CARMEL, Ind. — MISO officials are still hashing out how they can best model and analyze energy storage-as-transmission in the RTO’s transmission planning process.
During a Dec. 10 Reliability Subcommittee meeting, MISO Senior Manager of Expansion Planning Edin Habibovic said planning for storage-as-transmission boils down to four key modeling factors:
Determining the voltage, thermal or stability need;
Asking if storage is the most effective, efficient and economical solution;
Examining what level of megawatt or mega volt amps of injection is needed to resolve the issue; and
Investigating how long the reliability issue usually lasts.
Habibovic said MISO also must study how frequently a storage asset would have to operate to resolve a reliability issue and how that cycling may impact the operational life of the asset. He also said MISO will need to look into seasonal load levels to estimate how often the asset may be dispatched in scenarios under the RTO’s annual Transmission Expansion Plan (MTEP).
Storage solutions would also be evaluated to make sure charging and discharging don’t cause harm either to the MISO transmission system or to generation projects in the definitive planning phase in the interconnection queue, Habibovic said.
“Just like any other reliability project, it can’t solve one problem and cause another,” he said.
But storage could be dispatched to minimize transmission system upgrade needs from generation projects in the definitive planning phase of the interconnection queue, he said. The result would be more flexibility in modeling the definitive planning phase.
WPPI Energy’s Steve Leovy asked if MISO would employ a storage-as-a-transmission-asset (SATA) study process on solutions submitted for MTEP 19. Habibovic said MISO would study storage projects and might provide additional MISO assessments and discussions about the study results and feasibility of such projects. MISO already has at least one proposed storage project lined up for study under Appendix A of MTEP 19.
So far, MISO is only proposing a model for storage to act as a transmission reliability solution, solving thermal, voltage or stability issues. The RTO is leaving more complex SATA issues for later rules. (See Few Clear Lines in MISO Storage as Tx Plan.)
MISO is accepting stakeholder comment on the challenges and benefits of incorporating transmission-level storage in reliability planning through Jan. 7.
Inverter Projects to Prove Stability
MISO has added an option for owners of inverter-based generation to prove the system won’t suffer degraded reliability because of their projects.
In October the RTO said it was mulling requiring owners of inverter-based resources to supply their short-circuit ratios at the point of interconnection before completing an application to enter the queue. (See MISO Moving to Head off Inverter-based Instability.)
Interconnection customers with an inverter-based project can now demonstrate a stable interconnection later in the queue process using one of two demonstration methods.
According to MISO interconnection engineer Warren Hess, project owners can either submit an Electromagnetic Transients Program (EMTP) study report confirming stable operation or, by the first decision point about 120 days into the queue, submit a short-circuit ratio at the point of interconnection and a manufacturer’s letter stating the equipment operates reliably.
As with the first proposal, any project owner unable to prove stable operation must either add equipment to raise the short-circuit ratio or reduce the size of the project.
MISO is accepting another round of feedback on the proposal through Jan. 2.
NYISO said Tuesday it will have adequate capacity on hand to meet its forecasted peak demand of 24,269 MW for the 2018/19 winter season, well under last winter’s peak of 25,081 MW.
The ISO expects capacity resources, including imports and demand response, to total 43,943 MW this winter, ISO Vice President of Market Operations Emilie Nelson said in a review of the winter outlook.
Installed generation amounts to 41,539 MW, while the ISO has acquired external capacity of 1,519 MW for the winter. Projected demand response resources equal 884 MW, Nelson said.
NYISO long-term winter forecast for 2018 to 2025, including transmission and distribution losses. The low and high forecasts are at the 10th and 90th percentiles for extreme weather conditions, respectively. | NYISO
The ISO forecasts a capacity margin of 11,436 MW based on a 50/50 winter peak forecast with average winter weather conditions consisting of composite statewide temperatures of 15 degrees F. More extreme temperatures in the model (approximately 5 degrees statewide) result in a higher forecasted 90/10 peak load of 25,884 MW, with marginal capacity of 9,821 MW.
“Last winter’s peak [on Jan. 5] occurred during a two-week cold snap, and the all-time winter peak of 25,738 MW occurred in January 2014, during what was called the polar vortex,” Nelson said.
In response to the harsh winter five years ago, “we have fine-tuned many of the things we do in advance of the winter season,” Nelson said. The ISO enhanced its winter reliability planning by providing stronger incentives for generators to secure fuel for winter peak demand needs and improved its monitoring of the natural gas system and checking of generator fuel inventories.
“In preparing for the winter 2018/19, we start by conducting a generator fuel survey … and also we like to understand any arrangements they have in place for replacement fuel,” Nelson said. “This is particularly important in New York, because so many of our generators are located along waterways that allow replenishment of fuel storage through the winter.”
When considering resupply, the focus is on oil, which is typically used as a backup fuel in New York, prompting the ISO to differentiate between resources with fuel tanks that will be drawn down throughout the season and those that can resupply from barges as needed, Nelson said.
In the spirit of testing for extremes, the ISO forecast models a loss of natural gas scenario, which is less about replenishment than demand coming from both homes and power generators, she said.
FERC on Monday denied SPP’s request for waivers from regulations guiding the confidential treatment of information in its explanation of how it allocated costs related to a NERC fine, the amount of which has not been publicly disclosed because of grid security concerns (ER19-97).
SPP filed the Section 205 request in October with an explanation of its allocation of costs associated with a NERC fine for alleged violations of reliability standards. The heavily redacted public version of the request shows the RTO asked for waivers from the requirement to include a protective agreement and from the regulations authorizing release of the filing’s confidential version to entities signing a nondisclosure agreement. SPP claimed that disclosing the information could jeopardize its system’s security.
