Page 1251 – RTO Insider

April 22, 2019

SPP MOPC Briefs: April 16-17, 2019

TULSA, Okla. — Like the walking dead, Tariff Attachment Z2 keeps returning from the grave, much to the consternation of SPP and its stakeholders.

General Counsel Paul Suskie last week laid out before the Markets and Operations Policy Committee the implications of FERC Reverses Waiver on SPP’s Z2 Obligations.)

The commission ordered SPP to refund, with interest, credit payment obligation amounts dating back to 2008, except for the one-year billing adjustment limit allowed in the Tariff. SPP has estimated the obligations to be approximately $200 million.

SPP was seeking a retroactive Tariff waiver allowing to invoice transmission service customers for Attachment Z2 credit payment obligations for the 2008-2016 time period prior. FERC ruled the waiver request to be retroactive ratemaking, saying SPP did not provide adequate notice.

“In my opinion, FERC had no idea of what it was unraveling,” Suskie told the MOPC on April 16. “We’ve listed 20 issues that are going to be challenges if we undo this.”

Included among those is how SPP will redistribute to transmission owners’ point-to-point revenues it had clawed back in the historical settlements process. Staff said it would share the full list of issues with stakeholders.

Suskie said SPP and other parties on April 1 asked FERC for a rehearing and clarification of the order (ER16-1341). He also said the RTO is developing a compliance plan to be filed with FERC no later than June 28.

Attachment Z2 details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP said that delays in implementing computer software kept it from listing certain creditable upgrades in aggregate facilities study reports, calculating and assessing costs, and distributing credits to transmission customers before August 2016.

SPP Proposing to Assign Kansas NTC to GridLiance

SPP’s proposal to assign the Kansas Power Pool’s (KPP) notification to construct (NTC) a 69-kV rebuild to GridLiance High Plains met pushback from the MOPC over increased costs within transmission zones and the usual turf battles between the RTO’s legacy TOs and smaller entities.

“If this was someone else other than GridLiance, or another [investor-owned utility], you would gladly accept the assignment,” Tri-County Electric Cooperative’s Chris Giles complained to the committee’s membership.

“Amen!” came a voice from the opposite corner of the meeting room.

The project was originally assigned to KPP in February 2018. Rather than reconductor 4 miles of 69-kV lines from the city of Winfield, Kan. — a KPP member — to a Westar Energy substation, KPP decided on a full rebuild and raised the initial estimate from $1.5 million to $3.6 million.

Larry Holloway, KPP’s assistant general manager for operations, said his company has been unable to gain the obligation to build from Kansas regulators, which led to GridLiance’s involvement. The five-year-old company, which partners with public utilities, announced in January a “long-term partnership” with Winfield in which GridLiance would acquire 65% of the city’s 29 miles of 69-kV facilities and invest in a “needed reliability upgrade.”

SPP said GridLiance’s own data show it will increase the annual cost to customers if it retains the NTC, largely because its tax requirements are greater than KPP or Winfield’s.

GridLiance High Plains President Brett Hooton said the cost of the project itself remains the same, regardless of the assignment from Winfield to GridLiance. He said SPP’s cost estimate over the project’s four-year life works out to $75,000/year.

“The cost difference on rates primarily relates to the fact that GridLiance is a taxable entity and the city is not,” Hooton told RTO Insider. “Any time there is an assignment from a municipal utility to a taxable utility, there will be similar cost impacts.”

GridLiance’s Noman Williams (left) and Brett Hooton | © *RTO Insider*

Hooton said GridLiance intends to build the facilities with 138-kV capabilities, matching Westar’s existing infrastructure.

The issue is likely to receive similar pushback during the April 29-30 Regional State Committee and Board of Directors meetings. SPP’s Tariff required staff to “advise” the MOPC of the proposal, with the final decision being left to the board.

“If the board were to reject the assignment because of the small cost impact, it would set a precedent that municipal utilities would virtually be unable to ever assign or novate an NTC because of their tax-exempt status,” Hooton said.

Staff Explains 9-Month Delay to New Settlement System

Staff briefed the MOPC on its delayed new settlement system, which was supposed to go live May 1. However, a condensed project timeline and missed deliveries left developers without enough time to build software and train end-users, pushing the implementation back to Feb. 1, 2020.

SPP announced the delay to project participants on Feb. 15, saying the project was in red status because of “various system issues” and that it was pausing member testing as it reassessed the timeline, remaining work and required testing.

Settlements Director Don Shipley said incorporating additional applications and links to other systems increased the project’s risk. The settlement system replacement project will consolidate several systems and automate manual processes, reducing staff costs and improving personalized customer service, he said.

“We had several parallel paths — development, testing, training — all going on at the same time, rather than back-to-back,” Shipley said.

Shipley said the inability to run the system end-to-end meant staff couldn’t do day-in-the-life testing, which also meant members couldn’t “appropriately” test their internal systems. Even then, there were frequent errors in the software’s calculations, he said.

“The right decision was to delay and ensure we have a system that worked. The most catastrophic thing that could happen is if we couldn’t settle the entire system when we cut over,” Shipley said.

Following several weeks of analysis and review, SPP has worked to improve its communications both internally and with the vendor, Symphono. Daily meetings, called “scrums,” are held to “understand what is going to be happening” and to discuss any issues at the vendor level. Staff are now focused on the “total development effort,” with a June 28 deadline to complete all code, and internal testing and training has been increased.

