MISO Triennial Review Shows Multi-Value Project Benefits

By Amanda Durish Cook

After a second full review of the 2011 slate of multi-value transmission projects, MISO has concluded that although project costs are rising, benefits still far outpace them.

MISO said its multi-value project (MVP) portfolio creates anywhere from $12 billion to $52 billion in net benefits. Total portfolio costs have increased from an estimated $5.6 billion during MISO’s 2011 Transmission Expansion Plan to $6.5 billion today.

MISO MVP multi-value project — | © *RTO Insider*

The findings were part of a mandated, three-year review of the MVP portfolio, included in MTEP 17.

MISO’s MVP portfolio was approved by the RTO’s Board of Directors in 2011 and contains 17 transmission projects designed to cut costs, support regional reliability and broaden access to renewable resources. The RTO said its MVPs currently show benefit-to-cost ratios ranging from 2.2:1 to 3.4:1. MISO only measures benefits for its Midwest region, as MISO South was not yet part of the RTO at the time of project approval. In 2014, the RTO put the benefit-cost measure at 1.8:1 to 3:1.

The results also “reconfirm the MVPs are essential to meeting renewable portfolio standards goals,” said MISO engineer Ben Stearney during a Sept. 27 Planning Advisory Committee meeting. MVPs will allow the delivery of 52.8 million MWh of renewable energy through 2031, supporting states’ renewable energy mandates and goals, he said. Had the project portfolio not been approved six years ago, an estimated 11.3 GW in dispatched wind generation would have to be curtailed in 2026. Wind curtailments in MISO are currently rare, due in large part to the RTO increasing dispatch frequency from one hour to five minutes and introducing its Dispatchable Intermittent Resource type, which allows wind operators to respond economically to dispatch instructions.

Stearney said projected natural gas prices represent the largest difference between the MTEP 14 and MTEP 17 reviews, the latter of which shows much lower prices.

MISO will file the MVP report with FERC in spring.

October 3, 2017

Report Decries Rising PJM Tx Costs; Seeks Project Transparency

By Michael Brooks

More than half of the $24.3 billion in transmission projects in PJM since 2012 were unneeded to comply with RTO or federal reliability requirements and were not subject to rigorous review, according to a report commissioned by American Municipal Power.

At a teleconference Friday, AMP used the findings to call for more transparency into transmission owner-proposed supplemental projects, which represented $12.7 billion of the total spending since 2012.

Supplemental projects are proposed by a TO and fully paid for by its customers. They are not required to fulfill any reliability obligations from NERC, FERC or PJM, which reviews the projects only to make sure they do not negatively impact the grid. This is in contrast to network upgrades and regionally funded baseline projects proposed by PJM to address violations of RTO, NERC, ReliabilityFirst or TO planning criteria. Supplemental projects also are exempt from the competitive transmission requirements of Order 1000.

Of the $28.1 billion in planned or in-service transmission projects from 2005 to 2012, only 24% ($6.8 billion) were supplemental, according to the report by Ken Rose, an independent consultant and senior fellow at Michigan State University’s Institute of Public Utilities. After 2012, supplemental projects made up 52% of total spending, compared to 48% ($11.6 billion) in baseline projects and network upgrades.

PJM transparency transmission projects — | *AMP*

“There is a shift from baseline projects to supplemental projects as revenue requirements and transmission rates have gone up, a lot — way beyond the levels of inflation,” Rose said. “Basically, if you continue to have a process where it is fairly easy for the regulated entity to pass project costs through, there is going to be an incentive to continue pursuing supplemental projects.”

PSEG, AEP, PPL Cited

Three TOs — the “overachievers,” as Rose called them — were particularly aggressive in such spending. Between May 9, 2005, and September 2017, supplemental projects represented more than 44% of the transmission spending within the PSEG zone, 40% of spending in the AEP zone and almost 59% of that in the PPL zone.

The three TOs also saw their transmission revenue requirements and rates more than double since 2009, with PSEG’s requirements jumping 420% and its rates increasing 465% since 2009, far more than any other TO.

“Those transmission costs that we’ve seen increasing are being passed along to our members,” said Jolene Thompson, executive vice president of member relations for AMP, which provides generation, transmission and distribution to 135 members in Delaware, Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia. AMP has “prioritized trying to find ways to mitigate the impact of the increasing transmission costs” on its members, she said, and chief among those is shedding light on the RTO’s supplemental projects.

“Our members are seeing their transmission rates skyrocket,” AMP President Marc Gerken said in a statement. “We need to able to tell them why this is happening.”

Aging Infrastructure

At a 2015 FERC technical conference, PJM Vice President of Planning Steve Herling told commission staff that supplemental projects are often proposed to replace aging infrastructure. “If you went down the list in our database, I guess half of them start with the word ‘replace,’” he said. (See PJM TOs Defend Jurisdiction at FERC Conference.)

The conference led FERC last year to issue a show cause order finding that PJM’s TOs were not complying with Order 890’s requirements that stakeholders have “early and meaningful input and participation” in the planning process for supplemental projects (EL16-71). The commission said some TOs “appear to be identifying — and even taking steps toward developing — supplemental projects before providing any opportunity” for stakeholders’ input through the Regional Transmission Expansion Plan. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)

While insisting they already comply with Order 890, the TOs in October proposed a Tariff amendment they said would increase transparency. FERC, which had no quorum between February and August, has yet to act on their response.

“PSE&G works closely with PJM and its stakeholders to review and respond to questions about its transmission projects, including supplemental projects,” said Karen Johnson, PSE&G director of communications. “Projects also obtain state and local permits and approvals from state agencies, municipalities, environmental permitting agencies and other local stakeholders. We work closely with all of them to ensure that transmission is built in a cost-effective manner that mitigates environmental impacts and is consistent with customer needs.”

Johnson also said that investment in transmission “puts downward pressure on energy and capacity prices by alleviating congestion on the system” and that ”PSE&G’s electric bills have remained flat to slightly lower over the past nine years.”

AEP and PPL did not respond to requests for comment.

Task Force

In the interim, the TOs and stakeholders have resumed meetings of the Transmission Replacement Processes Senior Task Force, which had gone on hiatus awaiting a FERC ruling. (See related story, Softer Rhetoric as TOs, Customers Seek Accord on Replacement Rules.)

AMP wants to “proceed as aggressively as we can in the current PJM stakeholder process in trying to get the transmission owners to provide a similar amount of information and transparency of data for the supplemental projects as they do for the baseline and Regional Transmission Expansion Plan projects,” Ed Tatum, AMP’s vice president of transmission, said at the teleconference. FERC’s show cause order gives the organization “a good opportunity to get the transparency that we need. But it’s important that those orders be implemented in the spirit with which the commission intended them.”

Asked by RTO Insider why PSEG, PPL and AEP proposed so much supplemental spending, Tatum responded, “I think you make our point for us right there: We don’t know.”

He said PJM should be doing more to protect ratepayers.

“By virtue of being the regional transmission organization … they are in charge of the planning and operation of the system. We see [TO-proposed] projects that come in that talk about building new infrastructure or replacing infrastructure. We have this crazy idea that it’s planning. … There’s certainly an important role for the transmission owners, but at the end of the day we do believe it’s PJM’s process and I think the commission has been clear on that, saying that PJM is in charge of not only the regional but the local planning processes as well.”

“This is a complex issue and one we continue to work through with our stakeholders. It is important to note that there is an active FERC proceeding right now,” PJM spokesperson Paula DuPont said. “We believe in the importance of transparency in all aspects of the planning process and that’s why we’ve been working with stakeholders on it.” She pointed to Planning Community – an online communications platform – and the new Manual 14F: Competitive Planning Process, saying they “demonstrate the value we place on transparency.”

AMP acknowledged that PJM is not alone in seeing increasing transmission costs. But “this supplemental cost category is unique to PJM and those are the ones we really have an issue with because they lack the same rigorous oversight process,” said Lisa McAlister, AMP’s senior vice president and general counsel.

MISO ‘Out-of-cycle’ Controversy

TO-proposed projects also have generated controversy in MISO. In 2015, the RTO approved a $187 million “out-of-cycle” project by Entergy in Lake Charles, La. Transmission developers complained that they had been denied an opportunity to compete on the project, which Entergy had argued was an “immediate need” and thus could not wait for the RTO’s next Transmission Expansion Plan. The complaints led the RTO to change the rules for dealing with out-of-cycle proposals under a new “expedited review” procedure that was added to its transmission planning manual (Business Practices Manual 20) in May 2016. (See Ideas to Reform MISO Out-of-Cycle Process Emerge.)