But FERC ruled that “SPP has neither adequately supported its concerns nor justified the adverse effect that its waiver request would have on participants in this proceeding.” As the cost allocation plan did not include a proposed protective agreement, the commission dismissed it. It did so without prejudice, meaning it did not rule on SPP’s approach to covering the penalty cost.
FERC noted intervenors would be willing to sign a protective agreement to review SPP’s filing and evaluate its proposed cost allocation.
SPP’s headquarters in Little Rock, Ark. | WER Architects
In the cost allocation filing, SPP said it paid the penalty costs using surplus funds, although a Tariff provision allows the recovery of such costs by direct assignment or cost allocations to members or market participants. The RTO’s Board of Directors approved offsetting the costs with employee compensation funds for 2018, an approach SPP said it adopted from FERC Order 693, which it said suggested RTOs and ISOs could tie employee compensation to compliance with reliability standards as a means of reducing repeat incurrences of penalties. The order also declined to provide grid operators blanket authority to recover penalty costs from members on a generic basis.
Under the board’s recommendation, the reduction in compensation would be reflected as a surplus in the administrative fee’s true-up for 2018, which would reduce the fee for 2019.
The West Texas Municipal Power Agency (WTMPA), created by the cities of Lubbock, Brownfield, Floydada and Tulia to increase their negotiating strength, intervened in the docket. While it did not protest the cost allocation plan or waiver request, it urged FERC to “strictly and expressly limit such findings to this case” if it approved them. The agency asked that interested parties be allowed access to information about the penalties and cost allocation, contending that it would be otherwise impossible for ratepayers to determine whether the penalty’s allocation was just, reasonable and not unduly discriminatory.
FERC regulations provide that any participant in a proceeding — or that has filed a motion to intervene or notice of intervention — can make a written request to the filer for a copy of the document’s complete, nonpublic version. The request must include a signed copy of the filer’s protective agreement and a statement of the person’s “right to party or participant status or a copy of their motion to intervene or notice of intervention.”
SPP members Evergy, Oklahoma Gas & Electric and Western Farmers Electric Cooperative also intervened in the docket.
Commissioner Kevin McIntyre, who has been battling health issues, did not vote on the order.
WASHINGTON — Experts in cybersecurity last week painted a somewhat dire picture when detailing the threats to the electricity industry posed by countries such as Russia, Iran, North Korea and China.
Perhaps the only thing they described that was more worrying than hackers’ persistence and the inevitably of a major attack on the U.S. grid was the No. 1 cyber risk: lack of common sense.
Eight out of 10 cyberattacks are caused by people making very poor decisions, said Jerome Farquharson, a cybersecurity consultant at Burns & McDonnell. “One of the biggest things, and I always say this when I sit down and start talking about cybersecurity and trying to close the gaps, is that cybersecurity [requires] a common-sense approach,” he said. “If we just did some very simple things, we can start making ourselves secure.
“Human nature by itself is very trusting. But when we start training people, for an example, not to use USBs [thumb drives] or not to click on email links [when] you know you’re not winning the lottery any time soon, [they] still click on them! … We go to vendor shows, and guess what vendors give out? USBs.”
Farquharson told several stories to illustrate his point. In one, an employee allowed his children to play on his laptop — the same one he used to perform system maintenance at a substation. The laptop became infected with malware at home, then went on to infect the substation’s system and his colleagues’ computers, leading to a control center outage.
In another example, Farquharson’s team sent phishing emails to a company’s 200 employees to test them after it had trained them in cybersecurity awareness for a week. More than 90 employees clicked on the links in the emails. After retraining those employees, it conducted another test a week later. More than 50 of those employees still clicked on the links.
In a different training exercise for another company, Farquharson’s team scattered USB thumb drives infected with malware throughout the company’s building and parking lot. Twenty employees picked them up; 10 plugged them in.
“The biggest threat sometimes is the human factor,” he said. “And so that’s where you have to really [spend] a lot of time on training and awareness.” The most secure companies are those with consistent, regular training, he said.
On another panel at the summit, Jim Cunningham, executive director of nonprofit Protect Our Power, said he sees similarities between the pre-9/11 airline industry and the electricity industry’s defenses against cybersecurity today. He recounted his experience witnessing the explosion caused by United Airlines Flight 175 crashing into the South Tower of the World Trade Center on Sept. 11, 2001. He recalled that television media at the time were calling the attack “sophisticated.”
“I thought, ‘Oh my God, that’s wrong.’ It was 19 guys with boxcutters; it was an unprepared airline industry; and it was an unprepared security industry,” he said. “We were paying people at the airports $10/hour to keep bad people off the planes. And we didn’t spend a few extra bucks to take those thin doors that were in front of the cockpit and make them stronger.”
Cunningham’s organization recently published a report focusing on the solar inverter supply chain. It found that about 47% of the world’s inverters come from Huawei, “a company that is banned by the U.S. government from the telecommunications business,” he said. The report says evidence is mounting that Huawei regularly flouts U.S. and international laws. “A threat actor with access to the inverter supply chain allows the manipulation of massive quantities of inverters, the ability to embed malware into the operating system away from the end-consumer and to operate under the veil of a reputable manufacturer,” it says, and makes several recommendations to mitigate the risk.
Still, preventing a catastrophic cyberattack on the grid “is the equivalent of a modern-day moonshot,” he said. “We’ve got to get everybody together, we need to get all the money we need and we have to get the smartest people on this issue to come up with a solution now.”
Ronald Keen, senior energy adviser at the Department of Homeland Security’s National Risk Management Center, said the days of companies independently defending themselves “are pretty much gone. We need to begin looking at cohesive defense: defense where we’re working together. We need to be able to start working together to design multilayered defenses that work with each other.”
WILMINGTON, Del. — Ten Consumer Advocates of the PJM States (CAPS) members signed onto a letter urging PJM’s Board of Managers to let “that process play out” concerning analysis of the RTO’s financial transmission rights market and any subsequent rule changes, CAPS Executive Director Greg Poulos told stakeholders and staff at Thursday’s Markets and Reliability Committee meeting.