“We don’t want this to become a pattern. What are we doing to learn from mistakes like this and Z2 to ensure it doesn’t happen again?” asked Kansas City Power & Light’s Denise Buffington, the MOPC’s vice chair.

“I understand where you’re coming from, with the Z2 followed by the settlement system,” Shipley said. “We’ve already applied some of the lessons learned from Z2, so it’s an incremental process. We still have to understand how we efficiently deliver projects.”

Lanny Nickell confers with SPP’s Dustin Smith (left) and Derek Wingfield on a presentation. | © *RTO Insider*

“Communication is critical. Everyone has to be talking to each other,” said SPP’s engineering vice president, Lanny Nickell. “We tend to overcomplicate things, and we tend to be optimistic. We tend to set very aggressive schedules.”

Shipley was reluctant to lay the blame on Symphono, which built a similarly customized system for MISO. He said because of SPP’s larger footprint and “the way we settle,” SPP needed “something different.”

“I do think we underestimated some of the complexities of adding [other capabilities] to our systems,” he said. “This vendor worked very hard with us. They made mistakes and missteps, but we did as well. We all bear some responsibility of where we were in February. We all bear the responsibility of the new timeline.”

The project was approved two-and-a-half years ago with an estimated capital cost of $5.3 million. The implementation delay has not increased those costs, SPP said, but will likely result in additional maintenance costs because the existing settlement system and other legacy systems and software will run longer than planned.

FERC on Thursday granted SPP’s request to defer several Tariff changes because of the settlement system’s delay (ER17-1568). The Tariff revisions were filed because of changes to other systems as a result of the new settlement system. (See related story, “SPP Granted Delay for Tariff Revisions,” FERC Tells SPP to End Exit Fee for Some Members.)

SPP Broadens PMUs’ Reach with Revision Request

SPP will get another chance to widen the use of phasor measurement units (PMUs) within its footprint with the MOPC’s approval of a revision request (RR) that addresses a FERC rejection of a previous RR.

RTWG RR340 changes the PMUs’ installation location from the point of interconnection to the point of change of ownership and classifies equipment as “transmission owner interconnection facilities” to fully address cost responsibility. The RR also adds language to allow existing equipment to serve as a PMU.

“This just clarifies the cost issue and where [PMUs] will be installed,” said American Electric Power’s Richard Ross during the heat of discussion.

AEP’s Richard Ross (left) makes a point as East River Electric’s Mark Hoffman observes. | © *RTO Insider*

The recommendation was passed over two opposing votes and a half-dozen abstentions, primarily over installation costs.

RR340 is a response to a previous change request that would have required PMUs at new generator interconnections but was rejected by FERC in August. The RTWG said the commission found the language regarding the PMUs’ installation funding unclear. The commission directed SPP to clarify how TOs will treat PMU installation costs to avoid including them in transmission rates. (See “Commission Rejects PMU Proposal over Cost Concerns,” 3rd Time’s a Charm for SPP Resource Adequacy Proposal.)

“This RR is trying to get in front so that we can capture more PMU data as it is brought on,” said Cody Parker, SPP’s supervisor of operations support.

Parker said the RTO has completed the first phase of its PMU project, creating an informational-only system not used in real-time operations. Subsequent phases will be dependent on increased PMU coverage, he said.

SPP defines PMUs as monitors that provide precise grid measurements for synchrophasors. PMU measurements are taken at high speed, typically at 30 observations/second. Each measurement is time-stamped according to a common time reference, allowing measurements from different locations and utilities to be synchronized and combined to provide a precise and comprehensive view of the entire interconnection.

DER White Paper Gains Endorsement

The MOPC endorsed a Supply Adequacy Working Group policy paper that further defines the requirements for demand response programs and behind-the-meter generation and addresses whether to treat them as a load modifier or capacity.

The Distributed Energy Resources Policy is intended to ensure that all net peak demand is carrying the appropriate capacity, as required by SPP’s resource adequacy requirements. SPP’s Tariff allows a load-responsible entity to reduce its forecasted peak demand through DR programs and controllable and dispatchable BTM generation.

MOPC’s leadership abides by Robert’s Rules of Order. | © *RTO Insider*

MOPC members debated the need to require DERs to attest to having firm transmission service to load, as the paper’s draft required. Oklahoma Gas & Electric’s Greg McAuley suggested the phrase “attest to having firm delivery to load” be used instead of “transmission service,” which helped to gain approval against one dissenting and one abstaining vote.

“Some of the potential resources in [the controllable and dispatchable resource] category are behind retail meters and, as such, may never impact the transmission system and, therefore, would never need or have firm transmission service,” McAuley explained.

The nine-page white paper, which has been approved by the SAWG and the Cost Allocation Working Group, will be turned into a business practice and eventually become an attachment to the Tariff’s Attachment AA.

HITT Working to Finalize Report to Board

Suskie told the committee that the Holistic Integrated Tariff Team hopes to complete its yearlong work by the end of the month and present a final report to the Board of Directors for its April 30 meeting.

Composed of stakeholders, regulators and staff, the HITT has entered the third phase of its work in drafting and finalizing a report to the board. The team has been meeting since April 2018 to determine the optimal alignment of SPP’s planning processes, cost-allocation methodologies, and market products and services. (See SPP’s Tariff Team Begins Carving up the Elephant.)

“We remain positive we can get through the end of the month, but we have left the most contentious issue for last,” said KCP&L’s Buffington, referring to zonal transmission cost allocations.