October 3, 2017

ERCOT Technical Advisory Committee Briefs: Sept. 28, 2017

After two months of significant discussion at various levels of ERCOT’s stakeholder process, the Technical Advisory Committee on Thursday unanimously approved compromise language eliminating the reduction of congestion revenue rights (CRRs), or “deration.”

The nodal protocol revision request (NPRR821) eliminates the deration process for resource node-to-hub or load zone CRRs. Stakeholders drafted compromise language in the Protocol Revision Subcommittee (PRS) to address concerns that the deration process interfered with hedging behavior.

In the end, stakeholders agreed that the language deters the exploitation of CRR gaming opportunities that pose the most risk to loads, and continues the policy of sharing CRR underfunding costs established when the nodal market went live.

“Stakeholders have been working on and debating a solution for three months now,” Reliant Energy’s Bill Barnes said. “Parties on all sides have had follow-up discussions and gotten comfortable with what’s proposed here.”

ERCOT — Reliant Energy’s Bill Barnes (right) makes his point as VEH/Discount Power’s Mohsin Hassan (left) and Just Energy’s Eric Blakey (middle) listen.

“This solution is better than what we had,” Shell Energy’s Greg Thurnher said. “I do believe this particular solution solves the vast majority of the needs. … I suggest we test the waters with this solution and revisit it in the future. The seemingly yearlong discussion may have been unnecessary, but we’ve rid ourselves of unnecessary processes.”

The new process will be implemented by July 1, 2019, despite a request by the Lower Colorado River Authority (LRCA), one of those pushing for the change, to deploy it as soon as possible.

“As soon as it’s implemented, we eliminate the risk we’re concerned about,” LCRA’s John Dumas said.

The TAC tabled the NPRR during its July meeting, then remanded it back to the PRS in August. (See “CRR Deration Remanded Back to Subcommittee,” ERCOT Technical Advisory Committee Briefs: Aug. 24, 2017.)

Revision Request Would Create Panhandle Hub

Stakeholders also easily approved NPRR817, which will allow additional trading liquidity and forward price discovery in the Texas Panhandle with the creation of the “Panhandle 345-kV Hub.” The revision excludes the new hub from the existing ERCOT-wide hub and bus average calculations.

Citigroup Energy’s Eric Goff argued the NPRR’s estimated $150,000 to $200,000 implementation costs would be a one-time hit, eased by additions of new hubs in ERCOT’s southern or western footprint.

“I anticipate further need for additional hubs that will reduce the cost substantially each time,” he said. “This NPRR allows very simple hedging for the Panhandle.”

Goff explained that, under current practice, any generator in that area seeking to hedge must pick a resource node that could at times be subject to a random outage because of maintenance or some unforeseen event.

“This will improve the commercial hedging and has one-time upfront costs that address concerns raised by those comments [about costs],” he said.

Staff agreed, saying future hubs could be created at 30 to 40% of the cost of the new Panhandle hub.

TAC Tables Several Market Changes

After a roll call vote following vigorous discussion, stakeholders agreed to table NPRR815, which would revise the current limit of 50% for load resources providing responsive reserve service (RRS) to any capacity above a minimum level of RRS offered by resources providing primary frequency response (PRF).

ERCOT CRRs — TIEC legal counsel Katie Coleman

Katie Coleman, legal counsel for Texas Industrial Energy Consumers, asked to table the NPRR following the filing two days earlier of a related revision request (NPRR848), which would create separate pricing for load resources and PRF-capable resources providing RRS. Coleman said she had not yet been able to gather her group’s position on the latest change.

“There’s a relationship between the issues in this NPRR and the issues in 848,” she said. “If 848 moves forward, we would want not only this but probably much more significant changes to how the load megawatts are determined.”

The motion to table was opposed by several generating members, who feared reliability issues. Bob Wittmeyer, a consultant with Resolved Energy, pointed to the change’s estimated $3 million in average savings and urged the TAC to considering rejecting the motion to table.

“Tabling this today is not a one-month delay; it’s a two-month delay,” he said. “There are two groups of people in this room — the ones that sell ancillary services and want to table it, and the ones that get fired if we have a reliability problem. The ones that get fired if we have a reliability problem are saying this is not a reliability problem. They’re also saying we can save $3 million a year.”

ERCOT staff pushed back against claims that grid reliability would be harmed, with Sandip Sharma saying he wanted to “rule out reliability issues.”

“This NPRR allows ERCOT to procure ancillary services in a more cost-effective way, while it is meeting its reliability obligation,” he said. “In the absence of this NPRR, we would do exactly the same study we do today, but we would increase the number, because there is a limitation on load resources. The loads are not allowed to provide more than 50%, especially during the time when they are more effective solving reliability issues … that’s the main issue here.”

Only three members eventually opposed tabling the NPRR.

The committee also tabled NPRR825 and a verifiable cost manual revision request (VCMRR019). Staff said it missed a system requirement in the NPRR’s impact analysis (IA), which likely would increase the costs of issuing DC tie curtailment notices before curtailing the tie’s load.

“We’re reviewing the IA process, so we can improve and bring things to you more accurately,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “That may require us taking more time than we have on some of these, but ERCOT-wide, from the executives to every person, we’re not satisfied with how this is playing out.”

PRS Adds Resource Definition Task Force

The TAC approved a previously tabled revision request (NPRR829), despite a revised impact analysis of between $200,000 and $300,000. The increase came after staff added previously overlooked distributed generation resources in its analysis.

The change requires the day-ahead market to use telemetered data from non-modeled generation to more accurately calculate collateral requirements for qualified scheduling entities (QSEs). The NPRR increases day-ahead liquidity through the increased participation of non-modeled generation, and potentially allows ERCOT to gain near real-time transparency into the generation.

“If we don’t do these infrastructure changes now, it’ll be sometime in the future,” Thurnher said. “It’s not a small segment anymore, in terms of megawatts. The class that will use this will continue to grow in the future. This levels the playing field. Right now, distributed generation does not get the same credit treatment as traditional generation does when it injects into the system.”

The NPRR passed, with three members voting against it.

The committee unanimously approved single NPRRs, nodal operating guide requests (NOGRR) and system change requests (SCR). It also approved ERCOT’s high-impact transmission element list, which doubled last year’s list at 222 elements.

NPRR840: Synchronizes implementation of NPRR782, which removes inconsistencies in protocol language governing the settlement of ancillary services for resources unable to deliver on their responsibilities due to transmission constraints. The change removes the two-hour advance notice period inadvertently left in the protocols when 782 was approved, allowing ERCOT to declare an ancillary service as infeasible in either the adjustment or operating period.
NOGRR173: Removes orphaned grey-boxed language in order to align with NOGRR166, which struck language added with NOGRR084. The change cleans up removal of other items related to NOGRR084 and NOGRR166, but does not remove any current reporting requirements in Section 9.4.3 (Resource-Specific Responsive Reserve Performance)’s duplicative language to the current black-lined language.
SCR791: Populates unused megawatt price values in SCED generation-resource data energy-offer curves with null values rather than zero. The zero values make the energy-offer curves non-monotonic and are indistinguishable from valid zero offers.

— Tom Kleckner

October 3, 2017March 25, 2024

Texas PUC Resistant to NextEra’s Minority Interest in Oncor

AUSTIN, Texas — Having thrice been rejected in its attempts to acquire Oncor Electric Delivery earlier this year, NextEra Energy is now making a long-shot bid to acquire a minority ownership in Texas’ largest electric utility.

However, the state’s Public Utility Commission has been resistant. During an open meeting Thursday, it invited Texas utilities to file amicus briefs and comments to help the commission determine whether Oncor should be a party to the proceeding (Docket 47453).

NextEra and Texas Transmission Holdings Corp. (TTHC) filed a joint application with the PUC in July seeking permission to complete an acquisition of TTHC’s 19.75% interest in Oncor. However, staff in August ruled the application deficient, saying neither applicant is a public utility under state regulations and that the case should not proceed without Oncor’s involvement.

“Information that is possessed by Oncor relating to Oncor’s facilities, customers and financial records will be necessary to assess the statutory factors to be considered in this proceeding,” staff said.