While the other five manual revisions on the agenda were approved by group acclamation, Poulos asked that the revisions to Manual 06: Financial Transmission Rights, developed as part of the manual’s annual review, be voted separately. They were approved with one objection and seven abstentions.
PRD Review for Capacity Performance Requirements
Stakeholders endorsed revisions that would align PJM’s price-responsive demand (PRD) rules with the Capacity Performance construct. While three proposals developed by the Demand Response Subcommittee were potentially under consideration, the voting didn’t get past the main motion, which received 3.72 in favor in a sector-weighted vote with a 3.34 threshold. The MRC vote was accepted in the subsequent Members Committee meeting, moving it on to the board.
The main proposal requires PRD to reduce load in winter like other CP resources and will leverage existing load reduction and capacity nomination rules already approved by FERC for demand response. The status quo does not require winter load reduction, similar to PJM’s rules for DR prior to CP. (See “Summer-only Demand Response,” PJM MRC/MC Briefs: Oct. 25, 2018.)
An alternative initially developed by Calpine proposed using performance assessment intervals (PAIs) to trigger performance assessments, bonuses and penalties instead of using them only when appropriate real-time LMPs are greater than the PRD energy price, which the endorsed proposal uses.
Susan Bruce, representing the PJM Industrial Customer Coalition, voiced support for a proposal from the Independent Market Monitor because it allows PRD to be based on summer load-reduction capability rather than year-round. The Monitor’s proposal would not require PRD to reduce load in the winter if the customer’s load is already low and would use the old DR measurement and verification method to meet the CP annual requirements, which was updated based on CP and subsequently approved by FERC.
Surety Bonds
Exelon representatives, who had initially introduced one of the proposals to use surety bonds as a form of credit, called for deferring a committee endorsement on two proposals until a special PJM board committee reports on its investigation of the historic GreenHat Energy FTR default. The proposals were developed at the Credit Subcommittee. (See “Surety Bond Use,” PJM Market Implementation Committee Briefs: Oct. 10, 2018.)
The main motion would allow surety bonds as collateral for all market purposes, except FTRs, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer. Exelon’s alternative proposal would allow surety bonds as collateral for all market purposes, with a $20 million cap per issuer for each member and a $100 million aggregate cap per issuer.
Some members were concerned about considering the proposals while the board’s investigation continues and because insurance companies can investigate claims against surety bonds prior to paying on the claims. PJM staff echoed previous assurances that the surety bond agreement language is designed to require immediate payment of claims, identical to the requirements of letters of credit, which are already approved forms of credit. While some of the language came from other RTOs/ISOs, it remains untested legally, staff said.
Both proposals will be reconsidered at the Dec. 20 MRC meeting. PJM CEO Andy Ott said representatives of the special committee will call in to provide an update on the investigation.
Gas Pipeline Contingencies
Load-side preference won the day for an alternative developed by the D.C. Office of the People’s Counsel to PJM’s proposed rules and compensation plan for handling supply-constraint contingencies on gas pipelines.
The main motion endorsed by the Market Implementation Committee, which was originally developed by Calpine, would have allowed units switching fuels at PJM’s direction to recover specific costs through a formula rate to be developed and filed with FERC. It would have been based on costs associated with fuel switching, exemptions from PJM performance charges during the fuel switch, and procedures for seeking cost recovery. (See “Gas Pipeline Contingencies,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)
Calpine’s David “Scarp” Scarpignato offered an amendment to remove gas pipeline penalties from the rate, which was accepted as friendly. He said it would be “untenable” for generators to potentially incur tens of millions of dollars in costs during an emergency and not be able to recover them.
The OPC’s alternative allows for cost recovery to be filed at FERC by the generation owner. Bruce supported this proposal, noting concerns about what could be included in rates developed through the main motion and how they would be audited. She said her members agree on the fundamental ideas behind the main motion but would be “behind the blocks” in having to file complaints about recovery charges rather than the generator having to seek recovery.
Poulos said his members also supported the OPC proposal and expressed “a lot of frustration” that discussion of the proposals received “short shrift” at the upper committees, as it was scheduled for first reads and votes at both the MRC and MC on the same day.
“I think that the risk of putting forward an inadequate proposal is greater than the risk of going one more winter without it,” said Panda Power Funds’ Bob O’Connell, announcing that he planned to oppose all the proposals.
The main motion failed, receiving 3.13 in favor in a sector-weighted vote with a 3.34 threshold. The OPC alternative was endorsed, receiving 3.77 in favor. It received 4.26 in favor in a subsequent endorsement vote at the MC.
In the MC, attendees agreed to move proposed credit-related Tariff revisions to the consent agenda, where they were endorsed with no objections. The revisions remove an apparent overlapping credit reduction provision for qualified transmission upgrades in order to clarify milestone documentation requirements for internally financed projects and that capacity market sellers should submit requests for reductions.
Committee Elections
Attendees also elected nominees to the Finance Committee, sector whips and American Municipal Power’s Steve Lieberman, representing the Electric Distributor sector, as vice chair of the MC for 2019.
Elections to the Finance Committee were:
The D.C. OPC’s Erik Heinle, from the End-Use Customer sector;
Jeff Whitehead, representing Eastern Generation, from the Generation Owner sector;
Credit Suisse’s Marguerite Miller, from the Other Supplier sector; and
Virginia Electric and Power Co.’s Jim Davis, from the Transmission Owner sector.
The tenures will all expire at the end of 2021. Tenures for the current representative from each sector on the committee expire either next year or in 2020, including the tenures for both representatives from the Electric Distributor sector.