“Like when the U.S. Constitution was drafted, there are a lot of different people on different sides,” Golden Spread Electric’s Mike Wise said. “I’m very optimistic that as a group, we are going to achieve what we set out to do, which is achieve value for members of the pool. Not everybody is going to be happy with it. I have compromised; Denise has compromised. I’m encouraged, very encouraged, where we are right now.”

The HITT meets in Dallas on April 25 to complete the report. It has posted a draft version on its website.

Dogwood Energy’s Rob Janssen (left) raises a question as Lincoln Electric’s Dennis Florom listens. | © *RTO Insider*

MWG Proposal Improves RR Impact Analyses

The MOPC unanimously approved a recommendation by the Market Working Group and RTO staff to improve the RR process’s impact analysis by revising the cost data that go into calculations.

SPP’s Gary Cate said the new methodology will provide a clear view of estimated vendor costs by no longer including capitalized costs, including those staff salaries that are already accounted for in the capital budget. The changes will also add transparency into staff time by adding the “true impact” to staff within the implementation timeline.

Staff costs will only include staff hours and remove redundant cost reporting between the capital and foundation budgets. Cate said the current method inflates staff cost by lumping average salaries into the cost of impact assessments.

With the change, impact analyses will provide a range of vendor costs rather than a single value with a rough order of magnitude +/- 50%.

Boston Marathoner Henderson Earns her Applause

Members greeted Golden Spread’s Natasha Henderson with applause when she joined the meeting, fresh off completing her second Boston Marathon the day before. Henderson battled unexpectedly warmer temperatures that slowed her pace, but she used a finishing kick to reach the finish line in just under four hours.

“I thought about dropping, but who drops out of the Boston Marathon? Not me,” Henderson told RTO Insider. A personal best and qualifying for next year’s marathon out of the question, she said, “this was now going to be a very long training run.”

Golden Spread’s Natasha Henderson crosses the finish line. | *Natasha Henderson*

Henderson was scheduled to run a half-marathon in early June in Steamboat Springs, Colo., but has changed her registration to run the full 26 miles in an attempt to qualify for next year’s Boston Marathon.

“Some days, like my second Boston Marathon, are not what I hoped they would be, but they make me stronger,” Henderson said. “For me, running is about pushing myself and being a better person. I learned from the experience and hope to have another Boston Marathon in my future.”

Members Pass 10 RRs on Consent Agenda

The MOPC unanimously endorsed its consent agenda, which consisted of 10 revision requests:

BPWG RR343: Automates a manual task with installed software to prevent interchange overscheduling.
BPWG RR344: Retires Business Practice 2500, which was implemented when the aggregate transmission service study could take years to complete. The study’s methodology has been revised to include a six-month completion requirement, making the practice obsolete.
MWG RR346: Includes transition major maintenance among the costs associated with start-up and no-load operations to be included in mitigated no-load and start-up offers beginning with the April 18, 2019, operating day.
ORWG RR338: Expands and clarifies the description of “most severe single contingencies” and other potential contingency events used to determine the reserve sharing group’s contingency reserve obligation.
ORWG RR349: Requires responsible entities to use the reliability communications tool (R-comm) instead of telephones to communicate with the SPP balancing authority.
RTWG RR345: Limits to three the number of identical transmission service requests impacting a DC tie during the submission window, as outlined in NAESB Business Standard WEQ 001-8.3.
RTWG RR347: Removes grandfathered agreements that have expired or are no longer in service.
RTWG RR353: Revises language in Tariff Attachment V to account for changes in RR335, which adds a three-stage generation interconnection study process and implements required changes in FERC Order 845-A.
STAFF RR351: Clarifies and modifies the RR process requirements, allowing change requests to be withdrawn without requiring MOPC review and action. Any actions may still be appealed by qualified entities to the MOPC.
TWG RR350: Eliminates language in the criteria that is already covered by NERC standards or other SPP standalone documents, minimizing inconsistencies or conflict with current and future NERC standards and revisions.

— Tom Kleckner

April 22, 2019

Texas Public Utility Commission Briefs: April 18, 2019

The Texas Public Utility Commission last week held off on giving its final blessing to $1.37 billion worth of transactions involving Oncor, Sharyland Utilities and Sempra Energy.

Handed a proposed order by Oncor the day before their Thursday meeting, the commissioners asked staff to bring a final order back to its May 9 meeting (Docket 48929).

PUC Chair DeAnn Walker opens the April 18 meeting.

“I’m OK with going ahead and approving the settlement,” said PUC Chair DeAnn Walker, drawing assent from her fellow commissioners.

The commission’s final order will give Sempra a 50% stake in Sharyland Distribution & Transmission Services and Oncor ownership of Sharyland’s transmission-owning InfraREIT. The asset exchange will increase Oncor’s footprint in West Texas and “de-REIT” the Sharyland utility in South Texas. (See Oncor -Sharyland-Sempra Deals Inch Toward Approval.)

“We look forward to continuing the dialogue about the draft order,” Oncor spokesman Geoff Bailey said. “We continue to believe that Oncor’s proposed acquisition of InfraREIT is good for Texas, the ERCOT market and for Oncor.”

Oncor to Pay $432K Penalty

The PUC’s consent agenda included the approval of a settlement agreement between staff and Oncor that will result in the utility paying $432,000 in administrative penalties for 2017 feeder violations (Docket 48841).

