Page 1238 – RTO Insider

June 6, 2019

NECPUC Day 2: McNamee Reiterates Storage Dissent

By Michael Kuser

HARTFORD, Conn. — FERC blurred the line between state and federal oversight over power issues last month when it rejected multiple requests to reconsider its landmark electric storage order, Commissioner Bernard McNamee told the New England Conference of Public Utilities Commissioners (NECPUC) at its 72nd annual symposium Tuesday.

The May ruling prompted a partial dissent from McNamee over the commission’s rejection of requests to allow states to opt out of rules giving FERC jurisdiction over storage resources connected to utility distribution systems (Order No. 841-A). (See FERC Upholds Electric Storage Order.)

“I dissented partially from this order because I felt that for behind-the-meter storage resources and those resources that are connected at the distribution system, FERC exceeded its authority,” McNamee said.

NECPUC — FERC Commissioner Bernard McNamee addressed the New England Conference of Public Utilities Commissioners at its 72nd annual symposium June 4 in Hartford, Conn. | © *RTO Insider*

The Federal Power Act took a two-pronged approach, giving FERC authority to make decisions about the transmission of electric energy in interstate commerce and the sale of electricity at wholesale, while also recognizing states’ jurisdiction over generation and distribution facilities, he said.

“The majority of the commission reasoned that because energy resources would affect wholesale prices, FERC had jurisdiction to tell the states that they had to allow energy storage facilities to connect at the distribution level and, by the way, saying, ‘You figure out the safety issues,’” McNamee said. “I fundamentally thought that was exceeding our authority.

“Where is the line between the states and the federal government on these issues?” he continued. “What’s the policy about this? What do the parties say of this? What is the legal thinking from the parties about this? I’m trying to decipher that.”

Issued in February 2018, FERC Order 841 set a Dec. 3, 2019, deadline for RTOs to comply with the directive to allow storage resources to provide any services of which they are capable. The commission in February approved FERC Accepts ISO-NE Storage Tariff Revisions.)

Utility-scale or not

The anticipated rapid growth of storage was a hot topic at the conference, with ISO-NE last month confronting 2,500 MW of storage resources in its queue, compared with 1,381 MW just a month earlier. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)

“Our interconnection queue doesn’t mean all those projects will get built,” said Christopher Parent, ISO-NE’s director of market development, adding that the RTO will focus on bringing storage projects into the market.

“Sometimes behind the meter, sometimes in front … our market constructs enable all storage to participate and select the services it provides,” Parent said. “It’s important to get the price signals right for the market.”

Mike Calviou, National Grid senior vice president for strategy and regulation, said his company will own and operate 25 MW/146 MWh of storage by the end of the year.

“We’re also interconnecting non-utility scale storage and have 17 MW paired with solar and 1 MW in the queue,” Calviou said.

The utility put a 6-MW/48-MWh storage facility on Nantucket to back up a diesel generator and avoid the need to build more costly transmission lines.

“We’re working with ISO-NE to maximize benefit, so you don’t just write incentives to create storage but to use it,” Calviou said.

“I think storage should be seen as part of the solution,” he said, adding that planners should not be technology-agnostic.

Jeffrey Bishop, CEO of storage developer Key Capture Energy, which has 10% of the storage in ISO-NE’s queue, said, “If the wholesale market doesn’t have the right incentives to support storage development, the states will step in and do that. Massachusetts has its Clean Peak Standard because the wholesale market doesn’t compensate for the various services that storage provides.”

Massachusetts mandates that electricity suppliers serve a certain portion of their sales with “clean peak” resources, with the state’s Department of Energy Resources each year determining the minimum standard. (See Mass. Inaugurates Clean Peak Standard.)

Lon Huber, a director at energy consultancy Navigant, cited time-of-use rates as evidence of how storage is moving from environmental value to systemwide benefit value.

Storage can respond to price signals at the peaks, Huber said, noting how fossil fuel-fired generators were unable to work in a cold snap and “should be penalized for not providing capacity when needed.”

Time-of-use rates are the tool that allow customers to shift their demand to shoulder periods, said Anne Hoskins, chief policy officer for solar developer SunRun.

“In two years, we’ve seen a dramatic increase in customer demand for storage,” yet in some ways the system is living in the past, Hoskins said. “During the wildfires there was a massive rush on generators … and it was very disconcerting to me, living in California in a fire district, to receive a notice from my utility that said ‘Be prepared for the shutoffs, and get your gasoline for your generator.’ And this is in a state where climate goals are very high, like the climate goals here.”

Connecticut Public Utilities Regulatory Authority Chair Marissa Gillett confessed that her state is one of three in the region (along with Rhode Island and Maine) that do not yet support a “bring-your-own-device” (BYOD) program.

BYOD offers utility customers rebates for installing and enrolling connected thermostats and battery energy storage devices.

“The New Hampshire public consumer advocate supported BYOD, but not my own state,” Gillett said.

Hoskins said that despite the slow start in some states, “New England is showing tremendous leadership in this area … and it takes a lot of legwork to set the tariffs.”