The sector whips were Old Dominion Electric Cooperative’s Adrien Ford, from the Electric Distributor sector; the PJM ICC’s Bruce, from the End-Use Customer sector; Gabel Associates’ Michael Borgatti, from the Generation Owner sector; Direct Energy’s Marji Philips, from the Other Supplier sector; and Exelon’s Sharon Midgley, from the Transmission Owner sector.
Bilateral FTR Retraction
PJM CFO Suzanne Daugherty announced PJM’s plans not to follow up on additional information requested by FERC in a recent FTR-related filing and instead pushed to have it withdrawn. The MC voted in favor of showing its agreement with PJM’s plan, but not without Shell Energy voicing its disagreement. The acclamation vote passed with six objections and 11 abstentions.
In the previous week, FERC approved two of four filings — and rendered moot a third — that PJM made in response to the GreenHat default. On the fourth filing related to bilateral FTR transactions, the commission issued a deficiency letter requesting more information. Shell and several financial traders protested the filings. (See FERC OKs Key PJM Changes to Address GreenHat Default.)
Shell’s Matt Picardi said his company protested to raise the issue of the underlying indemnification and that addressing the deficiency letter is important for hashing out those issues.
Daugherty responded that “Shell has been very straightforward” with its opinion, but that its interpretation of the indemnity provision differs from PJM’s. Staff would prefer to pull that back to discuss it in the stakeholder process because it was never addressed there, rather than hash it out at FERC.
“There was some discussion around the edges” of the indemnification issues during the GreenHat talks earlier this year, Picardi said. He said Shell would engage in any stakeholder processes on the topic but would not be “foreclosing” on its “other options” to push the issue.
Daugherty confirmed that PJM has no expectation of submitting another filing on the issue other than to have the discussion.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 03: Transmission Operations. Revisions developed to update the generator voltage schedule with new processes that require transmission owners to verify and submit voltage schedules via eDART, generation owners to review the schedules and the eDART contact to acknowledge the schedule. This will all need to be done annually. (See “Generator Voltage Schedule,” PJM Operating Committee Briefs: Nov. 6, 2018.)
Manual 10: Pre-Scheduling Operations. Revisions developed as part of a periodic cover-to-cover review.
Revisions to the day-ahead scheduling reserve for 2019. The 2019 calculation of 5.29% is a 0.01-point increase from the 2018 requirement. Endorsed with seven abstentions and one objection. (See “Day-ahead Scheduling Reserve Recommendation,” PJM Operating Committee Briefs: Nov. 6, 2018.)
SPP’s Holistic Integrated Tariff Team (HITT) wrapped up the educational portion of its work last week and will now begin refining the high-level recommendations it will make to the Board of Directors.
SPP General Counsel Paul Suskie, who serves as the HITT’s staff secretary, offered several suggestions on how the group might take the information and data it has gathered “and assimilate it into a report.”
Suskie broke down the recommendations into sub-sections dealing with transmission planning, congestion rights and hedging, and resource adequacy, among others. However, no action was taken to endorse any recommendations during the team’s Dec. 4-5 meeting, with stakeholders suggesting some of the concepts discussed be addressed by other working groups.
The HITT has an April 2019 deadline for delivering a report on the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services.
SPP announced Dec. 6 that senior executives Lanny Nickell and Barbara Sugg will take over the staff secretary positions on two of its most important committees, the Markets and Operations Policy Committee and Strategic Planning Committee, respectively.
The MOPC, relying on stakeholder groups, develops and recommends policies and procedures to the board. The SPC is responsible for the RTO’s strategic direction.
Nickell, vice president of engineering, will assume the MOPC’s reins from COO Carl Monroe, who has filled that position for 18 years. Monroe will continue to directly engage with the committee as a resource, CEO Nick Brown said.
Sugg, SPP’s IT vice president and chief security officer, will replace Michael Desselle, who served as the SPC’s staff secretary for 10 years.
Brown said the appointments will allow Nickell and Sugg “to continue [their] professional development and service to SPP.” He made the announcement in a pair of emails to stakeholders.
SPP’s Sorenson has Role at Bush Funeral
The SPP Market Monitoring Unit’s Greg Sorenson, a supervisor of market surveillance, was part of a special naval escort for dignitaries and family members attending President George H.W. Bush’s funeral ceremonies in D.C. last week.
Sorenson, a lieutenant commander in the U.S. Navy Reserve, arrived in the capital Dec. 2 to join 10 other Navy officers in escorting visitors at Andrews Air Force Base and the National Cathedral. Sorenson was present at Andrews when Air Force One landed with Bush’s body and met Sully, the president’s service dog.
“I had to rearrange some things, but [SPP was] very accommodating in allowing me to do this for our country,” Sorenson told the Northwest Arkansas Democrat-Gazette.
Staff Eyeing FERC Filing on Seams Projects
SPP staff were unable to gain stakeholder consensus last week on their proposal to change the criteria for regional funding of seams projects. The revision would apply to all seams projects unable to pass the interregional Order 1000 process and approved in an SPP regional study.
At the Seams Steering Committee meeting Wednesday, several stakeholders suggested the effort to create Tariff language would be worthwhile. However, committee Chair Jim Jacoby, with American Electric Power, said he wasn’t sure the time and effort was worth it.
“It won’t fix anything on the MISO side,” Jacoby said, referring to the inability of the RTOs to agree on interregional projects. “Having something in the Tariff is a good thing, but I’m torn over the amount of effort it will take versus the benefits it will provide.”
Staff said they will continue discussions with the committee in 2019.
They also told the SSC they were close to finalizing revisions to the joint operating agreement governing the coordinated system plan for interregional projects with MISO. Staff said the RTOs hope to reach an agreement during the Interregional Planning Stakeholder Advisory Committee’s Dec. 20 conference call, and then prepare the JOA for FERC filings in January or February.
