Page 1008 – RTO Insider

August 13, 2019

PJM MIC Briefs: Aug. 7, 2019

VALLEY FORGE, Pa. — PJM staff told the Market Implementation Committee on Wednesday that they will not file waivers for upcoming capacity auction deadlines and will instead rely on FERC to issue an order on its minimum price offer rule (MOPR) before the end of the year.

Pat Bruno, senior engineer for PJM’s capacity market operations, said it’s unlikely the commission would respond in time even if staff submitted a waiver for the upcoming Sept. 1 deadline in the 2023/24 Base Residual Auction. The next round of deadlines comes in December, he said, at which point FERC will have “hopefully” issued a ruling.

Last month, FERC halted the 2022/23 capacity auction scheduled for this month, refusing to “rule prematurely” on PJM’s request for clarification that if it ran the BRA using the existing MOPR that the commission would also agree to enforce any new rates prospectively, saving the auction from being rerun (EL16-49).

The last-minute directive from FERC came just hours after PJM staff told the Markets and Reliability Committee they would move ahead with the auction as planned. The RTO confirmed it would comply with FERC’s guidance — though it was the commissioners themselves who expressed frustration about their role in creating market uncertainty for participants. (See FERC Halts PJM Capacity Auction.)

‘Winter is Coming’ … Along with Gas Contingency Plan (Hopefully)

Thomas DeVita, senior counsel for PJM, told stakeholders that staff are preparing to file a revised gas contingency proposal with FERC by October, with hopes that the commission will give its approval by December.

“Winter is coming,” he warned repeatedly, reiterating stakeholder concerns about surviving a third cold weather season without a cost recovery plan for generators forced to switch fuel supplies at PJM’s discretion.

On Feb. 19, FERC rejected the member-approved mechanism that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with the RTO’s instruction to temporarily switch to an alternative fuel or fuel source because of pipeline breaks or the loss of compressor stations (ER19-664). The proposal included nine categories of switching costs, such as park-and-loan service charges and overrun charges. (See FERC Rejects PJM’s Gas Pipeline Contingency Proposal.) The commission also argued that the conditions for switching belong in the Tariff — not just business manuals — and gave PJM a chance to revise the proposal over the spring and summer.

DeVita said FERC staff dropped some hints about how to tweak the filing for better success the second time around. (See PJM Revisits Gas Pipeline Contingency Plan.) He said staff discouraged the RTO from submitting an itemized list of switching costs, as it did in the first filing, and instead focused on procedures surrounding “explicit authorization” to switch between pipelines and any new limitations on the amount of gas burned after the switch occurs.

In the draft language presented Wednesday, staff added “pre- or post-contingency” into the switching process triggered by a manual load dump and removed a requirement that generators must have documentation of unauthorized switching costs before filing for cost recovery at FERC. A reference to opt-in and opt-out intraday offers was also removed.

Staff also added the following paragraph to the proposal, meant to ease members’ concerns about the vague definition of switching costs: “PJM will commit to analyze, assess and address through a stakeholder process whether adequate compensation exists for any future operating instructions associated with gas switching that fall outside of the criteria established in this Tariff filing. Such analysis will also consider the mechanisms through which such compensation shall be obtained.”

Independent Market Monitor Joe Bowring asked DeVita whether PJM’s proposed language would permit companies to include the cost of penalty gas in their offers and therefore charge customers for the much higher cost of power that would result. Bowring pointed out that if the pipeline approved the use of the gas, it should not be treated as penalty gas. PJM indicated that the issue needed to be clarified.

Bowring also noted that the gas contingency procedures did not have a clear requirement that PJM take other emergency actions prior to the contingency, including calling on demand-side resources.

DeVita said the language is on track for endorsement at the September MIC and MRC meetings, with filing scheduled for Oct. 15.

Opportunity Cost Calculator Vote Delayed

Stakeholders delayed votes on several options for a more unified opportunity cost calculator after confusion over the implications of proposed changes left many unsure of how to move forward — if at all.

PJM — Bob O’Connell, Panda Power Funds | © *RTO Insider*

Bob O’Connell, executive director of regulatory affairs and compliance for Panda Power Funds, sponsored a motion to vote on three packages, drafted in consultation with Dominion Energy, that would streamline PJM’s calculator to varying degrees. (See PJM Stakeholders Push Unified Opportunity Cost Calculator.)

During a first read of the plans last month, O’Connell said the first package makes small changes that don’t force PJM to rewrite its calculator. The second revises PJM’s modeling process to mimic the Monitor’s, which many stakeholders prefer for its reliability. The third consolidates the former package into one single calculator, “eliminating all compliance risk,” O’Connell said.

Under current procedure, market participants can either use PJM’s calculator in Markets Gateway or the Monitor’s modeling system to build energy cost offers with appropriate adders that help ensure a generator will recoup opportunity costs when its resources have limited run hours for environmental reasons and are scheduled outside of their most economic operating intervals. Some of these opportunity costs arise when regulatory agencies impose environmental run-hour restrictions, physical equipment limitations trigger operational restrictions and force majeure events constrain access to fuel.

The problem for O’Connell and other stakeholders, however, is the riskiness associated with PJM’s calculator, which is designed to give market participants more control over submitted data and, therefore, more opportunity for operator error. PJM staff said the majority of stakeholders — perhaps up to 98% — use the Monitor’s calculator already, with just two choosing to use the RTO’s within the last year.

“When I look at the Market Monitor’s calculator, I view that as very little compliance risk,” O’Connell said. “The only issues we have are — are we being honest and forthright with the information we provide to the Market Monitor, and did we copy and paste correctly? From my [compliance] perspective, something like the IMM’s calculator is preferable.”

Glen Boyle, manager in PJM operations analysis and compliance, pushed back against the simplified explanation of the Panda/Dominion proposals, noting that the calculator changes being suggested raise “serious concerns” — including those that would set aside hours from the performance assessment interval.

“There’s already a process in [PJM Manual 13] where if you start to run out hours, you can put those remaining into max emergency,” he said. “FERC was very clear in its order on opportunity costs. Only things related to environmental, insurance carrier and [original equipment manufacturing] should be in the calculator. We agree with that, and some of these things shouldn’t be included.”