PUC commissioners confer with Stephen Journeay, director of commission advising and docket management.

Following an executive session, the commissioners also agreed to intervene in three FERC dockets:

ER19-1503: MISO and Entergy Services’ proposed revisions to Entergy operating companies’ transmission formula rate templates.
EL19-62: Springfield’s (Mo.) complaint against SPP over its pricing zone costs as a result of the RTO’s highway/byway allocation methodology. Springfield is asking FERC to “benefit-deficient zones,” like Springfield’s, from the methodology’s “unintended consequences.”
ER19-1541: A proposed settlement agreement between MISO, its transmission owners and East Texas Electric Cooperative over the withdrawal and transfer of 38 MW of load and related assets from MISO to SPP.

— Tom Kleckner

April 22, 2019March 19, 2025

Record Gas Demand, Production Highlights FERC Markets Report

By Rich Heidorn Jr.

WASHINGTON — Record high natural gas demand and production highlighted FERC’s 2018 State of the Markets report, released last week.

The report by the Division of Energy Market Oversight said gas demand was driven by electric generation and growing LNG exports. Despite big jumps in the Marcellus Shale and the Permian Basin regions, demand growth outpaced production increases.

As a result, storage levels were lower than average and “at times were the lowest in more than a decade,” FERC said, contributing to higher gas and power prices.

The Henry Hub benchmark averaged $3.12/MMBtu for the year, up 5% from 2017. Reduced storage inventories pushed Henry Hub prices up 31% in the fourth quarter over a year earlier.

| FERC

Although gas prices remained relatively low, there was increased price volatility because of storage constraints, extended winter cold and infrastructure constraints in the West. In January 2018, an East Coast cold snap pushed gas prices to $140.85/MMBtu in New York and $128.39/MMBtu in the Mid-Atlantic, with prices peaking at $78.88/MMBtu in Boston. In contrast, New York’s spot price never reached $21/MMBtu in 2017.

Gas production averaged 80.7 Bcfd, an increase of 12% from 2017. The Marcellus Shale was the most productive basin, averaging 19.4 Bcfd for 2018, up nearly 13.5% from 2017.

Haynesville Shale production jumped to an average of 6.5 Bcfd, a 46% increase that FERC attributed to higher gas prices and lower production costs. Rising crude oil prices were a factor in the 2.1-Bcfd increase in associated natural gas production in the Permian, a jump of 41%.

More than 689 miles of commission-jurisdictional pipelines, representing 13 Bcfd of capacity, went into service during 2018, much of it connecting Marcellus and Utica supplies to markets in the Midwest, Northeast and Southeast. There was no capacity increase in New England.

| FERC

Export Growth

New pipelines also provided links to LNG export terminals and exports to Mexico.

After becoming a net gas exporter for the first time in 60 years in 2017, U.S. net exports were almost 2 Bcfd in 2018, in part because of the opening of the Cove Point LNG facility in Maryland in March and the expansion of the Sabine Pass LNG terminal in Louisiana in October. LNG exports averaged nearly 3 Bcfd in 2018, a 50% jump from 2017.

Pipeline exports to Mexico rose almost 0.5 Bcfd to a new high of 4.6 Bcfd.

| FERC

The report predicted up to 4 Bcfd of new export capacity will be added in 2019, with LNG facilities at Cameron, Corpus Christi, Elba Island and Freeport expected to go into service and an additional expansion at Sabine Pass. (See related story, Enviro Protesters Scale FERC HQ as Agency OKs More LNG.)

Power Prices Rise

As gas continued its increasing role in electric generation, fuel price increases also caused a jump in power prices across the country.

Mean day-ahead on-peak LMPs jumped almost 25% at RTO/ISO pricing nodes. Prices in SPP, MISO and CAISO increased less than 15%, while PJM and NYISO prices rose about 20%. ISO-NE was up 33% and ERCOT had the biggest jump at 44%.

As in recent years, most new generation capacity in 2018 was natural gas, wind and solar, and most retirements were from coal.

| FERC

Capacity price trends varied in grid operators’ 2018 auctions. RTO-wide average prices declined 13% in New England’s auction for 2021/22, while the weighted average price in PJM’s auction for the same period rose 36%.

In NYISO’s spot capacity auction, prices in the high-cost Hudson Valley and New York City zones fell by 3% or more. Prices for Long Island rose 5% and the New York Control Area jumped 32%.

MISO’s Planning Resource Auction saw zonal prices rise clear much lower than in the other markets with a price of 30 cents/kW-month for most of the region for 2018/19, up 25 cents from a year earlier.

April 22, 2019

PJM: Dismiss Monitor’s Offer Cap Complaint

By Christen Smith

PJM wants FERC to toss out the Independent Market Monitor’s complaint about its default market seller offer cap (MSOC), saying the IMM’s February filing did not prove current rules encourage abuse of market power (ER19-4 7).

In an April 9 response filed with the commission, PJM said the Monitor didn’t provide enough evidence that its current cap — approved four years prior as part of the RTO’s Capacity Performance construct — and the results of Base Residual Auctions suddenly became unjust and unreasonable.

PJM said the commission’s order approving CP “explained that the default MSOC is just and reasonable because it reflects the amount that a competitive resource would accept to be committed as a capacity resource.”

