MISO is poised to recommend its first-ever storage-as-transmission project to ease reliability issues in central Wisconsin, though the RTO doesn’t yet have rules to govern the project’s operation.
The RTO last week said it reviewed American Transmission Co.’s Waupaca area energy storage project against an alternative wires solution also submitted by the company. MISO concluded that while both projects improved reliability, a comparison of life cycle costs proved the storage project more cost-effective. Consequently, the project is set to be included in MISO’s 2019 Transmission Expansion Plan (MTEP 19) for approval in early December.
The 2.5-MW/5-MWh battery project is expected to cost $8.1 million and be in service at the end of 2021. ATC’s alternative 115-kV double circuit rebuild would have cost $11.3 million.
“There’s a big asterisk on” the project, MISO expansion planner James Slegers told stakeholders during a conference call Friday.
ATC SATA project map | MISO
ATC plans to automate the storage facility, which will be triggered only on a post-contingency basis. ATC’s Jim Hodgson said costs of battery degradation are all included in the company’s estimated operations and maintenance costs and based on “the best available information.” The storage project also includes two new capacitors.
The company doesn’t expect the battery to be used often but notes it would have to cycle daily to keep in good condition. ATC is working off the assumption that the battery will last 20 years. The company also expects no public impact on rights of way. (See MTEP 19 Could Yield First MISO SATA Project.)
“First and foremost, it’s a reliability asset,” ATC’s Bob McKee told MISO and stakeholders.
ATC’s Waupaca area contains a local 69-kV system supported by a nearby multi-segment 115/138-kV transmission line. The area is at risk of voltage collapse if it experiences a double contingency or outage in conjunction with prior maintenance. When both ends of the 115/138-kV supply line are out of service, the system cannot sustain local loads at certain levels, Slegers said.
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. The battery is designed to operate after a second contingency.
MISO Manager of Expansion Planning Lynn Hecker said the RTO has worked closely with ATC to understand the operation of the battery and the maintenance costs.
RTO staff said the battery wouldn’t negatively impact the dispatch of the four nearby generation projects finishing the final phase of the generator interconnection queue. However, MISO hasn’t yet determined the network upgrades the projects might require because the projects entered the definitive planning phase in spring 2018.
MISO will post a draft MTEP 19 report on Sept. 16. So far, the RTO is positioned to recommend 529 new projects at $4.4 billion. The newest estimate is higher than those released in spring. (See MTEP 19 Revealing High Price Tag.) If approved, this year’s buildout package will be MISO’s most expensive. Last year, the RTO cleared a $3.3 billion, 442-project MTEP 18.
MISO will host an in-depth workshop this fall on how to incorporate generation projects that draw on more than one fuel source.
The workshop, tentatively planned for Oct. 8, will focus mostly on intermittent generation projects paired with electric storage. The workshop idea materialized during a Steering Committee call Thursday, when members of the former Energy Storage Task Force presented a list of hybrid resource topics to be assigned to stakeholder groups for developing possible Tariff changes and Business Practices Manuals.
The list of 22 topics regarding hybrid generators is the pièce de résistance of the ESTF, which sunset in June after identifying energy storage topics that MISO and stakeholders should focus on in order to integrate storage into the RTO’s markets. The list of hybrid considerations was the final document the group produced. (See “Next up: Hybrid Resources,” MISO Undecided on Amending Storage Plan.)
Currently, MISO models hybrid resources separately for each fuel source. The ESTF said addressing its list would help “facilitate non-discriminatory market participation.”
Committee members were initially daunted by the length of the list until Chair Tia Elliott suggested the all-stakeholder workshop. The committee is responsible for routing new grid topics to the appropriate MISO stakeholder committee.
Among other ideas, the ESTF wants MISO to begin considering: capacity accreditation; ensuring hybrid output doesn’t exceed interconnection service levels; addressing state of charge; whether to allow separate or dual metering; how the RTO’s must-offer rule would apply; participation in ancillary services; and asset registration.
The Planning Subcommittee is already considering how a hybrid resource will be studied in the generator interconnection process, one of the ESTF’s priorities. (See MISO Queues up Interconnection Options.)
“Hybrid storage resources are under active development and could be online in MISO in the near term. Prompt resolution to the … issues is necessary not only to ensure accurate assessment of the business case for market participants, but also to ensure these resources are appropriately participating in the market under the required rules and structures,” the ESTF said.
The ESTF has requested the hybrid topics receive immediate attention from the Market Subcommittee, Resource Adequacy Subcommittee, Planning Advisory Committee and Reliability Subcommittee. Former ESTF Chair John Fernandes said many of the issues couldn’t wait until MISO’s 2020 Integrated Roadmap list of market improvements, explaining that hybrid projects are already in the works in the RTO’s footprint. He pointed to Entergy’s proposed 100-MW hybrid solar-and-storage project, currently before the Arkansas Public Service Commission. The project is expected to enter service by 2021.
“We do want to create a little bit of urgency around this,” Fernandes told Steering Committee members.
Clean Grid Alliance’s Rhonda Peters seconded Fernandes’ call for urgency and urged the committee to track the topics on the list to make sure stakeholder groups are actively tackling them.
“This issue list is comprehensive, and it shows how much work the task team put into it,” MISO Market Design Adviser Bill Peters said.