She noted that neighboring NYISO is also active on the issue, and that PSEG Long Island in the next couple of weeks is about to launch its own BYOD program.

(For Day 1 coverage of the NECPUC event, see New England Regulators Talk Wholesale Market Evolution.)

June 6, 2019

NERC Operating Committee Briefs: June 4-5, 2019

ORLANDO, Fla. — The NERC Operating Committee approved the following in meetings Tuesday and Wednesday:

The Resources Subcommittee’s revised reliability guideline on primary frequency cont rol under BAL-001-TRE-1 and PRC-001-WECC-CRT-2. Originally published in 2015, the guideline’s definitions were updated and the section on recovery periods was expanded. Applicable to: balancing authorities, generator operators (GOPs), generator owners (GOs), transmission operators (TOPs) and transmission owners.
The Data Exchange Information Requirements Task Force’s compliance guidance on data exchange infrastructure and testing requirements under TOP-001-4 R20, R21, R23 and R24, and IRO-002-5 R2 and R3. Includes clarification of “redundant and diversely routed” language and testing requirements. Applicable to: TOPs, BAs and reliability coordinators.
The Real–time Assessments Quality Task Force’s compliance implementation guidance on the quality of analysis used in completion of a real-time assessment under TOP-010-1(i) R3 and IRO-018-1(i) R2. Applicable to: TOPs, RCs and applicable supporting entities.

The committee also authorized the posting of the Event Analysis Subcommittee’s revised ERO Events Analysis Process for a 45-day industry comment period. Version 4.0 adds: information on weather-related events; references to inverter-based resources in Categories 3 and 4 events; and expanded appendices. Applicable to regional entities and registered entities (e.g., TOs, GOs, load-serving entities).

IRPTF Scope Document Remanded

Task force Chair Allen Schriver, of NextEra Energy, said the new document was a spinoff of the group’s September 2018 reliability guideline: BPS-Connected Inverter-Based Resource Performance.

“The [inverter] manufacturers kept telling us, ‘Nobody told us what they wanted.’ … So we wrote this performance guideline, and industry came back to us and said, ‘Can you turn that into interconnection requirements?’”

Schriver said the new document recommends improvements to both performance and modeling requirements. “Modeling is still an issue we have with solar sites in providing the correct models for how the site operates,” he said.

The committee postponed a vote on a revised scope document for the task force. OC Chair Lloyd Linke said he, Planning Committee Chair Brian Evans-Mongeon and task force leaders agreed that “the product of the task force is still too vaguely defined.”

Rich Bauer, NERC’s associate director of reliability risk management-event analysis, suggested the committee consider converting the task force into a working group, saying there is no clear end to the task force’s work.

“What we discovered was, once we got the task force together and we started talking about momentary cessation, every time we talked about something … there’s something else that crops up that we didn’t know, we didn’t understand, that we need to have more work on,” he said. “Inverter-based resources are changing our lives in the way that we operate the system. … The work that we’re doing is not just a specific function with borders. It is a body of work that is ongoing, at least for the near future.”

Linke’s Poignant Farewell

Linke received a standing ovation from the committee after concluding the final meeting of his two-year term as chair. The Western Area Power Administration vice president of operations choked up as he recalled his tenure.

WAPA’s Lloyd Linke received a standing ovation at his last meeting as Operating Committee chair. | © *ERO Insider*

He said the IRPTF’s high-profile work in response to the Blue Cut Fire and work by other special task groups “overshadowed a lot of our normal day-to-day activities in ensuring reliability.”

“I’m just hoping that … we’re still able to do the reliability work we’ve done in the past,” after the proposed reorganization that could combine the OC with the Planning Committee and the Critical Infrastructure Protection Committee. (See “Potential Change to Committee Structure,” NERC MRC, Trustees Meeting Briefs: May 8-9, 2019.)

WAPA’s Lloyd Linke concluded his two-year term as chairman of the NERC Operating Committee. | © *ERO Insider*

Asked after the meeting whether he feared the committee’s role could be diminished, Linke responded, “The devil is in the details.”

“That process can move forward and be totally successful. I don’t have any doubts about that,” he continued. “But it’s also going to lead to a period of turmoil, which all change creates. And … how that group deals with that turmoil and drives through that turmoil would have an impact on their capabilities. The key is in the subcommittees. As long as the activities of the subcommittees is not significantly disturbed, [it will be OK].”

MISO’s David Zwergel was elected to succeed Linke as chair for 2019-2021. Doug Hils of Duke Energy was elected to succeed Zwergel as vice chair.

Nominations for the annual OC election will be accepted through June 24.

June 5, 2019

Costco Stays with Dominion, Va. Commission Rules

By Christen Smith

In a ruling that highlights growing rifts in Virginia’s electricity sector, the State Corporation Commission rejected Costco’s bid to buy power from utilities across state lines, saying that keeping the retail giant a customer of Dominion Energy best serves the public interest.

