Page 1046 – RTO Insider

April 28, 2019

Texas RE 2019 Spring Standards and Compliance Workshop Briefs

AUSTIN, Texas — The Texas Reliability Entity has rev i sed its self-certification process to make it more efficient for registered entities, staff said last week.

Self-certification is an attestation by registered entities on whether they are compliant or not with a reliability standard requirement. They can also declare that they do not own facilities subject to the requirement or that the requirement is otherwise not applicable.

Texas RE’s Spring Standards and Compliance Workshop attendees listen to a presentation. | © *RTO Insider*

Keith Smith, manager of operations and planning compliance monitoring, told attendees of Texas RE’s Spring Standards and Compliance Workshop on Thursday that registered entities will now be given more advance notice of the process and that Texas RE has worked to improve the quality of information it first receives.

In previous years, registered entities were given 30 days’ notice before the start of the self-certification process, with attestations due on the day the process begins. They will now be given 90 days, with submissions due 60 days before self-certification starts. That gives entities an extra 60 days of back-and-forth communication with Texas RE.

“We want you to provide us all the information up front, so we don’t have this continuous back and forth,” Smith said.

Texas RE’s self-certification worksheets will include questions crafted to obtain “appropriate and sufficient evidence” of compliance, he said. Registered entities will also be asked to provide narratives that support the attestation and identify internal controls, helping staff in understanding how the entity arrived at its attestation.

Smith hopes this will eliminate the constant clarification requests and responses during self-certification, which slows the entire process. Texas RE processed 12 self-certifications in 2018 and is already halfway to that number this year.

New Systems to Improve Efficiencies

COO Jim Albright advised entities to be on the lookout for a pair of new technology systems that will be coming online over the next two years.

The Centralized Organization Registration ERO System (CORES) is scheduled to go live June 17, replacing several other systems on NERC’s ERO Portal. A repository for collecting registered entity data and documentation, CORES will improve the processing of registration requests, Albright said.

Texas RE will host testing of the system at its office May 16.

Texas RE COO Jim Albright briefs entity reps on new software systems. | © *RTO Insider*

Albright also discussed the new Align system, a common portal for use by NERC, regional entities and registered entities in performing their compliance monitoring and enforcement program activities. Align, which Albright called a “whole new tool for work,” will be released in three stages, beginning in September. Release 2 is scheduled for the first half of 2020, with Release 3 anticipated in the second half of 2020.

The first release will enable entities to create and submit self-reports and self-logs, view and track enforcement actions, and receive and respond to requests for information.

Albright said the system will use CORES’ information to align NERC and the REs’ business processes, improve documentation, sharing and analysis of compliance activities, and provide “deep and broad views” of reliability across the ERO enterprise.

“We’re banking on this creating efficiencies across the ERO and [allowing] us to work with other regions,” said Albright, chair of the project’s steering committee. “We can’t share information easily now. Align will take care of that.”

TRE CEO Welcomes Attendees

Texas RE CEO W. Lane Lanford made a brief appearance at the workshop to welcome attendees and remind them that ERCOT’s historically low 7.4% reserve margin does not mean the end times are here.

“I remember when I was at the legislature and it was a hot day. We would be hoping everything would work out alright,” said Lanford, who managed legislative issues during his 12 years as the Public Utility Commission’s executive director.

“The narrower reserve margins [Texas faces] doesn’t mean the sky is falling or you run out with your hair on fire,” he said. “It’s something we hope you are preparing for. If we can help you, call on us. We all have to get there somehow.”

FBI: Cyber Crime Growing from New Software Tools

FBI Senior Special Agent Duncan Edwards gave a “non-classified” presentation on cybersecurity issues, warning attendees of the latest developments in ransomware, botnets, spoofing and dark web marketplaces.

The availability of Wi-Fi “crackers” and other software applications are driving the surge in cybercrime, Edwards said. “You don’t have to be a super hacker. Like anything in life, if you can make a buck on it, why not do it?” he said.

Edwards pointed out that the weakest link in internal security measures is “human error.”

“Your training is only as good as the individual who follows the training and protocols in place,” he said.

NERC Collecting Data on Wind Resources

NERC’s Generation Availability Data System (GADS) is expanding its collection of wind data and is planning to add solar data, said Mark Henry, Texas RE’s director of reliability services.

