Page 1179 – RTO Insider

May 1, 2018

ISO-NE Planning Advisory Committee Briefs: April 26, 2018

MILFORD, Mass. — ISO-NE’s 10-year Capacity, Energy, Loads and Transmission (CELT) forecast predicts 2026 annual net load will be about 3.7% lower than estimated in the 2017 forecast, Load Forecasting Manager Jon Black told the Planning Advisory Committee (PAC) on Thursday.

Net load forecasts, developed by subtracting energy efficiency and behind-the-meter solar from gross forecasts, are intended to be representative of energy and loads observed in New England in real-time.

The final 2018 CELT forecast update was changed slightly from the draft version presented at the March 15 PAC.

The behind-the-meter solar photovoltaic (PV) forecast is approximately 0.4% lower in 2026, slightly higher than the draft 2018 forecast, while the energy efficiency (EE) summer forecast is approximately 12.9% higher in 2026, down from the draft 2018 EE forecast. (See ISO-NE Planning Advisory Committee Briefs: March 15, 2018.)

ISO-NE load forecasting — 2018 CELT Energy Forecast | *ISO-NE*

Compared to last year’s forecast for 2026, the 2018 CELT gross load forecasts show annual energy approximately 0.3% higher, gross summer 50/50 load about 2.7% lower and gross summer 90/10 load about 2.8% lower.

Net load forecasts, updated since March 15, show the net summer 50/50 forecast approximately 5.4% lower in 2026, with the net summer 90/10 forecast approximately 5.3% lower.

All forecast data will be posted on the RTO’s load forecast web s ite by May 1.

Winter Review Highlights Fuel Security Issues

The RTO’s review of 2017/18 Winter operations showed stress on the grid from a severe cold snap around the turn of the year and from an exceptional chain of four nor’easters in March.

System Planner Mark Babula said the RTO avoided initiating emergency capacity deficiency procedures but did declare “Master/Local Control Center 2” procedures in early January and for each March storm, making them “hands-off” periods for regular generator maintenance or unnecessary outages.

As natural gas prices spiked, generators that could turn to oil did so, rapidly depleting the entire season’s oil supply.

Sea and river ice hindered ship and barge deliveries to fuel oil terminals in New Hampshire and Maine and on the Hudson River, so the RTO “monitored ice with the U.S. Coast Guard, trying to get those ice-breakers up the rivers to keep the natural gas supply lines open,” said Babula.

ISO-NE load forecasting CELT — Winter natural gas (left in thousand MCF) versus oil consumption (in barrels) and net generation (thousand MWh) | *ISO-NE*

The Winter 2017/18 Reliability Program started Dec. 1, 2017, and 86 generator units participated in the oil program for a total of 3.9 million barrels of oil. Approximately 2.9 million barrels of the total inventory on Dec. 1 are eligible for compensation according to winter reliability program rules, with total oil program cost exposure projected to be $29.62 million (at $10.33/barrel).

The reliability liquified natural gas (LNG) program had no participants this winter, while three assets providing 7.5 MW of interruption capability participated in the demand response (DR) program, with the total program cost exposure projected to be around $23,000.

Babula said daily communication with suppliers and pipeline operators is key to ensuring adequate fuel supplies, whether of oil, natural gas or LNG. (See ISO-NE Sees Growing Fuel Security Risks, RTO R esilience Filings Seek Time, More Gas Coordination.)

Natural Gas Rules Home Heating in Northeast

New England and neighboring states have seen household natural gas customers grow by 1 million since 2010, with gas increasingly fueling energy generation as well, Tom Kiley, president of the Northeast Gas Association, told the PAC.

Kiley’s regional gas market update highlighted recent market growth, pipeline development and lessons learned from the winter cold snap from around the holidays.

The United States set a new gas sendout record of 150 Bcf on Jan. 1, 2018, while most local gas distribution companies in the Northeast set multiple sendout records in the first week of the year. New England natural gas utilities set three new sendout records that week — with a new all-time peak near 4.4 Bcf set on Jan. 6.

LNG played a key role in supplying generators during the cold snap, with the Distrigas terminal importing six cargoes totaling about 16 Bcf. Canaport LNG provided input into the Maritimes and Northeast Pipeline during the same period, with three cargoes in January, totaling about 9 Bcf.

Kiley cited a FERC report issued Apr. 19 that said “natural gas prices in New York City, New England and the Mid-Atlantic all set all-time record highs, with next-day trades reaching as high as $175/MMBtu in New York City on January 4. Although Operational Flow Orders limited shippers’ flexibility to exceed their contractual obligations to meet varying natural gas demand, there were no pipeline outages or firm service curtailments.”

The Natural Gas Act’s (NGA) gas supply task force has good communication protocols in place between gas pipeline control rooms and the power grids, Kiley said.

While gas utility demand continues to rise, New England has added nearly half a billion cubic feet per day of new pipeline capacity since November 2016, he said, with multiple projects planned to go into service through 2019. The Northeast region currently produces about 27 Bcf/d, with further growth expected; Pennsylvania is the second largest gas producing state in the U.S.

Updating Needs Assessments to Reflect Latest Forecasts

The RTO presented an update on the transmission Needs Assessments for Maine (ME), New Hampshire (NH), Southwest Connecticut (SWCT), Western and Central Massachusetts (WCMA) and Southeastern Massachusetts and Rhode Island (SEMA/RI).

Brent Oberlin, director of transmission planning, said the assessments attempt to balance the benefits of incorporating the latest load forecast against adding delays to each of the studies from including the data. A preliminary review shows the new forecasts could potentially eliminate some system needs.

