Page 1243 – RTO Insider

October 4, 2017

FERC Approves 6-Year Cycle for SPP RCAR Review

FERC has approved SPP’s request to change the frequency of its regional cost allocation review (RCAR) from every three years to every six, overruling member objections. The change became effective Oct. 1.

Sunflower Electric Power and Mid-Kansas Electric protested the tariff change, saying problems with the RCAR’s study assumptions, analysis and results made it unreasonable to decrease its frequency. The commission ruled their concerns as being out of scope (ER17-2229).

SPP cost allocation RCARs — Sunflower Electric Power was one of two companies that objected to SPP lengthening its regional cost allocation review to every six years | *Holcomb Station photograph © Sunflower Electric Power*

In their Sept. 29 order, commissioners said that while Sunflower and Mid-Kansas “may be correct that a relatively small change in transmission investment could have a large effect, that does not persuade us that conducting a mandatory review of the entire cost allocation methodology every six years instead of every three years is unjust and unreasonable.”

SPP and the commission both noted that any member that believes it has an imbalanced cost allocation can request relief through the RTO’s Markets and Operations Policy Committee. The RTO has also said it is trying to improve the review process by using more accurate information.

Stakeholders approved the Regional Allocation Review Task Force’s revision request in April, based on its recommendation that the change would save SPP manpower and consulting costs. (See “RSC Approves Six-Year Cost Allocation Review,” SPP Regional State Committee Briefs.)

The most recent regional cost review (RCAR II) showed more positive benefit-to-cost ratios and only one deficient transmission zone, which already has a project in the 2017 Integrated Transmission Planning assessment.

SPP said it took about 2,100 employee hours and more than $417,000 in payments to outside consultants to complete that review. The two RCARs have cost more than $1.5 million in outside consulting just to conduct the analysis, and each study has taken at least six months to complete, according to the RTO.

— Tom Kleckner

October 4, 2017

Vermont a Leader in Renewables, PUC Chair Says

By Michael Kuser

BURLINGTON, Vt. — Vermont isn’t just moving in the right direction on renewable energy; it’s helping to lead the country despite — or because of — its modest size, the state’s top regulator told attendees at a recent conference.

ISO-NE vermont renewable energy — Roisman | © *RTO Insider*

“Unlike New York and California, which want to lead on energy, Vermont is not a battleship, we’re a PT boat, so we can turn on a dime,” Vermont Public Utility Commission Chair Anthony Roisman said Oct. 2 at the Renewable Energy Vermont (REV) Conference.

Gov. Phil Scott appointed the 79-year-old Roisman as chair in June.

Vermont is one of the top two states nationwide in terms of clean energy employment as a share of the workforce. The 13,000 jobs created in the state’s sector since 2000 represent 6% of the state’s workforce, REV Executive Director Olivia Campbell Andersen said at the conference.

When Roisman served on the siting board for New Hampshire’s Seabrook nuclear plant 40 years ago, the people interested in renewable energy wouldn’t have filled one table, he noted. In contrast, the REV2017 Conference drew hundreds of people who not only promote renewable energy, but also work in the field.

Kerrick Johnson with Vermont Electric Power Co. asked Roisman how long he expects to serve in his current role, given his age.

“I have a six-year term and I can’t predict who the governor will be in six years, but I don’t see any finite limit to how long I will serve,” Roisman said. He noted that Berkshire Hathaway CEO Warren Buffett is 87 and U.S. Supreme Court Justice Ruth Bader Ginsburg is 84. “I feel as though I’m a little young for the position, but I’m hoping to make up for that with my enthusiasm and energy.”

Siege Mentality

During the conference, state officials described how they see Vermont, like the U.S., as standing at a critical crossroads in terms of both climate change and politics.

“When we have a federal government that abdicates its responsibility to protect its people and our environment, the attorney general’s office will be the first line of defense and the last line of defense,” said state Attorney General T.J. Donovan.

“Now we’re realizing that democracy is not just on election day, but all the time,” Lt. Gov. David Zuckerman said.

The growing season is going to be longer and both wetter and drier at the same time, he said.