The SCC ruli n g handed down June 1 prevents the company from aggregating its total electricity consumption to take advantage of a 2007 state law that allows large-scale customers with a peak demand of 5 MW or higher to shop around for suppliers The law provides the SCC with broad discretion for how to apply it.

While the commission agreed with Costco’s contention that Virginia’s regulatory framework supports unjustified rate hikes, it shifted the burden onto the state legislature to solve the issue of rising energy costs.

The SCC noted Dominion’s “rate-captive” customers have faced “a decade of rising rates and the likelihood of even higher rates in the future.” Allowing Costco to abandon Dominion under existing rules, the commission said, would force other ratepayers to make up the $1.57 million in lost annual revenues.

Although the state law enshrines an “escape valve,” the SCC determined it unfair for Costco to save money “at the expense of other customers.”

“This Commission will not allow small customers who cannot escape this structure, predominantly small businesses and residential customers, to be further burdened by the identified cost-shifting that will occur if larger customers like Costco choose to seek better deals for themselves outside of Dominion’s system,” the SCC wrote.

Costco argued “a wave of commercial customers leaving the utility through aggregated retail choice” would encourage Dominion to stop hiking prices to fund expensive system upgrades — often incompatible with clean energy goals. The commission denied Walmart’s request in February, while petitions from Target, Kroger, Harris Teeter and Cox Communications remain outstanding.

In the filing, a Costco witness accused Dominion of “over-earning on its frozen base rates for a number of years,” creating an “enormously frustrating” incentive “to keep what I view as the customer’s money.”

Costco’s comments underscore the rising tension between retail choice advocates and Dominion Energy, Virginia’s dominant utility company and most generous corporate campaign donor. Last month, a coalition of unlikely allies launched efforts to bust up the company’s monopoly — more than a decade after state lawmakers officially abandoned the deregulated electricity market design — insisting its well-funded lobbying efforts leave ratepayers footing the bill for wasteful infrastructure spending. (See Va. Group Seeks End to Dominion M onopoly.)

Dominion contributed more than $452,000 to state candidates and committees last year, according to the Virginia Public Access Project, making it the commonwealth’s largest campaign donor within the energy sector. That same year, the utility also advised lawmakers on an overhaul of its regulatory framework that allowed it to invest a larger share of revenues in new projects, rather than refunding customers for “overpayments” — as the SCC often made the utility do in years past.

Greg Morgan, Dominion’s general manager of regulatory affairs, said companies only began using the aggregation clause to pursue retail choice last year, despite its existence since 2007.

The utility also defended its infrastructure investments during an interview Tuesday, citing plans for six new solar facilities with a combined 350-MW capacity in Virginia and North Carolina, scheduled to come online in 2020. Dominion also supports cutting greenhouse gas emissions in half over the next decade and by 80% by 2050.

When it comes to the SCC’s decision, Dominion agreed it best protects customers from the shifting burden of costs while still supporting the diversification of the utility’s energy portfolio to include more renewable resources. Le-Ha Anderson, a Dominion spokesperson, said the company offers many different rate structures for customers unhappy with costs — a much more reasonable alternative than leaving the company altogether.

June 5, 2019

CAISO’s RC West Earns NERC Certification

By Robert Mullin

CAISO said Monday its RC West operation has achieved a “major milestone” after attaining the NERC certification needed to begin providing reliability coordinator services to balancing authorities in California and parts of Mexico on July 1.

The certification — issued by the Western Electricity Coordinating Council through its delegated authority from NERC — marks a key step in transitioning RC oversight of the Western grid away from Peak Reliability, which last summer announced it would be ceasing operations by the end of 2019.

“The NERC certification is an important turning point in our effort to become the reliability coordinator for the Western region,” CAISO CEO Steve Berberich said in a statement. “This was a huge lift for our staff since beginning this venture in January 2018, and the certification speaks to the dedication and hard work across the organization.”

In early January 2018, CAISO announced it would “reluctantly” depart from Peak Reliability and create its own RC — just a month after Peak floated its plan to develop an organized electricity market in partnership with PJM, competing with the ISO’s own expansion efforts. (See CAISO to Depart Peak Relia b ility, Become RC.) By last July, it was evident Peak would lose most of its customers to CAISO’s lower-cost services, prompting the Vancouver, Wash.-based company to begin winding down its own operations and pull out of the joint effort with PJM. (See Peak Reliability to W ind Down Operations.)

Since then, CAISO has worked quickly to stand up RC West as the Western Interconnection, facing the uncertain journey of moving from two to five RCs, with SPP, BC Hydro and Gridforce also sharing in the carve-out of Peak’s former territory. (See RC Transition Fraught with Pitfalls, WECC H e ars.) The Alberta Electric System Operator has historically acted as its own RC and will continue to do so after the dissolution of Peak.

WECC conducted its full certification review of RC West in late March, which consisted of an onsite visit by observers from WECC, NERC and one other RC, as well as at least one BA and transmission owner. During the process, RC West staff were required to provide any requested documentation and answer questions intended to demonstrate readiness for taking on the RC function.