The RTOs have agreed to revise the JOA to improve the chances of funding interregional projects. The changes will eliminate the $5 million cost threshold for the projects, add avoided costs and adjusted production cost benefits to project evaluation, and remove the joint modeling requirement in favor of individual RTO regional analyses. (See MISO, SPP to Ease Interregional Project Criteria.)
M2M Payments Flow in SPP’s Direction Again
| SPP
Staff told the SSC that the market-to-market (M2M) process wound up in SPP’s favor in October, reversing three consecutive months of net payments to MISO.
Flowgates along the seam were binding for a total of 663 hours on SPP’s side, resulting in more than $380,000 in M2M payments. SPP has now amassed $51.6 million in distributions since the two RTOs began the M2M process in March 2015.
Payments have flowed SPP’s direction 20 of the last 25 months.
Walker: More Visibility Needed into DERs, Self-Gen
Calling ERCOT’s recently projected reserve margin of 8.1% for 2019 a “very concerning number,” DeAnn Walker, chair of the Public Utility Commission of Texas (PUCT), last week urged the grid operator to gain a “better sense” of the distributed resources and self-generation that could be affecting the system.
The Texas PUC’s Dec. 7 open meeting
“I think we’re getting to a point where we need more transparency into those issues,” Walker said during the PUC’s Dec. 7 open meeting. “I think the electric system is changing, and we’re moving to a more customer-initiated ownership” of energy resources.
A Buc-ee’s station near Houston | Buc-ee’s
Using her favorite example of the mammoth Buc-ee’s convenience stores found along Texas highways, Walker noted how the chain “is dropping gas units behind [the stores] to get away from high prices or to sell into the market.”
“More and more people are going to be doing this,” Walker warned. “I really want ERCOT and the market to move forward to give them more visibility into what we have out there.”
PUC Chair DeAnn Walker questions legal counsel during the open meeting.
Warren Lasher, ERCOT’s senior director of system planning, agreed with Walker that the initiative does not require a rulemaking from the PUC.
“We have been working with stakeholders on a different number of fronts,” Lasher said. “It’s likely our current efforts are not urgent enough to meet the need associated with the changing grid and the resource reports we have been issuing lately. I would take that need back, and maybe set a slightly different tone working with stakeholders.”
ERCOT has seen a 62% growth rate in distributed energy resources over the last three years, CEO Bill Magness said during a November Gulf Coast Power Association luncheon. Although DERs currently account for about 1.3 GW of capacity, Magness said staff have worked with transmission and distribution providers to map some of the 93 existing registered DERs and to map all registered DERs to the system load. (See ERCOT CEO: Solar Growth ‘an Interesting Challenge.’)
ERCOT’s Warren Lasher explains ERCOT’s position to the commissioners.
Commissioner Arthur D’Andrea pointed out that the lack of visibility into DERs and self-generation hampers the preciseness of meeting projected load.
“It’s striking how much well-spent time ERCOT [uses] estimating load out in West Texas, and how much time we spend getting it right,” he said. “Then you have that precision undermined by someone and having this giant question mark out there.”
SPS, DOE Dispute Dismissed
The PUC agreed with an administrative law judge’s dismissal of a dispute between Southwestern Public Service and the U.S. Department of Energy’s Pantex nuclear weapons facility near Amarillo, Texas (Docket 48440).
The department sought an order from the commission compensating it for excess generation from the facility’s 11.5-MW wind farm. The request was part of a broader SPS rate case but was severed from the application in 2017.
The ALJ found SPS met its burden of proof in showing its billing arrangement with DOE was appropriate and ordered that no changes be made.
PUC Issues $1.49M in Fines
The commissioners approved $1.49 million in administrative penalties following settlement agreements in nine dockets. The largest fine, $1.1 million, was assessed to generator Luminant for providing ERCOT with false telemetry data, which prevented the grid operator from economically dispatching units (Docket 48607).
Two retailers, Source Power and Gas and Reliant Energy Retail Services, were fined $50,000 and $100,000, respectively. Source improperly placed switch-holds on 91 customers who had entered into payment arrangements and failed to remove 71 switch-holds in a timely fashion (Docket 48608), while Reliant was docked for failing to timely send bills to customers and for improperly billing more than 47,930 customers (Docket 48773).
The commission also approved $240,200 in electric utility service quality settlements involving six different utilities in the following dockets: 48573, 48628, 48642, 48674, 48772 and 48774.
Following its executive session, the PUC agreed to intervene in Xcel Energy’s request before FERC to change SPS’ transmission formula rate template (ER19-404).
SPS is seeking a $9.4 million increase in its 2019 wholesale transmission service revenues, with almost $5 million being recovered from wholesale customers in the company’s SPP transmission rate zone and $4.5 million being recovered from other SPP tariff customers through regional transmission rates.
CARMEL, Ind. — Several MISO stakeholders are criticizing Tariff filings the RTO plans to make by the end of the year to free up an additional 5 to 10 GW of capacity in time for the spring outage season.
The discord played out in meetings as part of MISO Board Week and during a special conference call of the Reliability Subcommittee on Dec. 7.
At the Dec. 5 Advisory Committee meeting, Reliability Subcommittee Vice Chair Ray McCausland, of Ameren, said MISO worked unusually fast on the short-term resource availability and need filing.
“For those used to MISO running at the lightning pace of a glacier, MISO has flown through this,” he joked. McCausland also acknowledged stakeholder concerns about the pace of the filing. He said a few have voiced skepticism that the new load-modifying resource (LMR) treatment and outage coordination can in fact free up the capacity the RTO has cited as the reason for the Tariff filing.
Earlier this month, several stakeholders criticized MISO’s plan to require more testing of and data from certain LMRs and impose stricter notification times for planned outages. (See Stakeholders Critical of MISO Resource Availability Filing.)
Because of stakeholder pushback, the RTO said later in the Dec. 7 conference call that its originally planned Tariff filing will now become three separate Tariff filings: one each for demand response capability testing, LMR seasonal availability documentation and a new 120-day notice time for planned outages.