Shell Energy and Old Dominion Electric Cooperative failed to make their case that they belong at the GreenHat Energy settlement table, FERC said in denying the companies’ rehearing requests Thursday.
FERC said the companies’ argument that they are “uniquely situated” in the proceeding and that their late intervention would not “unduly burden or prejudice any party” was “unpersuasive” (ER18-2068).
“We do not find that failing to grant late intervenors party status will necessarily result in a settlement that is not ‘fair and reasonable and in the public interest,’” FERC said. “Should the parties reach settlement in this proceeding, the commission will review the terms of that settlement and determine whether such settlement meets the relevant standard.”
Shell’s request for rehearing argued that FERC erred when it dismissed more than a score of late-filed motions from intervenors seeking to participate in the unwinding of GreenHat’s financial transmission rights portfolio. GreenHat was declared in default in June 2018 after it failed to make good on its mounting losses. (See Shell Demands Seat at GreenHat Settlement Table.)
An independent consultants’ report said GreenHat’s trading “was conspicuous in that its positions were far larger and of longer tenor than those of other financial participants in the FTR market.” | PJM
Shell was among more than 20 petitioners that filed after the comment period for PJM’s request passed. FERC rejected the late filings, saying none demonstrated “requisite good cause for late intervention.”
Shell said a PJM Tariff provision caused its tardiness, a circumstance that it says none of the other petitioners faces. It had explained that it entered into three bilateral contracts with GreenHat that involved transferring FTRs back and forth between the two companies. Liquidating the GreenHat portfolio “could substantially affect the amount sought by PJM from Shell for the guarantee and indemnification claim” the RTO placed on the portion that was transferred. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
“Shell Energy knew at the time PJM filed its waiver request that it had transactions with GreenHat that a commission ruling might affect,” FERC said. “Regardless of whether Shell Energy agreed with PJM’s request for waiver, it could have intervened timely to protect its interests.”
ODEC had said its late filing was nothing more than an “oversight” — an explanation the commission found lacking. It said ODEC’s interests in the case, which could set a precedent for financial defaults in RTOs, could be “sufficiently” represented by other timely intervenors.
“Old Dominion does not explain in seeking late intervention how other participants will not sufficiently represent this generalized interest, and there are, in fact, others who timely intervened on the basis they too would be impacted by the outcome of the proceeding,” FERC said. “Moreover, concern that adverse precedent may be created is not a persuasive basis for late intervention.”
A U.S. bankruptcy judge stalled FirstEnergy Solutions’ reorganization plan last week over unresolved contract disputes with workers at its Perry and Beaver Valley nuclear plants.
Judge Alan M. Koschik told lawyers for the utility that he cannot approve its reorganization plan — which includes shedding $3.6 billion in debt, cutting ties with FirstEnergy Corp. and possibly changing its name — until the issue is resolved. He set a status hearing for Sept. 10.
FES wants to renegotiate the terms of the collective bargaining agreements with the Utility Workers Union of America and the International Brotherhood of Electrical Workers that were originally approved by FirstEnergy because the company claims it cannot afford the pension benefits post-bankruptcy. (See FES Seeks Bankruptcy, DOE Emergency Order.)
A U.S. bankruptcy judge stalled FirstEnergy Solutions’ reorganization plan over unresolved bargaining contract disputes with workers at its Perry and Beaver Valley nuclear plants.
“We are pleased with the progress made in the hearings, which resolved substantially all non-labor-related issues pertaining to confirmation of our plan,” FES spokesman Tom Becker said in a statement Friday. “We remain focused on confirming the plan to exit bankruptcy by the end of 2019.”
In court documents filed earlier this month, Joyce Goldstein, attorney for both unions, argued that they had struck contracts that contain a “strong successorship” clause requiring FES to assume the terms of the agreements. Goldstein also noted that because Ohio lawmakers passed a bill to subsidize the state’s nuclear plants, FES will “have even more cash” on hand to pay benefits. (See Ohio Approves Nuke Subsidy.)
“There is no impediment to assuming the CBAs and providing benefits that mirror those currently provided, as has occurred eight times before,” Goldstein said, referencing FirstEnergy’s decision to assume bargaining unit contracts when it acquired other utility companies pre-split. FES “would simply prefer not to.”
Frank Meznarich, president of UWUA Local 270, applauded Koschik’s decision in a statement Friday, calling it a “significant victory for our members.” UWUA represents workers at the Perry nuclear plant, located 40 miles northeast of Cleveland along Lake Erie. IBEW Local 29 represents workers at the Beaver Valley plant near Pittsburgh.
“FES cannot escape bankruptcy without fulfilling its obligations to the individuals who maintain and operate these facilities,” Meznarich said. “Our members have been unwavering in their efforts to deliver power to ratepayers who rely on it and we expect FES to honor its legal obligations to our members.”
FES CEO John Judge wrote in an Aug. 18 column for The Columbus Dispatch that his company’s good faith negotiations have resulted in signed framework agreements at three of its five nuclear plants since March. He said the latest proposal submitted to the bargaining units at Perry and Beaver Valley include terms that preserve the wages, raises, work rules, medical, dental and paid time off benefits found in the existing contracts.
“The only open issue we have is retirement benefits after emergence, since we can no longer participate in the FirstEnergy Corp. pension plan at that time,” he said. “No retirement benefits earned prior to emergence will be taken away.”