O’Connell said the changes deserved further consideration.

“If you look at the situation right now, there’s sort of a disconnect between actions a company takes to put a resource into max emergency versus assumptions that are made in the capacity market,” he said. “This serves to link them more closely. … [It’s] an expectation [of] how market participants should behave with respect to a decision that they are getting down to too few hours. Really, the status quo lacks that linkage.”

He did, however, agree that the goal of “getting to one calculator” took priority over approving changes and agreed to drop those elements from the third proposal in the interest of moving forward — prompting Bowring to question the necessity of voting on a plan that appears to require PJM to make its calculator mirror the Monitor’s.

“If the point is to force PJM to create a calculator exactly like ours, then I believe that’s a demonstrable waste of time and money,” he said. “It seems to me you have what you want here.”

O’Connell agreed that there was no reason to force PJM to spend money to modify their calculator and that the Monitor’s calculator addressed the requirements of members.

MIC Chair Lisa Morelli suggested delaying the votes until the September meeting so that stakeholders could take more time to review the changes contained within.

Modeling Units with Stability Limitations

Stakeholders unanimously endorsed a problem statement and issue charge from Panda that address concerns over proposed revisions to Manual 10 that would require generators to use outage tickets for stability-related limitations, possibly encouraging price distortion. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)

PJM — The Market Implementation Committee met Aug. 7 in Valley Forge, Pa. | © *RTO Insider*

O’Connell told the MIC last month that PJM’s decision to remove supply from the market to address stability constraints will result in some units committing at price-based offers, rather than cost. (See “Modeling Units with Stability Limitations,” PJM MRC Briefs: July 10, 2019.) Under the RTO’s rules, only the affected generator would know of the constraint, O’Connell said, therefore gaining a competitive advantage over other units and possibly incorporating greater mark-ups into their offers.

As a solution, O’Connell suggested PJM implement a closed-loop interface around the affected resource that restricts the output to below the stated stability limit — and that it must be used in each of the RTO’s markets. He also encouraged PJM to publicize stability limits on OASIS prior to contacting the affected generator.

The MIC will work on possible solutions during the committee’s meetings over the next few months.

Price Formation

The MIC continues its review of how prices are formed every five minutes in PJM based on a problem statement and issue charge created by the Monitor and approved by the MIC in June.

Catherine Tyler of IMM Monitoring Analytics provided education on the relationship between the megawatt dispatch and price signals sent to generators by PJM systems for each five-minute interval. Tyler explained that the signals should be for the same point in time but are not. She said the practice is inconsistent with basic economic logic and creates incentive issues for generating units that are given price signals inconsistent with dispatch signals and are paid in a manner that does not match their dispatch instructions. This is the case for both energy and reserves.

Manual Revisions Endorsed

The MIC endorsed the following revisions to PJM manuals:

Manual 11 (Energy & Ancillary Services Market Operations): Revisions will document procedures for addressing missing historical performance scores in the regulation market and also clarify that the reserve requirements used in the market clearing process are based on the potential largest single contingencies that are communicated by PJM operations and modeled in the markets clearing software. Scheduled for MRC first read later this month and endorsement in September.

Manual 18B (Energy Efficiency Management & Verification): Updates to conform with Tariff revisions that detail energy efficiency rules issued by authorized relevant electric retail regulatory authorities and those dealing with seasonal capacity resources.

Manual 27 (Open Access Transmission Tariff Accounting and Manual 28 – Operating Agreement Accounting): Revisions include language to comply with electric storage participation mandates from FERC Order 841-A.

– Christen Smith

August 13, 2019

PJM PC/TEAC Briefs: Aug. 8, 2019

VALLEY FORGE, Pa. — PJM staff on Thursday unveiled to the Planning Committee a proposed new fee structure for a more involved cost-containment process.

The proposal suggests charging a $5,000 nonrefundable flat fee to all developers who submit competitive projects. Itemized study costs will be added as necessary. Mark Sims, PJM’s manager of infrastructure coordination, said the intent is to bill projects that incur the extra expense. Late payment and nonpayment conditions have yet to be determined.

PJM — The Planning Committee met on Aug. 8 in Valley Forge, Pa. | © *RTO Insider*

Sims previously told the PC that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: June 13, 2019.)

Sims said PJM will host a special PC workshop on Aug. 29 to discuss this structure in more detail, which will eventually be added to Manual 14F.

Cost Allocation Dispute Leaves Tariff Changes in Limbo

PJM staff said required Tariff changes covering cost allocation for transmission projects remain in limbo as the RTO waits on FERC to respond to a motion to address a remand related to the issue.

Pauline Foley, PJM’s associate general counsel, said transmission owners made the motion after the D.C. Circuit Court of Appeals “set aside” a 2016 FERC ruling that allowed transmission projects driven by local planning criteria to be exempt from competitive bidding. (See FERC Sides with Incumbent TOs; OKs Limits on Competition.)

On clarification, the court, citing its original opinion, said it held “‘only that FERC did not adequately justify its approval of the [Tariff] amendment at issue.’ Nothing in the opinion prevents FERC on remand from attempting to ‘provide a better justification for its approval of the Tariff amendment.’”

Petitioners Old Dominion Electric Cooperative and Dominion Energy filed motions for an order on remand arguing that the court’s decisions leave no doubt that the 50/50 cost allocation for regional facilities is in effect pending further action by FERC. LS Power commented that it is appropriate for the commission to bring the matter to an end.

FirstEnergy, Dominion Solutions

Dominion proposed the following solutions for several proposed supplemental projects in Virginia:

Cut an existing 230-kV line between Roundtable and Buttermilk substations. Construct a 1.8-mile, 230-kV loop to Lockridge substation. At Lockridge, install four 230-kV breakers to terminate the two lines. Install two 230-kV circuit switchers and any necessary high-side switches and bus work for two initial transformers (five ultimate). Cost estimate is $35 million and in-service date is July 31, 2022.
Install a 1,200-amp, 50-kAIC circuit switcher and associated equipment (bus, switches, relaying, etc.) to feed the new transformer from the existing 230-kV bus No. 5 at Beaumeade. Cost estimate is $750,000, and in-service date is March 31, 2020.
Re-conductor Cochran Mill-Ashburn 230-kV and Ashburn-Beaumeade 230-kV line segments using a higher capacity conductor, as well as upgrade the terminal equipment to achieve a rating of 1,572 MVA. Cost is $15 million and in-service date is June 1, 2023.