“You say, ‘How is that possible?’ But we’ve seen it this year,” said Zuckerman, who owns a farm in Hinesburg. “This summer was one of the worst growing seasons, at the beginning of the season, that any farmer I know has seen, with incredible rains for a long time. And now my pond is almost empty because for the last month and a half it’s been very, very dry.”

Project Siting and Policy

Conference panelists also discussed how a 2016 state law that calls for greater local government involvement in the generation siting process has exacerbated the NIMBY syndrome.

The law (Act 174) represents “a big change from the status quo,” according to Alex “Sash” Lewis, a lawyer with Dunkiel Saunders Elliott Raubvogel & Hand. In the past, state officials had to give “due consideration” to local and regional planning standards when siting resources, but now they must give “substantial deference” to those requirements.

“The PUC is now going to be considering specific municipal plans,” he said.

The law establishes a new set of energy planning standards that municipalities and regions can adopt on a voluntary basis, earning them the right of substantial deference in the siting process. Regions and municipalities that do not wish to update their plans will continue to receive due consideration in the process.

Jon Copans of the Vermont Council on Rural Development considers that holistic approach to energy planning to be a good thing: “You can’t just look at the electric sector without considering many others.”

Catherine Dimitruk of the Northwest Regional Planning Commission pointed to a correlation between prime wind areas and nature conservation areas. She said her commission has a goal of developing 19 MW of new wind generation in the northwestern part of the state, to be achieved only through small-scale wind, and is relying on evolving technology to make it possible.

Kimberly Hayden, a lawyer with Paul Frank + Collins, said that in the past five years “our CO₂ footprint has gone up 2.5% because, while we are retiring nuclear, we’re replacing it with natural gas-fired generation.” The New England Power Pool’s Integrating Markets and Public Policy process “looks very promising … but it’s very political.”

New York and Illinois are doing interesting work, but New York’s Value of Distributed Energy Resources Phase II process “will be going on until the end of time, which scares me,” said Nathan Phelps of advocacy group Vote Solar. “The market is really hurting in New York right now because of uncertainty, which scared off a lot of developers.”

October 3, 2017

Softer Rhetoric as PJM Members Seek Replacement Rules Accord

By Rory D. Sweeney

VALLEY FORGE, Pa. — Discussion at PJM’s Transmission Replacement Processes Senior Task Force has not advanced much in the four meetings the group has held since being reactivated in late July, but the rhetoric has softened.

PJM DER FERC Office of Enforcement Low income customers — Tatum | © *RTO Insider*

The PJM Transmission Owners, their customers and RTO officials all took that as a positive sign at the task force’s most recent meeting Wednesday. Throughout the meeting, all sides thanked each other for the cooperative tone.

“We don’t think we’re that far apart,” American Municipal Power’s Ed Tatum said. AMP’s Lisa McAlister hoped it wasn’t overly optimistic to anticipate that the group might agree on a joint filing to FERC. Participants agreed to define “end-of-life” at the next meeting on Oct. 25 and determine what transmission equipment should be included in that definition.

Hiatus

The atmosphere was a far cry from the Markets and Reliability Committee meeting in July, where load interests blocked TOs’ attempt to continue the task force’s 10-month hiatus. (See Load Blocks TO Effort to Delay PJM Tx-Replacement Talks.)

The hiatus began last September, after FERC questioned whether the TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation” as required by Order 890 (EL16-71).

Supplemental projects are proposed by TOs to meet local needs, but they are not required by PJM’s reliability, economic efficiency or operational performance criteria. Their costs are paid by the TO zone and are not regionally allocated, unlike baseline upgrades resulting from the RTO’s Regional Transmission Expansion Plan.

The commission’s show cause order directed the TOs to file rule revisions, or counter with evidence that they were already in compliance, within 60 days. The TOs responded Oct. 25, contending that the Operating Agreement already complies with Order 890 but also proposed a Tariff amendment, Attachment M-3, that they said would improve transparency. Attachment M-3 would institute an annual stakeholder review of TOs’ assumptions and methodology. It also would require TOs to present their view of local transmission needs and proposed solutions for stakeholder comment.

FERC, which was without a quorum between February and August, has not ruled on the filing despite promising it would act within about three months of the TOs’ response.