Post-bankruptcy, FES plans to offer an “enhanced defined contribution plan” that matches 50 cents of each $1 contribution made by employees up to 6%. Employees with long tenures will receive additional contributions up to 9%, and those closest to retirement will be offered bridge payments to soften the blow of plan changes.
Judge said the program exceeds industry standards and serves as a “fair offer … since we kept other elements of the existing wages and benefits intact and all benefits earned to date will be paid.”
“Our power plants must compete with other unregulated power generators in what is a tough economic environment,” Judge said. “None of our competitors has started a new traditional pension plan or offer such a plan to new employees. Our proposal allows our plants to remain competitive, stay open and continue to employ the workers we rely on to operate those plants.”
New England Power Pool Counsel Eric Runge provided the Transmission Committee with an update on the hearing procedures in the proceeding under Federal Power Act Section 206 on network service formula rates (EL16-19-002).
The settlement proposed new rates and a new rate design for regional network service (RNS), local network integration transmission service (LNS) and point-to-point (PTP) transmission service for all the TOs in the region. It would have replaced the existing RNS and LNS rates with new formula rate templates and associated protocols.
FERC trial staff argued that the settlement was unfair because it would have set unreasonable rates and “contains fundamental defects.” Staff cited the TOs’ ability to conduct “extra-formulaic, ad hoc” ratemaking for all externally sourced inputs every year and over-recover certain plant costs.
The commission instituted the proceeding in December 2015, saying ISO-NE’s Tariff “lacks adequate transparency and challenge procedures” on the NETOs’ formula rates and that the network rates “lack sufficient detail” to determine how costs are derived and recovered.
Under a scheduling order approved Aug. 13, direct testimony from witnesses seeking changes to the existing rates is due Oct. 10, with answering testimony to defend the existing rate due Jan. 10, 2020. Rebuttal testimony responding to answering testimony is due March 2, and discovery requests must be submitted by March 12. A hearing is scheduled for April 27 through May 12. Oral arguments, if necessary, will be held Aug. 10 with an initial decision targeted for Sept. 21.
Runge said the commission could issue an order by the end of next year. The order, he noted, could be followed by rehearing requests.
Changing Interconnection Capability Following Partial Market Exits
Director of Transmission Strategy and Services Alan McBride led a discussion of ISO-NE’s proposed procedural changes to clarify how the RTO adjusts interconnection capability after partial market exits.
The RTO is drafting Tariff changes to collect in one place the rules now in three schedules and Planning Procedure No. 10 that detail how it updates interconnection service limits for generators. The rules would apply after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the Forward Capacity Market. The changes, to be collected in a new section II.48 of the Tariff, also would apply to external elective transmission upgrades.
The changes include an exception process for reducing summer capacity without changing winter limits. The exception would allow generators to provide engineering information to the RTO to prove that the formula-based, proportional winter capability adjustments for a partial retirement do not accurately calculate their winter interconnection capability.
The RTO hopes to make the changes effective in January following approvals by the Reliability Committee in September, the TC in October and the Participants Committee in November.
ISO-NE Director of Transmission Planning Brent Oberlin outlined proposed Tariff revisions to accommodate Order 1000 competitive transmission solicitations.
The RTO said the changes are needed because the selected qualified transmission project sponsor agreement (SQTPSA) did not specify that project modifications may be required under section I.3.9 of the Tariff and that failure to reach agreement on modifications may be grounds for termination. It also said changes were needed to Attachment K of the Tariff to consider system performance as an evaluation factor and specify that participating TOs must stop work on projects related to the upgrade of existing facilities once a developer has been selected as the “stage two” solution. It is also refining the definition of “localized costs” to make it consistent with the intent of the competitive process and differentiate it from asset condition projects.
Oberlin outlined several changes to the SQTSPA and Attachment K since the July TC meeting.
The TC will vote on the revisions Sept. 17 with a PC vote expected Oct. 4.
Cost Recovery for CIP Standard Compliance
ISO-NE’s Jonathan Lowell presented the RTO’s proposal for a cost recovery procedure for generators’ compliance with NERC’s critical infrastructure protection (CIP) standards. Generators designated by the RTO as “critical” to the determination of interconnection reliability operating limits face higher CIP standards than “non-critical” generators, and the costs cannot be competitively offered and recovered through the energy and capacity markets.
Lowell said the RTO’s goal is to reduce the time and expense involved in the cost filings and provide guidance on cost identification and categorization while avoiding the need for reconciliation and true-up procedures. It will “emulate a ‘formula rate’ construct as much as possible,” Lowell said.
A new Schedule 17 will set out a procedure for generators to make FPA Section 205 filings to gain FERC approval of the costs. The proposed costs would be posted for at least a 60-day review period before the FERC filing, and there will be Webex or in-person briefings for interested stakeholders. The prefiling review is intended to result in uncontested FERC filings and definitive orders that the RTO can rely on for billing.
Range of study time frames for establishing interconnection reliability operating limits | NERC
The RTO will support “direct cost” categories identified in the Schedule 17 template. Generators would have to support other costs not covered by the template.
Once approved by FERC, ISO-NE will bill the costs over 12 equal payments over a year.
Lowell said the RTO has eliminated previous proposals for 24-month and 36-month amortization periods and differentiations for “recurring” and “nonrecurring” costs.