The RTO has already posted a draft scope of work reports and intermediate study files for SEMA/RI and WCMA and will publish the SWCT scope of work in early May, with a finalized Needs Assessment due to be complete in September.

Maine and New Hampshire updated scope of work reports will also be published in early May, with final Needs Assessment reports slated to be delivered in October.

Cost Recovery in Flood Hazard Areas

Michael Drzewianowski, an ISO-NE lead engineer, outlined the RTO’s new recommendations for regional cost recovery for transmission resources built in flood hazard areas. Large storms and other weather-related events in the past several years have changed the RTO’s thought process on designing for flood hazard areas, he said.

Drzewianowski’s report said the relevant Tariff clauses are defined on the Federal Emergency Management Agency (FEMA) Flood Insurance Rate Map (FIRM).

In inland locations (defined as areas that have no chance for “wave action”), the RTO is now recommending cost recovery for infrastructure constructed to withstand the higher of the 100-year flood level plus two feet or the 500-year flood level.

For coastal locations, the RTO recommends adding another foot to the inland figure to account for sea level rise. For existing equipment that needs to be raised, the recommendation is to the bottom of sensitive equipment.

The RTO’s previous recommendation was to construct to the 100-year flood level, plus an additional one foot, developed after review of national information available, including recommendations from FEMA and the American Society of Civil Engineers (ASCE).

Comments on the plan can be submitted to PACMatters@iso-ne.com by May 10, ahead of the Reliability Committee review process anticipated to begin in June.

Eastern Conn. 2027 Needs Assessment Update

Jon Breard, associate engineer for transmission planning, presented an update on the Eastern Connecticut Needs Assessment results showing non-transmission options are not adequate to relieve the area’s reliability criteria violations.

All updated needs are time-sensitive and based on the location of the reliability criteria violations; the RTO will work with participating transmission owners as needed. The final Needs Assessment report will be posted by May 31, and the PAC will be presented solution alternatives in the third quarter.

In addition, Kannan Sreenivasachar, principal engineer for transmission planning, presented an update on preferred solutions for SEMA/RI.

FCA 13 Zonal Boundary Determinations

Al McBride, director of transmission strategy and services, presented a review of interface transfer capabilities for a proposed capacity zone construct for the 13th Forward Capacity Auction (FCA-13, Capacity Commitment Period 2022/23).

The review showed no change to the interface transfer capabilities as a result of the new certifications for FCA-13.

The electrical limit of the New Brunswick-New England (NB-NE) Tie is 1,000 MW but drops to 700 MW when adjusted for the ability to deliver capacity to the greater New England control area.

The Hydro-Quebec Phase II interconnection is a DC tie with equipment ratings of 2,000 MW. Due to the need to protect for the loss of this line at full import level in the PJM and NY control areas’ systems, the ISO-NE has assumed its transfer capability is 1,400 MW for capacity and reliability calculation purposes.

New York interface limits were modeled without the Cross Sound Cable and with the Northport Norwalk Cable at 0 MW flow and show that simultaneously importing into New England and SWCT or CT can lower the NY-NE capability by around 200 MW.

The Maine Load Zone will be evaluated as a potential export-constrained capacity zone, and a significant backlog of requests exists in the interconnection queue in Maine. FERC’s Nov. 1, 2017, approval of the RTO’s clustering proposal will enable the queue to move forward in Maine, which will allow more resources there to qualify for the FCA.

Northern New England will be evaluated as a potential export-constrained capacity zone that could be modeled either with or without Maine. The zone’s potential boundaries will be tested and presented to the Power Supply Planning Committee in May.

Transmission Planning Technical Guide Update

ISO-NE is continuing to revise the Transmission Planning Technical Guide, which it reorganized last year into a new format. Revision 2 was posted on the ISO website on Nov. 14, 2017.

Steve Judd, lead engineer for system planning, presented the technical guide report and said staff is now updating the following sections for consistency with the RTO’s style guide and publication template:

All Sections – Changes to terminology with Price Responsive Demand (PRD)
Section 2.2 – Clarification to system load level definitions and what is tested
Section 2.8 – Simplified generic interface transfer levels section and moved detailed methodology to Section 4
Section 2.11 (New) – Moved power flow solution settings to assumptions from methodology subsections
Section 3.1.2.5 – Added maximum bus voltage limits for nuclear units to Table 3-2
Section 4 – Split transmission Needs Assessments and Solutions Studies into a separate subsection 4.1 and Proposed Plan Application Testing into subsection 4.2 to allow for clarification in differences between study methodologies
Section 4.1 – Detailed review to reflect current process for transmission Needs Assessments and Solutions Studies
Section 4.2 – Moved previous description of stressed transfer levels from Section 2.8 to new subsection of PPA studies

Proposed revisions to the Transmission Planning Technical Guide are to be posted to the PAC website, and stakeholders can provide comments by May 13 to PACMatters@iso-ne.com. Further detailed review of the guide will continue, with future revisions planned for 2018.

— Michael Kuser

April 29, 2018

Calif. Legislation Shields Utilities from Wildfire Costs

By Jason Fordney

A bill allowing utilities to recover wildfire costs if they conform to state-regulated safety plans moved through the California legislature last week, but it faces heavy opposition from some who say it lets utilities off the hook for their contribution to wildfires.

Cost Recovery PG&E utilities Wildfire Costs California TURN — Dodd | *U.S. Army Corp. of Engineers*

The relevant language in SB 1088, introduced by Sen. William Dodd (D), requires each electrical and gas utility to submit a biennial safety, reliability and resiliency plan to the California Public Utilities Commission (CPUC), beginning Jan. 15, 2019. It would require the CPUC to review the plans in a single consolidated proceeding and verify the plans comply with all rules, regulations and standards. The initial plan must be limited to addressing fire risks, with subsequent plans addressing risks associated with routine operation and all major events.

