2022.

FERC found the RTO’s Tariff was not just and reasonable because it lacks a way to address fuel security concerns that could result in reliability violations as early as 2022. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

On July 13, FERC tentatively accepted a cost-of-service agreement for Mystic, ordering an expedited hearing process on unresolved issues (ER18-1639). (See FERC Advances Mystic Cost-of-Service Agreement.)

FERC’s July 2 show cause order set an Aug. 31 deadline for ISO-NE to submit interim Tariff revisions for filing a short-term, cost-of-service agreement to address fuel security concerns and a July 1, 2019, deadline for filing long-term Tariff revisions.

ISO-NE said it plans to review retirement de-list bids and Substitution Auction demand bids and may reject either type of bid for fuel security or reliability reasons. The RTO will notify market participants with retirement de-list bids that are needed for fuel security at the same time they receive the retirement determination notification from the Internal Market Monitor.

The RTO also said it may reject a reconfiguration auction demand bid if the resource has been identified as a fuel security resource in an FCA. It is proposing a “status quo” approach for Forward Capacity Auction 13, by which resources retained for fuel-security reliability will be entered as price takers, the same approach applied to resources retained for transmission reliability. “FERC has found such treatment just and reasonable in that context; fuel security is another reliability retention,” the RTO said in a presentation.

It said it will work with stakeholders to develop alternatives to the status quo for FCA 14 and FCA 15.

Price Suppression Concerns

Brett Kruse, Calpine’s vice president for governmental and regulatory affairs, told RTO Insider his company and other generation owners are concerned that pricing the Mystic units at zero in FCAs 13, 14 and 15 will suppress prices, fears they expressed in protests in the docket.

Kruse noted that FERC’s order rejecting the fuel security waiver outlined ways to treat Mystic’s out-of-market capacity to mitigate price suppression. “Notwithstanding FERC’s clear concern about price suppression, ISO-NE has since told us — and reiterated clearly this week — that they will not consider either of FERC’s suggested approaches, instead reverting back to their original position of putting Mystic in at zero,” Kruse said in an email.

Who Pays?

ISO-NE proposed to allocate out-of-market costs incurred to retain resources for fuel security regionally based on real-time load obligations (RTLOs). The new Tariff provisions would apply to FCAs 13, 14 and 15. The RTO said it was proposing regional cost allocation based on FERC’s prior ruling on allocating costs of its winter reliability program (ER13-1851).

iso ne nepool fuel security cost allocation — | *ISO-NE*

The NEPOOL Reliability and Markets committees will meet separately on Aug. 22 to vote on the proposal ahead of an Aug. 24 review and vote by the Participants Committee.

Some stakeholders expressed concern at Tuesday’s Markets Committee meeting that the RTO’s Pay-for-Performance program may not spread the costs for ensuring fuel security equitably. Under the program, launched June 1, costs for performance bonuses are supposed to be funded mostly by penalties on nonperforming resources and not directly by customers.

George McCluskey, assistant director for wholesale electric markets at the New Hampshire Public Utilities Commission, told the committee that his agency is concerned PFP will not eliminate fuel security risks because of state emission policies that limit operation of existing dual-fuel units and discourage investment in new dual-fuel capability.

“If resources are retained to address unmitigated fuel security risks, the out-of-market costs should be allocated to states whose emissions policies restrict market response to PFP,” McCluskey’s presentation said.

ISO-NE has identified Massachusetts and Connecticut as states with emissions policies that restrict market response. New Hampshire disagrees with Connecticut’s inclusion in that list and thinks costs should be allocated to Massachusetts only.

The RTO has also suggested that it may rely on reliability-must-run contracts for units needed to meet winter system reliability needs, for both fuel and transmission security, proposing that such units recover costs through regional allocation.

The Maine Public Utilities Commission opposes regional cost allocation, saying in a presentation that ISO-NE “offers no reason why it departs from long standing cost-causation principles” and that RMR costs should be assigned to local reliability areas.

“Regional allocation of RMR costs for units that are both transmission and fuel-insecure will mask underlying transmission issues,” the PUC said.

The commission noted that Mystic Unit 7 was retained for transmission security purposes in FCA 12 and said an analysis of Mystic Units 8 and 9 could reveal a similar need, but that ISO-NE has not conducted a study.