PJM Transmission Replacement Processes Senior Task Force — Godson | © *RTO Insider*

At last week’s task force meeting, Exelon’s Gloria Godson reviewed a timeline of the issue and a summary of the proposed amendments.

AMP followed with a presentation that compared the TO’s suggested changes through the M-3 proposal to changes AMP proposed to the PJM Operating Agreement, Schedule 6, Regional Transmission Expansion Planning Protocols. AMP’s position would apply the same PJM process used for baseline project planning to end-of-life project planning, which Tatum said would result in the PJM Members Committee retaining filing rights under Section 205 of the Federal Power Act as opposed to shifting filing rights to the TOs as the M-3 proposal would do.

The organization said it was focused on the processes to determine when infrastructure has reached the end of its serviceable life and how it gets replaced. (On Friday, AMP released an analysis showing that more than half the transmission spending in PJM since 2012 was on supplemental projects. See related story, Report Decries Rising Tx Costs; Seeks Transparency on TO Projects.)

RTEP Process ‘Working Well’

Mark Ringhausen of Old Dominion Electric Cooperative called for pulling the TOs’ local planning for certain Supplemental projects into the RTEP process and requiring designated entity agreements between PJM and the transmission developer to set expectations and remedies for nonperformance for better PJM planning models. He said it would “provide consistency and transparency across all the TOs and PJM if we use a process that’s been working well for the past 15 years.”

He and AMP also asked for one-line diagrams to be provided for some project presentations, which they said would speed up meetings and reduce their questions and information requests.

TOs hesitated to agree to the one-line requests in public meeting materials, citing Critical Energy/Electric Infrastructure Information (CEII) concerns and that they often lack comprehensive information when projects are presented. But they said that the information is available with appropriate CEII protection. PJM acknowledged the concerns. The TOs noted that they provide project maps during the planning process, which they said serve a similar purpose, but AMP and ODEC disagreed.

Frustration

The hesitation has frustrated customers, who said they’ve heard the same arguments before and that other PJM stakeholder groups “don’t seem to have a problem working” while awaiting the FERC decision.

“You’re working very hard to improve the process without asking us what we want or need,” McAlister said.

PPL’s Frank “Chip” Richardson said the TOs are not willing to discuss augmenting what they’ve already filed at FERC but will consider other items.

Godson stressed the gravity of the show cause order, noting it “is not something that happens often.”

“Unfortunately, FERC failed to issue an order within three months as indicated due to the lack of a quorum,” she added.

GT Power Group’s Dave Pratzon said he doesn’t have a direct interest in the dispute, but he suggested that the customers list their requests and that the TOs then indicate which of them they can talk about “rather than have everybody dance around the table.”

“Let’s get to the substantive work. We’re tired of having this same discussion. We understand the TOs’ litigation position and believe that what we’re proposing is within the bounds of the task force’s charter and not that far off — from a substantive perspective — from what the TOs proposed,” McAlister said.

“I would love nothing better than to engage in a productive discussion with the TOs on this. I can’t make them love me. … I can’t force them to do that. But we do have an MRC-approved taskforce and charter with things to work on,” Tatum said. “There’s lots of opportunities to do productive things here. There’s one group who won’t play.”

“It’s not that we won’t play. We’re here. We have considered things,” Richardson responded. “Just because we’re not willing to negotiate what is pending at the FERC in a stakeholder forum — and require the task force to work within its charter — doesn’t mean we’re not willing to play.”

October 3, 2017

FERC Grants NYISO Shortage Pricing Waiver

FERC last week granted NYISO a waiver of its shortage pricing rules, giving the ISO time to align its Tariff with its market software (ER17-758).

NYISO requested the waiver after its Market Monitoring Unit discovered that the ISO’s software had not been calculating prices in accordance with the Tariff language since it implemented transmission shortage cost pricing in February 2016.

FERC NYISO waiver Shortage Pricing — | *NYISO*

The MMU, Potomac Economics, reported the problem to the ISO at the end of August 2016. After further investigation, the ISO told stakeholders Nov. 3 that the inconsistencies constituted a “Market Problem” because they had materially impacted its markets.