ISO-NE proposes costs be allocated to transmission customers based on monthly regional network load and monthly average through or out service. “Incremental CIP compliance costs are not a transmission cost, but it is correct and efficient to allocate these costs to transmission customers as beneficiaries,” the RTO said.
Charges will be separately identified on RTO customers’ monthly non-hourly charges statements.
The NERC Standards Committee last week approved posting for industry comment the Evidence Retention Report produced by the Standard Efficiency Review (SER) Phase 2 team, which recommends reducing the number of evidence retention schemes to eight from the current more than 50.
Unless otherwise specified, the default retention period would be a rolling 48 months, which the report says “is useful for high [violation risk factor] requirements where an entity is audited every six years. It is not useful for medium and low VRF requirements.”
“High volume data” would be retained for 30 days except for a small set of requirements that would be kept for six months.
Voice and audio recordings, which take up a lot of space on computer systems, would be retained for only 90 days.
Michael Puscas of ISO-NE said evidence retention was one of the higher priority issues identified by the Phase 2 team.
A 2014 white paper had also recommended reducing the requirements, but the changes were not enacted. As a result, the report says, “data and evidence retention schemes remain overly complicated and burdensome.”
The committee voted to reject Arizona Public Service’s April 2018 standard authorization request (SAR) for BAL-002-3 (Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event).
APS said the proposed change — allowing compliance with the standard to have been reached once interconnection frequency has recovered — would prevent the recovery of one event from contributing to the creation of another event. The company said it was attempting to draw attention to a situation in which a balancing authority’s area control error (ACE) is low while the interconnection frequency is high.
APS said intentionally increasing frequency when it is already high is not permissible in normal operations and should be discouraged during emergency operations.
The Standards Committee said modifying requirement Part R1.1 of the standard to include interconnection frequency assessment “would modify the original intent of standard, which is the demonstration of the deployment of reserves to recover from reportable balancing contingency events.”
It said that APS’ concerns “can be addressed by other means.”
“Compliance guidance, reliability guidelines and/or reference documents can be developed to instruct BAs/[reserve sharing groups] on how this should be addressed, including modifications to the Operating Process and Operating Plan (see R2) to better prepare for such situations and manage reserves so that injection of power or firm load shed is not the default response. An effort to develop any of these documents, in concert with the appropriate NERC technical committees, could be completed more quickly than the entire standard revision process. Such an effort will provide different solution(s) than proposed but will align with and not circumvent the requirements in the standard.”
In May, the committee delayed a vote rejecting the SAR after several members said they wanted to add the technical justification for its rejection to the record. (See NERC Panel Delays Action on BAL Standard Request.)
| Pixabay
Committee Ponders less In-person Meetings
Director of Engineering and Standards Howard Gugel proposed reducing the committee’s face-to-face meetings, citing internal staff discussions and those with the SC’s Executive Committee.
Gugel proposed “as a conversation starter” reducing the in-person meetings from four to two or three annually, all to be held at NERC’s Atlanta headquarters. NERC is converting its entire sixth floor into conference space to reduce outside meeting costs.
Gugel said the in-person meetings could be supplemented by conference calls every four to six weeks when needed.
“Some of our face-to-face meetings have been rather brief,” Gugel said. “It requires a lot more work for us before the face-to-face meetings than the calls. It can be very taxing on the staff.”
He suggested the Atlanta meetings be scheduled in the spring and fall, when the weather is most temperate and hotels are less busy.
The proposal was quickly endorsed by ISO-NE’s Puscas.
But Venona Greaff of Occidental Chemical said new committee members would benefit from meeting the other members immediately after joining, which is typically in January. Evergy’s Jennifer Flandermeyer and Amy Casuscelli of Xcel Energy agreed.
“I’m pretty reluctant to agree to just two meetings a year. I think that there is real value in face-to-face interactions. We talk about things. It really contributes to the cohesiveness of the committee as a whole. I think that there are some softer, more intangible benefits that often get overlooked when we think about efficiencies and people’s schedules and their travel calendars,” she said. “I would hate to see us lose any effectiveness for the sake of trying to make things better.”
Casuscelli also expressed concern that limiting the meetings to Atlanta might hurt participation by West Coast stakeholders.
California-based consultant Barry Jones seconded Casuscelli’s concern, suggesting consideration of a “NERC West” office.
“I’ve primarily been in the California, Nevada [and] Arizona regions, and when we fly to Atlanta, we lose three hours and it’s really exhausting,” said Jones. “When we fly West to East it eats up an entire week just to go for two days [of meetings].”
Chairman Andrew Gallo said, “There is a good benefit to face-to-face meetings, even when they’re brief,” noting committee members seem to comment more freely in person.
“I do think it sparks more enthusiastic participation,” he said. “There’s just not a whole lot of commenting [on calls]. I don’t know if people are distracted.”
Barry Lawson, of the National Rural Electric Cooperative Association, opposed cutting in-person meetings in half immediately but said he would support an initial switch from four to three meetings “and see how it goes.”
Gugel said the next step will be further discussions with the Executive Committee. “We’ll have more conversations, and at some point, this will be a decision the committee as a whole will be making,” he said.
Other Actions
The committee also:
Approved the procedure for electing its chair and vice chair for two‐year terms beginning Jan. 1. The election will be held at the Sept. 18 committee meeting in Kansas City.