GADS has long collected outage data and operating history on conventional generation. Filings are due 45 days after the end of each quarter.

GADS Wind is collecting similar data from wind resource owners, with a phased-in implementation though 2020. GADS began collecting data on 200-MVA resources in 2018, and those between 100 and 200 MVA started filing in 2019. All units greater than 75 MVA must begin filing in 2020, and smaller units may participate voluntarily.

GADS Solar is on the horizon, possibly in 2022, Henry said.

Texas RE Budget Up 5.7% for 2020

Texas RE’s Board of Directors reviewed its preliminary budget proposal for 2020 during a Wednesday conference call. The $13.8 million budget is a 5.7% increase over 2019’s final budget of $13.1 million.

Personnel costs, Texas RE’s largest expenses, are up 4.3%, though staff’s size will remain constant for 2020. Medical benefits are increasing 14%, with a possible future increase of 20 to 25% leading staff to consider changing providers.

Texas RE’s operating expenses are increasing 12% because of an increase in its office rent. The entity has $2.7 million in operating reserves.

The Member Representatives Committee will review the budget during a Friday conferenc e call before it goes to the board for its final approval on May 15. The budget will be presented to FERC and NERC in late May.

— Tom Kleckner

April 28, 2019

ISO-NE Planning Advisory Committee Briefs: April 25, 2019

WESTBOROUGH, Mass. — Two of three economic study requests presented at ISO-NE’s Planning Advisory Committee meeting Thursday pertained to offshore wind development, while the other concerned transmission upgrades needed to accommodate onshore wind resources in Maine.

The New England States Committee on Electricity (NESCOE) requested that the RTO analyze various scenarios of the integration of OSW of up to 4,000 MW by 2030 and 7,000 MW by 2035.

“We’re trying to figure out the best place for these [offshore projects] to interconnect,” said Dorothy Capra, NESCOE director of regulatory services.

Transmission developer Anbaric Development Partners requested a study to review the impacts of OSW on energy market prices, emissions and regional fuel security in 2030.

Theodore Paradise, senior vice president of transmission strategy and counsel at Anbaric, predicted there will be between 8,000 and 12,000 MW of OSW nameplate capacity in New England by 2030, not including the current 9 GW target to serve New York loads.

“One of the great things we’ve done in New England over the past decade or so is spend $13 billion to $14 billion on infrastructure … so it looks like the system can handle the extra generation,” Paradise said.

One stakeholder, however, wondered whether the industry is reaching a level of irrational exuberance, with several parties potentially relying on the same resources for reliability.

RENEW Northeast Executive Director Francis Pullaro presented a request to evaluate the economic impact of two conceptual alternate transmission upgrades that would increase the hourly operating limits of the Orrington South interface in Maine.

If the study shows the expected production cost savings from one of the scenarios exceeds the expected cost of the upgrade, RENEW will ask the RTO to identify the project as a possible market efficiency transmission upgrade.

Eversource to Rebuild Conn. 69-kV Line

Eversource Energy is completely rebuilding 6.1 miles of the 69-kV 667 transmission line from the Falls Village substation to the Salisbury substation in Connecticut, with completion expected by year-end.

Eversource transmission hardware dating back to 1926 | *Eversource Energy*

Eversource planning engineer John Case detailed the estimated $24 million project to replace 51 lattice towers, and one wood tower, with 18 engineered and 35 light-duty weathered steel structures. The line, designed for 115 kV, was built in 1926.

The project will also add one light-duty structure outside the Falls Village substation to improve clearances, replace steel-reinforced aluminum conductor with steel-supported aluminum conductor and replace existing shield wire with new optical ground wire.

Final 2019 Load Forecast

ISO-NE’s 2019 Capacity, Energy, Loads and Transmission (CELT) winter forecasts are slightly higher relative to last year, with the 2027 winter 50/50 gross demand forecast up about 1.1% and the net demand forecast for that year about 1.2% higher.

ISO-NE implemented monthly energy modeling for this year’s forecast, rather than annual, Manager of Load Forecasting Jon Black said.

“We did that intentionally so that we could capture seasonal trends as they diverge,” Black said.