FirstEnergy solutions for Pennsylvania projects include:

Replace line trap and substation conductor at the Shawville 230-kV substation and replace line relaying, line trap and substation conductor at the Shingletown 230-kV substation. Cost is estimated at $900,000 with an in-service date of Dec. 1, 2020.
Replace line relaying, line trap and substation conductor at Elko-Shawville 230-kV Line 546/666 and Elko 230-kV substation. Replace line relaying and line trap at Shawville 230-kV substation. Estimated cost $1.3 million, with an in-service date of June 15, 2020.
Replace the Homer City North 345/230/23-kV transformer and associated equipment with 345/230/23-kV, 336/448/560-MVA transformer. Estimated cost is $6.6 million, and in-service date is Dec. 31, 2021.
Rebuild and reconductor approximately 33 miles of wood pole construction for the Armstrong-Homer City 345-kV line. Estimated cost of $138 million and in-service date of Dec. 31, 2023.

– Christen Smith

August 13, 2019

Texas PUC Briefs: Aug. 8, 2019

The Texas Public Utility Commission last week asked for more information on eight small municipal utilities’ appeal of ERCOT’s definition of transmission operator (TO) (48366).

The PUC directed the State Office of Administrative Hearings to return ERCOT’s order to the commission so that it could solicit feedback from stakeholders in a docket. Given legal briefs and other information, the commission would then be able to dismiss the ruling and open a rulemaking or project.

The Small Public Power Group (SPPG) — composed of utilities for the cities of Bartlett, Bridgeport, Farmersville, Goldsmith, Hearne, Robstown, Sanger and Seymour — is appealing the ERCOT Board of Directors’ 2018 rejection of a proposed change to the Nodal Operating Guide (NOGRR149).

“We will, of course, provide comments on the questions the commission [poses] and look forward to the discussion that follows,” Clark Hill Strasburger’s Tom Anson, legal counsel for SPPG, told RTO Insider.

The NOG requires every transmission or distribution service provider in ERCOT to either register as a TO or designate a representative on its behalf. The TOs communicate with ERCOT during emergency events and the management of load-shed activities, among other responsibilities.

NOGRR149 would have exempted municipal distribution service providers without transmission or generation facilities from having to procure designated TO services from a third-party provider if their annual peak load is less than 25 MW. SPPG developed the revision request in 2015 to settle the noncompliant status of six municipally owned utilities with loads of 9 to 21 MW. Goldsmith and Bartlett joined the proceeding later. The Technical Advisory Committee and its Reliability and Operations Subcommittee also rejected the change. (See “Small Public Power Group’s Appeal Again Meets Defeat,” ERCOT Board of Directors Briefs: April 10, 2018.)

Transmission and distribution operators AEP Texas and Oncor are the only two intervenors.

“When I looked at the docket and who intervened, I was shocked there were only the two intervenors,” PUC Chair DeAnn Walker said during the commission’s open meeting Thursday. “This has been a hard-fought issue at ERCOT where a lot of people put stakes in the ground, and they’re not putting them here, and I don’t understand why.”

“This commission can operate better in a project when we can hear from all the stakeholders and ask them questions,” Commissioner Arthur D’Andrea said during the commission’s debate over how to proceed.

The SPPG says its proposal would conform operating guides to the “existing factual situation.” None of the SPPG members is or ever has been in the ERCOT load-shed table, the group said, and the revision would not “in any way, affect the reliability of the ERCOT system.”

“Several SPPG members are so small, they are physically limited in their ability to comply with the relevant ERCOT requirements,” according to the group’s filing.

ERCOT has asked that the PUC deny the appeal because SPPG “has not demonstrated any legal basis for reversing the [board’s] decision to reject NOGRR149” and because it has not alleged “any credible violation of law.”

Walker said she wanted to ensure the commission was protecting its oversight of ERCOT.

“There are policy decisions made at the ERCOT board we don’t agree with. I believe we still have the authority to set that policy and the obligation to set that policy,” she said. “I don’t want to take away our oversight of those policy decisions.”

Walker Warns SPP Recs Could Raise Tx Costs

Walker briefed D’Andrea and Commissioner Shelly Botkin on the SPP Regional State Committee’s recent discussions and disagreements over the Holistic Integrated Tariff Team’s (HITT) recommendations. The RTO’s Board of Directors approved the 21 recommendations, despite some minor pushback. (See SPP Board Approves HITT’s Recommendation.)

Calling the conversations at the RSC “a whole lot of mess,” Walker said the three recommendations assigned to the committee will affect Texas because of changes to cost-allocation methodologies. The committee has until next July to:

propose how to decouple two transmission pricing zones under SPP’s Tariff, creating new, larger zones in one, and smaller sub-zones in the other;
evaluate the byway facility cost-allocation review process; and
charter a study of the generator injection rate (based on energy produced by resources without network or point-to-point service).

(See “Regulators Approve ‘Wind-Rich’ Report, HITT Recommendations,” SPP Regional State Committee Briefs: July 29 & Aug. 5, 2019.)

“While most of the utilities here [in Texas] support the decoupling, how those zones would [be] set up is important,” said Walker, the lone RSC member to vote against the HITT proposals. “Almost every recommendation I have seen has Texas paying more.”

Noting the HITT study was pushed by utilities in wind-rich areas concerned that their transmission spending was benefiting customers elsewhere, Walker said, “We’re not wind rich. We’re just under wind rich.”

“My concern is we end up at the end of the day with everyone else getting what they wanted and us needing to make a fight at FERC,” she said.

D’Andrea, who sits on Organization of MISO States’ board of directors, said some of the same discussions are being held there. OMS is currently working on long-term transmission planning principles, he said. “That conversation is almost impossible to have without cost allocation,” D’Andrea said.