In September, Oncor filed for intervention as a party to the proceeding, making it clear to the PUC that it is not an applicant and “is not seeking commission approval of the proposed sale.”

“We didn’t want [the case] dismissed on a technicality that the utility wasn’t a part of it,” Oncor CEO Bob Shapard told the commissioners. “That would essentially be us ruling on the issue. We’re clearly not advocating the transaction, but we felt like it should be put it back in your hands, where it belongs, and not ours, to make a decision.”

“Thanks,” Commissioner Ken Anderson responded wryly.

TTHC is owned by Cheyne Walk Investment, BPC Health, Borealis Power Holdings and Hunt Strategic Utility Investment.

NextEra last year tried to acquire the minority share along with the rest of Oncor, but the commission rejected the deal in April. It then turned down two subsequent requests for rehearing. (See NextEra-Oncor Deal Meets Third Denial.)

Anderson said he was not ready to consent to a preliminary order, saying he has a concern as to whether the applicants should include the utility in question, even if the acquisition is hostile or “not friendly.”

“Should the utility be an applicant or joint party, or not an applicant at all?” Anderson asked. “How can you be opposed to a transaction and be both applicant and an opposing party? Oncor has not filed any briefing materials because they weren’t party to order, or didn’t want to be. Can the [utility or its holding company] be forced to be an applicant? Can they be forced to be joined?”

Anderson said the utility’s stockholders and ratepayers should not bear the costs in these kinds of transactions and asked for a “full airing” of the issues. Newly minted PUC Chair DeAnn Walker agreed, asking for additional briefings from the parties.

Parties have until Oct. 12 to file briefs on whether Oncor should be a joint applicant, whether the commission has the authority to order Oncor’s participating in the case, and when the 180-day timeline to consider the application should begin.

The PUC said it may consider the draft order at its Oct. 26 open meeting.

“How we decide this has ramifications that go beyond this,” Anderson said. “Let’s say we have another … hostile takeover bid and [the acquirer] files a [sale, transfer and merger form] seeking to approve it. The consensus in an existing brief is the commission can require you to be a party. If a utility is forced to participate in a proceeding, should the real party, the real applicant be required as a condition to be either an intervenor or a co-applicant, to agree in advance to reimburse the utility for all the expenses by the utility?”

California-based Sempra Energy has since become the third entity to seek regulatory approval of an Oncor purchase. Sempra emerged from a pack of suitors in August and said it would put down $9.45 billion for bankrupt Oncor parent Energy Future Holdings and its 80% interest in Oncor. (See Sempra Begins ‘Listening Tour’ of Key Stakeholders.)

Oncor, Sharyland Face More Work in Proposed Swap

Oncor and Sharyland Utilities went into the open meeting hoping for a final order in their proposed swap of $400 million in assets, but instead they discovered they have much work in front of them (Docket 47469).

Walker filed a memo before the meeting, asking the parties for more specificity on the assets to be transferred and expressed her concern about the proposed treatment of the refunds related to the energy efficiency cost recovery factor (EECRF) for both Oncor and Sharyland.

“I really believe this transaction is in the best interest of the ratepayers,” Walker said. “I’m not trying to be a deal-killer, but I have questions and concerns.”

Walker asked for responses by Oct. 4 to help the PUC meet its Feb. 1 deadline for reaching a decision.

The asset swap would resolve rate cases for both Oncor and Sharyland and would help the latter address customer complaints about Sharyland’s high rates. The two companies are continuing to hammer out details in settlement negotiations.

“Systemwide rates are the goal here,” said Vinson & Elkins’ Jo Ann Biggs, representing Oncor. “After the [new] rates go into effect, Oncor would prefer a single refund under the EECRF. We want to treat Sharyland customers like all Oncor customers.”

One of the issues is whether Oncor can charge incoming Sharyland customers for deploying an advanced metering system (AMS), already in place in much of its service territory.

“We feel strongly that Sharyland customers should be treated like Oncor customers,” said Laurie Barker, with the Office of Public Utility Counsel (OPUC). “We feel like it’s important Sharyland customers be treated like any other customer that comes into the Oncor system. We’ll have that same issue with the AMS charges.”

The PUC approved a preliminary order on the proposed swap in August. (See “PUC Approves Preliminary Order in Oncor-Sharyland Asset Swap,” Public Utility Commission of Texas Briefs: Aug. 31, 2017.)

The order lists a set of 27 issues to be discussed before the PUC renders a decision, which is due by Feb. 1. Oncor and Sharyland filed a settlement agreement in July, asking the PUC to expedite the case by deciding it without referring it to the State Office of Administrative Hearings (SOAH). The companies said Sharyland’s current retail customers will receive “substantial rate relief” under the transaction, in which Sharyland will take over 258 miles of 345-kV transmission from Oncor in exchange for Sharyland’s distribution network and retail delivery customers.

The PUC on Thursday did approve Oncor’s request to recover a retail-customer surcharge over the next nine months of almost $27.2 million, as corrected by an administrative law judge (Docket 46884); Sharyland’s amendment to a certificate of convenience and necessity for an $18.6 million, 7-mile, 138-kV transmission line southwest of Abilene in West Texas (Docket 46726); and applications by Oncor (Docket 47235) and Sharyland (Docket 47248) to adjust their energy efficiency cost recovery factors. Should the transaction be closed, Oncor would be refunded nearly $6.1 million for over-recovered energy-efficiency costs in 2016, and Sharyland would be credited about $243,000 for its over-recovered 2016 costs.

But the commission dismissed a Sharyland request dating back to 2015 to deploy an advanced metering system (Docket 44361) and a rate review rendered moot by the swap (Docket 45414).

Walker Takes Chairman’s Gavel in First Meeting

Walker wasted no time asserting herself in her new role during her first open meeting.

After calling the meeting to order, Walker admitted she was nervous and excited. She then asked for a moment of silence to recognize the many victims of Hurricane Harvey, including, by name, a Kentucky lineman who was killed during the restoration effort.

The meeting marked Walker’s return to an organization she served as an assistant general counsel and an ALJ from 1988 to 1997. She thanked staff and her family for their support, and Texas Gov. Greg Abbott for her appointment.

Abbott “has bestowed a great duty, obligation and honor on me. I take it very seriously,” she said. “He has taught me how to do hard work, and to do it with integrity. I assured him that is my intention while I am here, to work hard and to serve with integrity.”

Adrianne Brandt, who was formerly with San Antonio’s CPS Energy and chaired ERCOT’s Technical Advisory Committee, will serve as Walker’s adviser, effective Oct. 16.

Walker replaces Donna Nelson, who stepped down as the PUC’s chair in May. She will fill out the remainder of Nelson’s term, which expires in September 2021. (See Texas PUC Chair Nelson Stepping Down.)

Previously Abbott’s senior policy adviser on regulated industries, Walker spent 15 years at CenterPoint Energy as director of regulatory affairs and as an associate general counsel.

Walker also agreed to take on Nelson’s role with SPP’s Regional State Committee, which Commissioner Brandy Marty Marquez had been filling.

“I think it’s a great opportunity for you to step into SPP and see what that is all about,” Marquez told Walker. “They’re great people.”

Anderson will continue representing the PUC on the Organization of MISO States. Anderson and Marquez have kept the three-seat PUC running while waiting on Nelson’s replacement. Anderson has served on the commission since September 2008 — a record tenure — though his term expired Aug. 31. Marquez’ six-year term expires in September 2019.

Utilities Make Final Harvey Restoration Reports

Texas utility representatives gave the commission a final update on their Hurricane Harvey restoration efforts, after which the commissioners extended their Aug. 31 order directing retail providers to offer their customers deferred payment plans, “recognizing that many customers are still recovering” (Project 47552).

The utilities said their efforts were aided by the state government, mutual-assistance agreements between each other and community support.

“Customers were bringing us food, even when it wasn’t needed,” AEP Texas CEO Judith Talavera said.

“Texas rocks,” said Kenny Mercado, CenterPoint’s senior vice president of electric utility operations. “I can’t say enough about the friends and neighbors who chipped in.”

Mercado said the heavy rains and flooding resulted in the utilities relying on air boats, drones, amphibious vehicles and mobile substations to restore service.

“We were using different equipment than we’ve ever used before. I’m not sure we even knew we had air boats,” he said.

