SPP stakeholders on Wednesday approved staff’s recommendation to remove American Electric Power’s 2-GW Wind Catcher Energy Connection project from the 2019 Integrated Transmission Planning’s (ITP) assessment scope.
The Markets and Operations Policy Committee approved the scope change by an 82.1% vote during a special conference call. Staff said the call was necessary to keep the ITP work on schedule to meet its planned completion in October 2019.
The change removes Wind Catcher, planned for near Tulsa, Okla., from two study futures. The MOPC had approved the scope earlier this year.
Staff presented three options to the MOPC. The recommended option maintains the assessment’s timeline and makes use of the 215 resource hours staff has already put in.
Juliano Freitas, SPP’s manager of economic planning, said staff had already proceeded with the option to mitigate any schedule delays. He said the original assumptions included an expectation that Wind Catcher would be built; “thus it is appropriate to remove it and reduce the wind levels to be studied by a corresponding amount.”
The original scope included 32 GW of wind energy.
One other option was to continue the ITP without changing the model, with Wind Catcher acting as a “proxy” for other wind generation in the area.
The third option would have replaced the project with other wind sites, keeping the same 32 GW of wind.
MMU White Paper Proposes Capturing ESRs’ Opportunity Costs
The Market Monitoring Unit has published a white paper that proposes a framework for capturing the opportunity costs of electric storage resources’ (ESRs) mitigated energy offers.
The MMU produced the document to respond to FERC Order 841, which addresses electric storage participation in RTO and ISO markets.
MMU Manager Barbara Stroope said in an email to RTO Insider that ESRs are new technologies with costs that are “potentially quite different from traditional generation resources.” She said the paper provides “a solid theoretical foundation for the design efforts currently underway in SPP, and we think it can serve as the basis for a design that balances accuracy with simplicity.”
The white paper defines a mitigated energy offer as reflecting a generating resource’s short-run marginal production cost. Typically, the calculation derives from variables that include the incremental heat rate and fuel cost (where applicable), and variable operations and maintenance cost. The short-run marginal cost may also include the opportunity cost of foregone incremental generation when a resource’s ability to operate is limited.
“In the case of an [ESR], generating or charging at a given point in time may only be possible by forgoing profit opportunities later in the day or optimization period,” the MMU staff wrote, saying it’s “appropriate” to include the marginal opportunity cost in the basis for an ESR mitigated energy offer.
“The marginal opportunity cost of an ESR at any point in time is most accurately determined as the result of a dynamic optimization problem that considers the resource characteristics, state-of-charge and all future profit opportunities in the optimization period,” the MMU said.
Admitting that this approach could be “difficult or impractical” to implement in calculating a mitigated energy offer, the Monitor said a “reasonable approximation of this opportunity cost” can be determined for ESRs with relatively short charge and discharge times by “considering a simplified case to establish a lower bound of expected profits.” The lower bound would be represented by the maximum profit that would be earned if actual prices were realized as predicted.
“The approximation of marginal opportunity cost can then be determined by assessing the reduction in this expected maximum profit that may result from operating at a given point in time,” the MMU said.
July M2M Payments in MISO’s Favor
MISO reversed 11 months of market-to-market (M2M) payments to SPP, incurring $1.7 million in its favor in July. The RTO has not been on the positive side of M2M payments since July 2017.
| SPP
MISO and SPP outages in North Dakota and western Minnesota contributed to heavy loading on two temporary flowgates. The two constraints were binding for a combined 91 hours, accounting for slightly more than $773,000 in payments to MISO.
Temporary flowgates were binding for 416 hours in July. Six permanent flowgates were binding for 45 hours, leading to a little more than $15,000 in M2M payments in SPP’s favor.
July’s results reduced MISO’s M2M payments to SPP to $51.9 million since the two grid operators began the process in March 2015.
NERC Circulating Study on ‘Accelerated’ Retirements
By Rory D. Sweeney
VALLEY FORGE, Pa. — Generation reserve margins might drop and fuel-assurance risks could increase if coal and nuclear units retire sooner than anticipated, according to the preliminary findings of a NERC study focused on PJM and ERCOT.
PJM staff confirmed at the RTO’s Planning Committee meeting on Thursday that NERC had discussed the study at its own Planning Committee meeting earlier last week. The draft report has been sent out to members of NERC’s PC for comment, with the reliability overseer planning to present the final version to its Board of Trustees at its meeting on Nov. 6-7.
NERC spokesperson Kimberly Mielcarek said the target for public release is “before the end of the year.”
She declined to provide details before the study is final but pointed to the PC agenda, which outlines the study’s history.
NERC began soliciting policy input in May 2017 from stakeholders, proposing to conduct “an assessment of the potential impacts on Bulk Power System (BPS) reliability that could be caused by accelerated retirements of traditional baseload generator resources … to understand and address reliability challenges associated with the changing resource mix.”
NERC staff analyzed aggregated supply and demand projections for the study, along with engineering studies on specific retirement scenarios. They also reviewed regional processes for managing plant deactivations.
According to the agenda’s description, the study found that “when generation retirements exceed or outpace needed replacement resources, the BPS is less capable of withstanding contingencies, unplanned facility outages and extreme conditions.”
It added that “replacing retiring coal-fired and nuclear generation with natural gas-fired generation provides essential reliability services but can result in near-term stress on the natural gas infrastructure and create challenges to fuel deliverability in extreme winter conditions and major natural gas contingencies.”
Managing those issues will require “continued adherence to rigorous resource adequacy assessment and transmission planning processes” as “large amounts of generator retirements can result in extensive network upgrade requirements” and “potentially the increased use of out-of-market solutions such as reliability-must-run (RMR) designation to address resource adequacy issues,” NERC said.