If utilities are found to be in “substantial compliance” with the plan, “the utility’s performance, operations, management and investments addressed in the plan must be deemed reasonable and prudent for all purposes,” a bill ana l ysis said. The legislation would not protect utilities from civil lawsuits, which represent a separate area of liability for the fires.

The cost recovery issue is front and center for California investor-owned utilities, regulators and ratepayer interests as utilities try to recover costs of the devastating disasters. The CPUC last December denied San Diego Gas and Electric’s (SDG&E) request to recover $379 million from ratepayers for 2007 wildfires. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) Commissioners at the time said the decision turned on a specific case of whether SDG&E had reasonably maintained its facilities, not on the cost recovery issue.

California law requires that any costs ratepayers incur on behalf of a utility must be just and reasonable, but the CPUC found SDG&E’s management and control of its facilities prior to the 2007 Witch, Guejito and Rice Wildfires were unreasonable, mentioning poor vegetation management and other activities.

Seeing the writing on the wall for future cost recovery of last year’s fires, the state’s two other large investor-owned utilities, Pacific Gas and Electric (PG&E) and Southern California Edison joined SDG&E in requesting a rehearing of the CPUC decision and launched a fierce response on legislative, regulatory and legal fronts. (See Sempra Joins ‘Three-Pronge d ’ Wildfire Front; P G &E Vows Fight over Wildfire Cost Recovery.)

PG&E and other investor-owned utilities are being investigated for causing the 2017 fires, but utilities say they cannot be held solely responsible for the increasingly high-risk fire conditions in California, which most observers attribute to climate change. Sempra Energy CEO Debra Reed told shareholders in February she expected legislative action on the issue. And state lawmakers such as Assembly Utilities and Energy Committee Vice Chair Jim Patterson (R) are sounding the alarm about IOU bankruptcies after utilities lobbied in Sacramento earlier this year for a legislative fix. (See Wildfire Costs Ignite Worry at C PUC, Legislature.)

In his author’s comments on SB 1088, Dodd said that climate change will cause more frequent and intense storms, floods, mudslides and wildfires, and eight of the 20 most destructive wildfires in state history have happened since 2015, with five occurring in 2017. “Many scientists predict the 2017 fire season is not an anomaly, and similar wildfires are likely to continue into the future,” he said.

Opponents of the bill include California Large Energy Consumers Association, California League of Conservation Voters, Consumer Attorneys of California, Consumer Federation of California, Environment California, Environmental Defense Fund, Silicon Valley Leadership Group and The Utility Reform Network (TURN).

TURN said the bill “would enrich utility shareholders at the expense of vulnerable households who would be forced to pay large rate increases for bloated programs of unproven benefit to safety risk reduction. TURN fully recognizes the increased risk of wildfires poses new challenges and financial threats to both ratepayers and utilities. Unfortunately, SB 1088 is fundamentally flawed and offers no such constructive solutions.”

The Senate Governmental Organization Committee cleared the bill on April 24 on an 11-1 vote, and it now goes to the Senate Appropriations Committee. The Senate Energy, Utilities and Communications Committee passed the measure on April 17 with a 9-1 vote.

April 29, 2018

Stakeholders Oppose PJM PFR Mandate for Existing Units

By Rory D. Sweeney

VALLEY FORGE, Pa. — Although FERC has required almost all new generating units to provide primary frequency response, PJM stakeholders are strongly opposing any move by the RTO to require existing units to follow suit.

That disapproval became clear last week at a meeting of the Primary Frequency Response Senior Task Force (PFRSTF), during which staff reviewed the resu l ts of a nonbinding poll that revealed stakeholder support for the only PFR proposal that does not impose a mandate on units that don’t increase their output.

PJM FERC primary frequency response PFR — Stakeholders at PJM’s Primary Frequency Response Senior Task Force meeting listen to a presentation from PJM staff on why PFR is necessary during system restoration. | © *RTO Insider*

The proposal from American Electric Power (AEP) would apply PFR capability requirements on new units and existing units that modify their interconnection agreement to increase their output. Units that already provide PFR would be “encouraged to continue to do so” and can seek compensation at FERC. Units would annually confirm whether they will continue to provide the service, and PJM and transmission owners would revise system restoration plans accordingly.

A 10% dip in the system-wide aggregate PFR would trigger reconvening the task force “to analyze and suggest, if necessary, possible solutions.”

Stakeholders strongly opposed all three other proposals, two of which came from PJM and the third from the Independent Market Monitor. They all applied PFR capability on existing units but differed on minimum size or use thresholds and cost-recovery mechanisms.

“Part of the hang up we have with PJM’s initial proposal is the universal requirement for all. Where we get concerned is … if there’s compensation involved, we’ve got to foot the bill here,” explained Dave Mabry, who represents the PJM Industrial Customer Coalition (ICC). “I think the AEP proposal gets us a little bit closer to looking at: Does it make sense for a unit to have it?”

The PJM ICC believes existing units already have an avenue to be compensated for PFR costs through the capacity market, Mabry said, and would support provisions that develop a cost-benefit analysis for whether units should make those investments.

Carl Johnson, who represents the PJM Public Power Coalition, said he was “a little confused” by the lack of support for PJM’s “option B” proposal, which would require PFR only for units involved in system restoration plans and would offer them a one-time capital recovery method.

“On behalf of my members who both represent load but also self-serve load and have a lot of generation … we have concerns about anything that’s going to add costs for a service that we think maybe you should be providing anyway, but at the same time we have concerns about being audited and reported for failure to provide it, [including] the possibilities of selective enforcement. So, we’re of two minds on this,” he said. “I think we still need to work out a lot of issues with regard to what a broad requirement for PFR would be.”