SPS to Refund $14.5M in Fuel Costs

The PUC signed off on Southwestern Public Service’s request to refund its Texas retail customers $14.5 million for over-collected fuel costs from January 2016 through May 2018. SPS reached a unanimous settlement with commission staff, Texas Industrial Energy Consumers (TIEC) and the Alliance of Xcel Municipalities (AXM) (48718).

SPS has a separate docket before the PUC, in which it has asked permission to replace its two seasonal formulas used to determine its fuel factors with a single formula (49616).

The company said the move is necessary because its new 478-MW Hale Wind Project has changed its resource mix and because SPP’s market has affected its system-average fuel and purchased power costs. The new formula will ensure the wind facility’s benefits are passed on to customers “timely,” SPS said.

TIEC, AXM and the Office of Public Utility Counsel have intervened in the proceeding.

Residential customers will see about a 3.25% increase on their bill from June through September, or about $3.73/month for those using 1,000 kWh/month of electricity, the company said.

Broker Registration Forms OK’d

The commission approved electric broker regist ration forms to comply with Senate Bill 1497, which requires representatives paid for brokerage services to register with the state (49711).

The bill goes into effect Sept. 1. The PUC will maintain a list of registered brokers on its website.

Thoughts, Prayers for El Paso Victims

Walker opened the meeting by extending thoughts and prayers on behalf of the commission to three El Paso Electric employees who she said had family involved in the city’s deadly Aug. 3 shooting. She said one of the employees lost their mother.

“It’s rocking the entire community,” Walker said.

— Tom Kleckner

August 13, 2019

ISO-NE Planning Advisory Committee Briefs: Aug. 8, 2019

ISO-NE planners will update the base cases for the Boston 2028 Needs Assessment to include Central Maine Power’s New England Clean Energy Connect (NECEC) and the Revolution and Vineyard offshore wind projects, senior engineer for transmission planning Pradip Vijayan told the Planning Advisory Committee on Thursday.

NECEC will be modeled as a 1,090-MW injection at the Larrabee Road 345-kV line in Maine, while Revolution Wind will be modeled as a 120-MW injection at the Davisville 115-kV line in Rhode Island (20% of the contact value of 600 MW). Vineyard Wind is also modeled at 20% of its contract value, or 160 MW. Revolution Wind is being included even though its impact on the Boston study area is not considered significant, Vijayan said.

The update also will reflect Forward Capacity Auction 14 retirement and permanent delist bids and FCA 13 retirement and delist bids outside Boston, resources which were assumed to be available for dispatch in the previous assessment. Additional active demand capacity resources will reduce net load by 55 MW.

The update will be restricted to an evaluation of 2028 peak load conditions; the changes are not expected to impact assessments of minimum load, short circuits or the 2022 peak load.

The RTO plans to issue its first request for proposals for a competitively developed transmission solution under ISO-NE Refines Competitive Tx RFP Template.)

ISO-NE planners want to maintain as much as possible of the current restoration plan, in which Mystic 8 and 9 are among the first units brought online to energize the Boston transmission system. The units help regulate system voltage during the energization of the cables. To replace them, the RTO will be seeking a dynamic reactive device capable of absorbing the charging associated with the cables, Vijayan said.

The device must be able to be re-energized remotely and adjust its voltage control set point remotely based on ISO-NE dispatch instructions. To meet NERC standard PRC-024-2 and ISO-NE’s transient voltage criteria, it also will be required to stay connected on a low-voltage ride-through for between 0.15 and 10 seconds, depending on voltage. Required high-voltage ride-through will be 0.2 to one second.

The RTO has identified several potential locations for the device: Mystic 345-kV or 115-kV; North Cambridge 345-kV or 115-kV; Wakefield Junction 345-kV or 115-kV; Woburn 345-kV or 115-kV; and Tewksbury 345-kV.

ISO-NE is also working with Eversource Energy and National Grid to develop solutions to the time-sensitive high-voltage needs identified at minimum load levels in the Needs Assessment.

They have narrowed the potential solutions to a single 160-MVAR reactor at Golden Hills 345-kV or one 76-MVAR reactor at each location for one of the following combinations:

Everett 115-kV and K Street 115-kV
Everett 115-kV and Lexington 115-kV
K Street 115-kV and Lexington 115-kV

Cost estimates and evaluations of the options will be discussed at September’s PAC meeting, when a preferred alternative will be selected. The PAC will discuss the results of the Needs Assessment update in October.

Stakeholder comments on the PAC presentation should be submitted to pacmatters@iso-ne.com by Aug. 25. The RTO set the same deadline to be informed of projects that should be reflected in the assessment update because of state-sponsored solicitations.

RSP 19 Stakeholder Comment Review

ISO-NE’s Director of Resource Adequacy and System Planning, Carissa Sedlacek, presented a review of stakeholder comments on the draft 2019 Regional System Plan (RSP).

Sedlacek went one by one through 83 comments, explaining why RTO staff did or did not accept suggested edits. Some comments were legalistic tweaks to the wording, such as deleting a reference to “regional regulators,” as there is no such thing.

In several instances, the RTO preferred the phrases “energy constraint” to “fuel constraint,” and “energy storage” rather than “battery storage.”

“ISO-NE is trying to be more generic in the language, for the region has large pumped hydro facilities that are storage facilities,” Sedlacek said.

Regarding a question on exactly what the RTO meant by “variable energy resources” (VERs), she said “the sentence states that ‘VERs … are replacing nuclear, coal and oil resources…’ which is true. The [RTO] is not stating that VERs are the same as gas-fired generation, just that VERS are variable.”

Synapse Energy, commenting on behalf of the Maine Office of Public Advocate and the energy-buying consortium PowerOptions, suggested ISO-NE add a mention to 1,381 MW of storage in a section that described the region’s wind and large-scale PV resources and that it specify whether the storage is behind-the-meter, front-of-the-meter or both.

Sedlacek referred to the RTO’s comment that it considers all behind-the-meter resources in its peak and energy forecasts. “However, we don’t create a BTM energy storage forecast,” she said.

David Ismay of the Conservation Law Foundation (CLF) wanted wording changed to reflect that “five of the six” New England states have climate change as a top priority. But Sedlacek said staff did not accept that suggestion because the RSP “is not intended to be a breakout of state policies.”