If Mystic 8 and 9 are needed for local reliability needs, the PUC said, congestion would occur at the Maine-New Hampshire interface in a fuel security event, meaning load shedding in Maine would not provide fuel relief to southern states and the state’s consumers would not benefit from avoiding load sheds.

“Maine, or any other reliability region, should not pay for RMR contracts related to fuel security unless Maine, or any other reliability region, can be seen as a beneficiary of the RMR,” the commission said.

Dan Dolan, president of the New England Power Generators Association, told RTO Insider his group strongly opposes ISO-NE’s proposal to apply an out-of-market approach to FCA 15 and potentially FCA 16, calling it an abdication of the grid operator’s market design and price formation responsibility.

“We have two fundamental issues: ensuring that this type of an out-of-market approach to fuel security ends as soon as possible and that resources held do not undermine the economic price formation in the Forward Capacity Market,” he said.

Calpine, NextEra Energy and Direct Energy are sponsoring an amendment that would allocate costs to network load instead of ISO-NE’s proposed allocation to real-time load obligations. Kruse said he expects support for their amendment from public power and state-represented entities.

Kruse noted that ISO-NE is using the transmission security RMRs as precedent for pricing treatment, but not for cost allocation.

Unlike the winter reliability program, whose costs were capped in advance and ranged from $30 million to $70 million annually, Kruse said, Mystic’s RMR costs will probably exceed $200 million per year. Because load-serving entities will add risk premiums to their expected costs, “the scope is significantly larger,” Kruse said. “Additionally, some LSEs may decide to sit out the market for now and not expose themselves to this pricing risk. Effectively, New England consumers will pay significantly more if the cost is allocated to RTLO instead of network load.”

August 17, 2018

CAISO Regionalization Bill Cast on Uncertain Course

By Hudson Sangree

SACRAMENTO, Calif. — Gov. Jerry Brown’s controversial plan to transform CAISO into an RTO took an unexpected turn Thursday in the State Senate’s Appropriations Committee.

CAISO regionalization western energy imbalance market — Brown | © *RTO Insider*

The committee’s members were set to vote on the plan’s first step, AB 813, either killing it or sending it to the Senate floor. Instead, the bill was withdrawn from Appropriations and sent back to the upper house’s Rules Committee.

The move likely was intended to give proponents time to work out a deal to allow the state-chartered CAISO to transform itself into an independent organization positioned to expand into the vast Western energy market.

“The Senate is taking the time needed to get this right, which is so important because full integration of the western electricity grid is vital to California’s clean energy future,” the Natural Resources Defense Council, a supporter of the measure, said in an email immediately after the move was announced.

The measure now could languish in Rules or be sent directly to the Senate floor as the legislature nears the end of its two-year session Aug. 31. Previous efforts to authorize CAISO’s expansion have stalled during the past two years in the face of strong opposition both inside and outside of California. (See Governor Delays CAISO Regionalization Effort.)

Regionalization Risks

AB 813 would authorize CAISO’s Board of Governors to submit a plan to the California Energy Commission to change the ISO’s governance structure to include transmission owners from outside California. If adopted, it would be the first step in a multiyear process to make CAISO an RTO for the West.

Those who’ve opposed AB 813 include the Sierra Club, municipal utilities and ratepayer advocates. They contend the measure would lump California in with coal-producing states such as Wyoming and put California at risk of greater interference from federal regulators under the Trump administration.

“I don’t buy the argument that we have to regionalize to take advantage of opportunities elsewhere,” said Barry Moline, executive director of the California Municipal Utilities Association, which represents publicly owned utilities throughout the state.

Moline told RTO Insider that the Western Energy Imbalance Market is already doing a good job at allowing energy to be bought and sold as needed among Western states, without building new transmission lines from wind farms in Wyoming to consumers in California.

Creating more renewable energy sources in California and using in-state transmission lines would further the state’s aims without adding risk, he said.

Moreover, he said, AB 813 would benefit wealthy out-of-state investors and conglomerates that want California ratepayers to pay for infrastructure from which they’d profit.