GT Power Group’s David Pratzon and Tom Hyzinski voiced concerns about “retroactive ratemaking” and unfair demands on generators.

“If you take a look at those existing resources, a lot of them are resources that are financially challenged in the market right now. So, on one hand, to say they’re absolutely critical to the integrity of the system but then to turn a blind eye to the fact that they’re challenged in the market and to not make any attempt to compensate the vast majority of them for this critical value that they bring to the table” is unfair, Hyzinski said.

Package Criticism

PJM’s Glen Boyle said staff heard feedback that the proposals weren’t aligned with FERC Order 842, which some stakeholders believe specifically exempts existing resources from PFR requirements — the opposite of PJM’s interpretation. Stakeholders also said that exempting nuclear units — in harmony with the exemption of any new nuclear units in FERC’s order — was discriminatory.

The requirement would be an “unfunded mandate” and wouldn’t support capital cost recovery, stakeholders said. Calpine’s David “Scarp” Scarpignato agreed.

“If you have to go through a complex, very expensive, tedious process in order to get paid back for something, and there’s no kind of internal rate of return, I think some people might view those as unfunded,” he said.

Finally, RTO staff heard they did not satisfactorily make the case for the requirement, a criticism they attempted to address with presentations on a recent repo r t from the Lawrence Berkeley National Laboratory and the i m portance of PFR in system restoration. PJM’s presentation detailed the many uses of PFR during such events, while the laboratory study emphasized the importance of having as many generators as possible provide the service.

Pratzon noted the possibility that some units may find it’s not worth the investment to provide PFR if they’re required to do so, weighed against a related concern that, without such a mandate, those who continue to provide PFR will be unfairly overcompensating for those who don’t.

“There are problems going down either direction,” he said.

Next Steps

Johnson noted that FERC is awaiting a report from NERC in July on the availability of existing facilities to provide PFR and suggested that discussions should continue but hinge on the report’s publication.

Scarp said he plans to offer an alternative package based on the feedback from the meeting.

PJM staff decided against moving for a binding vote until the group comes to a consensus or FERC responds to a request for rehearing of Order 842. The task force’s next meeting is May 23.

April 29, 2018

MISO Storage Group Begins Order 845 Consideration

By Amanda Durish Cook

CARMEL, Ind. — MISO’s Energy Storage Task Force will now add to its to-do list storage-related aspects of FERC’s recent rulemaking on generator interconnection procedures (Order 845).

The group said it will begin examining how MISO might need to alter provisions for energy storage interconnection to comply with the April 19 order, which prescribes more transparency and timeliness for RTOs’ large interconnection agreements.

MISO Energy Storage — AES battery storage | *AES*

The order is expected to remove even more barriers to storage interconnection, according to MISO stakeholders. It explicitly revises the definition of a generating facility to include storage, permits interconnection customers to apply for interconnection service lower than the capacity of their generating facility and requires transmission providers to provide interim interconnection agreements for limited operation of a generating facility prior to completion of the full interconnection process, among other rules. (See FERC Order Seeks to Reduce Time, Uncertainty o n Interconnections.)

“There are plenty of decisions in that order that are going to be impactful to storage,” Energy Storage Task Force Chair John Fernandes said during an April 26 meeting.

Currently, there’s just under 500 MW of energy storage in various stages of MISO’s interconnection queue.

The task force began discussing the order after an April 25 conference call in which MISO’s Steering Committee agreed to allow the group to explicitly consider both Order 841 and Order 845 when identifying discussion topics to recommend to other stakeholder groups. (See Committee Ponders Expanded Role for MISO Storage Group.)

MISO executives at the meeting said they are still reviewing Order 845 to identify how the RTO will be required to alter the interconnection process.

Executive Director of Resource Planning Patrick Brown said FERC’s final order did not prescribe how to best model electric storage for the interconnection process, instead leaving storage modeling to be worked out between transmission providers and stakeholders.

Brown also noted the final order denied a request that energy storage be modeled as transmission assets in the interconnection process but said MISO is still determining whether the denial precludes storage from being treated as transmission.

“We’re going to have to talk with our legal team about this,” Brown said.

However, American Transmission Co.’s Bob McKee said he found nothing in the order preventing storage from being modeled as transmission.

“FERC is certainly still open to storage as a transmission asset,” McKee said.

“Storage as transmission, that’s kind of the next big thing in our industry to get FERC to make some rules around,” Fernandes said. “I still think FERC is giving the green light to go ahead and do this; they’re just not providing explicit rules yet.”

Brown also said MISO may have to make a few tweaks to allow for interconnection service with surplus capacity, although the RTO’s process for net-zero interconnection service requests could probably cover most of the directive.

“We believe that revisions to our net-zero provisions take care of that,” Brown said, while conceding that some of MISO’s net-zero rules may be too restrictive to meet FERC’s compliance.

However, Wind on the Wires’ Rhonda Peters said it’s too “cumbersome” for projects to line up for net-zero interconnection service because of the requirement that customers must already be in the queue and provide milestone payments before they’re able to respond to a request for proposal for net-zero service.

But Fernandes cautioned that while the Energy Storage Task Force could debate the interconnection queue as far as storage eligibility, queue improvements are the domain of MISO’s Interconnection Process Task Force (IPTF).

“This task force is not assigned queue reform,” Fernandes said.

Brown agreed a majority of work on Order 845 will be done at the IPTF. Fernandes said he would try to plan a joint conference call of the IPTF and the Energy Storage Task Force prior to mid-May to discuss how FERC’s order might make MISO’s queue process more storage-friendly.