Kevin Murray, representing the Coalition of MISO Transmission Customers and the Eligible End-User Customers sector, called the original filing “controversial.” He said a full filing runs the risk of garnering so many protests that FERC will refuse to act on it, especially considering a D.C. Circuit Court of Appeals ruling last year that the commission overstepped its authority in its approval of PJM revisions to its minimum offer price rule. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
“I’m here to express my profound disappointment that we’re here today,” Murray said during the Advisory Committee meeting. He added that the RTO should do something about its lack of fast-start resources as winter approaches, particularly in MISO South.
Coalition of Midwest Power Producers CEO Mark Volpe said MISO’s proposed limits on outages may be punitive to generation owners. “We’re going way too fast here on something this serious,” Volpe said.
Jim Dauphinais, a consultant with Brubaker and Associates representing end-use customers, said the filing seeks to unnaturally force improved availability.
Imagining Blackouts
Board members who heard the discord urged stakeholders to work through their differences with MISO.
Director Baljit Dail asked stakeholders to imagine how they would respond today if the RTO experienced rolling blackouts. “How would you approach this problem differently? How would you change your answer?” he asked.
“I appreciate that no one wants rolling blackouts in the press … but I think there’s an unintended consequence here,” Madison Gas and Electric’s Megan Wisersky said. She said more rules for LMRs would drive some out of the market, resulting in reduced resources.
“I urge caution here,” she said.
However, representatives of the State Regulatory Authorities sector said they were supportive of a filing. Minnesota Public Utilities Commissioner Matt Schuerger said stakeholders cannot deny the urgency of needing changes.
Speaking at a Dec. 4 meeting of the board’s Markets Committee, MISO Executive Director of System Operations Renuka Chatterjee said “availability of resources is the key to avoiding real-time shortages.”
“We’re seeing an increase in unavailable megawatts for each of the last three winters,” Chatterjee told the committee.
Almost 12 GW (about 9%) of MISO resources are classified as LMRs, accessible only as part of emergency load management. The RTO had not called on LMRs for a decade after a localized Wisconsin emergency in February 2007 but has relied on them three times since 2017, most recently in MISO South in mid-September. Independent Market Monitor staffer Michael Wander said most MISO South LMRs were unable to respond in time during the September event because the units have long start-up times.
MISO has seen a 4.6-GW decrease in installed capacity from existing resources since 2017.
“We’ve experienced retirements of what we considered excess capacity,” RTO President Clair Moeller explained to board members.
Dail said the situation underscores the need for MISO to be able to better supervise planned outages. “This just looks like it’s going to get more complicated as we go forward,” he said.
Responding to a question from Director Barbara Krumsiek about whether MISO’s neighbors face similar availability challenges, Moeller said SPP has a similar experience of growing renewable resources paired with conventional generation retirements.
Seeking Clarity
MISO discussed a few recent additions to the possible multiple filings during the Dec. 7 conference call.
Staff said they propose to issue scheduling instructions up to 12 hours in advance based on resource lead times but would not actually call on the resource until two hours before it’s needed. Demand response resources that acknowledge scheduling instructions but are not ultimately called would nevertheless receive credit toward the five deployments per year that would be required of LMRs.
DR would also prove demand reduction capability by “performing to its requirements when called upon during the prior planning year” in addition to MISO’s original proposal of participating in a real power test. Testing of DR resources would begin for resource qualification in the 2020/21 planning year.
But stakeholders said the new demonstration option was vague, with some asking about the minimum number of performance hours and how MISO would account for performance when it calls up partial demand-reducing output.
MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO’s testing requirements would require full output of a DR resource for at least an hour.
Xcel Energy’s Kari Hassler asked what would happen if a properly scheduled planned outage takes more time to complete under the original scope of work and an emergency event occurs during the outage extension.
Rauch said the outage extension would likely fall under MISO’s “high-risk” determination, and the outage could be rebranded as a forced outage for the time it overlaps a maximum generation emergency, which would count against a resource’s accreditation.
However, she also said MISO is still working through revisions of its proposed filings and may choose to delay the outage coordination piece until January, still targeting changes by the spring outage season. She said the RTO will accept another round of feedback through the end of the week. MISO is planning to post an updated version of its filing or filings by Wednesday and will use stakeholder feedback in final revisions.
[Editor’s Note: An earlier version of this story incorrectly identified Jim Dauphinais’ affiliation and misnamed the Coalition of MISO Transmission Customers.]
WASHINGTON — When it comes to the smart grid, count consumer advocate David Springe as a nonbeliever.
He began his talk at gridCONNEXT 2018 last week with a vendor’s definition: “Smart grid is the convergence of information and operational technologies applied to the electric grid, allowing sustainable options to customers and improved security, reliability and efficiency to utilities.”
Then Springe gave the consumer advocate’s definition: “Smart grid employs new technologies that are more expensive and less secure than the current technologies to give pricing flexibility that customers don’t want, to communicate with small and smart appliances customers don’t own.”
Although he wrote that definition eight years ago, Springe, executive director of the National Association of State Utility Consumer Advocates (NASUCA), said it still applies. “The vast majority of customers don’t interact with their meters; [they] aren’t on time-of-use rates,” he said.
Customers, he said, have seen little benefit from replacing $100 analog meters that were depreciated over 30 years with digital meters that cost twice as much and are depreciated over only five years. “Frankly, all that meter infrastructure was pretty much used to read meters once a month. We spent a lot of money. If we did it under the premises of providing something that consumers wanted, we failed.
“There’s a million great ideas out there that only need somebody’s money to make it happen,” he continued. Consumer advocates “see this at the ground level where all these grand ideas that are being shared in this room show up on the utility balance sheet, show up on the utility bill.”