“In particular, it is designed to allow capacity market sellers to recover the costs, investments and expenses needed to ensure that their resources can perform during emergencies occurring at any time of the year. In other words, the default MSOC is intended to reflect the opportunity cost that a resource faces when choosing whether to become a committed capacity resource,” PJM said.

PJM said the Market Monitor isn’t authorized to file a complaint on the market seller offer cap. | *PJM*

The Monitor said in its initial filing that PJM’s MSOC has been inflated by the “unreasonable and unsupported” expectation of 30 performance assessment hours (PAHs) annually. As a result, the Monitor said, it has been prevented from effective mitigation of market power, able to subject only a small number of very high offers to unit-specific cost reviews. (See Monitor Asks FERC to Cut PJM Capacity Offer Cap.)

Unit-specific MSOCs are supposed to be based on the opportunity cost of taking on a CP obligation, with its expectations of bonus payments or penalties for performance during an emergency, PJM said. (The time span for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAIs) in compliance with FERC Order 825 in 2018.)

In August, the Monitor concluded that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 BRA because of economic withholding encouraged by the inflated MSOC. (See IMM: PJM 2018 Capacity Auction was ‘Not Competitive’.)

PJM asked the commission to reject the Monitor’s proposed replacement rate of 60 PAIs and instead adopt a method that applies the same measurement to equations for both the default MSOC and the nonperformance charge. This rate, the RTO asked, would not take effect until after the 2022/23 BRA, for which several compliance deadlines for market sellers have already passed.

“The Market Monitor’s proposal is unjust and unreasonable due to, among other reasons, the disconnect between the number of expected performance assessment intervals in the nonperformance charge rate and the default MSOC,” PJM said. “Retaining the same value of performance assessment intervals in both equations is essential to maintaining the underlying logic of the existing default MSOC equation.”

April 22, 2019

Renewables Outlook to Get Boost in MTEP 20 Futures

By Amanda Durish Cook

After prodding by stakeholders, MISO now says it will boost renewable generation estimates in each of the four 15-year future scenarios that guide its annual transmission planning process.

MISO had previously proposed relying on an older set of futures to inform the 2020 Transmission Expansion Plan (MTEP 20). But stakeholder pushback prompted the RTO to increase the minimum renewable penetration levels for each future by 5%, bumping projections from 15-35% of the generation mix to 20-40%.

Speaking at a Planning Advisory Committee meeting Wednesday, MISO Planning Manager Tony Hunziker noted the high degree of consensus among stakeholders to increase renewable estimates.

Increased renewable projections in MTEP 2020 futures | MISO

The MTEP will also assume the solar investment tax credit — which allows a 30% federal tax deduction of installation costs — will continue into 2023. The RTO will also rely on the National Renewable Energy Laboratory’s Annual Technology Baseline capital cost projections for renewable generation instead of using a 30% variance on those projections.

However, some stakeholders said they’d like to see a more nuanced approach to projecting renewable growth based on subregional characteristics to avoid blindly increasing renewable projections. For instance, MISO shouldn’t expect significant wind generation growth in sunny MISO South, some noted.

“MISO is not a resource planner. We don’t dictate renewable resource additions,” Hunziker responded.

Entergy’s Yarrow Etheredge said MISO didn’t adequately support the case for a blanket increase of every type of renewable generation everywhere in its footprint.

“This is basically just an adder,” Etheredge said, asking MISO to defend the change using data.

Hunziker promised a complete rework of MTEP 21 futures with stakeholders and reminded PAC members that MISO was up against a June deadline to finalize MTEP 20 futures definitions and assumptions.

The RTO last month said it would rely on the same set of 15-year futures for the third straight year to evaluate transmission projects in MTEP 20, though some stakeholders criticized the RTO’s limited fleet change future as no longer a likely scenario. (See MISO Going Back to the Futures for MTEP 20.) The futures scenarios include a limited fleet change, continued fleet change, accelerated fleet change, and a distributed and emerging technologies future.

Hunziker said the renewable increase should alleviate specific concerns about MISO’s limited fleet change future, which has been criticized as improbable because it projects only an 11-GW growth in renewable generation through 2033. MISO’s interconnection queue currently includes about 420 projects worth a combined 70 GW; renewable resources account for about 90% of the queue. Historically, about 18% of proposed projects clear the queue.

Last month, members of MISO’s Board of Directors also questioned whether the limited fleet change future was still plausible.

“It seems like the rate of adoption is increasing,” Director Thomas Rainwater said, while also acknowledging that MISO is “no California” in terms of appetite for renewables. He asked if the RTO will consider “a more radical adoption” of renewables and distributed resources in a new set of futures for MTEP 21.

MISO Vice President of System Planning Jennifer Curran said the accelerated fleet change and distributed and emerging technologies scenario are fast becoming the most probable futures and noted the RTO will soon revisit how futures are developed. But she also cautioned that MTEP futures represent possible trends and are not meant to be forecasts.

At the April PAC meeting, Minnesota Public Utilities Commission staff member Hwikwom Ham said he remained concerned that the limited fleet change and continued fleet change scenarios still risk obsolescence because they don’t account for the zero-carbon pledges of multiple utilities and increasing electrification of the economy. He also pointed out that equity investors are now contemplating a company’s carbon footprint as a risk factor before making investments decisions.

“Who is going to be in the White House next year? It’s going to be a different business model,” Ham added, referencing President Trump’s rollbacks of environmental regulations.

Hunziker said MISO will raise those topics in the redevelopment of futures in time for MTEP 21.