ALBANY, N.Y. — The New York State Public Service Commission on Wednesday expanded the eligibility of distributed energy resources to be compensated under the state’s “value stack” tariffs, particularly standalone storage systems with 5 MW or less of capacity.
| NY DPS Webcast
The commission’s Sept. 12 order (Case 15-E-0751; 15-E-0082) mentions that “energy storage systems charged by using regenerative braking technologies, such as those used by New York subway systems, be eligible for the Value for Distributed Energy Resources (VDER) tariff for any hourly injections to the grid.”
Sayre | NY DPS Webcast
The order also authorizes interzonal crediting, allowing DERs receiving value stack compensation to apply credits to the bills of customers in the same utility territory but different NYISO load zones.
“It’s good policy to continue to expand the value stack to new types of projects and to larger sizes of existing projects,” Commissioner Gregg C. Sayre said.
Kelly | NY DPS Webcast
Ted Kelly, assistant counsel for the Department of Public Service, testified that combined heat and power (CHP) systems would not be eligible for value stack compensation now, but that staff would analyze CHP to establish “under what conditions CHP would be eligible and that greenhouse gases would not be worse than under system power and that it does not cause local impacts in sensitive areas such as environmental justice areas.”
The PSC in February ordered the state’s utilities to open participation in their value stack programs to DER projects up to 5 MW, more than doubling the previous 2-MW limit. (See NYPSC Expands VDER Project Size to 5 MW.)
The commission’s original VDER order of March 2017 (Case 15-E-0751) directed that compensation for eligible DER transition from net energy metering (NEM) to the value stack, a methodology that bases compensation on the benefits provided by the resources.
The new order expands the eligibility for value stack crediting to any clean generation technology that qualifies as a Tier 1 resource under the Clean Energy Standard (CES). The new rules also make resources that would qualify for Tier 1 but for their start date before the Jan. 1, 2015, eligible for compensation under the value stack.
The new eligibility rules also cover tidal energy generators, biomass generators and food waste digesters that meet CES requirements.
“There is no reason to exclude any renewable DERs from value stack compensation, as the value stack represents a determination of the actual value created by those generators,” the commission said.
Burman | NY DPS Webcast
Commissioner Diane Burman voted against the measure.
“Some of this has direct impact on other pending proceedings, including some declaratory ruling requests,” Burman said, adding that careful analysis and wording is needed to prevent unnecessary requests for clarification of commission orders.
In a related matter on its consent agenda (Case 18-E-0130), the commission accepted the environmental review of policy options to implement New York’s Energy Storage Roadmap, supporting the state’s energy storage target of 1,500 MW by 2025.
PSC Rules on CDG Compensation
The PSC backed NRG Community Solar in its dispute with Central Hudson Gas & Electric and Orange & Rockland Utilities over compensation for NRG’s community distributed generation (CDG) projects.
The commission’s declaratory ruling (18-E-0485) said the NRG Energy subsidiary had identified a conflict between the PSC’s VDER transition order and the utilities’ Phase One NEM tariffs.
NRG said the utility tariffs would pay its projects through monetary crediting (dollar-value credits based on the $/kWh rate applicable to the project) although they were designed assuming they would receive more lucrative volumetric crediting (kilowatt-hour credits that reduce the bill based on the $/kWh rate applicable to that subscriber).
“CDG projects receiving compensation under Phase One NEM … should receive volumetric crediting, regardless of the project’s service class, meter type, or billing methodology,” the commission said. “As this declaratory ruling is explaining and clarifying the effect of prior orders, rather than establishing a new rule or modifying existing rules, it applies to all utilities with VDER tariffs.”
The ruling does not affect the compensation of CDG projects receiving value stack compensation.
Rhodes | NY DPS Webcast
“There is in fact an inconsistency between the orders and tariffs cited here,” PSC Chair John Rhodes said. “That fact is objectively true. I find this recommendation carefully and clearly addresses that inconsistency.”
Burman voted against the ruling. “What if the issue is we didn’t intend it, but that’s what happened and we didn’t do the right analysis?” she said. “If we’re saying there’s an inconsistency between the VDER order and the tariff, maybe we need to look more closely at some of the challenges that are being raised with the VDER order.”
PSC Expands Con Edison EV Smart Charging
The PSC approved Consolidated Edison’s request to expand its electric vehicle charging program, SmartCharge NY, to allow the utility to offer incentives to customers who charge medium and heavy-duty EVs during off-peak hours.
The commission’s order (Case 16-E-0060) said “it is critical to begin testing the efficacy of off-peak charging programs for the full gamut of EVs at a time when EV penetration is comparatively low.”
“This strikes me as a useful, budget-prudent and limited expansion of an existing and innovative program, tailored to some market realities,” Rhodes said.
Burman voted against the expansion, saying “this order does not clearly define or give clear guidance on the specifics of the implementation plan.” She said the commission was shirking the “hard work” of defining potential logistical issues.
The order noted that the transportation sector is the largest contributor of GHG emissions in the state, and that diesel-powered medium and heavy-duty trucks account for a disparate share of total automobile pollution.
Expanding the SmartCharge NY program should cut carbon emissions and help meet the state’s goal of reducing GHGs by 40% by 2030, the commission said.
New York’s Zero-Emissions Vehicle (ZEV) plan calls for creating statewide EV infrastructure to support 30,000 to 40,000 EV sales by the end of 2018 and 10,000 charging stations by 2021. The commission reported 26,470 EVs are now registered in New York.
On its consent agenda, the commission also approved Con Ed’s shared solar program for low-income customers, with modifications, and with a budget not to exceed $9 million (Case 16-E-0622).