Instead of lusting after new technology, Springe said, utilities and regulators should focus on increasing efficiency and reducing costs through outsourcing and cloud computing. “Why does every utility have its own communication system? Meter system? Back office systems?” he asked.
Springe said consumers are seeing reduced generation costs swamped by increases in distribution and transmission charges.
That’s due in part to antiquated cost-of-service ratemaking that is preventing innovations that could save consumers money, said former FERC Chair Jon Wellinghoff, who shared a panel with Springe.
Wellinghoff is much more bullish on new technology, such as transmission devices that can add capacity without reconductoring or adding new substations.
He cited a project that Pacific Gas and Electric is building in West Oakland, which will combine distribution-level storage, behind-the-meter controls for demand response and distributed generation, and the aggregation of rooftop solar to address reliability concerns over the retirement of a Dynegy generator. The $100 million project won out over a $300 million proposal to add a new 230-kV transmission line.
That was good news for consumers, but not for PG&E, which won’t get to earn a return on the more expensive transmission investment, said Wellinghoff, who served for seven years as Nevada’s consumer advocate before joining FERC.
“We have to reconcile this somehow … so that utilities will have … incentives aligned with what we all would like to have for consumers, which is [an] efficient, cost-effective system that is clean,” he said.
Narrow Window for Energy Legislation in 2019
The conference also featured discussions on prospects for energy legislation in the new Congress.
The new Democratic House majority will have only a few months to work with Senate Republicans and President Trump on energy policy before the 2020 presidential election intrudes, said Jason Hartke, president of the Alliance to Save Energy.
Hartke said likely Speaker Nancy Pelosi (D-Calif.) will face a challenge managing the tension between “a whole lot of excited new members who want to do things like build the Green New Deal versus [veteran Rep. Paul] Tonko [D-N.Y.] talking about singles and doubles.” (See Optimism Rising on EVs as Sales Hit 1 Million Mark.)
Hartke said a bipartisan infrastructure bill that includes spending for grid modernization and electric vehicle charging is “the one opportunity for a home run.” But he said the fate of such legislation hinges on whether Trump engages and can win the support of the Republican-controlled Senate.
“We’re working hard now for a tax extenders package that makes sense. Right now, the House package is looking backwards, so it’s retroactive [extending already expired tax breaks]. We want it to look forward, so you could actually change behavior.”
Attorney Andrew Shaw, senior managing associate with Dentons, said new members who campaigned on bold action on climate change will be motivated to support smaller changes so they can take credit for legislative accomplishments.
“Something like an infrastructure bill — which faces a lot of hurdles undoubtedly — is a vehicle that you could maybe get some of those wins, because everybody wants to be able to go back home and be able to talk about what they’re doing,” Shaw said.
“It’s not a given that energy’s going to be in the mix” in an infrastructure bill,” said Amit Ronen, deputy chief of staff to Sen. Maria Cantwell (D-Wash.) in a separate discussion. “It’s something we’ve got to educate members … on.”
Ronen noted that Cantwell, the ranking member of the Energy and Natural Resources Committee, cosponsored the $7,500 passenger EV tax credit with Orrin Hatch (R-Utah).
“So now we’re looking at, is there a role for the government in incentivizing electrification of other transportation? We’re talking about boats, trucks, buses, even planes, which two years ago I wouldn’t have even thought … was possible.”
Shaw said there has been some progress in the last six years in building consensus on climate change, noting the introduction last month of a bipartisan bill that would set a carbon tax beginning at $15 per metric ton in 2019. The bill is based on the carbon dividend proposal offered last year by Republican party elders James A. Baker III and George P. Schultz. (See Lott, Breaux Join Push for Baker-Schultz CO2 Dividend Plan.)
“Unfortunately, in the House we did lose some more moderate [Republicans] who do believe in climate change science and were willing to engage,” Shaw acknowledged.
Companies are “being forced to act [on decarbonization] because government has failed us,” said Amy Davidsen, North America executive director for the Climate Group, which manages RE100, a collaborative of more than 150 businesses that have committed to using 100% renewable electricity.
Bill Weihl, former Google “green energy czar,” predicted RE 100 companies will grow to more than 300 in the next several years.
Weihl said the big innovation the last few years has been less about technology and more about development of new products, such as the two dozen “green” tariffs in 15 states.
But Hans Royal, director of strategic renewables for Schneider Electric, said many of the tariffs are too expensive or put too much risk on corporate buyers to be effective.
Electrifying Bus Transit
The two-day conference also provided an update on accelerating efforts to electrify city bus fleets.
“The orders for battery electric [buses] are ramping up really rapidly,” said Lisa Jerram, director of bus, paratransit and surface transit for the American Public Transportation Association.
Jerram said only about half of city transit buses are now pure diesel, down from 90% 10 years ago.
Compressed natural gas powers about 25% of fleets now, with hybrid diesel-electrics comprising about 20%, according to Jerram and Ryan Popple, CEO of electric bus maker Proterra.
But Jerram said many transit agencies need utilities’ assistance to make the transition. “They don’t understand utility systems that well; they don’t understand rate structures,” she said. Utilities also can help bus operators manage the logistics of charging in their depots and on routes, she said.
Popple said his company has received orders from 39 states. “If you add up the cities that have already mandated that they’re going electric — that includes … cities like Seattle and New York City — 10,000 of the 70,000 buses on the road are already politically mandated to go electric. So it’s coming. And the things that we figure out on the bus side you’ll need to them again at larger scale in school bus and truck [conversions].”
Europe’s Challenges
The conference heard a keynote address from Laurent Schmitt, secretary-general of the European Network of Transmission System Operators (ENTSO-E), which he described as “kind of the FERC of Europe.” The organization has 43 transmission system operators in 36 countries.