The ISO asked FERC to waive the relevant Tariff provisions from Feb. 11, 2016, until the Services Tariff was revised — as occurred June 14, 2017, when the commission accepted the ISO’s proposed revisions, under delegated authority.

“NYISO now realizes that it inadequately explained the pre-existing logic for its software and the interaction of this logic with the graduated transmission shortage cost provisions,” FERC recounted.

Noting that no commenters opposed the waiver, the commission said that the ISO had “acted in good faith and worked diligently with MMU and its stakeholders to resolve the inconsistency.”

— Rich Heidorn Jr.

October 3, 2017

MISO Ranks MTEP 18 Futures by Stakeholder Preference

By Amanda Durish Cook

Stakeholder sectors have eschewed MISO’s suggestion that they apply equal importance to each of the RTO’s four 15-year future scenarios used for next year’s transmission planning, instead giving more weight to the potential for a slow-and-steady evolution of the generation fleet.

As a result, MISO’s 2018 Transmission Expansion Plan will include a 30% weighting for a continued fleet future, 25% each for limited fleet change and distributed and emerging technologies futures, and 20% for an accelerated fleet change future. The RTO used sector averages and rounded figures to the nearest 5% increment.

Some stakeholders asked why MISO decided to round the averages.

MISO MTEP 18 Futures — Ellis at June’s Planning Advisory Committee meeting | © *RTO Insider*

“A percentage here and a percentage there — that doesn’t make a big impact when it comes to project recommendation,” MISO policy studies engineer Matt Ellis said during a Sept. 27 Planning Advisory Committee meeting.

MISO had recommended an equal 25% weighting for all four MTEP 18 futures. Beginning with MTEP 19, equal importance will be assigned to all four grid and generation scenarios, effectively eliminating differential weighting. Staff initially said MISO would abolish weighting beginning with MTEP 18 but changed course in August, explaining that MTEP 18 futures were developed with the understanding that stakeholders would be involved in deciding their importance. (See MISO Delays Removing MTEP Futures Weighting to 2019.)

Minnesota Public Utilities Commission staff member Hwikwon Ham said he supported MISO’s August plan to apply an even 25% likelihood across the board for 2018.

“I share MISO’s concern that we are spending too much time slicing and dicing percentages,” Ham commented, saying that stakeholders were devoting too much time to debating issues that wouldn’t alter project recommendations.

Resource Additions Estimates in MTEP 18

MISO has meanwhile completed a draft projection of future resource additions to inform MTEP 18. The RTO is not projecting much change in resource siting between the MTEP 17 and MTEP 18 futures. However, it created an additional future scenario for the 2018 cycle — the distributed and emerging technologies future — that it predicts will show more than 20 GW of distributed solar in the next 15 years.

Additionally, MISO found that the MTEP 18 futures overall indicate that demand-side and distributed technologies would be spread across more buses in the footprint than in previous cycles.

The futures set out the following scenarios:

In a limited fleet change future, MISO predicts about 32 GW of generation additions and almost 30 GW of retirements, resulting in coal inching forward to take a 51% share of the resource mix by 2032, compared with today’s 48%. Natural gas generation remains unchanged at 24%, while renewables crawl forward to take a 10% share of generation, up from today’s 8% share.
In the continued fleet change scenario, the RTO projects more than 54 GW of additions and just about 38 GW of retirements, with a resource mix consisting of 43% coal, 27% natural gas and 15% renewables.
The accelerated fleet change future yields the most additions at roughly 82 GW, offset by 38 GW of retirements, resulting in 35% coal, 21% natural gas and 30% renewables fleet mix.
In a distributed and emerging technologies future, generation additions hit 70 GW, while retirements slightly exceed 40 GW, producing a mix of 40% coal, 27% natural gas and 21% renewables.

“There are 45 GW of renewables in the definitive planning phase of the interconnection queue set to come online in the next three years,” Ellis reminded stakeholders. “Now, it’s safe to say that not all of that will come online. I’ll leave that to you to determine. But, if you look at historic trends, roughly 60% of projects make it through the queue.”

October 3, 2017

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.