National Grid has begun operating a vanadium redox-flow battery (VRB) with its 1-MW solar PV array in Shirley, Mass., to demonstrate utility operation of storage.
The company was the prime recipient of an $875,000 Massachusetts grant awarded to an application team that also includes Vionx Energy, Worcester Polytechnic Institute and the Energy Initiatives Group. (See Massachusetts Awards $20M in Energy Storage Grants.)
Carlos Nouel, vice president of innovation and development at National Grid, told RTO Insider that “the Shirley project will serve as a test bed for integrating storage and solar through the use of flow batteries, and support the development of new frameworks for dispatching stored solar power.”
This table details feeder and solar site characteristics for National Grid’s site in Shirley, Massachusetts. | National Grid
Massachusetts lags far behind California in deploying utility-scale energy storage, but it is trying to integrate the technology into its power supply.
California utilities must procure more than 1.3 GW of energy storage by 2020. As of August, the state’s three largest investor-owned utilities are in the process of actually procuring nearly 1.5 GW, with about 332 MW currently online, according to a report last month by the California Energy Commission.
In contrast, Massachusetts last year said the state’s utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020. ISO-NE in April reported more than 500 MW of storage capacity in its interconnection queue. (See Overheard at the Energy Storage Association Annual Conference.)
Home-Grown Storage
Vionx (rhymes with “bionics”) is supplying the energy storage system for the Shirley solar project, which lies about 30 miles west of the company’s lab and headquarters in Woburn, Mass.
The company uses vanadium rather than lithium for energy storage, seeing the alternative flow battery technology as the best fit for utility-scale applications, including microgrids or industrial, behind-the-meter systems.
The use of vanadium in a flow battery was first explored in the 1930s and only made workable in Australia in the mid-1980s. Today, many companies use the technology, from giant Sumitomo to tiny CellCube, a VRB manufacturer trying to vertically integrate with its own vanadium mine in Nevada.
A VRB stores chemical energy in the form of vanadium-based electrolyte and generates electricity by inducing a reduction-oxidation (redox) reaction: that is, a transformation of matter by electron transfer across an ion exchange membrane, within a battery stack. The reaction is achieved by either applying an electrical load (discharge) or an electrical supply (charge) to the battery stack as the electrolyte is flowing or being pumped across the membrane.
“Lithium is dominating the storage market, but it is not always the best tool for the job,” said Jonathan Milley, director of business development at Vionx. “Lithium batteries are really for power applications, best-suited for short duration purposes, while vanadium flow batteries are for energy applications, and are therefore a more serious tool for keeping the lights on overnight.”
A lithium-ion battery undergoes a physiochemical change that degrades the electrodes during charging and discharging, but with a VRB, the charge differential is created by an ion exchange across a membrane, meaning the element does not wear out.
“So unlike the lithium-ion battery in your laptop, you never have to replace a Vionx battery,” Milley said. “Certain applications in the grid can cause huge challenges for a lithium-ion system. If you’re trying to drive a screw in, don’t use a hammer.” The Vionx system is also safe and cannot burn because the electrolyte is 70% water, he added.
Elemental Capacity
“The vanadium doesn’t wear out; it doesn’t degrade; it doesn’t need to be replaced or augmented,” Milley said. “The vanadium goes in the electrolyte on Day 1, and if 30 years from now you want to take the whole system apart, the vanadium is fully recoverable. It retains its commodity value [it is a key component in steel production] because it’s not consumed.”
Because the electrolyte is flowing past the electrode, a flow battery allows for the physical separation of capacity and energy, or megawatt and megawatt-hours. Vionx takes an architectural design that capitalizes on that ability and separates the two intentionally, Milley said.
“This allows for scaling at increasingly greater economies of scale; since we are adding only electrolyte to get an additional hour of run time, the cost per kilowatt-hour is much less for a 10-hour system than for a four-hour system. Also, if we have a customer who’s looking at eventually using the system to clear in the PJM capacity market or to be used as a reliability product, but in the near term needs ramping support and load reduction, then a four-hour system can be installed initially, and in the future another six hours of electrolyte can be added to achieve a 10-hour duration system,” Milley said. “Only the electrolyte is added, not any battery stacks, pumps or control components.”
Milley acknowledged that vanadium can be expensive, but he said it is still cheaper for long-duration applications than a solid-state battery that requires the purchase of more cells to expand its capability.
“In our case, you’re simply buying one component or one aspect of the system,” he said.
Team Effort
Vionx is owned by Starwood Energy Group, Vantage Point Capital and other private equity firms, and by United Technologies, whose battery stack design is under exclusive license to Vionx.
3M supplies the membranes and Jabil is the system fabricator. Glencore is currently supplying the vanadium electrolyte, by sale or lease, depending on whether the buyer wants to book it as a capital expenditure or operating expense. Siemens cooperates on a project-by-project basis.
CARMEL, Ind. — MISO has sufficient resources available to once again cope with unseasonably warm conditions this fall, although there is a small risk it may be forced to order emergency procedures.
The RTO foresees a 19% chance that it will invoke emergency operating procedures to call on load-modifying resources (LMRs) this fall, stakeholders learned at a Sept. 13 Market Subcommittee meeting. Those resources are not obligated to respond when called upon after Sept. 1. MISO expects to have about 11.8 GW of available LMRs, based on availability forecasts provided by resource owners.
MISO forecasts anywhere from a 110- to 120-GW peak load for September and said it prepared for loads more in line with summer conditions. The National Oceanic and Atmospheric Administration predicts above-normal fall temperatures for the MISO region.
“September generally aligns more closely with summer system conditions, at least for the last few years,” said Jeanna Furnish, MISO manager of outage coordination.