ERCOT COO Cheryl Mele said the ISO did much of its work in preparing for Harvey’s landfall. Transmission and generation outages resulted in a load drop of 15 to 20 GW below normal August conditions, she said.

“We never had a shortage of generation on the system,” Mele said, noting ERCOT never had to shed load or call for imports. The ISO issued reliability unit commitment instructions just twice.

Walker asked PUC staff to work with the utilities in evaluating the future use of mobile substations, ensuring an accurate outage count and how to better share equipment.

“This to me is about Texans helping Texas,” Walker said. “I know El Paso Electric and [Southwestern Public Service] never got called on. It’s a lot quicker to get them here than people from Kentucky.”

Walker also wondered aloud whether substations should continue to stand in areas that were flooded.

SOAH to Hear Discovery in LP&L’s Migration to ERCOT

After some debate, the commissioners postponed until their next open meeting a final decision on whether they would hear Lubbock Power & Light’s proposal to migrate part of its load from SPP into ERCOT or send the application to SOAH.

PUC staff will meanwhile conduct an Oct. 9 prehearing conference to set a procedural schedule in the case (Docket 47576). Staff expects an LP&L filing this week, which will set a 180-day deadline for a decision on the migration.

The commission appears to be leaning toward letting SOAH handle discovery for the docket. Several intervenors support that decision, pointing to the “extensive discovery” needed to explore the large number of modeling studies that have been conducted on the issue.

“There aren’t a bunch of documents, but questions about modeling assumptions and what happens under different scenarios,” said Katie Coleman, legal counsel for Texas Industrial Energy Consumers (TIEC). “That could get extensive, given the number of studies in the case.”

ERCOT, SPP and LP&L have all filed studies in the case, which began in 2015 when Lubbock announced it intended to move 470 MW of its approximately 600 MW of load into ERCOT. LP&L is hoping for a decision before March 2018, which will enable it to maintain its plan to integrate with ERCOT by June 2021, after extending a power purchase agreement with SPS.

Anderson noted that while SOAH would develop “specific facts” that would help the commission reach a decision, “90% of that decision is going to revolve around big policy issues.”

“The ALJ’s decision would be purely advisory,” he said.

Walker agreed with Anderson, saying the decision would be “policy-driven.”

“I guess we’ll hear it ourselves,” Anderson said.

SPS, TIEC, ERCOT, the Office of Public Utility Counsel and Golden Spread Electric Cooperative have intervened in the case. Oncor and the Alliance for Retail Markets have filed pending motions to intervene.

Commission Approves RMR Rule Change

The commissioners approved revisions to its reliability-must-run (RMR) service rules, accepting Anderson’s modifications that exempt seasonally mothballed units from the must-run alternative (MRA) solicitation process (Project 46369).

Staff’s draft order adjusts the suspension-of-operations notice requirements and complaint timeline, requiring written notification to ERCOT at least 90 days before a generating resource is seasonally mothballed. The ISO would then have 60 days to respond.

The order also gives ERCOT discretion to decline entering RMR service agreements based on the economic value of lost load; requires ERCOT board approval of staff recommendation regarding RMR and MRA service; and requires capital expenditure refunds related to the service agreements in certain circumstances.

The ISO and its stakeholders have already taken action to address RMR contracts, driven by a 2016 agreement with NRG Texas Power’s Greens Bayou Unit 5 in Houston. The contract was terminated last month. (See ERCOT Ending Greens Bayou RMR May 29.)

ERCOT’s recent protocol revisions require that RMR units only be procured when they have a material impact on expected transmission overloads, clarify the grid operator’s commitment process for RMR units, and update the contracting and reimbursement process for RMR units.

October 3, 2017April 9, 2024

FERC Opens Proceeding over Entergy Nuclear Power Sales

By Amanda Durish Cook

FERC last week opened settlement proceedings to address a two-state complaint against an Entergy subsidiary’s proposed return on equity for nuclear power sales to four other company affiliates.

Utility commissions in Arkansas and Mississippi earlier this year filed a protest claiming that the ROE used by System Energy Resources Inc. (SERI) in its current formula rate for energy sales from the Grand Gulf nuclear plant is excessive and outdated. They’ve asked FERC to open an investigation to determine the fairness of the return.

SERI owns 90% of the 1,400-MW facility in Port Gibson, Miss., and sells the plant’s output under a FERC-regulated wholesale rate to Entergy Arkansas, Entergy Mississippi, Entergy Louisiana and Entergy New Orleans under a power sales agreement.

The commission said it will forward the matter to a still-unnamed administrative law judge who will oversee settlement discussions and report whether parties can negotiate a fair ROE. Barring a settlement, the issue would move to a trial-type evidentiary hearing (EL17-41).

Regulators from the two states contend that Grand Gulf should sell its energy to Entergy affiliates at cost-based rates “to avoid overcharging retail customers.” They point out that SERI’s current ROE of 10.94% was calculated using an average of three discounted cash flow analyses produced in 1996 and seek to reduce the figure to 8.5%, in part reflecting a reduction in income tax from $125 million to $97 million.

A “re-examination of [the] current cost of equity is more than due,” the two states argued, especially considering that the Nuclear Regulatory Commission last year extended Grand Gulf’s license another 20 years, until 2044.

In opening the proceeding, FERC brushed aside SERI’s argument that its existing ROE falls into the “zone of reasonableness” and does not require adjustment. The commission said it “has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE.”

Depreciation Rates also Under Review

The proceeding will also include an examination of SERI’s depreciation rates for Grand Gulf.

In a separate August FERC filing prompted by the license extension, SERI sought to revise Grand Gulf’s depreciation rates to an average 2.66% under the same power sales agreement for the four Entergy utilities (ER17-2219). The current 2.85% depreciation rate was based on the assumption that plant would operate only until Nov. 1, 2024. The Arkansas and Mississippi commissions, along with 10% plant owner Cooperative Energy, argue that SERI has not provided enough support for the new rates.

While FERC has for now accepted SERI’s proposed rates effective Oct. 1, it said its own review “indicates that a further decrease may be warranted” and consolidated the matter into the larger ROE settlement procedures.

October 3, 2017

PJM MRC/MC Briefs

Markets and Reliability Committee

Give me a B…

VALLEY FORGE, Pa. — PJM is attempting to calculate the market seller offer cap (MSOC) for Capacity Performance units for the 2021/22 delivery year, but it’s come across a hitch in the process, stakeholders learned at last week’s Markets and Reliability Committee meeting.

The MSOC is calculated using the balancing ratios, often represented as “B,” from the three calendar years prior to the Base Residual Auction. The BRA for 2021/22 will happen next May.

B is calculated when emergencies, or performance assessment hours (PAHs), are called. It is used to determine each generation capacity resource’s obligation to deliver energy during the PAH.

market seller offer cap, MSOC, PJM — Keech | © *RTO Insider*

However, no PAHs happened in 2015 or 2016, and none has happened so far in 2017. Even if one did, the resulting B might not be known in time for the MSOC values to be posted mid-December, PJM’s Adam Keech explained. That timing is important because market sellers will need to determine in early January whether they want to use the default MSOC values or pursue unit-specific valuations, he said.

PJM has proposed revising the Tariff to carry over the B used in the 2020/21 BRA of 78.5%, along with a problem statement and issue charge to explore a long-term solution that would be filed with FERC by October 2018, in time for the 2022/23 BRA. The focus of the investigation would be to determine if B should remain based on historic performance or something more prospective. Keech gave a presentation on the issue at September’s Market Implementation Committee meeting.

Joe Bowring, PJM’s Independent Market Monitor, disagreed with the proposal, saying the current Tariff language addresses such a situation. The math, he said, implies that B goes to zero and the MSOC values revert to each unit’s avoidable cost rate (ACR). Keech disagreed with that interpretation.

“In the absence of data, we don’t just assume that it is zero. And that’s the case that we don’t have balancing ratios to use,” he said. “PJM is not comfortable assuming that it’s just zero because that’s not the way the Tariff reads.”

“I’m not assuming anything,” Bowring responded. “It is a fact that there is zero performance assessment hours. It is a fact that the average of the last three years is zero.”

Calpine’s David “Scarp” Scarpignato asked how PJM planned to address other formulas that use B, such as the CP penalty calculations.

“If you’re changing your assumptions or calculations related to performance assessment hours [and how B is calculated], you should change it elsewhere in CP also because it’s all tied together,” he said.