Brown said some work to comply with Order 845 will come down to finding language already included in MISO’s business practice manuals and copying that language into the Tariff.

Some stakeholders asked if MISO would consider requesting an extension with FERC on the July compliance filing deadline for Order 845. Brown said MISO is judicious when requesting extensions, making sure it requests them only when necessary.

“It’s a fairly short lead time,” Brown conceded.

Process Holdup?

Stakeholders in attendance worried the July deadline would not provide enough time for the task force to identify Order 841/845 storage issues, then turn them over to the Steering Committee, which must then assign discussion to other stakeholder groups.

Customized Energy Solutions’ Ginger Hodge said she was becoming “increasingly concerned” that the formal process of identifying issues and sending them to the Steering Committee was creating a roadblock to getting proposals written and vetted in other stakeholder groups.

Hodge said she didn’t want the Steering Committee to become a place where “good ideas are quietly strangled.”

April 29, 2018

Dominion: ‘No Flexibility’ on SCANA Bid

By Rory D. Sweeney

South Carolina legislators continue to maneuver as if there is some room to negotiate the terms of a deal to sell SCANA to Dominion, but Dominion CEO Thomas Farrell emphatically rejected that presumption on a Friday conference call to discuss the company’s first-quarter earnings.

“No flexibility,” Farrell said. “We’ve made our offer, and it’s going through the political process now.”

The state legislature must approve the nearly $8 billion takeover bid, which includes controversial provisions for customers to continue paying on a failed nuclear plant in the state. He noted that the legislature’s session ends on May 11.

Dominion reported first-quarter operating earnings of $741 million ($1.14/share), which beat analysts’ estimates by $0.08/share and improved on earnings of $611 million ($0.97/share), for the same period in 2017. Revenue of $3.47 billion improved 2.7% from the same period last year but missed expectations by $50 million.

Dominion Energy SCANA big earnings Q1 2018 — Dominion announced its first-quarter earnings on Friday. | *Dominion*

The company’s unadjusted earnings were $503 million ($0.77/share), compared with $632 million ($1.01/share), for the same period in 2017.

Paul Koonce, Dominion’s executive vice president and CEO of the Power Generation unit, was also upbeat about the prospects for its Millstone nuclear plant to receive subsidies through a Connecticut procurement process previously reserved for renewables. State officials will be issuing requests for proposals for renewable generation in May, he said. Bids will be open through September and approved by year end. The company plans to pursue an “at-risk” designation for the plant that will allow it to include non-price factors in its offer, including zero carbon emissions, fuel diversity and grid reliability, he said.

“They have a report … that showed what it would cost consumers if Millstone were to retire, so I think there is some recognition of the value of Millstone, so really [all those developments are] supposed to play out between now and September with bids being approved by year end,” he said.

April 29, 2018

PJM Stakeholders Clash Over “Heart” of Containment Provisions

By Rory D. Sweeney

Stakeholders last week plowed through several hours of material at a special PJM Planning Committee session on whether the RTO should include cost containment provisions in its analysis of competitive bids for new transmission, but they ended up tabling what has become the most important issue.

The wide-ranging discussion covered the results of a stakeholder p o ll and related comm e nts, PJM’s proposal temp l ates, proposed contract languag e regarding revenue requirement provisions and proposed chan g es for evaluating Order 1000 projects. However, stakeholders were unable to reach consensus on whether PJM’s criteria for selecting projects should weigh a developer’s commitment to a cap on the return on equity (ROE) it will seek during its ratemaking process at FERC. The issue received a significant amount of contentious discussion, including a consumer advocate pres e ntation on the importance of such caps, but no decision was reached.

PJM Planning Committee Cost Containment Provisions — PJM is considering a realignment of how it considers competitive transmission proposals to include cost-containment provisions. | *PJM*

Alex Stern with Public Service Electric and Gas (PSEG) said he didn’t think the idea is consistent with applicable law and called it “a complete end-around” of Section 205 of the Federal Power Act.

“I am very concerned about enforceability,” he said.

Erik Heinle of Office of the People’s Counsel for the District of Columbia, who presented on the value of ROE caps, disagreed that the voluntary proposals ran afoul of FERC’s authority.

“We are very clear that FERC is the rate-maker. They should be the rate-maker,” he said. “I don’t think this makes it some sort of coercive issue where everybody has to do it.”

LS Power attorney Mike Engleman of Washington, D.C., firm Engleman Fallon also took issue with objections to the provisions.

“We completely disagree that this is outside what PJM can look at or do. PJM isn’t setting the rates. PJM is accepting a voluntary commitment of what the developer will do in filing at FERC,” he said. “The entire purpose of Order 1000 is to get the benefits of these types of proposals to ratepayers. … Nobody’s forcing PPL or PSEG or anybody else to make a proposal they don’t want to make.”

Representatives from fellow transmission owners PPL and Duquesne Light Co. backed Stern’s position, noting legal precedents for why the provisions wouldn’t stand. However, Ruth Ann Price, who represents the Delaware Division of the Public Advocate, challenged them to provide their cases.

“At the right time, they’ll be provided,” Stern responded. “That’s what we do when we go to FERC. This is not a legal proceeding.”

“What right time? Now is the right time. We’re discussing it,” Price said.

PJM staff attempted to reach agreement that everyone favored additional transparency and move on from the topic, but LS Power’s Sharon Segner insisted that it continue to be addressed.

“The ROE discussion is at the heart of what this discussion is supposed to be about,” she said. “It is not a discussion solely about transparency.”

The issue will be addressed again at the next special session on the issue on May 11.