RC West operators have been shadowing Peak’s operations since May 1, taking part in nearly every call, including an energy emergency alert event occurring just hours into the process, Director of Operations Tim Beach told the RC Oversight Committee last month (See RC West Moving Smoothly Toward July Han d over.)

The shadowing process also has RC West staff “verifying system data, conducting operational analysis and monitoring system conditions using situational awareness tools,” CAISO said Monday. The RC function now includes 17 full-time operators working on rotating shifts, with one position still open.

Beginning July 1, RC West will become the RC for 16 California BAs and transmission owners, as well as CENACE in northern Mexico. A second certification review is slated for August, ahead of RC West taking on 24 additional entities on Nov. 1. By then, it will have assumed oversight for about 87% of the West’s load.

SPP and Gridforce last month both said they’re on track to begin shadow operations with Peak in August in preparation for a Dec. 3 transition date. BC Hydro will take over RC functions within its own British Columbia territory Sept. 2 after commencing shadow operations in July. (See New RCs Tell WECC Tra n sition on Schedule.)

June 5, 2019

NERC Sees Summer Risks for Texas, Calif.

By Rich Heidorn Jr.

ORLANDO, Fla. — Most regions have sufficient resources to meet anticipated loads this summer, but Texas and California are at risk from potential natural gas shortages and wildfires, NERC reported Tuesday in its 2019 Summer Reliability As s essment.

The report, which covers June through September, noted ERCOT’s warning it may have to issue energy emergency alerts to respond to resource shortfalls as its summer reserve margin has fallen to 8.5%. (See ERCOT : More Capacity, but Emergency Ops Still Expected.)

Meanwhile, natural gas supply from interstate pipelines will be insufficient to power electric generation on summer peak load days in Southern California, requiring withdrawals from the Aliso Canyon storage facility. NERC also cited concerns over Southern California’s ramping capacity and transmission line shutdowns during wildfires.

ERCOT

ERCOT’s reserve margin dropped from 10.9% a year ago, the result of continued demand growth, delays in planned generation and the mothballing of the 470-MW Gibbons Creek coal-fired generator.

Although its 2018 reserve margin was below its reference margin of 13.75%, ERCOT survived without calling emergency alerts thanks to “high levels of generator availability, response to market signals and unit performance,” NERC said.

ERCOT’s operating plans include voluntary load reductions and power imports if needed.

ERCOT’s summer Seasonal Assessment of Resource Adequacy (SARA), released last month, said the grid operator may tap load resources that can provide operating reserves, use contracted emergency response resources and instruct utilities to employ load management and distribution voltage reductions. It may also import emergency power across its DC ties and ask switchable generators serving ERCOT neighbors to prioritize it instead.

Ramping Concerns

In CAISO, NERC warns of shortages in resources with upward ramping capability, which it said could mean the need for imports to maintain system frequency and prevent load loss in late afternoons as solar generation output drops while loads remain high. “Should extreme temperatures extend over a large area to the point where neighbors lack surplus energy, load could be at risk from a shortage in ramping capability,” NERC said.

NERC said gas-fired generators in Southern California will need to tap fuel from storage because interstate pipelines may not be sufficient to meet peak loads. As a result, withdrawals from the Aliso Canyon natural gas storage facility would be necessary to ensure adequate fuel for generators in the area.

Restrictions on Aliso Canyon “remain an item of focus,” NERC said. High storage withdrawals during winter 2018/19 has meant below-average storage levels this summer.

“The Southern California Gas Company (SoCalGas) forecasts that it will be able to meet the forecasted peak day demand under a ‘best-case’ supply assumption even without supply from Aliso Canyon,” the report said. “However, under a worst-case supply assumption, supply from Aliso Canyon will be necessary to meet that forecasted peak day demand. Should operating restrictions result in natural gas supply curtailments that affect electric generation in the Southern California area, mitigation procedures that have been in place since 2016 can be used to maintain BPS reliability.”

Wildfires

NERC is also citing government warnings of an elevated risk of wildfires in the Western U.S. and Canada, noting utilities’ plans include shutting down transmission lines.

The April-June outlook from the National Interagency Fire Center, Natural Resources Canada and National Meteorological Service in Mexico predicted above-normal wildfire potential for California, the Pacific Northwest (Western Oregon and Washington), Western Alberta, British Columbia and Northern Mexico, NERC said.

In addition to preemptively de-energizing transmission lines in high-risk areas, utilities are using “enhanced vegetation management, equipment inspections, system hardening and added situational awareness measures,” NERC said.

Nevertheless, NERC said the risk of resource shortfalls in CAISO is lower this year than last summer, citing well above normal reservoir levels and mountain snowpack for “greatly reducing the potential for operating reserve shortfalls.” (See CAISO Predicts Plentiful Hydro, Gas C onstraints.)