“There’s a lot of transmission companies and a lot of renewable resource developers that want to deliver kilowatt-hours into California,” Moline said. “These folks want to make money off of California.”

The proposal’s champions include Brown, CAISO, some environmental nonprofits and companies that stand to profit. It was introduced by Assemblyman Chris Holden, chairman of the Assembly Utilities and Energy Committee.

Those arguing for the bill said it would further California’s ambitious renewable energy goals by tapping into Wyoming windmills and Arizona solar arrays, while spreading sustainable energy throughout the West.

“This is the direction the grid is heading in,” said Carl Zichella, NRDC’s Western transmission director. “We need to be able to operate the system as a congruent whole.”

A set of amendments adopted Aug. 7 was meant to ease the concerns of those who worried about linking deep-blue California with the red states of the interior West.

“The purpose of the amendments is to reassure people that the progress California’s been making on renewable energy and climate change are not likely to be interfered with,” Zichella said.

The new language included a requirement that a California TO, retail seller or publicly owned electric utility not join or remain a member of an RTO with a centralized capacity market.

The amendments also insisted the state not undermine its ambitious scheme for achieving reductions in greenhouse gases and for purchasing electricity from renewable energy and zero-carbon sources.

The Aug. 7 changes, however, were apparently insufficient to ensure the measure’s passage through the Appropriations Committee before Friday, the last day for fiscal committees to meet and report out bills.

AB 813 can now be amended in the Rules Committee and sent to a vote of the full Senate before the last day of August, bypassing Appropriations. The bill passed the Assembly last year.

If it clears the legislature, Brown would then have until Sept. 30 to sign the measure into law. If it proves too complex and divisive for quick resolution, Brown could call a special session of the legislature this fall.

August 17, 2018

New SPP Member Walmart Eyes ‘Everyday Low Costs’

By Tom Kleckner

OMAHA, Neb. — When SPP CEO Nick Brown welcomed Walmart as one of the organization’s newest members last month, he made a point of noting the company was the first in the RTO’s large retail customer sector, which has been vacant since 2003.

A big deal for SPP, maybe, but old hat for Walmart. The retail giant is a member of every U.S. grid operator except CAISO, though that could eventually change.

Walmart Chris Hendrix SPP — Hendrix | © *RTO Insider*

“It depends on the regulatory environment there,” Chris Hendrix, Walmart’s director of markets and compliance, told RTO Insider.

As it is, Walmart is involved in most states that are open to retail competition, along with markets in Canada and the U.K., the latter through its Asda affiliate. Other markets, national and international, could follow “depending on how they’re structured,” Hendrix said.

“It’ll be easier for me to tell you what markets we aren’t in,” he said, ticking off Delaware, Michigan, Rhode Island and D.C.

Walmart’s foray into electricity markets began simply enough in 2003, when it joined ERCOT as a retail electric provider (REP) through its Texas Retail Energy entity. The wholly owned company has a customer of one, procuring power for Walmart, Sam’s Club and other subsidiaries and their many stores and distribution centers.

“Initially, it was all about lowering our costs,” Hendrix said. “We’re like other REPs [in Texas], only we don’t have sales people or customer service reps.”

Hendrix, who brought 15 years of energy experience in both the gas and electricity sectors when he joined Walmart in 2003, is part of a team of 15 former energy insiders and company associates “doing all types of things.”

Everything, that is, except sales. There’s no need to market outside the Walmart family of companies.

“We can be in control of our own destiny,” Hendrix said. “We can buy power how and when we want to, as opposed to being beholden to somebody else’s buying schedule at the utility, or the market products they can come up with. We access the wholesale market when and how we see fit.”

No Middleman

Hendrix said Walmart benefits from its membership in SPP and other grid operators by gaining access to hourly pricing and managing it for the company’s needs.

“We cut out the middleman, and we leverage our credit as Walmart,” he said. “The cost savings come from leveraging our credit, as well as operational efficiencies from having less people and services that we have to offer.”

Asked to quantify Walmart’s energy savings, Hendrix demurred.

“Cutting out the middleman’s margin is basically the savings,” he said. “Our goal is everyday low prices, and along with that, everyday low costs. Anything we can do to lower the cost helps the business opportunities of Walmart.”