Segner acknowledged some very “positive developments” in the proposal templates PJM presented, particularly on aspects regarding clear disclosures of cost commitments. PJM’s templates would create clear, uniform and organized proposal submissions that would make project comparison easier. Segner, with strong support from several consumer advocates, has largely led the push for cost-containment considerations and templates, having proposed her own set in recent meetings. (See PJM Stakeholders Explore Cost Containment C o mplexities.)

Segner also noted that LS has backed away from proposing any caps on operations and maintenance costs and won’t include them in its proposal to the Markets and Reliability Committee on May 24.

“We weren’t able to find any evidence that the market was responding robustly to [operations and maintenance] caps” in other RTO/ISO competitive windows, she said. “These other issues are bigger-ticket items to the ratepayers, so why not focus discussions there?”

April 29, 2018

SPP Regional State Committee Briefs: April 23, 2018

KANSAS CITY, Mo. — SPP’s Regional State Committee (RSC) last week approved the scope for a study of cost allocation in wind-rich areas, a problem that grows along with the RTO’s wind generation.

The study will work with SPP staff to review correlations between generation and load flows on systems below 300 kV and identify potential rate approaches, selecting up to three for further review. Final recommendations are due back to the RSC in April 2019.

RSC SPP cost allocation Wind generation — Regional State Committee gathers for its April meeting. | © *RTO Insider*

“We’re not throwing the highway/byway out,” said Cost Allocation Working Group (CAWG) Chair John Krajewski, who represents the Nebraska Power Review Board, during the RSC’s Apr. 23 meeting, referring to the methodology by which SPP allocates transmission costs according to project size.

Under highway/byway, facilities of 300 kV or more are considered highway facilities and their costs allocated on a regionwide, postage stamp basis; facilities between 100 kV and 300 kV are categorized as byway facilities, with two-thirds of the costs assigned to the host zone and one-third allocated regionwide. Projects under 100 kV are allocated entirely to the host zone.

The RSC in January directed the CAWG to study the issue, following a presentation by Sunflower Electric Power on cost allocation issues in wind-rich areas. (See “Committee Takes on Cost Allocation Issues” in Mountain West, Cost Allocation Top SPP RSC Concerns.)

Sunflower’s Al Tamimi told the RSC in January transmission projects used to be based on changes in load or in designated resources in the same geographical area where the facilities are built. Today’s renewable generation is built at great distances from load centers, with many wind projects in small load zones exported elsewhere, he said.

While the local zones don’t necessarily benefit from the reduced energy costs from the additional wind, they are saddled with the byway costs in the highway/byway methodology, Tamimi said.

CAWG to Get Liaison with HITT

The RSC determined the CAWG should have a liaison on the Holistic Integrated Tariff Team (HITT), given that the group’s work overlaps with the HITT’s proposed scope. “HITT’s work touches on everything the RSC does,” said Oklahoma Corporation Commissioner Dana Murphy.

RSC SPP cost allocation — Missouri’s Scott Rupp (l-r), South Dakota’s Kristie Fiegen, Kansas’ Shari Feist Albrecht share a laugh. | © *RTO Insider*

The committee left the recommendation on a CAWG liaison to HITT Chair Tom Kent.

The RSC also voted unanimously to suspend “until further notice” the CAWG’s work on the new member cost allocation review process.

The committee had asked the group in January to draft a report on the effect of new members on existing cost allocations, a reaction to the Mountain West Transmission Group’s pending integration into SPP. Xcel Energy’s sudden departure from the group has temporarily rendered the report moot.

Committee Approves Triggers to Baseline Cost Escalation

The committee approved a Tariff change that memorializes as a business practice the current practice of using triggers to stop the annual escalation of transmission projects’ undefined baseline costs.

The Markets and Operations Policy Committee approved the Project Cost Work Group’s (PCWG) revision request on Apr. 10. PCWG-RR255 adds triggers when a designated transmission owner provides 1) SPP a letter of commercial operation; 2) notification that an upgrade is in-service; and 3) notification that an upgrade is complete.

— Tom Kleckner

April 27, 2018

EIM Body Approves Imbalance Conformance Rules

By Jason Fordney

Western Energy Imbalance Market (EIM) leaders on Tuesday approved rule changes that would allow EIM balancing areas to manually adjust load forecasts during market operations to ensure the grid can support system conditions.

The five-member EIM Governing Body at a meeting in Vancouver, Canada, approved the ISO’s proposed “Imbalance Conformance” rule changes, which allow operators to manually update the load forecast to account for changing grid conditions. Conformance is used to account for errors in the load forecast, CAISO Market Design Manager Brad Cooper told the body.

“A lot of times it is [used] because of supply deviations, whether it is generators deviating from their dispatch or renewable energy forecast error,” Cooper said during a pres e ntation. The body’s decision conforms with CAISO’s final proposal issued in mid-March, which clarifies that ISO and EIM balancing area operators can make imbalance adjustments, a clarification CAISO said it was making in the interest of transparency.

The proposal also includes alterations to the “Imbalance Conformance Limiter,” an ISO software tool designed to prevent price spikes caused by imbalance conformance adjustments. The adjustments can be imprecise, CAISO said, and the limiter keeps the market from trying to dispatch more supply than is available in a particular dispatch interval.

The Governing Body unanimously approved the tariff clarifications under its primary authority, while the Imbalance Conformance Limiter changes fall under the body’s advisory role. CAISO plans to seek approval from its Board of Governors on May 16 and then submit them to FERC.

Imbalance Conformance EIM Governing Body Western RTO — Average ISO conformance data from third quarter 2016 & 2017 | *CAISO*

The ISO said the changes were approved by all stakeholders, including Arizona Public Service, the Department of Market Monitoring, Pacific Gas and Electric, Public Generating Pool, Powerex, Southern California Edison and the Six Cities group of Southern California utilities.