Furnish said the RTO has so far this month experienced loads topping out at 114 GW, within about 1 GW of peak fall loads over the last three years.
For the last four years, MISO’s actual fall peak load has trended about 5 to 9 GW higher than load-serving entities have forecasted in 50/50 probability forecasts.
Furnish said MISO expects a 10- to 15-GW increase in planned outages from the end of September to the end of October, when load is projected to be lower. Navigating the outages will be “challenging, but manageable,” similar to the RTO’s experience in recent years.
Recent fall peak loads | MISO
After some stakeholders expressed confusion over the 19% statistic, MISO Executive Director of Market Development Jeff Bladen clarified that the RTO is not saying it will spend 20% of the fall in emergency operating procedures.
“There’s a 20% chance that we will go into emergency operating procedures at least once this fall,” he explained.
Some stakeholders wondered if MISO’s prediction was optimistic. Minnesota Public Utilities Commission staff member Hwikwon Ham pointed out NOAA predictions of a 40 to 60% chance of a major storm forming in the Gulf of Mexico last week. During the meeting, stakeholders also received an emailed capacity advisory notice for a possible shortage on Sept. 17 owing to outages and residual weather conditions from Hurricane Florence. MISO rolled out the new notification system in August for situations when its all-in capacity is forecast to be less than 5% above operating needs. (See “New Notification System,” MISO Moving to Combat Shifting Resource Availability.)
The Public Utility Commission of Texas on Friday approved Oncor’s application for a certificate of convenience and necessity to begin work on its Far West Texas Project, a transmission upgrade to meet the Permian Basin’s oil and gas production load growth (Docket 48095).
ERCOT approved the Odessa EHV-Riverton and Bakersfield-Solstice 345-kV transmission lines in 2017. The grid operator’s Board of Directors designated the Odessa-Riverton line as critical to system reliability in February. (See “Directors Grant ‘Critical’ Status to West Texas Project,” ERCOT Board of Directors Briefs: Feb. 20, 2018.)
The project is expected to cost $336 million to $501 million, depending on the route selected. Oncor has presented a recommended route and 88 alternatives, each between 110 and 133 miles in length.
Oncor said it has already acquired between 12 and 15% of the right of way, depending on the route selected.
Garland, Cross Texas to Share 345-kV Line
Limestone-to-Gibbons Creek transmission line | Cross Texas
The PUC approved a request by Cross Texas Transmission and the city of Garland to share a 67-mile transmission line, completed as part of the Houston Import Project (Docket 48202).
Cross Texas will transfer 38 miles of the Limestone-to-Gibbons Creek 345-kV double-circuit transmission line to Garland. Cross Texas, a unit of LS Power, built the line under an agreement with Garland, which paid for a portion of the line during construction. The line was energized in April.
ERCOT had directed the entities to build the line and upgrade the Gibbons Creek substation as part of the $590 million Houston Import Project. The rest of the project comprised transmission and substation upgrades.
PUC to Intervene in FERC Dockets
PUCT Chair DeAnn Walker | Admin Monitor
The commissioners went into a closed session as soon as they convened their open meeting. Following the 39-minute executive session, Walker said the PUC would intervene in three dockets at FERC:
ER18-2358, which would place GridLiance’s Oklahoma transmission facilities and its annual revenue requirement under SPP’s Tariff.
ER18-2273, in which MISO seeks a one-year waiver of its Tariff requirement to conduct quarterly voltage and local reliability (VLR) studies. The RTO also seeks permission to designate a VLR issue in the Baton Rouge, La., area as “commercially significant,” thus allocating the costs to load-zone asset owners in the EES, CLEC, LEPA and LAGN local balancing authorities.
ER18-2363, a MISO request to revise part of its resource adequacy construct, creating external resource zones, allocating excess auction revenues to load-serving entities affected by the changes, and aligning parameters used to calculate auction inputs.
The PUC also agreed to publish questions for stakeholder comment for a rulemaking addressing battery storage and other non-traditional technologies in delivery service (Project 48023).
It also set a deadline of 8 a.m. Sept. 17 for retail electric providers (REPs) to list their offerings in both Spanish and English on the commission’s Power to Choose website, where consumers in Texas’ competitive areas can shop for electricity providers.
Chair DeAnn Walker noted 34 of the 57 REPs on the website don’t include their offerings in both languages.
PUCT’s Shelly Botkin, DeAnn Walker, Artur D’Andrea (left to right) share a light moment with staff. | Admin Monitor
“I’m not happy with that at all,” Walker said. “I’ll give them the weekend to get it done. If they don’t have it at 8 a.m. Monday, [staff] will start pulling off the ones that aren’t” bilingual.
True to her word, the PUC deactivated 221 electricity plans from 18 retail electric providers Monday morning. Some plans were quickly reactivated later in the day, when the REPs listed their offerings on both websites.
The ERCOT market has 117 REPs that offer more than 900 electricity plans.
ERCOT Files Bylaw Changes for Approval
ERCOT on Sept. 11 filed amendments to its articles of incorporation and amended and restated bylaws for the PUC’s approval. The grid operator hopes to have the changes in place for the 2019 operating year.
The ERCOT board approved the changes in August, the first to the governing documents since 2000. The amendments to the bylaws clarify the definition of affiliates and affiliate relationships.
The New England Power Pool’s proposal to codify its longstanding ban on press and public attendance at stakeholder meetings was attacked by consumer advocates, environmental groups and press advocates Friday.
Only one comment — by six former NEPOOL chairs and current Chair Tom Kaslow — was filed in support of the press ban before Friday’s filing deadline (ER18-2208).