Meanwhile, MTEP 20 marks the first time MISO will work with Purdue University’s State Utility Forecasting Group and Applied Energy Group to create separate load forecasts that reflect each of the four futures. The RTO this month reported that entities representing 77% of its load responded to its request for load, demand and energy data.

April 22, 2019

More Time Needed for Storage Compliance, MISO Says

By Amanda Durish Cook

CARMEL, Ind. — MISO will ask for at least another year to comply with FERC Order 841, saying the intricacy and expense of incorporating storage into its markets is greater than it originally anticipated.

MISO leaders say the original Dec. 3 go-live date to comply with the order is no longer feasible given FERC’s recent deficiency letter in response to the RTO’s proposed storage participation model. MISO was counting on the commission accepting its filing this month to maintain a strict timeline for adapting its market to storage participation.

FERC earlier this month issued separate deficiency letters to all six jurisdictional RTOs and ISOs regarding their plans for energy storage participation. (See FERC Asks RTOs for more Details on Storage Rules.) The commission specifically asked MISO for several more details and explanations related to its phased participation approach, proposed commitment statuses, complexities for distribution system storage resources, conflicting offers and bids, and make-whole payments. The RTO has until early May to respond.

MISO Director of Market Design Kevin Vannoy said the combination of a later-than-anticipated FERC order, remaining uncertainty about what the commission will decide after the RTO’s response and holding work on software changes because of that uncertainty led to the request.

“In our response to this request, we are going to ask for a deferral,” Vannoy told the Energy Storage Task Force on Thursday.

Vannoy said the deferral would be “no earlier than a number of months after a clean order.” When pressed, he said the RTO could request for 12 to 18 months from when FERC fully accepts its filing.

The “cost and complexity” of implementing new bid parameters for storage was greater than MISO predicted in 2018, Vannoy said. Work also remains on how energy storage operators will communicate data to the RTO, he added.

MISO is in the process of answering FERC’s multiple questions in the 10-page deficiency letter, he said.

“We didn’t see anything in there one way or the other that they were leaning towards rejecting or accepting the filing. We think they simply need more explanation,” Vannoy said of the commission’s tone in the letter.

FERC also asked MISO to explain a provision that prohibits distribution-level storage resources from pseudo-tying into a different balancing authority. Vannoy said RTO leadership feels that pseudo-tying storage is beyond the scope of the final rule.

MISO had warned stakeholders in mid-April that it was anticipating a “significant delay” in developing a functioning model for storage participation.

During an April 11 Market Subcommittee meeting, Vannoy said MISO staff have been discussing the deficiency letters with other RTOs. He said MISO is limited by what its legacy market platform can handle as it’s gradually swapped out for a new cloud-based market platform. MISO Senior IT Director Curtis Reister said the RTO is targeting a complete replacement of the platform by 2024, and rolling out a new market user interface — the site market participants use to submit bids and offers — in mid-2021. (See MISO Seeking Multiple Vendors for Market Platform Redesign.)

The Energy Storage Task Force meanwhile is set to sunset in June. Task force Chair John Fernandes said that through next month, the group will create a spreadsheet of storage issues that other stakeholder groups can concentrate on, focusing heavily on how the RTO will integrate hybrid resources that contain storage assets.

April 21, 2019February 19, 2025

FERC Open Meeting Briefs: April 18, 2019

FERC Chairman Neil Chatterjee on Thursday named veteran commission attorney Maria Farinella as chief of staff to replace Anthony Pugliese.

FERC attorney Maria Farinella receives applause after being announced as the commission’s chief of staff. | FERC

“Maria’s longstanding career as an energy attorney, both at FERC for the past decade and in private practice, makes her uniquely qualified to fulfill this key role,” Chatterjee said in a press release.

Farinella worked as a senior attorney in the Office of the General Counsel’s Energy Markets Division from 2009 to 2011, and as a senior legal adviser in the general counsel’s front office from 2011 to 2019. She was a legal adviser to Chairman Joseph T. Kelliher from 2007 to 2009. She is a graduate of Smith College and American University’s Washington College of Law.

Pugliese, who abruptly left the commission March 15, had served as chief of staff since August 2017, before the arrival of Kevin McIntyre as chair in December of that year. He stirred controversy last July for remarks he made at a conference of the American Nuclear Society and on the “Breitbart Radio Show,” in which he praised President Trump and criticized Democratic governors for blocking gas pipelines.

Chatterjee last month denied any conflict with Pugliese but declined to say why he had left. (See Chatterjee Tight-lipped on Pugliese Departure.)

Chatterjee: No Comment on NEPOOL Rules

At his regular press conference after Thursday’s monthly meeting, Chatterjee declined to comment on whether he agreed with Commissioner Richard Glick’s criticism of the New England Power Pool’s policy of excluding the public and press from stakeholder meetings.

On April 10, the commission voted 3-0 to dismiss RTO Insider’s complaint under Federal Power Act Section 206 asking it to force NEPOOL to open its meetings or to strip it of its role as the stakeholder body for ISO-NE.

Chatterjee joined Glick and Commissioner Bernard McNamee in concluding FERC lacked jurisdiction to force such a rule change (EL18-196). Glick filed a concurrence, saying that while he agreed with his colleagues on the jurisdictional issue, NEPOOL’s meeting policies are “misguided” and should be changed. (See FERC Rejects RTO Insider Bid to Open NEPOOL.)

New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.