At the same time, Walmart’s involvement with RTOs and ISOs has been instrumental in the company’s sustainability program. The retailer has been working toward a goal of operating with 100% renewable energy since 2005.

Walmart has been the eighth largest corporate purchaser of wind and solar power globally since 2008 with 781 MW, according to Bloomberg New Energy Finance, and it gets about 28% of its electricity from renewables. Just before the presidential election in 2016, the company announced it intended to get half its power from wind and solar energy by 2025, passing Google as the world’s top buyer of renewable power.

Nothing has changed, despite the Trump administration’s lack of support for renewables.

“Our goals and objectives have not changed at all since they were first introduced … and more specifically, in November before the election,” Hendrix said. “By the time it’s all finished, 35% of our load in Texas will come from wind. That’s a significant number, but it’s still not a 50% number. We’re looking to do a lot more, because we can’t get there with on-site solar. It has to be large-scale solar and large-scale wind.”

Hendrix said one of the side benefits of participating in energy markets is purchasing renewables on a wholesale basis. To participate in most of the markets it’s in, Walmart had to become a member of the grid operators. SPP doesn’t have that same requirement, but its 18 GW of installed wind capacity was too enticing to pass up.

“As we do a lot more renewables, a lot of that … is in the SPP territory,” he said.

Walmart’s annual $6,000 membership fee is a small price to pay. As the executive responsible for regulatory and legislative matters for the company’s retail and wholesale energy businesses, Hendrix also gets to have a vote in SPP’s stakeholder process.

“We decided, as we have been in all those other markets and we have seen the benefits of being on those committees, it made sense to join SPP,” he said. “We try to understand what’s happening with the ISO’s policies and try to steer them in the direction that we think is best. We’ll always advocate for competition and free markets.”

SPP’s hefty exit fee — about $673,000 for non-transmission owners, the RTO estimates — has scared away some potential members, but not Walmart.

“We don’t intend to go anywhere,” Hendrix said. “It works out to $6,000 a year. We think we get the benefit of being involved in the market.”

August 17, 2018

Line Opponents Set Sights on PJM in Public Campaign

By Rory D. Sweeney

PJM may soon have to choose between continuing to greenlight its “largest-ever” congestion-reducing transmission project or risking a public relations war with opponents of the project who live in its proposed pathway and have gained influential allies in their fight to have it shelved.

The $340.6 million project proposed by Transource Energy would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border — one between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; and another between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.

PJM and regulatory filings refer to the project as “9a,” while Transource has dubbed it the Independence Energy Connection.

PJM Transource Independence Energy Connection — Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | *Transource*

“Until now, landowners have considered Transource to be their opponent, but unless PJM soon exercises its right to withdraw the project, we will hold PJM responsible,” wrote the opponents — consisting of three landowner groups in Harford, York and Franklin counties — in a June 30 letter to the RTO’s Board of Managers.

“PJM will become the target of our media outreach, our legislative efforts and, potentially, our legal efforts as we hold PJM responsible for the tremendous costs incurred by landowners who will ultimately emerge victorious,” the letter warned. “Further PJM support of this project will be viewed as an abuse of process.”

Project 9a

PJM selected Transource’s market efficiency proposal in August 2016 to reduce congestion along the RTO’s AP South interface. As part of PJM’s implementation of FERC Order 1000, the congested interface was included in its inaugural window for proposing such projects and received the most attention, attracting seven of the 17 total proposals submitted. (See AP South, Cleveland Draw Congestion Relief Proposals.)

At the time, PJM CEO Andy Ott called it “PJM’s largest-ever market efficiency project,” projecting it would save ratepayers $622 million in congestion costs over 15 years. The eastern portion would relieve the Graceton-Conastone 230-kV line, which was the most congested line in PJM’s 2016 long-term analysis. Its congestion costs in 2017 were $51.8 million and were expected to rise over the next 10 years to $68.88 million in 2027.

Another line leading into Graceton, the 230-kV Bagley-Graceton, was third on the list with $23.59 million in 2017 congestion costs and estimates of $59.57 million in 2027. A third line in the area, the 500-kV Peach Bottom-Conastone, was second on the current list with $32.78 million in congestion costs, which are expected to drop precipitously to $1.9 million in 2027.