If CAISO activates its emergency operating plan — for example, in response to the inability to meet spinning reserve requirements — it will employ a number of mitigation measures to minimize loss of load, NERC said including the following:

The Flex Alert program, which can reduce peak loads
The Restricted Maintenance program to reduce forced outages
The performance of manual post day-ahead unit commitment and exceptional dispatch of resources under contract to serve load and meet ramping requirements
The performance of manual exceptional dispatch of intertie resources with resource adequacy obligations to serve CAISO load
The use of demand response programs, including the Reliability Demand Response Resources (RDRR) under the “Warning” stage
The performance of manual exceptional dispatch of physically available resources not under capacity contract

June 4, 2019

UPDATED: RSC, OMS Approve Monitors’ Seams Study

By Tom Kleckner

State regulators in SPP and MISO on Monday separately approved recommendations to engage the SPP Market Monitoring Unit and the MISO Independent Market Monitor to conduct a joint analysis on seams issues between the two grid operators.

The SPP Regional State Committee, meeting by conference call, agreed unanimously with the RSC-Organization of MISO States Seams Liaison Committee’s recommendation to work with the Monitors. The MMU and IMM brought a scopin g plan to the Liaison Committee earlier in May, offering to identify and study seams issues, quantifying costs and benefits of proposed solutions when possible.

The recommendation directs the Monitors to immediately begin a Tier I study of market-to-market coordination, rate pancaking and joint dispatch.

A Tier II study following the completion of Tier I would focus on interface pricing, interchange optimization and regional directional transfer limits.

Both studies are to be completed by June 2020.

Tier III will serve as a parking lot for several other issues: exchanging firm flow entitlements in M2M transactions, targeted market efficiency projects, and outage and day-ahead coordination.

SPP — Shari Feist Albrecht | © *RTO Insider*

Kansas Corporation Commissioner Shari Feist Albrecht, who represents the RSC on the Liaison Committee, said stakeholder comments on potential study subjects centered on rate pancaking and joint dispatch.

“We decided that might be a significant issue from a state perspective,” Albrecht said. “We’re just trying to get some ballpark numbers to identify potential savings.”

Albrecht hopes the Monitors can finish their Tier I work in “six months or so,” then move on to Tier II.

The MMU’s Greg Sorenson addressed RSC concerns that the study would add incremental costs, saying the Monitor’s goal is to conduct four independent market studies each year; the RSC/OMS analysis would serve as one of those four studies.

The OMS Board of Directors also voted overwhelmingly to approve the Monitors’ joint study Monday in an email ballot, with 14 members in favor, one abstention and two non-participants, Executive Director Marcus Hawkins confirmed.

“Since both boards have approved the scope and prioritization, the monitors will now start to develop their work plans on the first phase of the study,” Hawkins said in an email to RTO Insider.

MISO stakeholders at a June 4 Seams Management Working Group conference call asked why the study was being conducted by the Monitors rather than RTO staff.

“We were looking for some independent analysis,” Missouri Public Service Commission economist Adam McKinnie explained.

The Liaison Committee has been meeting since mid-2018 to help improve the grid operators’ interregional coordination, which has never produced a major project. (See MISO, SPP to Ease Interregional Project Criteria.) That has frustrated some stakeholders and caused market inefficiencies.

Committee members will meet July 21 at the National Association of Regulatory Utility Commissioners’ summer policy summit in Indianapolis. The committee has invited FERC commissioners and staff to attend.

Amanda Durish Cook contributed to this article.

June 4, 2019

New England Regulators Talk Wholesale Market Evolution

By Michael Kuser

HARTFORD, Conn. — New England regulators are struggling to deal with how rapidly public policy is transforming the region’s wholesale electricity markets, state officials said Monday at the New England Conference of Public Utilities Commissioners’ (NECPUC) 72nd annual symposium.

As if to drive home the point about the pace of change, Connecticut Gov. Ned Lamont alerted the conference that his state would expand its offshore wind commitment more than six-fold.

“We had a 300-MW commitment, and our legislature, virtually as we speak, is going to up that commitment to 2,000 MW … over the next five to seven years,” Lamont said. (Two OSW bills — Senate Bill 975 and House Bill 7195 — were on Monday’s Senate agenda.) He was speaking just days after the Massachusetts Department of Energy Resources issued a report calling for that state to solicit an additional 1,600 MW on top of an existing 1,600-MW procurement.

“We’re doing the right thing to make sure we have a carbon-free future and a reliable, predictable energy source that allows our region to continue to grow and prosper,” Lamont said.

The governor said he had faced an energy crisis shortly after being elected last November.

“I got a call from [Department of Energy and Environmental Protection Commissioner] Katie Dykes, who said we may have an issue with Millstone, the nuclear power plant that supplies 50% of our electricity,” Lamont said, referring to Dominion Energy’s threat to shut down the 2,111-MW plant, claiming it was no longer financially viable.

In December, Millstone was thrown a lifeline as one of the winning bidders in a state solicitation for nearly 12 million MWh of zero-carbon energy, securing purchase of about half its output for 10 years. (See Conn. Zero-Carbon Awards Include Nukes, OSW, Solar.)

“We solved that Millstone problem … and I’m going to make sure that no governor gets stuck again in the same situation I was,” Lamont said.