Authorized the solicitation of additional nominees for the Project 2019-02 (BES Cyber System Information Access Management) standard drafting team (SDT), which recently lost several members, including its chair.
Appointed members, the chair and vice chair to the SDT for Project 2019-03 (Cyber Security Supply Chain Risks), as recommended by NERC staff.
VALLEY FORGE, Pa. — After months of wrangling, PJM and its stakeholders reached agreement Thursday on manual language detailing how the RTO will remove supplemental projects from its Regional Transmission Expansion Plan.
After American Municipal Power (AMP) and competitive transmission developer LS Power reached agreement with PJM on the manual language on Tuesday, Exelon crafted a friendly amendment Thursday that won support of most of the RTO’s incumbent transmission owners. (See related story, PJM, Stakeholders Strike Deal on Supplemental Projects.)
Supplemental projects are those that address local TO reliability concerns and are not required for compliance with grid criteria governing system reliability, operational performance or economic efficiency. The RTO does not approve supplemental projects but does study them to ensure they won’t harm reliability.
The Exelon amendment clarified that supplemental projects cannot be considered for inclusion in the RTEP base case during PJM’s modeling verification process, which generally precedes a submission window for competitive projects under FERC Order 1000. Sharon Segner, vice president of LS Power, described the verification process as the RTO’s version of “quality control,” implemented in order to assure the modeling assumptions used to solicit competitive projects are correct.
Segner said Exelon’s 23-word insertion in the last paragraph of section 1.3.4 in Manual 14B protects the integrity of the competitive process by preventing TOs from proposing supplemental projects designed to meet regional needs.
The paragraph states that “once PJM issues its preliminary RTEP models for verification of topology and dispatch prior to initiation of any preliminary RTEP analysis and quality control check in preparation for opening a proposal window, PJM will not consider for inclusion in the RTEP base case a subsequently submitted proposed supplemental project that would alleviate a violation identified in the proposal window.” (Exelon’s insertion is in italics.)
The agreements allowed members to finally vote on the revisions after four deferrals and eight months of discussion at special Planning Commission meetings. Six of 12 members of the TO sector endorsed the changes in the Markets and Reliability Committee vote, with four opposed and two abstaining. End-Use Customers, Electric Distributors and Other Suppliers gave near unanimous support to the manual change, which cleared by a sector-weighted vote of 4.55 to 0.45 (91%).
“These manual revisions are basically saying that when these Order 1000 windows open, PJM can consider projects that meet regional needs and regional drivers and can also consider supplementals that address these drivers to see if there’s a better regional solution,” Segner said. “The manual in and of itself is talking through what that looks like.”
LS Power had sought the manual revisions since the January MRC meeting, when PJM declined to implement stakeholder-endorsed language about planning transparency. Staff said the revisions were inconsistent with FERC rulings and would require the RTO to overstep its authority in the regional planning process. (See PJM Rebuffs Stakeholders on Supplemental Projects.) Spending on supplemental projects has tripled over the last 13 years, accounting for 62% of the submitted RTEP project costs since January 2017, according to an analysis from AMP. In 2018, AMP found, TOs added $5.7 billion in supplementals and just $1.5 million in baseline projects into the RTEP.
AMP said earlier this month that TOs have proposed an additional $3.4 billion in supplementals so far in 2019, exceeding the baseline total.
“We think we are at a better place than we were six months ago,” Segner told the MRC. “I’m talking about how to protect the integrity of the Order 1000 windows. So, we would say we are in a better place and there would be better protections in place than there are now.”
The revisions detail how PJM would alter the RTEP after siting authorities deny a permit for a supplemental project. The RTO has argued that it lacks the authority to remove such projects from the planning model and noted that a project can languish for years of litigation before a TO wins approval or abandons it.
The revisions state that if the denied application represents a final regulatory order, the developer must notify PJM. Staff would then review the “impacts associated with removing the project from the RTEP or continuing to include such project in light of such final regulatory order” and present its findings to the Transmission Expansion Advisory Committee.
“A project denied siting authority in a final regulatory order by the relevant regulatory siting authority will generally be removed from the RTEP base case as determined by PJM after discussion with the relevant transmission owner(s) or designated entity and vetting with stakeholders at the TEAC,” according to the new language.
The language also includes a path for TOs to dispute assumptions that a regional baseline upgrade will meet the needs of a proposed supplemental project.
Segner said that siting authorities will be notified when TOs stick with a supplemental project for which PJM has identified an appropriate regional solution — leaving it up to the states to decide what to do next.
She described PJM’s willingness to implement the changes as “the most important” outcome from the special PC sessions. When the vote results were revealed, many in the room — including most of PJM’s staff in attendance —broke into applause.
“That’s a victory for the stakeholder process, and we are at a better place,” Segner said.
Frustrated with the Process
Still, the process by which the issue was resolved left many stakeholders frustrated.
“This process has been very choppy and consumed an inordinate amount of time,” said Steve Lieberman, director of regulatory affairs for AMP, before agreeing that crafting language PJM would implement was the most important outcome of the special PC meetings. “That is a lesson that this membership learned, I think, in a hard way back in January. … I don’t know that we need to necessarily work that way all the time, but going into and having confirmation for a vote and both sides of the room agreeing with each other is a good thing.”