FERC approved a formula rate for the project in January 2017 and a settlement this January on Transource’s return on equity, but it refused to reconsider whether the company should be allowed to make single-issue rate filings or recover all costs if the project is canceled through no fault of the company.

Transource received permission, starting on Jan. 31, 2017, to recover all “prudently incurred costs” if it must abandon the project for reasons “beyond Transource’s control.” All costs prior to that are subject to a cost-sharing policy FERC ordered in Opinion 295, through which Transource could recover 50% (ER17-419).

‘Do the Right Thing’

But opposition has developed among residents who live around the proposed paths, and they have orchestrated an awareness campaign that netted support from high-level elected officials on both sides of the state border. U.S. Rep. Scott Perry (R-Pa.) wrote a letter to FERC in March, calling on the commission to reconsider whether Order 1000 “puts impacted private citizens at a distinct disadvantage” in opposing projects. FERC Chairman Kevin McIntyre responded in April, outlining how projects are selected through Order 1000’s competitive solicitation process and assuring Perry that PJM re-evaluates its decisions annually.

Maryland Gov. Larry Hogan wrote to PJM’s Board of Managers on July 10 to “express concerns” that “the project will take prime agricultural land out of production, including land that is in permanent agricultural easements.” He sympathized with “the need to reduce power congestion in Maryland” but requested that the project be halted pending a re-evaluation or rerouting using existing rights of way, along with greater engagement with residents and state agricultural and energy agencies.

PJM says it never received Hogan’s letter.

“We have no record of receiving it,” PJM spokesperson Susan Buehler told RTO Insider in an email.

But the PJM board did receive the letter from opponents, who mentioned McIntyre’s “favorable response” and called for the project to be removed from the Regional Transmission Expansion Plan because the benefits have dropped substantially since the RTO last analyzed it.

“While we understand that PJM feels a responsibility to Transource to allow them to fail gracefully at the state level after a protracted review, the facts demand that PJM cancel this project immediately,” they wrote.

The opponents argued that near-universal local opposition and unknown environmental impacts should induce staff “to use your professional and moral judgment to do the right thing.”

Citing testimony from PJM’s Paul McGlynn to the Maryland Office of People’s Counsel (OPC), they argued system changes since last year’s annual analysis have reduced the potential benefits while costs have likely risen. The reference was to a data request from the OPC to PJM as part of the Maryland Public Service Commission’s review of Transource’s application for a certificate of public convenience and necessity for the project. In a portion of the data request provided to RTO Insider by the opposition, McGlynn appears to indicate that the congestion savings have fallen from the $620 million expected when the project was approved to $245.75 million in the most recent analysis.

However, that number is not a direct input in PJM’s analysis of such projects. That analysis, which was performed last September and posted in January, still produced a benefit-to-cost ratio of 1.32, exceeding PJM’s 1.25 threshold for considering a proposal. PJM was unable to independently verify the document cited by the opposition but confirmed that the information McGlynn would have used came from the analysis that resulted in the 1.32 benefit-cost ratio. Any changes in the variables will be included in the next analysis coming in September.

“PJM is currently conducting a third evaluation of the project, and we are using up-to-date data in doing so,” PJM spokesperson Jeff Shields said in an emailed statement. “In the past, the PJM board has canceled several major transmission projects in the region — including the [Mid-Atlantic Power Pathway] and [Potomac-Appalachian Transmission Highline] projects in 2012 — as a result of such re-evaluations.”

Impact on the Ground

The opposition argues that PJM does not give enough consideration to utilizing existing infrastructure. They point out that PPL’s existing Conastone-Otter Creek 230-kV line, which largely mirrors the proposal’s eastern path, has capacity to run another line.

PJM confirmed that PPL offered a proposal among the 41 submitted to address the AP South interface congestion, but its benefit-cost ratio did not meet the 1.25 threshold. A PPL representative said the company’s proposal “involved adding equipment to an existing substation.”

[Editor’s Note: An earlier version of this article incorrectly reported, based on information provided by PJM, that PPL had not submitted a proposal.]

Because it’s PJM’s largest market-efficiency project, “they want it to go through at any cost to land owners and local communities,” said Patti Hankins of Harford County, who joined the opposition in 2017 after learning property belonging to her husband’s cousin would be impacted.