“What some are characterizing as ‘secret’ is merely a discreet and considerate process for considering options and pursuing consensus,” the group wrote. “From our personal experience, and from what we have overwhelmingly heard from NEPOOL members, the presence of press reporters to attend and report widely on meetings would unfavorably change the stakeholder process, leaving many of NEPOOL’s participant members hesitant to share their positions as openly during the problem-solving and deliberative process.”
The filing was authored by Joel S. Gordon of Public Service Enterprise Group. Signing it were Kaslow, of hydropower generator FirstLight Power Resources; Cal Bowie, of Eversource Energy; Dan Allegretti, of Exelon; consultant Peter Fuller, who chaired the New England Power Generators Association while a vice president with NRG Energy; consultant Robert Stein; and attorney Donald Sipe, who represents industrial consumers.
On Aug. 13, NEPOOL asked FERC to approve amendments to its Agreement to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings. The group drafted the revisions after RTO Insider reporter Michael Kuser, who lives in Vermont, applied for membership in NEPOOL’s Participants Committee as an End User customer in March.
RTO Insider responded to NEPOOL’s filing with a Section 206 complaint Aug. 31 asking the commission to overturn NEPOOL’s ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). Comments in that docket are due Sept. 20.
Former NEPOOL Chairs Cal Bowie, Joel Gordon, Pete Fuller, Don Sipe, Dan Allegretti, Roberto Denis, Bob Stein, and Brian Forshaw, pictured in the group’s 2014 annual report. All but Denis and Forshaw signed comments supporting NEPOOL’s ban on the public and press. | 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.
‘Opportunity to be Represented’
PSEG’s Gordon said that NEPOOL’s practices of posting meeting materials and minutes “ensure that all parties with a direct interest in the New England wholesale electricity markets have the opportunity to be represented and fully informed of issues under consideration and the direction of the solutions.”
But William P. Short III, who represents End Use customers at NEPOOL, said the meeting minutes are insufficient. He urged FERC to listen to the audio tapes of the May 4 and June 26, 2018, Participants Committee meetings at which the press ban was debated.
“At the May 4, 2018, meeting, we debated this issue for at least a half-hour, if not, an hour. The meeting minutes on the subject of banning the press from NEPOOL membership are just three sentences,” Short said. “The public needs to have the press in the room to catch these super-sanitized versions of these proceedings that mislead both non-attending participants, the public and the FERC commissioners and staff.”
Short — who joined with Massachusetts Assistant Attorney General Sarah Bresolin Silver to sponsor an unsuccessful proposal to allow press to become NEPOOL members — said he has been involved with NEPOOL since 1998. “Until Michael Kuser’s membership application, neither the Membership Subcommittee nor the Participants Committee had ever denied an applicant its request for NEPOOL membership,” he said.
Press, Consumer, Environmental Groups File Protests
Also filing a protest was Jordan Frias, president of the New England Professional Chapter of the Society of Professional Journalists (SPJ), who said the proposed ban “raises suspicion about what [NEPOOL] is trying to hide.”
“Not allowing reporters access to public policy debates that will determine changes to the electricity markets in regions, including New England, is doing a disservice to energy consumers,” Frias said. “FERC members need to think long and hard about whether they want to further cement lack of transparency from NEPOOL committee members or if they want restore the public’s trust in this committee by allowing journalists to do their jobs.”
Gordon expressed concern that stakeholders’ “questioning and brainstorming … might be reported as representing formal versus probative positions.”
But Rick Blum, policy director of the Reporters Committee for Freedom of the Press, a D.C.-based nonprofit that provides legal resources to protect journalists’ newsgathering rights, noted that other RTOs “operate effectively without a general ban on press.” He cited PJM’s media code of conduct, which states that “work products should be treated in the spirit to which they are intended, that is, not as final or complete documents nor the final position or view of a participant.”
The Union of Concerned Scientists’ Michael Jacobs noted that UCS is active in PJM and MISO stakeholder meetings, which RTO Insider covers. UCS’ experience “demonstrates that there is a productive public interest and stakeholder benefit to an active press presence at RTO meetings that outweighs NEPOOL’s stated rationale for this action,” Jacobs wrote.
He said press coverage helps his group with “the very real difficulty of tracking the many issues” before RTOs. “UCS believes that complex issues are better resolved when there are more informed parties, and information is more accessible. Press participation in NEPOOL improves our collective problem-solving abilities, not reduces them,” he said.
In a preliminary response, NEPOOL’s Participants Committee said the SPJ and UCS filings reflect a “fundamental misunderstanding” of the organization’s proposal.
“The amendments simply and clearly are solely about whether press can be members in NEPOOL, not whether press can attend NEPOOL meetings,” Day Pitney attorney Patrick M. Gerity wrote. “The amendments clarify that the press cannot become NEPOOL participants or representatives of participants. … There are widely published articles in the press on NEPOOL activities, notwithstanding that no press is or ever has been a member.”
Gordon: New England is Different
Gordon acknowledged that other RTOs conduct stakeholder meetings with press present. “While that approach may yield adequate dialogue for those regions, it does not follow that there will be no adverse impact on the existing dialogue within the NEPOOL stakeholder process if members of the press are in attendance,” he said.
He said NEPOOL’s six sectors allow “membership by all parties with legitimate interests in our mission.”
“A key principle for that dynamic is that the audience for the stakeholders who participate in NEPOOL meetings, and those for whom transparency is most critical, are the other NEPOOL stakeholders who hear the entire dialogue and understand and respect its context,” he continued. “We believe that this is an important and unique component of the New England stakeholder process that has made NEPOOL an effective stakeholder organization over the last decades — those who attend are communicating with ISO-NE, states officials, consumer representatives and all other stakeholders in attendance for the benefit of each other, not for the benefit of an audience outside the room.”