Market Disconnect

Restructuring of the electricity industry was meant to shift risks from ratepayers to the market players who stood to profit from their investments, said Sharon Reishus, president of Reishus Consulting and former chair of the Maine Public Utilities Commission.

“There was not an explicit design of the wholesale markets to address state environmental goals. There was an assumption that you would not harm environmental goals,” Reishus said.

In moderating a panel on markets, Reishus asked: “How do state energy procurements keep from shifting risks back to consumers, and what are the risks of unintended consequences?” She added that the regional wholesale market may not survive if states continue to pursue their own separate goals.

New England has seen a disconnect between the roles of state policymaking and the design of the markets, said Vermont Department of Public Service Commissioner June Tierney.

“There’s this tension in the market design between affording the states the proper” authority to pursue environmental goals and the mission of the grid operator to secure reliable energy at the lowest cost possible, Tierney said.

“The market exists to serve the needs of six sovereign states … which push much more in the same direction than in contrary ones,” she said. “It’s about using American ingenuity to … meet a basic need our citizens have, which is the need for electricity.

“When we were struggling with CASPR [Competitive Auctions with Sponsored Policy Resources] … the bottom line of that issue was that ISO-NE was engaged in tweaking market design,” Tierney said.

Pointing to Split FERC Approves ISO-NE CASPR Plan.)

Commissioner Richard Glick’s dissent caught her attention, she said. Glick contended that FERC had misinterpreted the Federal Power Act, failing to respect “that states, not the commission, are the entities primarily responsible for shaping the generation mix.”

“It isn’t FERC’s job to interpret the Federal Power Act as if the states didn’t have legitimate interests in propagating laws that effectuate renewable energy policy,” Tierney said.

Answering Reishus’ question about unintended consequences, Maine PUC Commissioner R. Bruce Williamson said, “In Maine, it’s a constant battle. We have to remind, even to unwilling ears, that there are cost implications to some of the great ideas.”

The region sees the benefit of retaining existing carbon-free resources in the market, but there is a misperception that state procurements of energy drive prices higher, Massachusetts Department of Public Utilities Chairman Matthew Nelson said.

“Out-of-market contracts get seen as the bogeymen here, but the most recent one occurred in Massachusetts and actually saw real reductions to ratepayers,” Nelson said. “We live in a complicated market, and ISO-NE is doing its best … but there’s no going back to a vertically integrated electricity market.”

“Folks start realizing they are paying for a renewable project in their bills, but [they] don’t understand the benefits,” said Nicholas Ucci, deputy commissioner of energy with the Rhode Island Office of Energy Resources.

“No system is perfect, especially one that is two decades old,” Ucci said. “This is a work in progress.”

Prayers Answered?

DEEP Commissioner Dykes said Connecticut has “gone from a minimal percentage of our load contracted to … close to 100%.”

“The contracting will only go so far,” Dykes said. “We have to assume that states are going to continue pursuing their environmental goals. The real question is: Are we going to do so in a coordinated way?”

New Hampshire Public Utilities Commissioner Kathryn Bailey noted that in 1996, her state was the first in the country to pilot restructuring utilities.

“Customers now have the ability to purchase their energy through competitive suppliers,” Bailey said, adding that the emphasis on least-cost generation resulted in an overreliance on natural gas.

Now, as regulators and ISO-NE work to both mold and adapt to a new resource mix, “utility-scale storage will be the answer to the prayer that we have today, and we’ll be able to balance the reliability with the long-term contracts that continue to be negotiated,” Bailey said.

“Having storage is really flexible and it’s probably going to be the answer … when we still need flexible resources, but 50% of the demand is powered by long-term contracts,” Bailey said.

June 4, 2019January 3, 2024

MTEP 19 Could Yield First MISO SATA Project

By Amanda Durish Cook

An American Transmission Co. effort to improve reliability in central Wisconsin could within two years provide MISO with its first-ever storage-as-transmission asset (SATA) project.

ATC is proposing to build a 2.5-MW/5-MWh battery on a 138-kV line in the Waupaca, Wis., area, installing two capacitors and upgrading a nearby 69-kV bus to accommodate the project. The project would cost an estimated $9.1 million and be in service at the end of 2021. ATC said the battery would be available for two-hour discharge times.

The company is proposing the project for inclusion in MISO’s 2019 Transmission Expansion Plan (MTEP 19) to function as strictly transmission. MISO is so far prohibiting SATA projects from also providing market services. (See MISO Limits Storage as Transmission Asset Ownership.)

During a West subregional planning meeting Friday, MISO staff said the project still requires study, including determining how it could impact load service risks and system reliability. The RTO said it will present final project justification results at another subregional planning meeting on Aug. 23.

The company has also submitted two alternatives — another battery farther north and a traditional wires solution — in the event that MISO finds negative impacts from the originally submitted battery format. The 5-MW/10-MWh alternate battery project would cost $10.4 million, and a rebuild of the Whiting Avenue-Hoover 115-kV would cost $12.4 million. Both would stick to a late 2021 timeline.