Opponents are also concerned about the safety of high-voltage lines and the potential impact on destination agriculture, such as Shaw’s Orchard Farm Market in White Hall, Md., and other farm-to-table operations. New construction should be the last resort, they argue.

“The impact on the ground is so significant that there should be no new construction until it’s absolutely necessary,” said Aimee O’Neill, a Maryland resident and president of grassroots group Stop Transource Powerlines MD, a signatory to the opposition letter.

Political Action

O’Neill has been lobbying state legislators to pass five bills that would require developers to use existing transmission infrastructure where possible before building new. Opponents of the bills, which O’Neill hopes will be reintroduced in the legislature’s 2019 session following mid-term elections, argue that state regulatory oversight is satisfactory and that such laws would significantly upset plans to replace much of the regional grid that is nearing the end of its usable life.

“Maryland is not prepared to protect the interests of the people in the face of a changing energy environment,” O’Neill said. “There’s really nothing wrong with requiring those upgrades to be completed in existing easements with existing equipment, and what we’ve learned is that unless there is legislation requiring that … people [opposing new projects] are doomed to go through this time and again.”

Every property owner along the proposed routes has objected to the project, so Transource will need eminent domain authority to take them, O’Neill said. The company is currently working through permitting and eminent domain proceedings with regulators in both states.

A Transource representative said the company would not a comment on the opponents’ letter because it is directed to PJM.

August 16, 2018

FERC OKs MISO Storage Filing; Rejects IPL Rehearing

By Rich Heidorn Jr.

FERC on Wednesday accepted MISO’s compliance filing spelling out rules for its new energy storage category, rejecting a protest and rehearing request by Indianapolis Power & Light (ER17-1376-002, ER17-1376-003).

MISO was responding to FERC’s March 23 ruling approving the creation of a Stored Energy Resource Type II that ordered the RTO to flesh out the concept further. MISO proposed the new storage category last year following IPL’s complaint against the RTO’s existing storage participation rules. (See FERC OKs MISO Plan to Expand Storage.)

SER–Type II FERC MISO energy storage IPL — IPL Harding Street Station battery interior | *IPL*

In its compliance filing, MISO revised the definition of SER-Type II resources to clarify that they are eligible for up/down ramp capability if technically capable.

It also said that SER-Type II resources will be subject to the same must-offer obligation that applies to other capacity resources. MISO said it would be expensive and time-consuming to redesign its day-ahead market software to exclude such resources from the must-offer obligation. However, MISO also revised its Tariff to allow the storage facilities to derate their capacity to limit their supply to four hours.

The filing also revised the definition of station power to exclude the energy used to charge an SER-Type II resource.

In Wednesday’s ruling, FERC said MISO’s filing was largely responsive to the March order, although it agreed with IPL that Tariff changes regarding up/down ramp capability are incomplete and ordered the RTO to add additional Tariff language.

The commission rejected IPL’s protest of MISO’s proposal to apply the must-offer rules to SER–Type II resources that provide capacity. But it noted that Order 841 required each RTO/ISO to demonstrate that its existing market rules allow storage resources to provide capacity in a way that acknowledges their limitations.

“Therefore, while we accept MISO’s clarification that its must-offer rules apply to SER–Type II resources, we note that MISO still has a compliance obligation under Order No. 841 to demonstrate how its capacity market acknowledges the energy limitations of electric storage resources,” the commission said.

The commission also rejected IPL’s request for rehearing, saying it had addressed the company’s arguments in both the March 2018 order and a February 2017 ruling. “Indianapolis Power does not raise any issues in its rehearing request challenging the commission’s conditional acceptance of MISO’s compliance filing that are new to this proceeding or that Indianapolis Power had not raised earlier,” FERC said.

August 15, 2018

NEPOOL Files Press Ban with FERC

The New England Power Pool filed a proposal with FERC on Monday to codify its unwritten ban on press attendance at stakeholder meetings (ER18-2208).

The proposed amendments to the NEPOOL Agreement add a definition of “press” and bar anyone working as a journalist from becoming a NEPOOL member or alternate for a participant.