CAISO initially announced the rule changes last November. Also called “load bias,” the practice has drawn comment from some market participants that note CAISO is increasingly relying on it, particularly in early morning and evening hours when solar generation comes online and offline. (See ‘Load Bias,’ Prices Rise in C A ISO Q3.)

In its proposal, the ISO noted that imbalance conformance is imprecise because it uses an aggregated value since manually updating all the supply deviations every five minutes with 100% accuracy is not possible. Using the load forecast allows the conformance adjustments to be spread evenly across the system.

Two Spots to Open

EIM Governing Body Chairman Doug Howe is due to step down from the panel at the end of June, when his first term ends. (See ‘Hesitancy’ Around Western RTO, E IM Chair Says.) Body member Carl Linvill’s term also ends on June 30, and it is not known whether he will seek re-nomination. Other members include Vice Chairs Valarie Fong and John Prescott, whose terms end in 2019, as well as Kristine Schmidt, whose term runs out in 2020. All five are original members of the panel overseeing the regional market, which is expected to incorporate CAISO’s day-ahead market functions, a major change. (See CAISO S a ys Changes Will Better Match Forecasting, Demand.)

CAISO Regional Affairs Manager Peter Colussy told the board that an eight-member nominating committee and a third-party executive search firm are looking nationwide to fill two positions on the board. In-person interviews for new EIM Governing Body candidates are set for May 10-11 in Phoenix, Ariz. Relevant expertise is needed, as well as a familiarity with the Western Interconnection, and candidates must be independent of participants in the ISO and EIM markets or those who advocate for certain positions in the ISO stakeholder process, Colussy said in a presen t ation.

The approved slate of candidates is due for approval by the Governing Body on June 20. Terms are three years, beginning July 1 of each year and ending on June 30.

In January, the EIM Governing Body rejected a proposal that would have changed how the board nominates members. (See EI M Body Tables Nominating Process Changes.) The rejected proposal would have eliminated the EIM Nominating Committee’s obligation to use an executive search firm to help fill Governing Body vacancies, instead encouraging committee members to rely more on their own contacts.

April 26, 2018

PSEG to Pay $39.4M to Settle FERC Investigation

By Rich Heidorn Jr.

Public Service Enterprise Group’s energy trading arm has agreed to pay $39.4 million to settle an investigation into violations of PJM’s energy market bidding rules over 9 years (IN18-4).

The commission’s April 25 order approving a consent agreement with PSEG Energy Resources & Trade, which markets the output of PSEG Power’s generation fleet, both praised and criticized the company’s actions in the matter.

The non-public investigation was disclosed earlier this month, when FERC’s Office of Enforcement issued a Notice of Alleged Violations charging PSEG with violating PJM’s Tariff and FERC regulations by submitting incorrect cost-based bids into PJM’s daily energy market between 2005 and 2014, when the company self-reported the violations to the commission. (See FERC Investigation Shows PSEG Violated PJM Bidding Rules.)

PSEG agreed to a civil penalty of $8 million and to pay PJM disgorgement of $26.9 million and $4.5 million interest. It also will submit annual reports to ensure future compliance. The company did not admit any wrongdoing.

In April 2014, PSEG told FERC of inaccuracies in the cost-based offers for some of its fossil units due to the inclusion of incorrect environmental adders for the prior two years. The company later provided the commission self-reports that identified incorrect cost-based offers dating to 2005.

public service enterprise group ferc pjm energy trading — Map showing location of PSEG’s fossil fuel generators | *PSEG*

Among PSEG’s “errors,” as FERC described them in its order approving the consent agreement, were: including CO₂ adders in its cost-based offers after New Jersey withdrew from the Regional Greenhouse Gas Initiative; including seasonal NOx adders in offers outside the NOx compliance season; incorrectly stating the amounts of fuel required for minimum operations at Unit 2 of its 1229-MW natural gas and kerosene Bergen Generating Station; and providing inaccurate heat rate data for some units.

The commission said it decided on the $8 million penalty considering “that PSEG self-reported the violations, cooperated fully and comprehensively throughout the investigation and has no prior history of violations. The remedy also reflects that although PSEG had a compliance program in place, it was not sufficiently robust to detect or prevent the violations.”

“In addition to responding to Enforcement’s data requests, PSEG provided extensive data, conducted extensive data analyses regarding the cost-based offers and demonstrated exemplary cooperation during the investigation,” the commission added.

But the order also noted, “PSEG’s compliance program and existing compliance procedures did not detect the errors in the cost-based components of the offers, in some cases, for multiple years.”

After the self-report, FERC said PSEG adopted new procedures requiring that daily offers be double-checked for accuracy and revised its fuel policy “to more clearly articulate the calculation of cost-based offers in accordance with PJM’s rules.”

The company also added staff to its internal audit department and hired an independent audit company to help develop additional compliance procedures.

It also made unspecified personnel changes in the trading and asset optimization groups “to impose additional accountability and focus attention on compliance issues,” FERC said.

FERC directed PJM to disburse the disgorgement and interest pro rata to affected market participants.

April 26, 2018

PJM to Consider Revisions to Demand Curve Design

By Rory D. Sweeney

When stakeholders begin considering potential changes to PJM’s demand curve next month, one of the main debates will likely center on whether combustion turbines (CTs) should remain the reference technology for estimating the cost of new entry (CONE) or be replaced by combined-cycle gas turbines (CCGTs).

PJM will take up the issue of revising its variable resource requirement (VRR) curve at its Market Implementation Committee meeting on May 2.