SAN ANTONIO — The Border Energy Forum XXIV drew attendees and speakers from both sides of the U.S.-Mexico border to the banks of the River Walk on Aug. 20-21. The North American Development Bank (NADB), created by the two countries to develop infrastructure and protect the environment along their border, hosted the event, which was begun in 1994 by the Texas General Land Office to exchange information about energy, economic development and environmental issues.
Of course, there have been many political, regulatory and market changes along the border during that quarter century. Duncan Wood, director of the D.C.-based Woodrow Wilson Center’s Mexico Institute, remembered a time “when you couldn’t talk as a foreigner about Mexican oil and gas.”
But when Mexico began opening its electricity market in 2013, it relied on ERCOT and other RTOs for best practices in operating competitive markets. Private investment in renewable projects and transmission was welcomed.
That all changed when Mexico elected Andrés Manuel López Obrador, commonly referred to as “AMLO,” to a six-year term as president. He put the brakes on the market reforms, moved to centralize authority and focused his attention on the country’s natural resources.
“Because of the change in government, we’re seeing a realignment of the priorities in the relationship,” said Wood, who has been tracking the U.S.-Mexico energy relationship since 2005. “We’ve moved from a paradigm focused on energy security to a focus on energy independence. The U.S. wanted a friendly, reliable partner for crude oil, but by 2013, the conversation was no longer about, ‘We need the oil.’ That’s good for Mexico. That will help them transform their economy, and it’s an opportunity for the U.S. to invest in Mexico.”
Wood said while investments have continued on both sides of the border, he is not as optimistic as others that the two countries will continue to share their expertise and trade. He said centralizing the decision-making within the state-run legacy petroleum and electric organizations and the “erosion” within the institutions from political pressure “make it really tough to stay optimistic.”
“Those two factors are really forcing a lot of people who haven’t invested in Mexico to think … ‘Now is not the time to go in,’” Wood said. “I feel we’re in very much of a pause, a prolonged pause. I don’t think we’re going to get very far. There’s much less progress than around [former presidents] Enrique Peña Nieto or Felipe Calderon.
“Are we seeing a closing of Mexico?” he asked, rhetorically. “I think it’s not unusual. This is more normal than the exception. Calderon and Peña Nieto were the exceptions. We hope there’s a further opening or reopening of Mexico. We will be missing out on a greater integration of energy infrastructure and the complementariness of renewable resources.”
“The changes under the last administration were enormous,” said Beth Urbanas, deputy assistant secretary for Asia and the Americas in the Department of Energy’s Office of International Affairs. “We do understand the new administration has priorities and concerns, mainly related to the energy system’s sustainability. We understand these are difficult processes to develop, and the Mexican system is now going through some of those pains.
“We want to be sympathetic and approachable, to carefully look at AMLO’s priorities and see areas where we can work together going forward,” she said. “We want to focus on areas where the door appears to be open. Our goal is about technology exchange and shared goals in the energy sector, like more energy efficiency, cleaner technologies [and] reliable resources. These are all things that are common across both administrations in the United States and Mexico.”
Wood did see a reason for hope. He noted López Obrador is only pausing the reforms, not rolling them back, and he understands the “retail aspect” of the energy reforms. That takes the focus off an economy that contracted by 0.2% in the first quarter this year and where oil production — a key economic driver — fell by 10% in May to its lowest level in 40 years.
“AMLO seems to like infrastructure,” Wood said. “Can he be convinced to spend because Mexico doesn’t have the will to take foreign investment?”
First USMCA, then Infrastructure?
U.S. Rep. Roger Williams (R-Texas), seated alongside Mexican Sen. Cruz Pérez Cuéllar, was among several speakers who extolled the United States-Mexico-Canada Agreement (USMCA). The pact, an update of the 1994 North American Free Trade Agreement, has yet to be ratified by Congress or Canada. Mexico’s government approved it in June.
“I believe NAFTA has really been good for Texas, but it’s a little long in the tooth,” Williams said.
“It’s the right thing to do: the right thing to get it on the floor, the right thing to get it passed. It’s political. One side doesn’t want to support it, because it’s a win for the other side,” he said, referring to political divisions in D.C.
Williams said he would like to see the approval of the agreement followed by infrastructure spending. His concern is the 28 points of entry between Texas and Mexico, where vehicles can wait six to seven hours to clear customs.
“We’ve got to have infrastructure if we want to move products and people across the border,” Williams said. “If you’re in the produce business and have to sit on the bridge for six hours, you may not have a product after that. I hope the passage of USMCA will force Congress to get an infrastructure bill to get things moving down here. Let’s pass this thing and get things going.
“At the end of the day, Mexico is our best friend. You’re our trading partner,” he told Pérez Cuéllar. “If it’s going to be good for you, then it’s good for us.”
The George W. Bush Institute’s Matthew Rooney offered a counterpoint to Williams, though he agreed the USMCA “represents a better effort to seize [on North American integration] than NAFTA did.”
“But missing from both USMCA and NAFTA are real commitments to cross-border infrastructure,” Rooney said. “There are no commitments to how we’ll move forward. That’s true in the energy space, and that’s true in transportation.”
Roberto Coronado, senior vice president at the Federal Reserve Bank of Dallas, said NAFTA’s integration of supply chains among the three North American countries has allowed Texas and other U.S. states to become more competitive in international markets, particularly in the manufacturing sector.