Chatterjee declined Thursday to say whether he shared Glick’s view that NEPOOL’s meetings should be open. “I voted for the order. I think it speaks for itself,” he said, declining to elaborate.

LaFleur: Not Leaving Yet

Lame-duck Commissioner Cheryl LaFleur did not vote on the April 10 NEPOOL order or on an April 16 order regarding ISO-NE’s energy efficiency rules. (See FERC: ISO-NE Won’t Change EE Rules Without Stakeholder Talks.)

With the June 30 expiration of her term approaching, lame-duck Commissioner Cheryl LaFleur said she’s not leaving just yet. | © RTO Insider

The recusals led to speculation that LaFleur — who announced Jan. 31 that she would not be appointed to a third term — has begun to search for her next job. Although her term ends June 30, she could serve the remainder of this year if no replacement is confirmed.

ClearView Energy Partners said such recusals are “common when a sitting commissioner is interviewing with an entity that may be involved in proceedings before the commission.”

LaFleur, a New Englander, came to FERC after serving as executive vice president and acting CEO of National Grid USA.

LaFleur — who previously declined to give the reason for her recusal on the NEPOOL order — did not offer any clues to her plans at Thursday’s meeting, where she introduced her son and husband in the audience.

“For the members of our friendly press corps, the fact that I have my family here does not mean this is my last meeting,” she said, turning to reporters. “I will let you know when it’s my last meeting. I promise.”

PJM MOPR Issue ‘Really Complicated’

Chatterjee said the commission hasn’t yet acted on PJM’s proposed changes to its capacity market because of the complexity of the issues.

PJM, which normally holds its annual capacity auction in May, delayed it until August in the hopes that would give the commission time to rule on its proposed changes to its minimum offer price rule (MOPR). In June 2018, the commission ruled the RTO’s existing MOPR was unjust and unreasonable because it didn’t address price suppression from state subsidies for renewable and nuclear power. (See PJM to Hold Capacity Auction in August.)

Chatterjee was asked at his press conference whether FERC’s failure to act on the proposal suggested a 2-2 split among the current commissioners and the need to fill its fifth seat.

The chairman said although he was prohibited from discussing internal deliberations, he could comment “at the macro level.”

“When it comes to wholesale power markets, these aren’t things that break down on ideological or political lines,” he said. “It’s just something my colleagues and I and staff are working towards. It is not something that we’re gridlocked because of some kind of political difference. It’s really, really, really complicated.”

— Rich Heidorn Jr.

April 21, 2019

Chatterjee Denies Lobbying Against FERC Nominee

By Rich Heidorn Jr.

WASHINGTON — FERC Chairman Neil Chatterjee on Thursday denied a report that he lobbied to block the nomination of Republican David Hill to the commission.

Citing interviews with a dozen industry and political sources who requested anonymity, E&E News reported April 12 that Chatterjee made calls to energy companies and Republican allies to block Hill from replacing him as chairman. E&E quoted Hill, an energy attorney who served in the George W. Bush administration, as confirming that the White House told him he would be appointed FERC chair.

FERC Chairman Neil Chatterjee speaks to the press following the April 18 open meeting. | © *RTO Insider*

Chatterjee did not respond to E&E’s requests for comment before publication of the article. But in his regular news conference following the commission’s monthly open meeting Thursday, Chatterjee attempted to discredit the report.

Hill was the Department of Energy’s general counsel from 2005 until 2009 and NRG Energy’s general counsel between 2012 and 2018.

E&E said Hill’s nomination was all but official until lobbying efforts by Chatterjee, Energy Secretary Rick Perry and the coal industry caused the White House to abandon him. Hill had publicly criticized DOE’s bids to provide subsidies for struggling coal and nuclear generators.

Chatterjee gave his rebuttal Thursday when E&E reporter Rod Kukro, one of the authors of the article, asked him when he became aware that the White House intended to replace him with Hill.

Chatterjee challenged Kukro’s premise, saying two other reporters had pursued the story and published nothing because they were unable to verify it.

“I know you cited 12 sources that you talked to. I know for a fact that at least two of those sources pushed back aggressively on the story line, yet their statements weren’t reflected anywhere in the article. I also know that at least a couple of those sources directed you towards the actual people that were involved in this process and knew the details of it, and you ran the story without contacting the folks that were actually in the room and knew the circumstances of the story. You had no named sources. No corroboration.”

Chatterjee challenged E&E’s account that the White House and Hill began preliminary discussions in September 2018 about taking over for ailing Chairman Kevin McIntyre.

McIntyre, who was visibly unwell in his last commission meeting in July, relinquished the chairmanship to Chatterjee Oct. 24 after revealing that he had suffered a “serious setback” in his cancer fight. He died Jan. 2.

“David Hill is a good man, and I find it almost impossible to believe that David Hill would have been negotiating in September to be chairman of the commission while Kevin McIntyre was still alive and serving,” Chatterjee said.

“Well [Hill] was the source, and he was named in the story,” Kukro shot back. “Are you saying he’s lying that [National Economic Council Director] Larry Kudlow told him he was going to be chairman?”

“I can’t speak for conversations you had with David Hill,” Chatterjee responded. “I don’t know that that’s ever been corroborated by anybody.”

RTO Insider asked the chairman why he did not respond prior to the article’s publication.

“The story was so baseless that I didn’t think it merited a response,” Chatterjee said.