Stakeholders raised additional concerns, such as the use of 30 expected PAHs in the formula. Borgatti suggested adopting ISO-NE’s flat fee for the penalty instead of being formula-based. Following the discussion, PJM agreed to review the proposed Tariff revisions, problem statement and issue charge and bring the revised versions for a vote at next month’s meeting.

Amendment on DER Charter Sparks Debate

PJM proposed a draft charter to transfer all of its work on distributed energy resources into a subcommittee, but a friendly amendment by FirstEnergy sparked debate on how stakeholders should defer to local and state governments.

FirstEnergy proposed that the charter include a statement that “market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the Relevant Electric Retail Regulatory Authority (RERRA).”

Under FERC Order 719-A, demand response resources served by large electric distribution companies (>4 million MWh) are permitted to participate in wholesale markets unless their RERRA — such as a state regulatory commission — prohibits it. DR resources served by small EDCs (<4 million MWh) are prohibited from participation without RERRA approval.

PJM’s Chantal Hendrzak presented the proposed charter, saying the current problem statement and issue charge on DER is “very narrow” and should be broadened to incorporate issues such as microgrids, coordination with EDCs, the visibility of non-wholesale resources and the pending FERC Notice of Proposed Rulemaking on DER and energy storage RM16-23, AD16-20). (See FERC Rule Would Boost Energy Storage, DER.)

Hendrzak said special sessions of the Market Implementation Committee are not the right forum for the issues, which affect markets, operations and planning.

FirstEnergy’s Jon Schneider said the additional language was necessary to ensure the involvement of EDCs. “We think it’s important to have the right folks at the table, specifically distribution operators,” he said. “We don’t think it’s appropriate to assume that transmission operators will fully represent the interests of distribution utilities.”

“There is nothing that PJM does that would violate a reliability rule at the distribution company,” responded Direct Energy’s Marji Philips. “My concern is this is a very evolving industry. … To flatly say … that we’re not going to even talk about something because it violates an existing rule today doesn’t do anyone any good. The purpose of PJM is to provide a platform for discussion.”

Several stakeholders were concerned with another addition to the charter, which would require the subcommittee “proactively collaborate with states.” American Municipal Power’s Steve Lieberman said that commitment could lead to conflict about favoritism or prioritization.

“With 13 states [in PJM], if two of them feel you weren’t as proactive with them as you were with the other 11, then things could start to snowball unnecessarily,” he said.

Susan Bruce, who represents the PJM Industrial Customer Coalition, objected to the charter’s definition of DER including any generation or storage resource “behind a load meter.”

“Visibility into an industrial customer’s behind-the-meter generation that becomes visible to the world gives them a competitive disadvantage, and that’s a sensitivity that we would hope that PJM would respect for retail customers that are looking to just mind their own business, support their own operations,” she said. “The principle of what goes on behind a customer’s meter really is not anyone else’s business. It’s their economic decision from that perspective.”

Scarp found security in FirstEnergy’s amendment.

“If we’re going to delete that friendly amendment, I’m not sure I can still support the [proposed charter] because I don’t want to guarantee DER participation in the wholesale market. I think that’s a little bit strong when there’s lots of other things going on,” he said.

Hendrzak said staff will consider the comments in revising the charter before seeking an approval vote next month.

MTSL ‘Not Going Away’

The Monitor sought to resume a debate on calculating the minimum tank suction level (MTSL) for black-start units, arguing that the vote at September’s MIC meeting to forego changes was “clearly wrong.” However, Ruth Ann Price of the Delaware Division of the Public Advocate, who intends to sponsor the Monitor’s proposal, asked Bowring to delay his comments until the issue can be brought back to the committee after further consideration. (See “MTSL Revisions Kaput,” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)

Greg Poulos, the executive direction of the Consumer Advocates of the PJM States, explained that he had advised his membership “that this might not be the best time” to bring up the issue, which represents a relatively small amount of money, when there are many larger topics being debated.

Still, proponents warned that the issue wasn’t dead.

“There is a bit of heartburn if this comes off the table,” Bruce said. “To the extent that this is a vehicle being used for resilience, we would hope that there would be explicit recognition of that fact, that we are paying for this as a service.”

“As far as we’re concerned, this issue is not going away,” Bowring said. “It’s being postponed for a meeting or two. If you want to get it over with quickly and not waste any more time, just vote.”

‘Jump Ball’ on IA Changes Indicates Compromise Possible

None of six proposals considered by the Incremental Auction Senior Task Force won support of more than 39% of those taking part in a recent poll, but half the respondents called for some change to the status quo, giving some stakeholders hope that the issue is not dead. (See Consensus Fades on PJM Incremental Auction Solution.)

PJM’s Brian Chmielewski, who administers the task force, said the “jump ball” suggests that compromise is possible.

“Ending up with the status quo from a customer standpoint is not the right result,” Bruce said. “In the interest of not ending up with status quo, we are willing to negotiate, so I hope we get a chance to do so.”

“In the old days, we all gave blood,” said Philips, whose company proposed the problem statement that founded the group. “It looks like nobody wants to give blood anymore. The art of compromise is part of this process, and I hope we haven’t lost it.”

The group’s next meeting is Oct. 17.

Stakeholders Endorse Manual Revisions

Stakeholders endorsed several manual revisions and other operational changes:

The charter for the Primary Frequency Response Senior Task Force. (See “Primary FR Task Force Begins July 25,” PJM OC briefs: July 11, 2017.)
Tariff and Operating Agreement revisions to clarify definitions developed through the Governing Documents Enhancement & Clarification Subcommittee.
Manual 3A: EMS Model Updates and Quality Assurance. Revisions developed in response to a periodic review of the manual were endorsed by acclamation.
Manual 6: Financial Transmission Rights. Revisions developed to comply with FERC’s January order on financial transmission right forfeitures were endorsed in a sector-weighted vote with 4.26 in favor. (See “FTR Forfeiture Rebilling to Start,” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
Manual 11: Energy & Ancillary Services. Updated language to implement intraday generation offers were endorsed by acclamation. (See “PJM, IMM Agreement on Intraday Offers Seen as ‘Massive Change,’” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
Manual 14A: Generation and Transmission Interconnection Process. Revisions developed in response to a periodic review of the manual were endorsed by acclamation.
Manual 14B: Regional Transmission Planning Process. Revisions change the method for calculating capacity export transfer limits. (See Post-‘Wheel’ Changes Spark PJM Member Concerns.)
Manual 28: Operating Agreement Accounting. Changes eliminating redundant language and clarifying procedures associated with the implementation of intraday offers were endorsed by acclamation.

Members Committee

Stakeholders Approve Proposals

The Members Committee approved all proposals presented to them, including Tariff and Operating Agreement changes associated with PJM’s dynamic schedule pro forma agreements. (See Critics Protest PJM Dynamic Transfers Plan.)

Members also approved Tariff and OA revisions on limitations of billing claims and changes extending the proposal window for short-term transmission projects from 30 days to 60 days. (See “RTEP Cycle Revisions Approved,” PJM PC/TEAC Briefs: July 13, 2017.)

Nominating Committee Nominations Approved

Stakeholders appointed a representative from each of the five stakeholder sectors to a one-year term on the committee. The committee will be tasked with considering whether to nominate Neel Foster, Howard Schneider and Sarah Rogers, whose terms expire next May, for re-election to the Board of Managers.

DC Energy’s Bruce Bleiweis asked whether term limits could be waived “since we only have one original board member and we would not want him to leave” — a reference to Schneider, who has served on the board since its inception in 1997.

In 2015, PJM instituted term limits making board members ineligible for re-election once they either turn 75 or have served five three-year terms. (See New PJM Board Member Elected, Re-election Eligibility Changed.)

“I think waivers can be done through the board,” PJM CEO Andy Ott said. “I think I’ll just leave it at that.”

Reducing the Workload

MC Vice Chair Mike Borgatti of Gabel Associates announced that the MRC, MIC, Operating Committee and Planning Committee will be directed to determine if any timelines can be relaxed to “free up a little room in the schedule.” The directive came at the request of stakeholders, who have been complaining about the roughly 500 stakeholder meetings PJM conducts each year.

The workload concern is nothing new. In 2013, one member likened the stakeholders to ponies who will eat themselves to death if given unlimited access to food. (See PJM Faces Resource Limits.)