NEPOOL ‘Careerists’
New Hampshire Consumer Advocate D. Maurice Kreis, a member of the End User Sector, termed the signers of the Gordon filing “NEPOOL careerists,” saying they and their companies “benefit from the current arrangements” barring public and press attendance.
“NEPOOL relies on written testimony of an industry insider and NEPOOL veteran who has essentially built an entire career on providing information and insight that is otherwise unavailable to non-attendees because NEPOOL meetings are closed and secret,” he said, referring to the testimony filed by Stein that accompanied NEPOOL’s initial filing.
As an independent consultant, Stein testified, he supplies clients with “a confidential compilation of information from [NEPOOL] stakeholder meetings tailored to their individual business interests, giving them confidential analyses of issues of interest and insight on how their business interests could be affected by proposals by ISO New England Inc. (ISO-NE) and other stakeholders.”
Said Kreis: “The commission should view the proposed changes to the NEPOOL Agreement for what they are: an unabashed effort by the large and powerful corporate actors that dominate NEPOOL to strengthen the status quo to the detriment of consumers, public interest groups and others who would subject New England’s wholesale electric markets and bulk power transmission system to the skeptical scrutiny such a vital public resource deserves when left in private hands.”
Blum, of the Reporters Committee, made a similar observation, saying NEPOOL’s proposal “would appear to continue to allow meeting participants whose primary purpose is not news reporting to collect information based on their observation of, and participation in, NEPOOL meetings and distribute it to individuals or entities that do not themselves participate as members in NEPOOL meetings. The proposed amendments would only bar those individuals or entities whose primary purpose was newsgathering from membership and, thus, engaging in the same newsgathering and reporting activities.”
Tyson Slocum, energy program director for Public Citizen, raised the same issue. “When deliberative bodies are transparent and open to the public, information resources regarding details of their proceedings are inexpensive, reflecting the ease with which the information can be obtained and disseminated. Banning the public and journalists creates new ‘markets’ for those permitted access to NEPOOL proceedings to financially commodify access and intelligence about NEPOOL’s activities,” he said.
“NEPOOL’s restrictions on public and media access allow those with privileged access to possess valuable information about NEPOOL activities that are nonpublic, which they can then sell for lucrative amounts to interested parties. NEPOOL is rife with a small army of well-connected consultants — many of whom trade on their former roles as NEPOOL officers in a ‘revolving door’ scheme — who sell information gleaned from their exclusive access to private NEPOOL proceedings.”
Slocum noted that many NEPOOL members that voted in favor of the ban are active in other RTOs. “Should FERC agree with NEPOOL’s press ban, it is likely that these and other companies will push for similar restrictions in other RTOs,” he said.
Order 719
In a joint filing, environmental groups Earthjustice, the Conservation Law Foundation and the Natural Resources Defense Council’s Sustainable FERC Project said NEPOOL’s press ban “severely compromises the transparency of ISO-NE decision-making, undermines confidence in its proposals and decisions, and threatens to undermine public interest outcomes in the region.”
They said the policy is in “direct conflict with commission Order 719, including the mandate that RTO/ISO processes be inclusive, fairly balance diverse interests, represent minority interests and be responsive.”
“Opaque RTO/ISO deliberations undermine customer confidence by enabling the perception, whether justified in reality or not, that a group of privileged insiders wields outsize influence over grid operator decisions affecting millions of customers,” they said. “In contrast, press access can encourage customer confidence by demystifying RTO/ISO processes.”
FERC commissioners were unaware of the ban when they approved Order 719 (RM07-19, AD07-7) in 2008, former Chairman Jon Wellinghoff said last week.
Similarly, former FERC Chairman Pat Wood III and former Commissioner Nora Mead Brownell said they were unaware when they approved NEPOOL as ISO-NE’s stakeholder body in 2004 that NEPOOL barred the public and press from its meetings. (See Wood, Brownell: Unaware of Press Ban When OK’d NEPOOL.)
CARMEL, Ind. — MISO says the time is not yet ripe for creating a detailed solar capacity credit process, but it is leaning toward adopting a process similar to the one used to establish wind credits.
The RTO last week said it will continue its practice of using individual operational data to determine credits — with new solar units continuing to receive a 50% capacity credit — until more operational data are available to perform a full credit study. At that point, it will likely use its effective load-carrying capability (ELCC) measurement, a loss-of-load expectation-based study that examines the MISO system with and without certain resources, staff said.
Speaking during a Sept. 12 Resource Adequacy Subcommittee meeting, MISO Resource Adequacy Coordination Engineer Eric Rodriguez said the increasing number of proposed solar projects entering the interconnection queue portend a need for a study process. Solar projects comprise 35.7 GW of MISO’s 90-GW interconnection queue, but the RTO currently has just 314 MW of solar generation in commercial operation in front of the meter.
“Three hundred fourteen megawatts is not enough to perform the ELCC,” Rodriguez said.
Rodriguez pointed out that MISO first conducted an ELCC study for wind resources when MISO had between 5.6 and 8 GW of installed wind generation on its system. He said MISO would determine another accreditation process if a solar ELCC capacity credit study resulted in an unreasonably low credit.
He also told stakeholders that “other potential methods for crediting solar’s contribution to serving load will be investigated.”
“I hope we make good use of this buffer of time,” said Customized Energy Solutions’ David Sapper, suggesting that MISO’s wind capacity method might not work best for determining solar capacity credits, especially because the RTO’s recent renewable impact study shows that solar plays a role in managing the day’s traditional gross peak hour but leaves a more pronounced net load to be attended by other resource types. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)
MISO Manager of Probabilistic Resource Studies Ryan Westphal said the RASC will take up how solar is most effectively studied for capacity accreditation in 2019.