CLF also recommended discussing “the connection to ISO-NE’s fuel and energy security concerns, including capacity supply obligations granted to fuel-insecure plants at effectively their full nameplate capacity.” CLF said it was “particularly relevant” given FCA 13’s clearing of NTE Energy’s Killingly Energy Center, a 650-MW natural gas generator planned in Killingly, Conn.

“The RSP is not the place to have a discussion of matters in an open docket,” Sedlacek said. “ISO-NE awaits responses from FERC on open dockets for FCA 13 and Mystic 8 and 9.

“We hear you; we see your comments. We’re talking about energy security versus fuel security, and the integration of increasing amounts of renewable resources,” she said.

2019 Economic Studies Detailed Assumptions

Stakeholders discussed the detailed assumptions for three 2019 economic studies, as presented by ISO-NE staffers Peter Wong and Patrick Boughan.

The RTO agreed to analyze scenarios and market impacts for the integration of up to 9,700 MW of offshore wind by 2035, similar to what was requested separately by the New England States Committee on Electricity and transmission developer Anbaric Development Partners. (See ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)

The NESCOE scenarios will model five levels of offshore wind ranging from 1,000 to 7,000 MW, while the Anbaric scenarios will model three between 5,700 and 9,700 MW. They also will look at varying injection locations and several potential transmission expansions, most of them 345-kV reinforcements, Wong said.

In addition, planners will evaluate two potential transmission upgrades that would increase the operating limits of the Orrington South interface in Maine, as requested by RENEW Northeast.

In one scenario, planners will consider increases of 0 to 170 MW from the modified 2016 transfer limits provided by RENEW. In the second scenario, they will evaluate increases of 100 to 825 MW. The analysis will be performed with and without the interfaces downstream of Orrington South being modeled at the projected 2025 transfer limits.

Based on the currently expected transmission system for 2030, the RTO anticipates it could add about 7,000 MW of offshore wind without additional major 345-kV reinforcements, though some reinforcement or expansion may still be needed, Wong said.

If more than 7,000 MW is added, the RTO sees the potential need for transmission reinforcements or new injections.

NESCOE counsel and analyst Ben D’Antonio asked how ISO-NE ranked the alternative transmission upgrades or reinforcements to accommodate offshore wind. Wong said that the RTO would discuss the issue and report back.

“If there’s more reinforcements beyond 345-kV lines, we want to see that,” D’Antonio said.

“We will be developing plans and high-level expansion costs associated with those needs,” Wong said.

Theodore Paradise, counsel and senior vice president of transmission strategy at Anbaric, said, “When we get close, is it that 200 MW that really pushes it over [the transmission capacity limit]? … If we spread out these interconnection points so we don’t overload, we’re OK with that too.”

“We will have to decide what modeling to use for best results,” Wong said.

VELCO Berlin Substation Condition

Vermont Electric Power Co. (VELCO) engineer Hantz Presume reported on the dilapidated condition of the Berlin substation, which connects two 115-kV lines and one transformer.

Problems include obsolete relays, lack of protection for breaker or circuit switcher failures, lack of a back-up protection system, and lack of high-speed protection.

The control building lacks space to accommodate needed improvements, communication equipment and ancillary systems, Presume said, and its location does not meet National Fire Protection Agency (NFPA) requirements that it be more than 50 feet from any power transformer.

VELCO proposes replacing the control building and the protection and control (P&C) system, installing a breaker failure scheme and high-speed protection as the second scheme.

The New England Power Pool transmission facility portion of the costs is estimated at $5.9 million, and the non-PTF portion at $4.7 million, for a total project cost of $10.6 million (+/-10% accuracy and including 15% contingency).

Replacing the substation could cost up to seven times as much, Presume said.

Eversource 345-kV Structure Replacements

Eversource’s John Case presented the company’s plans to replace 1,483 345-kV structures at an estimated cost of $403.9 million (-25%/+50%).

The replacements will be light-duty tubular steel poles that comply with current clearance and strength code requirements. Eversource anticipates completion of the work in 2021.

After this replacement program, any future 345-kV upgrades that require PAC approvals will be brought forth on a line-by-line basis, Case said.

The company is supplementing foot patrols with high-definition cameras on drones, which allows inspectors to see possible damage from all angles, he said.

“The use of drones is phenomenal at getting right in there to see what’s going on; it’s a great tool,” Case said.

– Michael Kuser

August 12, 2019

Study: Password Practices Remain Poor

By Rich Heidorn Jr.

Despite nearly daily news of cyber breaches, most computer users practice poor password security, and many people working in information technology and security would not recognize a phishing attempt if they saw one. Those are some of the disturbing takeaways from a survey of 5,000 people released last week by antivirus provider PC Matic.

“Passwords are one of the weakest links when it comes to cybersecurity, yet the importance of proper password management continues to be minimized,” PC Matic said.

More than 80% of the respondents indicated they use passwords they have memorized (55%) or written down (26%), with only 19% reporting use of a password manager. About half said they change their passwords only when they are forced to do so, a vulnerability when users continue using passwords that have been compromised through data breaches.

password security — More than 80% of the survey respondents indicated they use passwords they have memorized or written down, with only 19% reporting use of a password manager. | *PC Matic*

“Over 55% of businesses require employees to change their passwords fewer than two times annually,” the company said. “Even more alarming, over 20% of government employee respondents reported never changing their passwords.”

In addition, 20% of respondents said they use the same passwords for work and personal accounts. “Therefore, if these individuals fall victim to a data breach, the risk spills onto their employers, as the passwords those employees are using are now on the dark web,” PC Matic said. “The majority of respondents who reported using the same passwords for both personal and work purposes were 18-29 years old, nearly doubling the percentages of other age groups.”

Almost half of those surveyed said they access their personal email accounts through corporate networks. “This may not be an issue if the personal email accounts are completely secure and the employee does not click on any malicious links or open a malicious email while connected to the company’s network,” PC Matic said. “However, how likely is that to occur?”

The survey found 69% of respondents have seen a phishing email, but that more than 16% were unaware of this threat. One-quarter of respondents who were unaware of phishing reported their employment was directly related to IT and security. “Alarming?” asked PC Matic. “Very.”

More than 64% of respondents reported using two-factor authentication at work, home or both, while 14% said they were unaware of the concept.