— Rory D. Sweeney

October 3, 2017

PJM Pressed on Plans to File Capacity Changes

By Rory D. Sweeney

VALLEY FORGE, Pa. — With a myriad of proposals emerging to revamp PJM’s capacity market, stakeholders are focused on what the RTO will do, but staff aren’t tipping their hand.

Attendees at Tuesday’s meeting of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) peppered PJM’s Stu Bresler with questions about his plans should stakeholders decide, after nearly a year of discussion, that the capacity market is better in its current design than anything else proposed. The RTO has proposed a two-stage “repricing” process that would ignore units that don’t clear the initial auction but clear in a second auction in which subsidized units are removed. Those so-called “in-between” units still wouldn’t receive a capacity commitment. (See NOVEC Offers 10th Capacity Proposal.)

DER PJM withholding requests for proposals — Bresler (left) and Anders| © *RTO Insider*

Stakeholders fear that, short of a clear mandate on which proposal to file with FERC for approval, PJM plans to file its own rather than maintain the status quo. They pressed Bresler to at least hint at PJM’s inclination, but he repeated that he would not be able to “definitively say” what staff will recommend to the Board of Managers by the next meeting of the task force on Oct. 16.

“It depends on too many factors,” he said. “We need to defend our markets.”

“It puts us all in the same predicament because we’re all trying to prevent something that we don’t really want to happen, and that is to have a unilateral filing made. We really want to avoid that,” said John Rainey of Northern Virginia Electric Cooperative (NOVEC).

Rainey said the “quandary” is that PJM has requested stakeholders declare their preferences among the proposals without indicating “whether status quo is a viable option.”

IMM Plan Leads Poll

Earlier in the six-hour discussion, the latest of 18 such meetings since March, attendees reviewed the results of a long-awaited poll on 10 proposals. The Independent Market Monitor’s extended minimum price offer rule (MOPR) proposal received the most overall support with a weighted average of 2.74. The three main two-stage “repricing” proposals from PJM, LS Power and NRG Energy received the next-highest levels of support of 2.05, 1.86 and 1.9, respectively.

The results also broke down how well the proposals addressed certain criteria, such as removing the price impact of a subsidy or driving a competitive outcome. The Monitor’s proposal received the most support in all but one question: whether it accommodated state initiatives. There, PJM’s design narrowly edged the other repricing proposals.

Four non-members also submitted responses. Their votes, which were presented separately from the member results, heavily favored a proposal from the Natural Resources Defense Council that would reduce the capacity requirement to the needs of the off-peak season and allow seasonal resources to account for the additional demand during the peak season.

Stakeholders complained that the structure of the poll was restrictive, so they provided comments to add nuance to their votes. However, PJM’s stakeholder process purposefully withholds any comparison to the status quo until stakeholders have chosen an alternative proposal on which to vote.

Strong Support for Status Quo

Some stakeholders, however, have already made up their minds.

“We’ve given this a huge amount of consideration,” said Carl Johnson, who represents the PJM Public Power Coalition. “How do we get across that we think that the current process is still the best process?”

Representatives from the Consumer Advocates of the PJM States and Old Dominion Electric Cooperative also said they preferred the status quo.

For the first time, the group hosted a substantial contingent of state representatives. In addition to Ruth Ann Price from Delaware’s Division of the Public Advocate and John Farber of the Delaware Public Service Commission, who are often involved in stakeholder meetings, the audience included Bill Fields from the Maryland Office of People’s Counsel, Kristin Munsch of the Illinois Citizens Utility Board and Brian Lipman from the New Jersey Division of Rate Counsel.

Lipman said his office’s understanding was that PJM is “going to file something,” which would indicate a change, and that the poll didn’t make it “obvious” how to indicate support for the status quo.

PJM’s Dave Anders, who administers the task force, acknowledged the complaints but declined to suggest any implications from the poll.

“I achieved consensus in a very difficult committee: Nobody liked the poll,” he said. “You’re all entitled to your interpretation of the results. I’m not trying to lead you [to any conclusions].”

Several stakeholders said their frustration was aimed at the topic, not Anders.

“Don’t take this as a knock on the poll design,” Johnson said. “I think it was a useful exercise, even though I didn’t want to do it. … Sometimes you can’t tease [your specific wishes] out until you have to make a decision about a question that’s right in front of you.”

NRG’s Neal Fitch asked that the poll results be used to “winnow down” the proposals still in contention to focus attention on viable candidates. PJM’s Adam Keech agreed that “maybe that’s a good place to start,” but Steve Lieberman of American Municipal Power, whose proposal polled near the bottom, cautioned against becoming narrowminded.

“Let’s be careful about latching onto one side,” he said.

To begin narrowing the options, Adrien Ford withdrew ODEC’s proposal, which took a different approach to the repricing concept, but also didn’t want to limit the focus.

“I struggle to agree that we should focus on the repricing proposals,” she said.

A Poll, not a Vote

Stakeholders also differed on how to treat non-member poll results. Calpine’s David “Scarp” Scarpignato said it “doesn’t mean much in regards to a pass/fail vote at the senior committee level.” Direct Energy’s Marji Philips said examining the results of an anonymous, four-voter poll is “inappropriate” and “could actually distract from the conversation.”

However, EnerNOC’s Katie Guerry said “it’s actually helpful to see what non-members think” in comparison to member preferences. “It’s so different,” she said.

Farber reminded stakeholders that “this is a poll, not a vote,” and that they should consider “the optics” of saying non-members can watch but not express opinions.

Anders requested that proposal sponsors indicate for the next meeting whether they intend to withdraw their proposal and, if not, to update the stakeholder matrix and develop a presentation with any changes. He also requested an “executive summary” describing the proposal.

“I don’t want a book. I don’t want 20 pages, but I want enough,” he said.

October 3, 2017

FERC’s Independence to be Tested by DOE NOPR

By Rich Heidorn Jr.

Energy Secretary Rick Perry acted within his legal authority in ordering FERC to consider his Notice of Proposed Rulemaking to support struggling coal and nuclear plants. But he has no power to make FERC provide the relief he is seeking, legal experts said Monday.

FERC DOE cybersecurity Rick Perry — Trump (left) and Perry

As a result, the outcome of the baseload battle will come down to the commission’s five members and how much they are willing to assert their independence from the Trump administration’s pro-coal agenda. Perry’s proposal would require that generators with 90 days of on-site fuel supply receive “full recovery” of their costs. (See related story, Perry Orders FERC Rescue of Nukes, Coal.)

Perry issued the NOPR under Section 403 of the Department of Energy Organization Act, subsection (a), which authorizes the secretary and the commission “to propose rules, regulations and statements of policy of general applicability with respect to any function within the jurisdiction of the commission.”

But subsection (b) gives the commission “exclusive jurisdiction with respect to any proposal made under subsection (a).”

“Section 403 is pretty clear. What [Perry has] done so far is within his authority,” said Douglas Smith, a partner with Van Ness Feldman who served as FERC general counsel from 1997 to 2001. “It’s also clear that the final determination about what to do with a NOPR like this rests entirely with FERC.”

The act also spells out FERC’s independence. Section 401 (d) states that, “In the performance of their functions, the members, employees or other personnel of the commission shall not be responsible to or subject to the supervision or direction of any officer, employee or agent of any other part of” DOE.

Does FERC have to Act?

The NOPR lists FERC docket number RM17-3, which was opened last December to consider fast-start pricing in RTO markets. (See FERC: Let Fast-Start Resources Set Prices.) But the commission filed the NOPR and Perry’s accompanying letter to FERC in a new docket, RM18-1. Late Monday, the commission issued a notice setting an Oct. 23 deadline on comments on the proposal, with reply comments due Nov. 7.

The notice came after 11 industry groups representing natural gas, wind, solar, rural electric cooperatives and other technologies filed a motion in that docket opposing DOE’s request and requesting a minimum 90-day comment period and a technical conference before the comment deadline. The groups said the deadline imposed by Perry — final action on the proposed rule within 60 days from its publication in the Federal Register — is “wholly unreasonable and insufficient.”

Former FERC Chairman Jon Wellinghoff, now a renewable energy advocate and consultant, said in an interview that FERC can ignore the proposal without taking any action.

But others said the commission will almost certainly make some sort of formal response.