Other stakeholders urged MISO to act quickly on the issue, given that utilities file 15-year resource plans and would like to accurately gauge the value of their solar capacity.
TEMPE, Ariz. — It’s been two months since Peak Reliability announced it will be winding down its operations at the end of 2019, but the issue won’t recede into the background any time soon, Western Electricity Coordinating Council members heard last week at the group’s annual meeting.
WECC held its annual meeting Sept. 11 in Tempe, Ariz. | WECC
Just the opposite: Industry participants must now race the clock to ensure the Western Interconnection makes a smooth transition into a new era of balkanized reliability coordinator (RC) coverage.
Frye | WECC
“The hot topic of the day, and will be for the coming months … is the RC issue,” CEO Melanie Frye told the WECC board of directors Wednesday, the same day she revealed that CAISO is slated to provide RC service to about 72% of the West’s net energy load. (See CAISO RC Wins Most of the West.)
“Count me among those heartsick at what’s going on with Peak,” said Brian Theaker, director of market affairs at NRG Energy who also sits on WECC’s Member Advisory Committee (MAC). “I mean, we spent all this effort to put together the West-wide, interconnection-wide view, only to have it unravel like this, and I’m still just shaking my head from it.”
Thilly | WECC
“I know that the Eastern Interconnection operates with multiple reliability coordinators … and the lights don’t go out,” said NERC Trustee Roy Thilly, who said NERC’s board has asked for a report on developments related to the RC issue at each of its meetings. “But the transition, I suspect, creates its own set of issues that we need to watch very carefully. We don’t want any gaps, no communication failures; and the structure has got to work in terms of the geography.”
Here’s more of what RTO Insider heard during the event about what Thilly jokingly referred to as “the little thing called the Western reliability coordinator set of issues.”
Transparency, Independency
Ortiz | WECC
David Ortiz, acting director of FERC’s Office of Electric Reliability, noted that the West consists of a network of load connected by a “relatively sparse” transmission network compared with the eastern U.S.
“The result is a system in which disturbances here in Arizona can be felt immediately in Washington,” Ortiz said, pointing out the region has deployed a collection of wide-area remedial actions schemes to support transmission operations. “Perhaps more than any region, maintaining reliability in the West does require a wide-area view.”
He said a successful RC transition will entail more than just the new RCs assuming Peak’s key functions. “This also requires that transmission operators and balancing authorities throughout the West work hand in hand with their reliability coordinators to maintain reliability.”
WECC members representing consumers expressed concerns that the new RC arrangement will be less transparent and provide them reduced input into reliability issues.
Maury Galbraith, executive director of the Western Interstate Energy Board (WIEB), previously told RTO Insider that WIEB has special concerns about how CAISO is proposing to govern its new RC. He noted that, unlike at Peak, CAISO’s member advisory committee would consist only of industry representatives. Also, CAISO does not plan to open RC meetings to the public, nor would meeting notes be made available to the public.
At the WECC meeting, Galbraith told WECC board members that WIEB’s Western Interconnection Regional Advisory Body (WIRAB) has submitted written comments to CAISO focusing on concerns about “transparent” and “independent” decision-making by the proposed RC, and a meaningful role for WIRAB to provide input and advice on RC activities.
Galbraith noted that WIRAB representatives had recently met with CAISO officials about their concerns, “and I’m hopeful that we’ll be able to resolve some of these governance issues with the folks at the Cal-ISO in the next several weeks.”
David Clark, a Utah Public Service Commissioner who also sits on both the WECC MAC and WIRAB, said state regulators have become accustomed to “an approach to RC coordination that has given us a lot of opportunity to participate, to observe, to gain comfort with the independence that’s been evident and the schemes that are used to remediate troubling — even threatening — conditions. In the future, we’re going to have a much different model, and we want to make sure that we don’t lose sight of some key principles as this new model evolves.”
Clark said those who have a statutory obligation to represent the interests of electricity customers “want some means of assuring ourselves that the daily, hourly, even minute-by-minute coordination is occurring effectively, independently of any improper influence. So we need transparency to be able to achieve that level of comfort.”
WECC’s annual meeting focused on the transition of the Western Interconnection from Peak Reliability to multiple reliability coordinators. | WECC
“We think WIRAB has an important role to play in this, and so we’re looking for WIRAB to be able to advise whoever is setting the policy for the reliability coordination function,” Clark added.
MAC representative Fred Heutte, of the Northwest Energy Coalition, said WECC end-use members seek “an appropriate role” for providing “broader input” into oversight of the region’s multiple RCs. “Not so much about the details, or about issues related to management of multiple RCs. But rather, what’s the appropriate role for the non-BA, non-TO stakeholders in the RC process.”
“That will be quite a bit different than what we’ve seen with Peak with member class representation and an independent board and a MAC and all that. The structures that will be in the new RCs will be quite different, but we think the same themes are involved,” Heutte said.
‘Clarity of Communication’
A guest panel on how reliability coordination works in the Eastern Interconnection — with its multiple RCs — pointed to the need for a different kind of transparency.
Arness | WECC
MISO seams management expert Ron Arness pointed out that his RTO coordinates its reliability activities with eight RCs.
“Transparency [into neighboring areas] is important,” Arness said, emphasizing the importance of “clarity of communications,” managing loop flows and developing congestion management tools. He also emphasized the importance of accurate internal and external models and performing drills to test coordination.
“It’s necessary to have a wide view,” Arness said.
Warren | WECC
Cameron Warren, manager of transmission operational planning at Entergy, noted that his utility joined MISO’s market and RC services in 2013 after functioning as its own RC since 1998. He offered a piece of advice to his Western counterparts facing the switch to a new RC.