Schmitt said although the Nordic countries are blessed with offshore wind, it is a challenge to move the power to load centers. “Our system does not get planned as efficiently as what we would like, and it’s getting very hard to get transmission lines [sited] in Europe, especially getting people from certain states understanding that they have to build the line for the sake of other Europeans,” he said.
Schmitt said Europe does not use LMPs, “but I think we will have to go into a similar model in the future” to address scarce grid capacity.
Europe also faces challenges as renewables replace traditional generation, he said. Fossil fuels (coal, gas, oil, mixed fuels and peat) were responsible for 43% of Europe’s energy production in 2017, with renewables adding 33% and nuclear 22%.
“Are we going to be able to maintain frequency … when we have no rotating mass?” he asked.
WASHINGTON — Storage resources seeking to provide capacity would face much tougher requirements in some regions than others under proposed tariff revisions filed by RTOs and ISOs last week in compliance with FERC Order 841.
Storage offering capacity would have to continuously supply energy for two hours in ISO-NE, but four hours in NYISO and 10 hours in PJM.
Together, the filings by CAISO (ER19-468), ISO-NE (ER19-470), MISO (ER19-465), NYISO (ER19-467), PJM (ER19-469) and SPP (ER19-460) total more than 2,500 pages. FERC, grid operators and stakeholders now have a year to review, revise and implement the plans under a Dec. 3, 2019, deadline set by the commission when it issued Order 841 in February. (See FERC Rules to Boost Storage Role in Markets.)
The complexity of the revisions led some grid operators to ask FERC to rule on their proposals quickly to give them enough time to implement all the changes by the deadline.
“The implementation of the revisions proposed herein is estimated to cost SPP alone in excess of $800,000, and the magnitude of the effort requires major software and process changes to core SPP systems,” said the RTO, which requested FERC rule by March 1.
NYISO requested that FERC rule by Feb. 1, and it further asked that its implementation deadline be extended to May 1, 2020, because it is in the middle of “a significant upgrade” to its market software.
While MISO did not request an extension, it too is undergoing an overhaul of its market platform, noted Tanya Paslawski, executive director of the Organization of MISO States.
Speaking at Infocast’s Federal Energy Policy Summit on Thursday, Paslawski said “there are limits to what [the RTO] can do” to implement the order given its outdated system. For example, MISO established a 100-kW minimum size requirement for resources — the maximum allowed by the order — “because MISO’s existing market systems do not support offer or bid quantities less than this amount.”
Comments on the filings are due by Dec. 24. Several industry groups — including Advanced Energy Economy, the American Wind Energy Association and the Solar Energy Industries Association — filed a joint request to extend the comment period for another 45 days.
“The standard 21-day comment period will not be adequate for interested parties to review and comment on all of the RTO/ISO compliance filings,” the groups said. “The filings are voluminous and contain proposed revisions to several tariff provisions and market rules.” They also noted that the comment deadline is “in the middle of the holiday season, when many organizations are short-staffed.”
“I think it’s probably likely that the comment deadline gets extended,” Scott Baker, senior business solutions analyst for PJM, said at the summit.
U.S. energy storage annual deployments will reach 3.9 GW by 2023, according to a report released last week by Wood Mackenzie. The report attributes the estimated increase in part to tariff changes spurred by FERC Order 841. | Wood Mackenzie
Requirements Vary
Each grid operator submitted a participation model for storage resources to provide any services of which they are capable, but requirements vary.
“RTOs have largely allowed storage to provide the same services, under the same conditions, as a provided by other types of resources. Sometimes this creates barriers to storage participation,” the New York School of Law’s Institute for Policy Integrity said in an analysis of the filings.
PJM’s “onerous” 10-hour requirement is only possible for most resources “through significant derating of capacity, and even then may not facilitate cost-effective participation in the capacity market,” the institute said.
“PJM also has proposed an accounting framework that effectively requires all charging by energy storage resources participating in PJM’s participation model that are not owned by load-serving entities to discharge (sell their energy) back to PJM,” it continued. “These resources cannot sell to others or use the stored power themselves.”
As for energy markets, resources would have flexibility under the proposals, with some grid operators allowing suppliers to participate in different “modes.” How many modes — and what they’re called — depends on the region.
PJM, for example, proposed to allow three modes: continuous, charge or discharge. In continuous mode, resources can both charge and discharge, with no limitations on start-ups or ramp rate.
NYISO would offer four modes: ISO-committed fixed, ISO-committed flexible, self-committed fixed and self-committed flexible. In the ISO-committed modes, suppliers would leave it up to NYISO to determine the most optimal dispatch times for their resources. In the fixed mode, the ISO would schedule them in the day-ahead market and dispatch them no more frequently than every 15 minutes in the real-time market. In the flexible mode, NYISO would dispatch resources in the real-time market based on LMPs. In the self-committed modes, suppliers would make these decisions themselves.
MISO would allow for eight “commitment statuses”: discharge, emergency discharge, charge, emergency charge, continuous, available, not participating and outage (offline). (See MISO Offers Storage Proposal, Promises to Exceed Order 841.)
Under the proposals, resources will able to participate in any market they choose, without having to participate in others. For example, Baker noted that PJM currently requires resources wishing to provide synchronized reserves also participate in the RTO’s energy market. “In other words, if you were just a battery that didn’t want to participate in the energy market, but you were sitting there and have the capability to respond within 10 minutes to a synchronized reserve signal, we didn’t have the ability for a resource like that to do that,” he said.
In part because of California legislation requiring investor-owned utilities to procure storage, CAISO filed the fewest revisions among the grid operators. One of the more significant changes was that it reduced its minimum size requirement from 500 kW to 100 kW, Andrew Ulmer, ISO director of federal regulatory affairs, noted Thursday.
SPP noted that it gave storage resources in its footprint — all of which are currently pumped hydro and not able to vary their dispatch mode — the ability to stick with its current model for participation or register as a market storage resource (MSR).