“We would expect the Texas economy and the U.S. economy should become even more competitive globally,” he said.
Agreeing with Wood that there’s a pause in investment in Mexico, Coronado said, “In due time, we can come back to the table and continue [investing in Mexico], because it presents even greater opportunities.”
Wood Urges Regional Approach to Border Energy
Wood used an example from the Great White North to suggest a regional approach, unhampered by national borders, to improved energy production. He cited a MISO initiative that he said stores renewable-sourced energy in pumped hydro facilities in the Canadian province of Manitoba.
“That seems commons sense. Why wouldn’t you use storage that’s just across the border?” he said. “The border is a literal line in the sand. It’s meaningless, but it affects us in so many ways. When you think in North American contexts, we would go a long way.”
“I love the idea of regional cooperation,” said Michelle De Blasi, senior energy and environmental attorney at Fennemore Craig and executive director of the nonprofit Arizona Energy Consortium. “Yes, countries have borders, but when you’re talking about energy and regional cooperation, it makes all the sense in the world. We miss opportunities because of border issues. You’ve got to get rid of the arcane laws that don’t make any sense to us.”
De Blasi’s organization helps the energy industry to support and retain companies in the state. She suggested a need to partner with Texas and New Mexico to share in the “plethora” of solar power. “In certain instances, California is paying us to take their solar power,” De Blasi said.
“Money follows certainty. If you don’t have the goal posts set for investors, they’re not going to invest,” she said. “The Mexican market is competing for dollars from investors who have other opportunities.
“Regulatory issues, mostly on the Mexican side, have changed [Mexico’s market]. You used to be able to bring outsiders into the market, but where there’s regulatory uncertainty … I don’t think we’ll get there,” De Blasi said.
Turning Attention to Central America
According to the Harvard Review of Latin America, the U.S. has intervened, directly or indirectly, in Central America 19 times since 1903. Several Border Forum speakers called for a joint intervention of a different sort to help stem the flood of Central American refugees at the U.S.-Mexico border.
“Mexico, because of the [energy] pause, is missing out on the chance to export energy to Central America,” Wood said. “AMLO wants development to solve the immigration problem. The U.S. and Mexico ought to be working much closer for providing gas and electricity to Central America.”
“We here in America would do wise in helping Mexico and countries south of Mexico to create an economy, build plants and facilities, give them a good wage,” said Williams, a co-sponsor of legislation in the House of Representatives that would increase U.S. funding of NADB. “When [Central America] has a strong economy, that’s one of the best things we can do as a country.”
Rooney said the energy price differentials between the U.S., Canada and Mexico reveal opportunity costs that reduce the continent’s global competitiveness.
“There’s an opportunity that the U.S., with its trading partners in the energy space, to open up economies for our friends in Central America,” he said. “By integrating the Central America energy market with the Mexico energy market, you will see the price differential decline between Mexico and Guatemala. That’s a huge impediment to the industrial development of Central America. We have an opportunity as a group to reach out and overcome that impediment and help Central America, which North America has been ignoring for decades.”
Energy Storage, Batteries Ahead of Regulations
A panel focused on new technology trends offered an optimistic view of the future.
Chris Melley, the director of business development for solar firm Origis Energy, said battery technologies are ahead of regulatory tariffs as their capacity improves and their costs decrease.
Battery costs continue to decline. | Bloomberg NEF
“We’re seeing a big change in battery energy storage,” he said. “Instead of more residential uses, we see an increased interest [in] utility-scale systems for commercial and industrial applications.”
“We’re living in the middle of a power sector transition,” said Riccardo Bracho, with the National Renewable Energy Laboratory. “Everywhere across the world, energy systems are looking for reliability, reducing carbon emissions [and] putting new cost-effect technologies to use, but they’re also looking at the challenges of electrification and also serving customers.”
Bracho said funding remains a concern in bringing these new technologies to market. “Funding gaps are very difficult to [overcome]. That’s where governments and universities have to take on [the responsibility] before private sectors can do something about it,” he said.
But Melley said many companies are not going to wait on governments or private investment to bring about the changes. He has first-hand experience, having been in Puerto Rico since Hurricane Maria devastated the electric grid in 2017.
“Multinational companies are doing this on their own [with batteries and microgrids],” he said. “They don’t want any electrons flowing past their meter, so that they get regulated. They’re not waiting for the regulators when the economics make sense, and they have the money to do so.”
Having taken over reliability coordinator functions in CAISO’s service territory this summer, the ISO’s RC West is now preparing to take over for most of the West come November. During a conference call Thursday, the RC West Oversight Committee was briefed on the results of the first transition and the progress of the second.
The July 1 handover of CAISO’s territory from Peak Reliability went smoothly, but there’s still room for improvement, ISO staff members told the committee. The large oversight committee is made up of representatives from the 39 transmission owners and balancing authorities that signed up for CAISO’s RC services.
CAISO will eventually take over about 72% of the load in the Western Interconnection from Peak, which decided to wind down its operations this year. RC West Moving Smoothly Toward July Handover.)