NEPOOL ISO-NE FERC stakeholder meetings — NEPOOL’s 2017 Annual Report included a photo of a stakeholder meeting. Of the seven RTOs and ISOs in the U.S., only New England’s bars the press and public from attending. | *NEPOOL*

New England is the only one of the seven U.S. regions served by RTOs or ISOs that prevents press coverage of stakeholder meetings.

NEPOOL’s Participants Committee approved the press ban June 26 with 79% in favor in a sector-weighted vote. An alternative proposal that would have made the press eligible for a non-voting membership failed with only 27% in support, with only the end-user sector strongly in support. (See NEPOOL Votes for Press Ban, Discusses Fuel Security.)

RTO Insider prompted the vote by having reporter Michael Kuser, who lives in Vermont, apply for committee membership as an end-user customer in March. NEPOOL has not acted on the application.

NEPOOL’s filing says that permitting press to become a participant or to represent a participant “would adversely impact NEPOOL’s ability to continue to foster candid discussions and negotiations in its stakeholder meetings. Without such discussions and negotiations among its members, ISO New England Inc. and state officials, NEPOOL would be limited in its ability to narrow or resolve complex issues within the NEPOOL stakeholder process. This could have the effect of increasing the issues and scope of litigation at the commission on ISO-NE Tariff changes and related matters before it.”

It cited concerns that press attendance at meetings “could encourage public posturing, pre-scripted statements and reduced willingness or ability by members to freely explore ideas or solutions.”

The filing notes that FERC ruled in a 2001 order that the NEPOOL Agreement is not a FERC tariff but “a supporting document … [and the] equivalent of a utility’s Articles of Incorporation.”

While it relieved NEPOOL of filing the agreement in tariff form, the commission said the organization must continue to file proposed changes to the agreement with the commission. “The commission will continue to review the proposed changes that fall within its authority under the [Federal Power Act],” the commission said.

NEPOOL said the commission is in “‘an essentially passive and reactive’ role’” and can only reject the filing if it finds the changes not “just and reasonable.”

“Thus, if the commission determines that a provision that precludes press from becoming a NEPOOL participant or participant representative falls within its authority, it can only reject that provision if it concludes that the changes are unlawful,” it said. “The commission’s review does not extend to the question of whether there are other reasonable approaches to the press membership issue.”

NEPOOL requested the change take effect Nov. 1.

RTO Insider began covering PJM stakeholder meetings in early 2013 and expanded coverage to stakeholder meetings of MISO and NYISO in late 2014, SPP in early 2015, and ERCOT and CAISO in 2016. RTO Insider also began covering ISO-NE in late 2014 but has been barred from all stakeholder meetings except for the Planning Advisory Committee, which is run by the RTO.

— Rich Heidorn Jr.

August 15, 2018

NYISO Business Issues Committee Briefs: Aug. 13, 2018

RENSSELAER, N.Y. — NYISO’s Business Issues Committee voted Monday to approve a revised charter for the state’s Integrating Public Policy Task Force (IPPTF), the group exploring how to incorporate the cost of CO₂ emissions into the ISO’s markets.

business issues committee nyiso bic carbon dioxide emissions ipptf — DeSocio | © *RTO Insider*

Michael DeSocio, NYISO senior manager for market design, highlighted a single sentence added to clarify the task force’s mission: “Incorporating the cost of carbon dioxide into the wholesale energy markets is intended to provide the most efficient means to incentivize carbon abatement from a broad set of electric suppliers, supporting the state’s clean energy policies to reduce electric sector carbon dioxide emissions while continuing to leverage market forces to provide affordable, reliable electricity.”

The IPPTF is being run by NYISO after initially being set up in collaboration with the state’s Department of Public Service. The group next meets at ISO headquarters Aug. 20.

Broader Regional Markets Report

Staff continue work on clarifying the minimum deliverability requirements for external capacity from PJM into NYISO’s Installed Capacity (ICAP) market, Nicole Bouchez, ISO principal economist, highlighted from the monthly Broader Regional Markets report.

At the July 31 Installed Capacity/Market Issues Working Group meeting, the ISO presented its proposed market design to improve the supplemental resource evaluation process for external capacity resources. It will communicate next steps after evaluating stakeholder feedback.