“I don’t think they can ignore it. It would, No. 1, not be politically cricket,” said former FERC Chairman and General Counsel James Hoecker. “Particularly since [interim FERC Chairman] Neil [Chatterjee] is from Kentucky and his former boss, Sen. [Mitch] McConnell [R-Ky.], has been pretty clear about wanting to soften the blows on the coal industry. I’m sure the commission will do something.”

“Regardless of what legally the commission has to do, I think it’s unlikely the commission is going to just stiff arm the secretary and the administration,” agreed former Commissioner Tony Clark, now an adviser with Wilkinson Barker Knauer.

One reason for uncertainty is the recent turnover in the commission’s membership: Chatterjee and fellow Republican Robert Powelson joined Commissioner Cheryl LaFleur on the commission in August. Republican nominee Kevin McIntyre and Democratic nominee Richard Glick are awaiting a Senate floor vote.

The commission has traditionally been independent and rarely decides issues on party lines. But some FERC watchers fear that could change because they believe the White House has already exerted its influence by dictating the selection of the commission’s new general counsel, James Danly, and Chief of Staff Anthony Pugliese.

The two were named by Chatterjee, who is serving as interim chairman pending the confirmation of McIntyre, who was tapped by Trump to lead the agency. New chairmen typically select their own general counsel and staff chiefs. But at a news conference following the commission’s meeting Sept. 20, Chatterjee suggested Danly — an Iraq War veteran who joined the commission from Skadden, Arps, Slate, Meagher and Flom — was not a temporary hire.

Asked whether Danly would remain in his position after McIntyre arrives, Chatterjee said of Danly, “I think his biography and service to his country speak for themselves, and at this time I don’t anticipate any senior-level staffing changes.”

The Commissioners

Chatterjee, who like McConnell is from the coal state of Kentucky, has appeared sympathetic to Perry’s claims that the grid’s resilience is at risk from coal retirements.

In a podcast interview posted on the FERC website in August, Chatterjee said “baseload power … including our existing coal and nuclear fleet, need to be properly compensated to recognize the value they provide to the system.”

He added, “as a nation, we need to ensure that coal, along with gas and renewables, continue to be part of our diverse fuel mix.”

Whether the other commissioners share that view is unclear.

Asked at his confirmation hearing whether he agreed with Chatterjee, McIntyre said that “FERC is not an entity whose role includes choosing fuels for the generation of electricity.”

Glick echoed McIntyre’s position, adding that although the grid study released by DOE in August did not conclude that the loss of baseload generation had impacted reliability, “they also suggested it was something to keep an eye on and look for in the future.”

“McIntyre and Chatterjee, I just think will have so much political pressure to pursue this, the expectation is that they will want to do so,” said one former senior FERC official who asked not to be named. “Glick and LaFleur I would expect to be less inclined. The interesting one is Powelson. He’s a pro-market person. … How will he reconcile competition with what is proposed here?”

Rather than pursuing a cost-of-service approach, he said, the commission could adopt a more market-based approach that boosted prices for all capacity resources, including natural gas. “Then the gas folks end up winning just as much as coal and nuclear,” he said. “My expectation is that Powelson would go more [for] that route.”

What Does Perry Want?

Smith said it was unclear whether Perry is seeking to ensure generating plants have fuel on site or is concerned about frequency response, inertia and other attributes of traditional baseload units.

“There’s precious little detail in the proposed regulatory text about what exactly would be responsive,” said Smith. “From FERC’s perspective that may be good. It gives FERC more discretion … to determine what is plausibly responsive to this.”

Ari Peskoe, senior fellow in electricity law at the Harvard Law School Environmental Law Program Policy Initiative, and a former FERC practitioner, said Perry raised more questions than he answered. “Is this cost-of-service ratemaking or is DOE suggesting that rate should be based on a plant’s ‘benefits and services?’” he asked in a series of tweets last week. “Does an eligible generator always receive this rate, or do they normally get paid LMP but receive this rate under certain circumstances? How does dispatch work if an eligible plant is not bidding into the market? Or is an eligible plant ‘bidding’ this special rate?”

If FERC issues a rule predicated on fuel supply and not on the type of fuel itself, some observers have noted, it could extend to gas plants that add a tank containing 90 days of fuel oil or those that sign firm pipeline contracts. (See Steve Huntoon’s commentary, Counterflow: Cash for Clunkers Redux.)

The proposed “rule doesn’t appear to have any real limiting principle, so nukes, coal and gas (so long as they kept on site diesel) could all qualify,” said Montana Public Service Commissioner Travis Kavulla, former president of the National Association of Regulatory Utility Commissioners in a tweet.

Wellinghoff noted that solar can bid into PJM’s capacity market with a discounted capacity value. “Can solar show it has 90 days of resource? That will be a very interesting question,” he said.

‘Just and Reasonable’ Standard

If FERC were to act in response to Perry’s proposal under Section 206 of the Federal Power Act, it would first have to make a finding both that current rules are not just and reasonable and that the new rules are, FERC legal experts say.

But the commission won’t find that evidence in Perry’s NOPR.

“The NOPR does not devote much attention to connecting the policy arguments in the preamble of the NOPR to the specific predicate findings required under Section 206, i.e., that current rates are not just and reasonable,” Smith said. “FERC would need to connect those dots.”

The evidence also is far from clear cut in the DOE grid study released in August. The study quoted NERC’s warning that “premature retirements of fuel-secure baseload generating stations reduces resilience to fuel supply disruptions.” But it also noted that NERC’s most recent State of Reliability report concluded “bulk power system reliability remained … adequate” in 2016, repeating the group’s findings from 2013–2015.

“If there’s some ability to make a showing that plants with on-site fuel contribute to resilience and reliability … it may be appropriate to compensate that value, but I have yet to a see a study that does that,” said Wellinghoff. “That’s why it was shocking to see this letter on the heels of the DOE grid study. It seems to be contradictory to that study.”

“DOE is calling this a proposed rule, but it’s not,” Peskoe said. “There’s no rule; just an impossible timeline for FERC/RTOs to figure something out. And since there’s no proposed rule, I don’t think FERC can proceed to a final rule; DOE’s timeline is practically and legally impossible.”

Peskoe quoted from the Administrative Procedure Act, which says a proposed rule must “provide sufficient factual detail and rationale for the rule to permit interested parties to comment meaningfully.”

“The two-sentence description of the proposed ‘Reliability and Resiliency Rate’ raises many questions that DOE doesn’t even attempt to answer,” Peskoe said. “There’s a legal question about what [Perry’s] document actually is. Can FERC treat it merely as a filed comment?

“DOE’s so-called proposed rule doesn’t say that current rates are not just and reasonable; hence, [there is] no authority for FERC to take final action,” he continued. “It’s not just that DOE’s notice is missing the magic words; it has no discussion of current RTO tariffs.”

Clark said that whatever FERC decides, it is unlikely to act in the short time frame Perry called for. “If they did something major within just the context of this rulemaking on a very expedited timetable, they’d probably open themselves to some litigation risk, because you have a fairly vague rule that people are being asked to comment on.”

Impact of the Proposal

Kavulla said Perry’s proposal would replace competitive markets with “FERC-administered cost of service regulation,” making it “the largest change to electricity regulation in decades.”

“Some conservative reforms might have tried to take away or mitigate subsidized resources’ perks. Instead, this reform is sort of the [DOE] equivalent of the Oprah ‘you get a car, and you get a car. And you? A car!’ approach,” he added.

“The practical effect of implementing the order as written would be to basically destroy the wholesale energy markets as we know them, and I don’t think anyone wants that,” Wellinghoff said. “Ultimately it will cause prices to go up significantly for consumers.”

Former Commissioner Nora Mead Brownell, a Republican, said she was “shocked and frankly disappointed” by the proposal. “If Republicans are presumably about fiscal responsibility and markets, this totally contradicts that,” she said in an interview.

“It’s the antithesis of good economics. It’s going to destroy the markets [and] drive away investment in new more efficient technologies, whether they be generating plants or energy efficiency, at a cost to business and ratepayers that is astronomical.”

“If you want to throw $80 or $90 billion at something, spend it on cybersecurity.”

Brownell noted that the coal and nuclear plants in question are fully depreciated and in many cases received stranded cost compensation in states that adopted retail choice. Before the rise of shale gas and renewables cut clearing prices,
“these plants made a lot of money,” she said. “In what other industry would we save old, fully depreciated, inefficient plants that have been paid for many times over? Markets are supposed to allocate resources efficiently and this totally distorts any valid signals you might have.”