PC Matic said companies should enable two-factor authentication and use virtual private networks, which use encryption to provide secure access to remote computers over the internet. It said companies should require employees to update their passwords every six weeks, prohibit recycling of passwords, require a predetermined password strength and offer them a password vault.

Users changing their passwords regularly will have some protection even if their vault is hacked, the company said. “It takes time for hackers to sell data on the dark web. Therefore, by the time it is actually sold, the passwords will be useless because users would have already updated them.”

August 11, 2019

UPDATED: Temps, Demand, Prices Soar in Texas

By Tom Kleckner

Summer has been late in coming to Texas, but it is quickly making up for the delay with triple-digit temperatures that are leading to four-figure prices in the ERCOT market.

AccuWeather says a ridge of high pressure has settled over Texas and will remain into the middle of this week, funneling hot air from the Western U.S. into the southern Great Plains. San Antonio and Dallas each had a single 100-degree day before last week. Houston hit 100 degrees for the first time on Thursday; heat indexes as high as 110 are expected into this week.

Naturally, energy consumption has been rising with the temperatures. On Wednesday, ERCOT demand peaked at nearly 73.1 GW during the interval ending at 5 p.m., falling just short of the all-time record of 73.5 GW set last July. Two days later, it topped 73.1 GW, setting an all-time high for August and marking the grid operator’s second-highest peak ever recorded.

ERCOT has so far met demand without resorting to the emergency measures it warned it might have to take before summer began. The grid operator has an 8.6% reserve margin and 78.9 GW of available capacity to meet a projected peak of nearly 75 GW. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)

“ERCOT expects to have adequate generation to serve customers during this hot spell,” spokesperson Leslie Sopko said.

Real-time prices peaked systemwide at more than $2,400/MWh on Aug. 5, then settled at a high of $1,238.97/MWh at the West hub the next day, before dropping to a high of $91.96/MWh in the Houston load zone Wednesday. Houston hub prices hit 1514.94/MWh on Friday during the 15-minute interval ending at 3 p.m.

Day-ahead power prices hit $209.25/MWh in the North hub Thursday, the highest since reaching $300/MWh the day before the record peak last July. The hub’s next-day prices were at $38.50/MWh on Aug. 5.

August 11, 2019

ERCOT, WMS Collaborate on Price Corrections

By Tom Kleckner

ERCOT staff have laid out a plan to work with stakeholders in addressing a May pricing event that has led to a complaint filed with Texas regulators against the grid operator.

Kenan Ögelman, ERCOT’s vice president of commercial operations, met with the Wholesale Market Subcommittee on Wednesday and proposed three issues for further discussion with market participants, including potential changes to the grid operator’s price-correction methodology; adding filters, requirements or different standards to the external telemetry coming into ERCOT; and improving the communications structure around price corrections.

Ögelman said staff would return to the WMS in September with an issues list. He said he expects “more topics than any solutions.”

“We’d like to give a high-level presentation and see if you have any other issues,” Ögelman said. “I think it’s important everyone see all the issues and where they’re going so we can get a solution.”

On May 30, prices briefly reached the $9,000/MWh maximum when the security-constrained economic dispatch system received bad telemetry data from Calpine. Staff quickly corrected the data, but they have refused to correct the prices because the data were external.

“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman told the grid operator’s Board of Directors in June.

Aspire Commodities, an energy broker, has filed a complaint with the Public Utility Commission of Texas asking that generators refund the market $18 million (49673). (See ERCOT Asks PUC to Dismiss Trader’s Complaint.)

Morgan Stanley’s Clayton Greer, who has complimented ERCOT on its quick response to the pricing error, urged quick decisions in the future.

“You let us know you were not going to reprice that day. The market understands once you do that, it’s final,” he said. “If you could find a way to put into words what you did [on May 30] into the protocols, that would be optimal.”

“We want prices to reflect the fundamentals of the market,” Reliant Energy Retail Services’ Bill Barnes said.

Luminant Generation’s Ian Haley indicated his company preferred to see bad telemetry rejected.

“We don’t think ERCOT should be in the business of determining what is and what isn’t correct,” he said.

August 11, 2019

MISO to Limit Capacity Resource Extended Outages

By Amanda Durish Cook

CARMEL, Ind. — MISO is working quickly to ensure its capacity resources are mostly accessible for the planning year after this spring’s auction cleared a Michigan generator scheduled to be on outage for the entire period.

The RTO proposed a provisional solution at the Resource Adequacy Subcommittee meeting Wednesday that would limit extended planned outages to fewer than 90 days to qualify for participation in the Planning Resource Auction. Additionally, resources expected to be unavailable for the first 90 days of the planning year would not qualify for PRA participation.

Cleared resources with planned outages lasting 90 days or longer must replace their capacity or be penalized at MISO’s approximately $250/MW-day cost of new entry. Currently, the RTO doesn’t impose any penalties for capacity resources that take extended outages.

“If you think about MISO’s resource adequacy construct, there is a reasonable expectation of availability,” Director of Resource Adequacy Coordination Matt Ellis said.

MISO plans to file the proposal with FERC by mid-October to have it in place in time for the 2020/21 PRA, an unusually fast turnaround for the RTO, which can spend several months to a few years formulating new Tariff language. MISO said it also plans to seek more fleshed-out outage rules for the 2021/22 auction.

Ellis said that while MISO may not be able to make a comprehensive filing now because it must examine several possible unintended consequences, it can impose a straightforward, 90-day requirement.

“It’s an incremental change. It’s intended to be a step in the right direction — something we can refine further as we go along,” Ellis said.

April’s PRA cleared a large generator in Michigan’s Zone 7 as a capacity resource for the 2019/20 planning year even though it is slated to be on an extended outage for the entire year. The Independent Market Monitor first criticized the move in June. (See “Extended Outages and the Capacity Auction,” Monitor Splits with MISO on Summer Readiness.)

Ellis said the 90-day requirement is meant to capture the possibility that a planning resource will be out for an entire season. Requiring availability in the first 90 days of the planning year also ensures that capacity resources will be available during summer months when availability is more critical. MISO planning years begin June 1.