“So, you’re saying you had no conversations with anyone regarding Hill’s candidacy?” he was asked.

“No reporter has been able to identify a single individual that I contacted or what I talked about,” Chatterjee said.

“That doesn’t sound like a denial,” the reporter said.

“That’s a denial,” Chatterjee said.

April 21, 2019

MISO PAC Contemplates SATA Shakeup

By Amanda Durish Cook

The MISO Planning Advisory Committee will vote by email on a DTE Energy proposal to broaden the scope of the RTO’s effort to create new rules allowing storage projects to solve transmission needs.

DTE’s motion proposes that stakeholders and the PAC recommend that MISO include a path for non-transmission owners as well as TOs to own and operate storage-as-transmission assets (SATA). The motion will appear on an email ballot April 22-26.

MISO’s Carmel, Ind., control room | *MISO*

In developing the rules, MISO determined that only registered TOs should be eligible to own SATA in order to avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.

DTE says non-TO SATA should be permitted to bypass the interconnection queue and connect to MISO’s transmission system via newly conceived storage interconnection agreements.

To be eligible to secure a storage interconnection agreement, DTE proposes that resources must resolve a transmission-reliability issue identified in the annual Transmission Expansion Plan (MTEP) process, “satisfy the same performance criteria” as other SATA in the MTEP analyses, and “be operated strictly at the direction of MISO’s transmission-reliability function to address such issues.”

DTE’s Nick Griffin said the motion will close an “equity gap” in MISO’s first SATA filing with FERC. Absent DTE’s provision, he said, the SATA ruleset would create preferential treatment for TOs and “create barriers for entry for storage.”

Griffin said the motion does not yet address cost recovery.

In a complicated interpretation of MISO’s stakeholder process, the Steering Committee last month directed the PAC to revisit the possibility of non-TOs owning SATA in response to DTE’s request. (See MISO Planning Committee to Reconsider Non-TO Storage as Tx.) Some stakeholders were concerned that PAC leadership prematurely suppressed conversation on DTE’s proposals by not holding a vote to gauge whether stakeholders thought the idea warranted further debate.

MISO has said stakeholders agreed before drafting the SATA rules that they would neither address non-transmission alternatives (NTAs) nor create an entirely new cost allocation as a part of the SATA policy development.

But MISO Director of Planning Jeff Webb said the RTO’s existing process to consider NTAs in transmission planning may cover what DTE seeks.

“As a general matter, we do not require non-transmission alternatives to complete the generator interconnection process unless the asset is a generation facility seeking access to the market,” Webb explained.

Not that Simple, Stakeholders Say

Entergy’s Yarrow Etheredge pointed out there is no structure in place for MISO to assume functional control over assets other than transmission. She said DTE’s proposal wasn’t as simple as minor Business Practices Manual or Tariff changes.

Great River Energy’s Jared Alholinna agreed that DTE’s motion would create a “gray area” around what is and isn’t transmission and could ultimately undermine the FERC definition of transmission.

“This is being characterized as quite narrow, but it really balloons out,” American Transmission Co.’s Bob McKee said.

Griffin said non-TO SATA could have similar treatment to a generator under a system support resource agreement, in which MISO dictates that assets be available for dispatch.

“We think with a few minor BPM and Tariff changes, we could achieve analogous treatment,” Griffin said.

But Etheredge said an SSR-style treatment still lacks the automatic controls that MISO has established with its TOs.

Xcel Energy’s Drew Siebenaler said the motion could create the discriminatory treatment DTE claims to combat because the proposal names a special interconnection path meant only for storage devices.

“I would view that as a discriminatory filing,” Siebenaler said.

DTE coming forward without a defined cost allocation was problematic as well, added Xcel’s Carolyn Wetterlin. She said she had never heard of a MISO project gaining approval without first having an established cost allocation method.

MISO’s Environmental sector took the discussion as an opportunity to call out the SATA proposal as too limiting in the first place. Clean Grid Alliance’s Natalie McIntire said the current plan ignores the full spectrum of storage capabilities. She said MISO has rushed the first SATA proposal and “unreasonably” limited the scope of a possibly “precedent-setting” ruleset.

Webb acknowledged that MISO’s “first stage” SATA rules are intentionally narrow so that storage doesn’t have to scale the approximate three-year interconnection queue before being eligible to solve a transmission need.

“We wanted to clear that barrier first,” he said.

Webb promised MISO stakeholders future Tariff proposals that would allow expanded and multifaceted storage use in the footprint.

The PAC will hold a May 15 conference call to discuss refinement of the SATA filing and announce the ballot results on DTE’s motion.

MISO hopes to file the new rules with FERC in June or July. One SATA project is currently moving through MTEP 19 in the hopes that rules are in place by the end of the year.

April 21, 2019

April 24 TAC Canceled; OCN Workshop Set

The ERCOT Technical Advisory Committee’s leadership has canceled the committee’s April 24 meeting because of a “limited number of items to be considered” and does not plan to hold an email vote.

TAC Vice Chair Diana Coleman and Chair Bob Helton | © *RTO Insider*

Instead, ERCOT will use the date to hold a workshop on outage activity related to its operating condition notice (OCN) in late February. The OCN set in motion events that resulted in market complaints about the grid operator’s communication practices and transparency. (See ERCOT Generators Upset over Early March Weather Event.)

The workshop will begin at 9:30 a.m. The TAC’s next regularly scheduled meeting is May 22.

— Tom Kleckner