Clark said the NOPR, like the DOE grid study, “puts another exclamation point” on the issue of price formation in the markets.

“Is the commission going to do more than it was already prepared to do? That I don’t know,” he said.

“It’s pretty clear it would be challenging to the market design as it exists today, like the New York and Illinois [zero-emission credits for nuclear plants are] challenging to those markets. You’d be talking about nuclear plants across the entire footprint of restructured markets, and most coal plants too.”

Michael Brooks contributed to this article.

October 2, 2017

ISO-NE Planning Advisory Committee Briefs: Sept. 28, 2017

WESTBOROUGH, Mass. — ISO-NE’s Planning Advisory Committee on Thursday hashed over technical details from about 95 stakeholder comments regarding the grid operator’s draft 2016 Scenario Analysis – Phase I Report.

“Two sets of comments concern carbon emissions and making some judgement on whether the region will meet the [Regional Greenhouse Gas Initiative] goals that are being promulgated,” said Michael Henderson, ISO-NE director of regional planning and coordination, as he reviewed the feedback during a Sept. 28 committee meeting. “Other comments concern the inverter-based resources (solar, wind, storage), which becomes more important with the growth of wind and the increased penetration of energy efficiency.”

The New England States Committee on Electricity wanted a disclaimer placed more prominently in the report saying, “The report and the hypothetical future scenarios are not plans, predictions or preferences.” The grid operator agreed to the request.

Scenarios, not Policies

Henderson emphasized that the report constitutes the RTO’s analysis of scenarios provided by the New England Power Pool — not an evaluation of state policies.

Bob Stein of Signal Hill Consulting Group said, “We have heard they are NEPOOL scenarios, but I don’t think NEPOOL endorses any of the scenarios, either.”

Joining by phone, David Ismay of the Conservation Law Foundation said, “The study would be more valuable to the region if it considered various state policies … what we’re getting at is a level of emissions that approximates goals.”

“The ISO is taking the proper approach,” said NESCOE’s Ben D’Antonio. “The idea here is to make sure the report is clear so people can understand it … keeping it straightforward and clear is right.”

The American Wind Energy Association complained that the report’s assumed wind development costs used out-of-date U.S. Energy Information Administration data.

“Our main concern is that transmission costs are too high by a factor of 10. Most obviously, there is a 50% ‘margin’ added to transmission costs which are already extremely high,” wrote AWEA’s Michael Goggin. “This assumption has a major impact on the results, since the transmission costs nearly as much as the wind generation in the scenarios with high levels of onshore wind.”

“I don’t think we are using the costs incorrectly, especially when you consider the interconnection costs for a wind farm in Maine can be extraordinarily higher than for one located right next to a major transmission line,” Henderson said.

Henderson added that the RTO didn’t just look at offshore wind and measure the shortest distance to shore to derive cost estimates.

“Transmission costs were the same issue and, again, they are order-of-magnitude estimates,” he said. “They proved remarkably accurate because they were part of the Maine wind integration study.” (See ISO-NE Files Cluster Study Rules; Window to Open in Nov.)

2027 Needs Assessment Scope of Work

ISO-NE senior transmission engineer Kaushal Kumar presented the assumptions and study methodology behind the 2027 Needs Assessment Scope of Work, a study produced biannually to provide insights into the system 10 years into the future.

The studies evaluate performance and identify reliability-based needs in six study regions, factoring in future load distribution, reliability over a range of scenarios, project coordination and the retirement or addition of major resources. They also apply all relevant transmission planning reliability standards from NERC, the Northeast Power Coordinating Council and ISO-NE.

Questioning Assumptions

One of Kumar’s slides contained a footnote saying that demand resource assumptions included 5.5% distribution losses. Stein asked where the figure came from, and also questioned the RTO’s assumption of cutting that loss to zero when modeling solar, contending that not all PV installations are located right next to load.

ISO-NE Director of Transmission Planning Brent Oberlin said the RTO’s modeling has long assumed an 8% energy loss, with 2.5% lost in transmission and 5.5% in distribution. But he added that he would consider refining the assumptions for PV’s reduction of distribution losses.

2017 Renewable Energy Integration Study Nears Completion

Professor Amro M. Farid, of Dartmouth College’s Thayer School of Engineering, briefed stakeholders on the scope of his team’s work on the grid operator’s 2017 System Operational Analysis and Renewable Energy Integration Study (SOARES).

The study focuses on regulation, ramping and reserves, and addresses the reduction in traditional thermal generation that provides the grid with inertia and other reliability services.

“We need to adopt a holistic way of looking at how renewable energy integration causes fundamental changes in grid dynamics and erodes the power grid’s overall dispatchability,” Farid said.

ISO-NE planning advisory committee SOARES — | *Thayer School of Engineering at Dartmouth*

Methodologies used in past renewable energy studies operate on assumptions for which there is no supporting research, Farid said. Farid said the Electric Power Enterprise Control System simulator his group developed to address this need can more accurately study such things as the impact of energy storage on load-following resources and the RTO’s day-ahead unit commitment.

SOARES is a key element of Phase II of the 2016 NEPOOL Scenario Analysis/Economic Study. Farid expects to complete SOARES by the end of the year.

— Michael Kuser

October 2, 2017

FERC Rejects ‘Carve-Out’ from SPP Congestion, Loss Charges

By Rich Heidorn Jr.

FERC last week rejected a request by several SPP members that they be exempted from congestion and marginal loss charges under a grandfathered contract signed before they joined the RTO (ER14-2850-008, ER14-2851-008).

The commission ruled Sept. 26 that Missouri River Energy Services, Basin Electric Power Cooperative, Western Area Power Administration – Upper Great Plains (Western-UGP), Heartland Consumers Power District and Nebraska Public Power District (NPPD) were ineligible for “carve-out treatment” under the SPP Tariff and a 1977 transmission service contract between NPPD and Basin Electric.

The 1977 contract arose from construction of NPPD transmission needed to deliver power to Western-UGP and Lincoln Electric System from the Missouri Basin Power Project — a venture owned by six public power and cooperative utilities that includes the 1,710-MW Laramie River coal generator, the Grayrocks Dam and reservoir, and more than 500 miles of EHV transmission.

SPP FERC congestion — Laramie River Station | *Burns & McDonnell*

The commission ruled that the utilities were not eligible for a carve-out, although it acknowledged that the section of the SPP Tariff governing grandfathered agreements (GFAs) was “ambiguous.”

The commission rejected the utilities’ claim that they should be exempted from the charges because FERC had previously granted carve-out status to Lincoln, which was also a party to the 1977 contract.

“Though parties to the same contract, Lincoln Electric and [the] parties seeking carve-out treatment are in a fundamentally different position with regard to the costs of participating in SPP because of when each party chose to join SPP,” the commission said. “Lincoln Electric, an SPP member since 2008, was subject to a forced transition to a day-two energy market when SPP adopted the Integrated Marketplace in 2014 and, therefore, received carve-out treatment along with several other non-jurisdictional GFAs that were also subject to a forced transition. On the other hand, [the] parties seeking carve-out treatment were not subject to a forced transition to a day-two energy market when they joined SPP after the commencement of the Integrated Marketplace. Parties seeking carve-out treatment had a choice of whether or not to subject themselves to SPP’s market rules.”

Network Agreements Approved

In a separate order Sept. 25, the commission approved SPP’s unexecuted network integration transmission service agreements with Kansas Power Pool (KPP) effective June 1, 2017, and its executed network operating agreements with KPP, Midwest Energy Inc., Mid-Kansas Electric Co. and Westar Energy effective Sept. 1, 2017 (ER17-2032-002, ER17-2038-002).

KPP protested the service agreements’ inclusion of language describing KPP’s potential liability for credit payment obligations. KPP said that SPP staff had informed it that transmission studies had indicated it would not be responsible for any credit payments because they would be fully covered by base plan funding.

The commission rejected KPP’s complaint, saying the company could be liable for credit payments because final cost information is not available for one upgrade under the agreements, the Woodward EHV 138-kV phase shifting transformer circuit #1.

“When SPP receives the final cost information for the Woodward upgrade, SPP can determine whether all the credit payment obligations are fully covered by base plan funding,” the commission said.