In related matters, Bouchez highlighted that the Independent Power Producers of New York last month filed a complaint asking FERC to direct the ISO to disallow PJM resources from selling ICAP into New York City (Zone J) using certain unforced capacity deliverability rights (UDR) facilities.

Public Service Electric and Gas in May had filed a complaint against Consolidated Edison concerning two transmission lines, B3402 Hudson-to-Farragut (B line) and C3403 Marion-to-Farragut (C line). PSE&G alleged that underwater portions of the lines may have been permanently damaged and should be removed.

On June 6, the ISO filed a protest with FERC indicating that removal of the B and C lines would undermine resilience in both New Jersey and New York and requested that PSE&G’s complaint be denied.

Sub-20-MW Constraint Reliability Margin Values

The BIC approved the ISO’s proposal to apply a sub-20-MW constraint reliability margin (CRM) value to certain facilities where warranted. A CRM is a portion of a transmission facility’s capacity kept in reserve to help meet NERC and other reliability standards. A few facilities use the normal 20-MW CRM under most conditions but also use a larger CRM during periods of higher load, such as the Gowanus Substation in Brooklyn.

David Edelson, manager for operations performance and analysis, said the ISO would base its determination to use a sub-20-MW CRM mainly on the desire to keep CRM values at a level representing no more than 10% of a facility’s rating.

NYISO’s Tariff currently requires use of a minimum value of at least 20 MW for any non-zero CRM value employed in the day-ahead and real-time markets. As the ISO continues to consider inclusion of certain 115-kV facilities with lower thermal ratings (relative to 230-kV and higher facilities) into its dispatch, a 20-MW CRM can often represent a significant percentage of the facility limits.

For instance, many 115-kV facilities have post-contingency limits of 150 MW or lower. A 20-MW CRM represents 13% of the rating for a 150-MW facility.

In megawatt terms, a facility with a 150-MW rating and a 20-MW CRM would be secured in the dispatch using a 130-MW limit. By comparison, a typical 345-kV circuit has a 1,550-MW post-contingency rating with a 20-MW CRM representing only about 1% of the rating.

The ISO will seek Management Committee approval at its next meeting Aug. 29, and by the ISO’s Board of Directors during a special call on the issue in early September, with a FERC filing targeted for the middle of next month.

T&D Manual Revisions

The BIC voted to approve incorporating into the ISO’s Transmission and Dispatching Operations Manual (T&D Manual) an existing technical bulletin on the procedures transmission owners must use to secure their facilities into the Business Management System (BMS) day-ahead and real-time market models.

The information would be located in a new section in the manual and would not substantively differ from the existing guidelines, said Ethan D. Avallone, senior market design specialist.

The committee also approved proposed revisions to Section 3.1.3 of the T&D Manual, specifying that the New York Control Area reserve is monitored through the use of the Reserve Monitor Program; and to Section 4.2.11, regarding procedures when a transmission owner or the Northeast Power Coordinating Council observes or reports significant geomagnetically induced currents.

Distillate Prices Up 40% Y-o-Y

NYISO locational based marginal prices (LBMP) averaged $39.58/MWh in July, up nearly 18% from June and 10% higher than the same month a year ago, Bouchez told the BIC.

Year-to-date monthly energy prices averaged $46.64/MWh in July, a 28% increase a year ago. July’s average sendout was 529 GWh/day, higher than 445 GWh/day in May and 454 GWh/day a year earlier.

Transco Z6 hub natural gas prices averaged $2.87/MMBtu, up about 17% from both June and a year earlier. Distillate prices dropped slightly compared to the previous month but were up 40% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $15.05/MMBtu and $14.81/MMBtu, respectively.

Total uplift costs and uplift per megawatt-hour dropped from June, but the ISO’s 44-cent/MWh local reliability share in June came in higher than the previous month’s 18 cents/MWh, while the statewide share dropped from 12cents /MWh to -57 cents/MWh. Thunderstorm alerts (TSAs) accounted for 21 cents/MWh for the month, down from 39 cents/MWh in June. TSAs occur when actual or anticipated severe weather conditions lead the ISO to reduce transmission transfer limits on the UPNY-SENY interface, which often leads to severe congestion.

— Michael Kuser