The RTO revised and updated the winter demand models, replacing dry-bulb temperature with effective temperature — to include the effect of wind on heating demand — and incorporating heating degree days as a second weather variable.

2019 New England gross 50/50 winter peak forecast | *ISO-NE*

The historical weather period used to generate a probabilistic forecast was shortened from 40 to 25 years, now covering 1991-2015.

Black said the 2019 model demonstrates improved performance relative to 2018 based on a comparison of mean absolute percentage errors: 1.1% during January 2019 non-holiday weekdays from 2.2% a year earlier.

“So this is really good feedback and shows we’re on the right track,” Black said. “If batteries come into our market, that’s not a load forecasting problem. All indicators suggest that the outlook for out-of-market batteries across the region are still too small to be a significant forecasting influence.”

Cutting Tx Review Periods to Save Time

ISO-NE will shave two months from its typically yearlong — and sometimes much longer — transmission planning process by halving the typical stakeholder review period for the Needs Assessment and Solutions Study documents.

“Stakeholders have said the transmission planning process takes far too long,” said Director of Transmission Planning Brent Oberlin, presenting a summary of the changes.

“Previous comments from stakeholders were to automate, automate, automate … which has been helped by a move to cloud computing,” Oberlin said.

Reducing the time for document review will provide further time savings. The RTO currently allows for 120 days of stakeholder document review in the planning process: 30 days for the draft scope of each document, followed by 30 days to review each final draft. But staff have determined that neither the Tariff nor the Transmission Planning Process Guide specify a duration requirement for the two review periods, enabling it to reduce those periods by half, in part because of redundancies within the documents.

The RTO expects to use similar time periods for stakeholder review of public policy and competitive solicitation materials generated by ISO-NE, unless otherwise mandated by the Tariff.

Tx Opportunity Reminder

Oberlin also reminded stakeholders of the qualified transmission project sponsor (QTPS) application process ahead of the release of ISO-NE’s first RFP in late 2019 or early 2020 for a competitive transmission solution based on the Boston Needs Assessment.

The RTO attempts to complete its review of QTPS applications within 90 days of the application being deemed complete, so any company planning to participate in the potential Boston RFP — or any other future competitive solution RFP — should apply soon, Oberlin said.

Eastern Conn. 2029 Needs Assessment Scope

ISO-NE Transmission Planning Engineer Jon Breard explained the changes between the 2027 and 2029 Eastern Connecticut (ECT) Assessments, noting that the RTO suspended the ECT 2027 Solutions Study process because of the changes in the 2019 CELT data.

Breard said the net load being used in the 2027 Solutions Study was too high given the change in estimated load, energy efficiency and solar PV from the 2017 CELT to the 2019 forecast.

The ECT 2029 Needs Assessment notably includes a scenario to capture stakeholder feedback on the 800-MW offshore Vineyard Wind project interconnecting to Southeast Massachusetts and the 1,090-MW New England Clean Energy Connect project interconnecting to the Larrabee Road substation in Maine, both selected in state-sponsored solicitations.

Stakeholders must submit comments on the ECT 2029 Needs Assessment to pacmatters@iso-ne.com by May 12. ISO-NE will post the assessment’s intermediate study files in the second quarter and post the report in the third or fourth quarter this year.

— Michael Kuser

April 28, 2019

Load Interests Endorse PJM-IMM Must-offer Proposal

By Christen Smith

VALLEY FORGE, Pa. — Load interests last week backed a joint proposal from PJM and the Independent Market Monitor that would strip capacity interconnection rights (CIRs) from generators seeking must-offer exceptions without a plan to become capable of meeting Capacity Performance requirements.

The Markets and Reliability Committee approved the proposal in a sector-weighted vote of 3.74 to 1.26 on Thursday, with unanimous support from both electric distributors and end-use customers. The two sectors shot down PJM’s original plan to take CIRs from resources after a three-year period of lost CP capability that was approved by 79% of the Market Implementation Committee in November, as well as an alternative from Exelon that would have allowed capacity resources to switch voluntarily to energy-only status and disallowed PJM to force such a switch.

Jason Barker and Sharon Midgley of Exelon | © *RTO Insider*

The PJM-Monitor proposal requires existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will become able to satisfy CP requirements in order to retain capacity status or else forfeit its CIRs. The requirement would be effective with the 2023/24 delivery year. Resources would be granted exceptions for no more than two auctions.