“You’re moving to a company that’s not as familiar with your territory as you are,” Warren said. “Training is key.”
Lorissa Jones, of the Bonneville Power Administration, asked whether outage coordination policies are aligned throughout the East.
Yes, Arness answered. “It is important that outages are coordinated and communicated,” he said. “That clarity of communication is important here.”
WIRAB’s Galbraith asked how MISO provides transmission congestion relief to its neighbors that don’t participate in organized markets. Arness pointed to the RTO’s use of the transmission loading relief process.
“It does not take economics into account” in dispatch orders, instead functioning “purely on a reliability basis,” Arness explained.
“Is there some sort of higher-level forum where RCs from the Eastern Interconnection get together to collaborate and talk about interconnection-wide models or broader issues that affect more than one RTO or TOP?” Frye asked.
Frye (left) and Heutte | WECC
“I’m not aware of an official NERC organization that deals with the coordination of [energy management system] models, but people — like myself — we have a communication process,” Arness responded. “We’ve worked out a process where [MISO’s RC function knows] when MISO updates models, and we have to know when our neighbor updates their models, and we have to know how MISO’s going to get a copy of those models and know what those changes are. So that’s a structure and a process that’s built-in. It’s paramount.”
WECC board Chair Kris Hafner asked what the West should do — or avoid — as it transitions to multiple RCs.
Warren pointed to the importance of “having the RCs get together, communicate, lay out the operating agreements on how they’re going to manage any congestion that’s going to impact one utility or another. And ensuring that they go into it with a true wide-area view.”
Arness reiterated the importance of clear communication.
“Make sure clarity of communication is in place not only within the reliability coordination entity and all the various people that are working on reliability coordination, but also with neighbors. … Have the coordination agreements in place that spell out that that’s going to occur.”
Illinois’ nuclear generation subsidies do not interfere with FERC-regulated wholesale power markets, the 7th U.S. Circuit Court of Appeals ruled Thursday in the latest judicial pronouncement on state-federal jurisdiction over the electric industry.
The 7th Circuit ruling in Electric Power Supply Association v. Anthony M. Starr upheld a July 2017 district court ruling and was consistent with an amicus brief by FERC that said the Illinois zero-emission credits program did not violate the Federal Power Act. Starr is director of the Illinois Power Agency. (See Analyst: FERC Asserts Role in Handling Nuke Subsidies.)
Exelon’s Clinton nuclear facility, which benefits from Illinois’ zero-emissions credit program. | Nuclear Regulatory Commission
The court’s opinion cited the Supreme Court’s 2016 Hughes v. Talen ruling, in which the court rejected Maryland regulators’ attempt to subsidize a combined cycle plant, saying that the state’s contract for differences — which required the generator to bid into and clear the PJM capacity market — could distort prices. The court cautioned that its opinion should not “be read to foreclose [states] from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation.’”
“And that’s what Illinois has done,” the 7th Circuit said Thursday. “To receive a credit, a firm must generate power, but how it sells that power is up to it. It can sell the power in an interstate auction but need not do so. It may choose instead to sell power through bilateral contracts with users (such as industrial plants) or local distribution companies that transmit the power to residences.”
EPSA had contended that the ZEC program infringed on FERC’s jurisdiction by indirectly regulating interstate energy markets by using average auction prices as a component in a formula that affects the cost of the ZECs. But the court said the value of ZECs does not depend on the generators’ auction offers.
“Every successful bidder in an interstate auction receives the price of the highest bid that clears the market. The owner of a credit receives that market‐clearing price, with none of the adjustments that Maryland law required,” the court wrote. “The zero‐emissions credit system can influence the auction price only indirectly, by keeping active a generation facility that otherwise might close and by raising the costs that carbon‐releasing producers incur to do business. A larger supply of electricity means a lower market‐clearing price, holding demand constant. But because states retain authority over power generation, a state policy that affects price only by increasing the quantity of power available for sale is not preempted by federal law.”
The court also rejected claims that Illinois’ program violated the dormant Commerce Clause, saying “the cross subsidy among producers may injure investors in carbon-releasing plants, but only those plants in Illinois (for the state’s regulatory power stops at the border).”
The court noted FERC’s June ruling requiring PJM to change its minimum offer price rule to address capacity market price suppression from state subsidies for renewables and nuclear power. (See FERC Orders PJM Capacity Market Revamp.)
EPSA had contended that FERC’s ruling was proof that the Illinois statute must be pre-empted. “But that’s not what the commission said,” the court noted. “Instead of deeming state systems such as Illinois’ to be forbidden, the commission has taken them as givens and set out to make the best of the situation they produce.”
EPSA said it was reviewing the order and hadn’t decided whether to seek a Supreme Court review. A similar court challenge is pending in the 2nd Circuit over New York’s ZEC program. (See 2nd Circuit Hears New York ZEC Appeal.)
“Today’s decision confirms that state subsidy programs such as nuclear bailout ZECs can harm wholesale markets,” EPSA said in a statement. “FERC told the 7th Circuit the commission can mitigate these negative effects and today’s opinion relies on that representation. EPSA now expects FERC to act promptly in the pending PJM capacity market docket to prevent the acknowledged harms state ZEC programs inflict on federally-regulated wholesale power markets.”
Analysts at ClearView Energy Partners issued a research note Thursday predicting the 2nd Circuit will also uphold the New York ZECs. “If the ZEC’s opponents seek review at the U.S. Supreme Court (via a petition for a writ of certiorari), we think they face an uphill battle,” ClearView said.
The analysts acknowledged however, that the 2nd Circuit’s rejection of the New York ZEC program “could meaningfully improve the prospects for Supreme Court review” to resolve the split rulings.