Stakeholders immediately inquired about planned outages that come in just under the threshold, but Ellis said MISO is starting by drawing the line at 90 days.

“And honestly, when we discussed this internally, that’s the first thing that came up: ‘What if units take an 89-day outage?’” Ellis said. “What’s the bright line? We chose 90.”

Ellis said MISO will revisit its proposal if 88- to 89-day outages begin to become “habitual.”

When stakeholders asked what would happen if a generator extends an outage to 90 days or longer, Ellis responded it wouldn’t be retroactively penalized to cover replacement capacity. However, MISO and the Monitor would keep a sharp eye for resource owners that might be seeking to game the rule with sudden extensions. Under the plan, the Monitor would have Tariff authority to audit outages for physical withholding.

Stakeholders said the proposal could encourage generators to take forced outages — and the accompanying hit to resource accreditation — over taking a long-term planned outage that would exclude them from a capacity payment for a planning year or face having to replace the capacity at a high cost.

MISO has left the proposal open to other stakeholder comments through Aug. 23.

August 11, 2019

NYPSC Opens Resource Adequacy Proceeding

By Michael Kuser

New York regulators on Thursday kicked off a proceeding to examine how to reconcile NYISO’s resource adequacy (RA) programs with the state’s renewable energy and carbon emission-reduction goals (Case 19-E-0530).

“This item to open an inquiry is important and timely,” Public Service Commission Chair John B. Rhodes said. “We at the commission have a duty to ensure safe and adequate power. Safe means safe, and adequate means, in this case, [that] there’s power when New Yorkers need it. … It’s becoming questionable whether the answers that were organized at least 20 years ago are in fact the best answers for the situation we face today.”

David Drexler, the PSC’s managing attorney, said “a major impetus” for the RA inquiry is New York’s recently passed Climate Leadership and Community Protection Act (A8429) — particularly its mandate that 70% of the state’s electricity be generated by renewable resources by 2030.

Commissioner Diane Burman said she understood the need to examine electricity issues, “but I do find it disingenuous to say that we have an obligation to do this when there are many other issues that we have an obligation to examine,” pointing to Consolidated Edison’s moratorium on providing new customers with natural gas hookups in Westchester County until it can ensure adequate supply to the region.

The PSC held its regular monthly session in Albany on Aug. 8, 2019.

“I think the chairman nailed it when he said that the current approach was set 15 to 20 years ago, and it’s based on the cost attributes of a fossil generator,” said Warren Myers, director of regulatory and market economics for the state’s Department of Public Service.

The inquiry will focus on answering several questions, including:

Are the state’s energy policies and mandates, such as those related to offshore wind, photovoltaics, other renewables and energy storage, compatible with NYISO’s RA mechanisms? If not, what issues are manifested? Also, if not, how could they be aligned? Do policies and market structure mechanisms result in safe, adequate service at just and reasonable rates?
Is an installed capacity (ICAP) product an effective long-term solution for RA given the required future generating resource mix, which may have lower marginal costs or different availability profiles than many current generation resources in operation? What are the salient attributes of such long-term solutions?
Is there a preferred mechanism for ensuring RA? What are the cost impacts and benefits to consumers under the various potential RA mechanisms?
Should alternative approaches be considered to ensure that procurement of generation resources is aligned with state policy goals? If so, which ones? Are there existing or proposed models that might be instructive, such as the state overseeing the RA portfolios of load-serving entities as in California, or should NYISO rules be restructured to accommodate state policies?
What is the state’s role with respect to RA matters?
What, if any, next steps should the commission take with respect to RA matters?

First of Many

NYPSC Resource Adequacy — Commissioner Diane Burman

Burman said she would ask the “elephant-in-the-room question,” wanting to clarify that the PSC’s new effort would not seek to “undo the role of the ISO” regarding RA, “but in fact is looking at how can we work on these issues.”

“The elephant is prematurely in the room,” Myers responded.

Drexler said, “Actually, from a staff perspective, we’re not prejudging any of the issues at this point. This is merely meant to start the inquiry.”

Commissioner James Alesi supported the inquiry, saying that “New York is already on its way to cleaner energy consumption.”

Commissioner Tracey Edwards said it was better to start asking the right questions now than later, “when we’d be doing so in a defensive posture.”

Attending his first session since being appointed to the PSC on July 19, Commissioner John Howard said, “The truth is, the ISO and its markets work today; the lights stay on; people get paid. If you’re an incumbent, things seem to be pretty well-ensconced. However, that doesn’t mean there aren’t holes that need to be examined. … I believe this will be the first of many inquiries.”

In an Aug. 8 blog pos t, Jackson Morris and Cullen Howe of the Natural Resources Defense Council welcomed the PSC’s inquiry and raised two points.

“A central concern held by many stakeholders, including NRDC, is that NYISO’s capacity market rules could prevent clean energy resources supported by state and local policies from selling in that market, thereby depriving these resources of an essential source of revenue. …

“Another concern is that NYISO’s rules undercount the value of cleaner resources like energy storage systems, as well as wind and solar, while over-crediting highly polluting power plants.”

Burman expressed additional concern that the proceeding seems to lack direction: “Ultimately, all we seem to be addressing is the capacity markets and buyer-side mitigation, and then taking a look at, in some fashion, whether or not we want to change those rules.”

The commission has asked interested parties to submit initial comments by Nov. 8. Commenters can file with the DPS by e-filing or by email to secretary@dps.ny.gov, or through the department’s Document and Matter Management System.

“Today’s order is the beginning of an important discussion on resource adequacy, and we look forward to engaging with the Public Service Commission throughout the process to share our expertise, information and ideas,” NYISO CEO Rich Dewey said in a statement.

August 11, 2019

NERC Weighing Concerns on Reorg.

By John Funk and Rich Heidorn Jr.

NERC’s plan to streamline its top technical committees appears to face limited opposition, although officials indicated Thursday they are considering proposals to increase sector representation and lengthen the transition.

The new structure, to be discussed in detail at NERC’s quarterly meeting in Québec beginning Tuesday, would merge the Planning, Operating and Critical Infrastructure Protection committees into a new Reliability and Security Council (RSC). While the three technical committees have almost 120 voting members, the proposal would limit the RSC to 33.