The review, which occurs every four years, must be completed by Aug. 31 to be filed for FERC approval by Oct. 1 and put in place for use in the 2019 Base Residual Auction (BRA). PJM has until May 15 to recommend proposed Tariff revisions, which are based on an analysis by the Brattle Group, who provided recommendations of its own, some of which differ from PJM’s.

Brattle’s Analysis

PJM hired the Brattle Group to analyze the shape of the VRR curve, the CONE for areas used in the VRR Curve and the methodology for determining the net energy and ancillary services (E&AS) revenue offset for the region PJM serves and for each zone. Brattle representatives presented their findings to stakeholders on Wednesday.

Brattle’s analysis found the Capacity Performance (CP) rules PJM implemented in 2016 would not significantly impact the curve it recommended in its 2014 report, but the net CONE has decreased “substantially” compared with the parameters that will be used this May in the 2021/22 BRA. CP flattens lower-priced offers in the supply curve but doesn’t affect the higher-priced side of the curve.

PJM demand curve — Capacity Performance rules have flattened out the lower-priced portion of the supply curve but left the higher-priced portion largely untouched. | *the Brattle Group*

“This reduces instances of very low prices and volatility but does not change results under high-priced, low-reserve-margin conditions that drive reliability performance,” the report said.

However, reducing net CONE would shift the VRR curve substantially down, such that the cost to procure PJM’s installed reserve margin (IRM) would be potentially cheaper by hundreds of dollars per MW-day.

Removing CT Base

Brattle recommended using the net CONE for CCGTs as the reference technology in conjunction with localized adjustments. PJM currently uses the net CONE for CTs, but Brattle’s analysis showed the construction cost for a CCGT has dropped as much as 40% so that it is just slightly higher than that of a CT. Net CONE for CTs also dropped in the updated calculations but not as much as net CONE for CCGTs, which Brattle estimates is between 44% and 76% lower than PJM’s 2021/22 parameters and between 25% and 63% lower than its updated CT Net CONE estimates, depending on location.

“CCs are more economic because their much higher net E&AS revenues more than offset slightly higher plant costs on a per-kW basis,” the report found.

“In reality, net CONE has declined substantially, especially for CCs, and this has major implications for the VRR curve,” Brattle continued. “… If in spite of that reality, PJM maintained a CT as the reference technology for anchoring the VRR curve, [but] continued low-priced entry of CCs would maintain average reserve margins substantially above target.”

Brattle estimated that using a CC as the reference technology, along with adjustments to compensate for triggering an alternative price cap provision, would achieve average reserve margins 1.4% above the IRM target and decrease annual average procurement costs by $212 million compared with the current CT-based curve and $138 million compared with adjusting the current curve 1% to the left to account for the expected over-procurement.

Brattle also determined that if its analysis underestimated the CONE by 20%, the average loss of load expectation (LOLE) would rise to 1.6 events every 10 years rather than its target of 1 event every 10 years.

That said, Brattle didn’t reject using the CT basis.

“We also see an argument for a CT-based curve if PJM and stakeholders are highly risk-averse about ever procuring less than the target reserve margin, since the incremental cost is modest in context,” the report said. “Even a $140-million difference in cost is less than 0.5% of PJM’s total annual wholesale costs.”

Additional Recommendations

Brattle also recommended changes to PJM’s methodology for calculating net E&AS revenues:

Update gas-pricing points for six locational deliverability areas (LDAs).
Update unit operating characteristics, such as heat rates.
Include net CP payments.
Move maintenance costs from variable operations and maintenance (O&M) costs into the fixed O&M cost component of CONE in the current cost development guidelines.
Implement forward-looking estimates of E&AS revenues rather than the current three-year historical calculations.
Calculate E&AS margins for RTO and other multi-zone LDAs based on median across zones.

PJM’s Recommendations

In a letter to stakeholders, PJM recommended updating the CT used as the reference technology to a GE Frame Model 7HA, which Brattle used in its analysis based on project development trends, improved efficiency and lower costs. Stu Bresler, PJM’s senior vice president of operations and markets, noted in the letter that NYISO, ISO-NE and the Alberta Electric System Operator all use CTs as their reference technology.

“The combustion turbine continues to provide the lowest CONE, shortest time to market, and derives the most significant portion of its revenue from the capacity market as compared to other resources. The fact that the CT receives the smallest amount of its revenue from the energy market means that its Net CONE value is the least likely to be significantly perturbed by potential changes in energy market prices,” Bresler wrote. “PJM’s certainty is provided through the use of a peaking unit as a reference resource because it minimizes the exposure to short-term energy revenue offset volatility.”

Maintaining the CT-based VRR curve with updated values for net CONE “will continue to provide long-term reliability at reasonable cost,” Bresler argued.

PJM agreed with Brattle’s CT estimates for all CONE areas except for the “rest of RTO,” which it felt was too low. PJM recommended $282/MW-day in that that zone, Cone Area 3, rather than Brattle’s recommendation of $269/MW-day.

PJM also agreed with several of Brattle’s recommendations on E&AS, including the update to unit operating characteristics and gas pricing hubs and using the median to determine net E&AS offset. It also recommended a 10% adder “to account [for] potential uncertainties in measurement” and to maintain dispatch flexibility.

But it differed on the methodology for calculating generator revenues, recommending use of the sum of the median monthly revenues from the last three calendar years rather than annual revenue averages.

“This approach provides a less volatile year-over-year determination of an annual net E&AS value than that provided by a three-year average by dampening distortion caused by a single anomalous month of unusual weather or fuel market conditions,” Bresler wrote.

PJM has scheduled additional meetings on the VRR curve updates, starting with an afternoon session on May 25. Subsequent meetings are planned for June 22, July 6 and July 27.