RC West will take over RC services for most of the Western Interconnection Nov. 1. | CAISO
The July 1 transition involved entities in California and Baja California that participate in CAISO. Fifty surveys sent out in July were intended to “get some feedback as to how the onboarding went, and specifically what are some of the things we might glean as far as lessons learned to improve our processes for the Nov. 1 customer launch,” said Joanne Serina, CAISO’s executive director of customer service and stakeholder affairs.
The surveys showed a handful of areas that could be improved upon, including a need for more clarity and explanation in the transition checklists new customers must follow. Those changes and others will be incorporated for the next group of new customers, Serina said.
Tim Beach, director of operations at RC West, said it was “pretty quiet on the operations front” because of milder temperatures in California this summer. But the Tucker Fire, a wildfire near the state’s northern border, threatened the California-Oregon Intertie, three 500-kV transmission lines that connect the states’ grids.
Two of the lines had to be taken out of service in late July, reducing capacity to less 600 MW and triggering a transmission emergency and multiple energy emergency alerts in California, Beach said.
Phase 2 Progressing
Nancy Traweek, executive director of system operations at CAISO, told the committee that a NERC-led team conducted a site visit at RC West at the end of July and plans to come back in September to follow up on pending tasks as part of its certification process.
A test of RC West’s messaging system and a “blast call” to customers went well recently, said Joanne Alai, RC project manager at CAISO.
RC West is in the midst of a two-month data validation process to ensure data from participants comes in clean.
Alai said it also is conducting “day in the life testing,” an “are you ready, and do you know what you’re going to be doing” dry run before RC West begins shadow operations in September. The shadow operations, in which CAISO staff observe Peak employees, is itself a preparation before operations officially commence in November, she noted.
Gridforce Runs out of Time
Gridforce Energy Management, which had intended to begin providing RC services to several small generation-only balancing authority areas in the West, instead reached an agreement to use RC West services through at least April 2021.
“The timeline [for certification] was tight,” Duncan Brown, director of power services corporate development for Gridforce parent NAES, told ERO Insider in an interview this week. Using RC West initially will “allow us to assess our options,” he said.
SPP is also going through its certification process, which included a site visit earlier this month by a 23-person team including staff from the Western Electricity Coordinating Council, Certification Team Checks SPP’s Western RC Function.)
QUEBEC CITY, Quebec — NERC’s Board of Trustees got to hear first-hand some of the concerns over the proposed merger of the organization’s three technical committees during the Aug. 14 Member Representatives Committee meeting.
The proposal by NERC’s Stakeholder Engagement Team (SET) would merge the Planning, Operating and Critical Infrastructure Protection committees into a new Reliability and Security Council (RSC). While the three technical committees have almost 120 voting members, the proposal would limit the RSC to 33.
The proposal prompted written comments from a dozen stakeholder groups, who were nearly unanimous in calling for a longer transition and an increase in the number of sector representatives in the new organization. Some also questioned whether security issues should be combined with operations and planning. (See NERC Weighing Concerns on Reorg.)
Exelon’s Jennifer Sterling, vice chair of the MRC and co-chair of the SET, opened the discussion by citing a need to become more efficient to respond to the increased pace of change in the industry.
“I’d love to say at Exelon we have infinite people to work on all these issues, but we don’t,” she said. “And so, we need to leverage that scarce talent to solve problems and maximize our return.”
Sterling said the SET will consider several potential changes to the proposal at its meeting Aug. 29, including whether the CIPC should be included, potential changes to the membership of the RSC and a longer transition period.
Asked why the team was reconsidering the inclusion of the CIPC, Sterling said, “It’s just an item for conversation at the next meeting.
“I came out of the operations and planning world, and security is more and more what I’m doing in my work,” she added.
Bill Gallagher, special projects chief for the Vermont Public Power Supply Authority and a representative of the Transmission-Dependent Utility sector, agreed on the need for change but said he would have preferred keeping the three committees and adding a Steering Committee between them and the board.
Gallagher said the proposal to have the NERC board select the members of the RSC and set the criteria for membership “turns the NERC process on its head.”
“l don’t think that’s an appropriate role for the board to be playing. I also don’t think it’s an appropriate role for management to be playing,” he said.
Gallagher also said the SET meetings should be open. “These are the stakeholders’ assets we’re talking about. … If you are going to have additional meetings you ought to consider some way of opening them up.”
West Virginia Consumer Advocate Jackie Roberts, a representative of the Small End-Use Electricity Customer sector, said she shared Gallagher’s concern about the selection of the RSC members. “We strongly believe that the member sectors should select their members. … No one knows who should best represent the end-use sectors than the end-use customers,” she said.
“I think we need to be very careful that we don’t make the system more efficient by losing its effectiveness,” she added.
Devin Hartman, CEO of the Electricity Consumers Resource Council, said sector control and the nominating process “will be a sticking point for some of us.”
Dominion Energy’s Lou Oberski, representing the Investor-Owned Utility sector, said the Edison Electric Institute supports the current plan but wants a “measured transition.”
“There’s no impending need to do it quickly,” he said, predicting the RSC will rival the MRC in importance. “So, let’s make sure we can get it right.”
Hydro-Quebec TransEnergie’s Sylvain Clermont, Canadian representative of the Federal/Provincial Utility sector, said he would like to see a smaller RSC. “I’m a bit scared of a committee with 33 voting members, and probably more,” he said.
Sterling responded: “I too share your concerns that if we get too big, we won’t [achieve the goals] that we set out.”