Only two stakeholders made comments during a webinar Thursday on the proposal, both questioning why NERC hasn’t quantified the proposal’s supposed benefits. But NERC also has received written comments from a dozen stakeholder groups, who were nearly unanimous in calling for a longer transition and an increase in the number of sector representatives in the new organization. Some also questioned whether security issues should be combined with operations and planning.

The collapse of the existing committee structures aims to save time and money and reduce the “silos” and inefficiencies that some NERC members believe the three existing committees have created over time.

Exelon’s Jennifer Sterling, vice chair of the Member Representatives Committee (MRC) and co-chair of the Stakeholder Engagement Team (SET) that made the proposal, led the webinar.

“The idea is that we pivot quickly and focus resources rapidly,” she explained in her opening remarks. “You are all aware that our world and our industry are changing quickly and that the pace only continues to accelerate. We need to be agile. We need to be readily deployed to address these emerging issues.”

Existing subcommittees and task forces would remain intact for the time being and report to the RSC. Subcommittees that do not have recurring tasks would be eliminated or combined with others. “The whole idea is that every subcommittee should understand what their task is,” Sterling said.

Reassurances

Sterling acknowledged some stakeholders have expressed fears that the overhaul could unintentionally eliminate networking, workshops, lessons-learned sessions and similar interactions that have developed over the years.

“That was never our intention,” she said. “We would expect that the [RSC] would continue those activities going forward.”

Sterling also addressed concerns that reducing the number of committee members would diminish transparency and stakeholder involvement. “We are committed to making sure the meetings are held in spaces that are open and that provide enough space for everyone who wishes to attend,” she said.

Potential Changes

Sterling also indicated NERC is considering potential changes to the plan based on stakeholder feedback.

The SET proposed a “hybrid” of the regional representation used by the CIPC, the sector-based membership of the PC and OC, and the at-large membership of the MRC and Reliability Issues Steering Committee (RISC).

The RSC would include one voting member from each sector (except for the regional entities), 20 at-large members, a chair and a vice chair. Members would be selected by a nominating committee of NERC officers and approved by the Board of Trustees, with selections based on interconnection diversity, subject matter expertise, and a mix of small and large entities.

“Let me emphasize the word ‘proposed’ here,” Sterling said in prefacing her description of the proposed RSC makeup.

“We have gotten a number of comments that perhaps people would like to see more sector representatives. Right now, we have one per sector, but people have asked for two. And also, there have been a number of comments that they would like to see the sectors elect their own representatives. … These will all be discussed at the upcoming [SET] meeting, and I’m sure it will be discussed next week at the MRC.”

Sterling said her team also has heard stakeholder concerns that the proposed timeline — which calls for nominating RSC members in the fourth quarter and completing the transition in the first quarter of 2020 — may be too aggressive.

Stakeholders also have expressed concern that the RSC’s name could cause confusion with the RISC. “Essentially, the RISC will be developing the lists of risks on a strategic basis,” Sterling explained. “That RISC report, along with other reports, would then be used by the RSC to develop their tactical work plans.

“There were some people who thought that name, the RSC, might be confusing,” she acknowledged. “So, we’ll talk about that as a group at our August meeting.”

Cost-benefit Analysis

Only two stakeholders had comments during the workshop. Barry Jones, of the Western Area Power Administration, asked why the plan did not include an “impact analysis.” Keen Resources’ Robert Blohm, a member of the OC, said the proposal might not produce the promised efficiencies.

“What we have now are three groups simultaneously dealing with three parts of the overall issue, saving a lot of time,” he said. “I would have been more comfortable seeing this [proposal presented in] a more objective or less presumptive fashion, where cost-benefit arguments, pro and con, are listed quite clearly.”

Sterling said the SET’s goal was achieving efficiency, “and hopefully cost savings will result.”

Mark Lauby, NERC chief reliability officer, said the revamping would increase NERC’s effectiveness at addressing issues in a holistic manner. “Going from 120, 130 people to whatever the size of this group ends up being, that will certainly be less of a burden and cost to industry,” he added.

Written Comments

The Policy Input Package for the August quarterly meetings includes written comments from 12 sets of stakeholders, including industrial consumers, cooperatives, generation owners, transmission owners, utilities and RTOs.

In addition to calling for an increase in sector representation, many of the commenters also recommended eliminating the requirement that RSC members have “executive leadership experience,” saying that subject matter expertise is more important.

The Canadian Electricity Association was among the most skeptical of the proposal. “While evolving reliability issues faced by the industry may require solutions and expertise that expand across traditional operating frameworks, many companies are still internally structured through a planning/operations/security model,” said CEA, which represents generators, transmission and distribution companies. “This reality may make it challenging to identify RSC members who can bring the necessary breadth of knowledge and experience to work across these industry areas.”

It also said issues addressed by the RSC must be “well-prioritized, while also guarding against dilution of attention due to a higher number of issues being overseen by one group rather than three.”

Several commenters said that while they agree with combining the OC and PC, they saw less synergy in combining them with the CIPC, which focuses on security.

The Electricity Consumers Resource Council (ELCON), which represents large energy consumers, recommended replacing the OC and PC while retaining a separate security committee. The ISO/RTO Council said that while “there is reasonable justification” for combining operations and planning, “including security matters in the combined group does not improve efficiency.”

The Cooperative Sector said its members were split on the restructuring. It was also critical of NERC’s transparency, saying some of its members “found it challenging to understand the deliberations of the SET meetings and that meeting notes/minutes were not provided to industry. Additionally, the proposal states that the current technical committee members were surveyed for input on the existing committee structure, but the survey results were not made public.”

Only one set of comments, from stakeholders representing state, municipal and transmission-dependent utilities, opposed the RSC proposal (Option 2) outright, saying they preferred Option 1: keeping the three committees and adding a steering committee above them.

“Option 1 provides oversight by refocusing the OC, PC and CIPC, while retaining the benefits those committees bring to NERC and the industry,” it said. “If it is not acceptable as a long-term solution, Option 1 should be adopted as the mechanism for achieving an effective and efficient transition.”

Most of the commenters called for a slower transition. Said ELCON: “Change management at this scale often takes about six months to complete.”