ATC said its preferred battery project is designed to more reliably maintain up to a 155-MW load level, capturing more than 90% of historical load levels in the Waupaca area. The area is currently at risk during multiple outage conditions, MISO expansion planner James Slegers said.

“At certain load levels, the system cannot sustain the load,” Slegers said.

Waupaca contains a local 69-kV system supported by a nearby multi-segment 115/138-kV transmission line. MISO said local loads cannot be sustained when both ends of the 115/138-kV supply line are out of service. ATC currently uses an operating guide to open line segments to serve load radially on the 69-kV system after load levels reach a certain point and after a first outage. While the operating guide allows loads to be served after a second contingency, it places up to 114 MW of load at risk of disconnection, according to MISO. ATC’s battery is designed to operate after a second contingency.

“There are not many hours in a year that you could take a maintenance outage and not sectionalize the system,” Slegers said, adding the solution aims to allow multiple maintenance outages without a loss-of-load risk.

MISO has completed a reliability assessment on the battery project. So far, it found the most effective siting of a SATA solution is near the Harrison 69-kV substation in the area, although other nearby 138-kV buses between Arnott and Waupaca “performed similarly well.”

MISO Manager of Expansion Planning Lynn Hecker said the RTO has so far been using a conservative, approximately 20-year life cycle assumption in battery reliability studies.

The RTO has yet to develop life cycle cost comparisons for ATC’s battery and alternate projects.

Slegers said MISO is open to studying even more project alternatives, if stakeholders offer them. The RTO has said it will work with stakeholders “to understand technical details and evaluate any additional alternatives proposed.”

He noted that the ATC project evaluation will serve as a starting point and “lessons learned” for other SATA projects proposed in future MTEP cycles.

June 4, 2019

SPP Tx Planners at Forefront of New Challenges

By Tom Kleckner

LITTLE ROCK, Ark. — The predominance of renewable energy and battery storage in the nation’s RTO interconnection queues is certainly no secret.

SPP’s queue is dominated by 51.8 GW of wind projects in all stages of study and development. That’s on top of 21.6 GW of installed wind capacity and another 7.7 GW of unbuilt projects with signed interconnection agreements. Layered on top of that is 25 GW of solar projects in the queue — 215 MW is already installed — along with 4.5 GW of battery storage.

Engineering Planning Summit attendees listen to SPP’s Jay Caspary. | © *RTO Insider*

Casey Cathey, SPP manager of reliability planning and seams, listed those numbers as he moderated a panel Thursday devoted to planning for an evolving grid.

“What’s our next challenge?” Cathey asked ITC Holdings’ director of regional planning, Alan Myers.

“Isn’t that enough?” Myers responded, drawing laughter from those gathered last week for SPP’s Engineering Planning Summit.

Turning serious, Myers offered a response: “It’s matching that variable to the variability of the load.”

“It used to be generation was the variable. Now, we’re seeing load becoming a huge variable,” said fellow panelist Holly Carias, NextEra Energy Resources’ director of origination. “It will take different technologies to maximize what we already have. Not only with transmission, but on the load side. We have to focus on providing service to the end customer and give them a better customer experience.”

Daniel Brooks, who manages the Electric Power Research Institute’s grid operations and planning research group, threw a wrench into the discussion when he reminded the panel and audience, “EVs are coming.”

Brooks said 10 to 20 years ago, automakers were first attempting to turn a car’s wheels with batteries.

“Listen to those [original equipment manufacturers] today. They’re completely committed to moving to electric vehicle fleets,” he said. “Some heavy-duty vehicle fleets are talking about multi-megawatt charging stations. That’s a challenge, but an opportunity as well.”

As Brooks is fond of saying, “It’s tough to make predictions, especially about the future.”

SPP — Evergy’s Katy Onnen (left) listens as co-worker Derek Brown asks a question. | © *RTO Insider*

So far, SPP has been pretty successful with its forecasts. It says its planning efforts have resulted in $10 billion of construction projects over the last 14 years, allowing the RTO to focus on smaller upgrades and reliability projects.

The RTO’s Board of Directors in April approved a $1.8 billion Transmission Expansion Plan that will build projects in 13 states over the next five years. Members last year completed 98 transmission system upgrades in seven states at an estimated cost of $779 million.

A 2016 SPP study indicated $3.4 billion of transmission upgrades during 2012-2014 resulted in more than $240 million in fuel-cost savings for SPP members during the first year of the Integrated Marketplace. The RTO has said it expects the benefits to exceed a net present value of $16.6 billion into the 2050s, with a benefit-to-cost ratio of 3.5. (See SPP Begins Promotional Campaign to Tout Transmission Value.)

‘Big Boys’

“Transmission planning provides a lot of value, particularly when it results in construction,” SPP Engineering Vice President Lanny Nickell said in opening the summit Wednesday. “We have a lot of metrics that have determined we do provide a lot of value through the expansion of transmission.”

Stakeholders reviewed the transmission projects that could make up the 2019 Integrated Transmission Planning assessment, which will go before the board in October for approval.

The 2019 portfolio’s cost could be as high as $407 million, though staff estimate the projects could provide as much as $2 billion in benefits. Several of the projects target the southern corner of SPP’s footprint in Kansas and Missouri. There, congestion on MISO’s side of the seam has resulted in more than $60 million in market-to-market payments to SPP since March 2015. Constructing new 345-kV lines in the area could cost as much as $158 million, according to one proposed project.

Cathey noted SPP can no longer look at other RTOs — and Denmark and Germany, both leaders in renewable integration — for guidance on the ratemaking that will eventually help pay for the lines.

“SPP is kind of at the forefront of some of these challenges. We’re kind of the big boys now,” he said.

“A big gap I see is that relationship between planning and regulatory. We’ve always been on the tail end. We find out what the regulatory decision is, then we scramble to make our plan fit that,” SPP Planning Director Antoine Lucas responded. “I don’t think we can expect that we’ll drive the regulatory process, but there has to be some form of collaboration on the front end to develop solutions that benefit both sides. It will be a big value-add if we can figure out ways to work in different partnerships with different organizations to tackle these problems.”

As the summit wound to a close, Jay Caspary, SPP’s director of research and development and special studies, reminded stakeholders that the RTO and its members will also have to deal with the footprint’s aging infrastructure, some of which is more than 60 years old.

“We’ve got to manage these assets in the field,” he said, referring to himself as an “aging asset too.”

“There are a lot of uncertainties, but one thing that isn’t is that time marches on. These things are getting older by the day. I want us to get ahead of that.”

“There’s a lot to consider. It’s not like it was 10 years ago,” Cathey said. “These will be interesting times moving forward. We’ll see if we’re accurate with our transmission planning as we were with all the transmission we built 20 years ago.”

June 3, 2019January 26, 2025

NERC Team Seeking SOL Data to Answer FERC Concerns

By Rich Heidorn Jr.

A NERC panel considering a proposal to limit reporting on system operating limit (SOL) exceedances will be seeking data to support its claims that excessive compliance requirements are a reliability threat.

Members of the standards development team (SDT) for Project 2015-09 (Establish and Communicate System Operating Limits) will be gathering the data in response to concerns by FERC staff over a proposal that would require logging, communication and documentation only when SOL exceedances last for 30 minutes or longer.

The proposal, which came in response to comments by the Midwest Reliability Organization, has received “a lot of positive feedback from industry,” SDT Chair Vic Howell, of Peak Reliability, told stakeholders Wednesday. Current NERC standards do not clearly define what is an SOL exceedance or when it must be reported, he said.

Howell provided a briefing on a May 2 conference call that he and several other SDT members had with FERC staff on the proposal.

“It wasn’t very clear [to FERC] that this was a reliability issue as much as it was a compliance issue. … We tried to explain that it is a reliability issue because if operators are so busy doing all this documentation for compliance evidence, it takes their eye off the ball for performing actual operations and addressing actual SOL exceedances,” Howell said. “We got to a place where FERC staff understood our concerns and … they wanted us to come up with data to back up our concerns.”

System operating limits development in the operations horizon | SPP

Following the FERC call, Stephen Solis of ERCOT compiled preliminary statistics to facilitate discussions of what the actual data request could look like. The preliminary data showed that in January, about 2% of the Texas grid operator’s five-minute exceedances of pre- and post-contingency thermal or voltage limits lasted longer than 30 minutes. He acknowledged that ERCOT’s data includes 69-kV lines that are below NERC’s Bulk Electric System threshold and a number of non-exceedances that show up as the values approach close to an exceedance.

Reporting only the exceedances of more than 30 minutes would require almost 40 communications a day, Solis said. “The rest of it is just normal everyday seeing things, responding; seeing things, responding; repositioning the system very quickly.”

Solis said if ERCOT had to report each of the nearly 76,000 five-minute exceedances for the month, “we’d have to hire two or three people just to get on the phone and call people.”

“It’s not realistic and that would be a detriment to reliability,” he continued. “Of every 50 violations, one will make it greater than 30 minutes. We’re doing a very good job of catching things, fixing things. If you’re going to penalize companies for doing a good job, there’s something broken there.”

Howell said the team will seek data from MRO and others outside the SDT but that it would not be an industry-wide effort. “Whoever we can get to give us the data and do the data analysis so that we have a good representation and a reasonable pool, then we’ll go with that,” he said.

FERC staffer Eugene Blick, who participated in the Wednesday SDT meeting, suggested the team obtain data from “multiple [reliability coordinators], because keep in mind, what you’re proposing to change is in a continent-wide standard applicable to all RCs and all [transmission operators].”

Blick said one other entity that commission staff have spoken to didn’t see the issue as a problem. “They didn’t have many SOL exceedances during their operating day because their [operational planning analysis] served as a means to filter or mitigate some of the SOL exceedances.”

He said seeming exceedances that result from telemetry or modeling problems should be excluded in the data collection.

Howell said the team will spend the next couple weeks refining its data request before seeking contributions.