“The main motion would permit hoarding of CIRs inappropriately,” Monitor Joe Bowring said. “We continue to believe the compromise we worked out with PJM makes the most sense.”

The votes represent an about-face for stakeholders, who threw 61% support behind Exelon’s plan at the March 6 MIC meeting. Only 35% preferred the PJM-Monitor plan at the time. (See Showdown Set on PJM Must-offer Exceptions.)

“We realize the CIR issue has been very charged, but the conversation has lacked data and facts,” said Sharon Midgley, Exelon’s director of wholesale development. “The PJM-IMM proposal would create an unlevel playing field.”

Traditional generation owners balked at the notion that resources exempted from the must-offer requirement, including renewables, don’t face the same possibility of losing CIRs.

David “Scarp” Scarpignato of Calpine called the rules “discriminatory” and warned PJM of moving forward with the package, noting it would exacerbate problems in the future.

“PJM itself should be weary of putting forth a proposal like that,” he said. “I don’t think you are supposed to put forward discriminatory rules, and these are very discriminatory. This is a critical issue to us, and quite frankly it’s becoming more and more apparent in the stakeholder process that some resources get preferred treatment.”

Stu Bresler, PJM’s senior vice president of operations and markets, argued that the disparity is a result of the market rules created by stakeholders and ultimately approved by FERC.

Susan Bruce, representing the PJM Industrial Customer Coalition, suggested the MIC continue discussion about CIR inequities in future meetings. Staff agreed to review the original problem statement and issue charge for further Manual 18 revisions and return to the May 15 MIC meeting with a path forward. The PJM-Monitor proposal has not yet been scheduled for endorsement by the Members Committee.

April 28, 2019

Avangrid Earnings Drop on Weak Wind

By Michael Kuser

Declining wind output drove down Avangrid’s first-quarter earnings by 11% compared to a year earlier, company officials said last week.

Avangrid posted net income of $217 million ($0.70/share), down from $244 million ($0.79/share) in the same quarter a year ago. The drop was driven primarily by a $46 million decrease in the company’s Renewables business, from $50 million in Q1 2018 to $4 million this year. Wind production during the period averaged 14% below 2018 levels, reflecting “the impacts of storms and severe weather,” CFO Doug Stuver said in an earnings call Thursday.

BOEM map shows Vineyard Wind wind energy lease area offshore Martha’s Vineyard and Nantucket. | *BOEM*

The drop in the Renewables business was partially offset by an $18 million increase in the company’s Corporate segment “due to favorable tax impacts,” Stuver said.

Total revenue for the quarter was down by 1.2%, from $1.865 billion in 2018 to $1.842 billion.

CEO James Torgerson told analysts that despite the hiccup in wind output, Avangrid expects nearly 1 GW of renewables under construction to come online this year and has increased its pipeline by 1.6 GW to 15.4 GW, which includes 4.4 GW of solar.

Its Vineyard Wind offshore project, a joint venture with Copenhagen Infrastructure Partners, is on track, “with nearly 70% of the supply chain secured,” Torgerson said. The project’s contracts with the electric distribution companies recently received Massachusetts Department of Public Utilities approval. “Now, we are targeting to have all 800 MW in operation by the end of 2021,” he said.

With their Liberty Wind project, Avangrid and Copenhagen also submitted a bid in New York’s first offshore wind solicitation, with options for 400, 800 and 1,200 MW. (See Four Bidders Vie for NY Offshore Wind Project.) The New York State Energy Research and Development Authority is expected to announce the winner this spring.

The companies also submitted to Rhode Island two proposals of 200 MW and 300 MW each, with the selection of bidders expected in May.

April 28, 2019

AEP off to ‘Excellent Start’ with Q1 Earnings

American Electric Power said it is off to an “excellent start for 2019,” beating analysts’ expectations for the first quarter and completing a deal with Sempra Energy that adds more than 700 MW of wind generation.

AEP on Thursday repor t ed earnings of $572.8 million ($1.16/share), exceeding Zack’s consensus estimate by 6 cents and beating 2018’s first-quarter profits of $454.4 million ($0.92/share).

The Columbus, Ohio-based company began the week by anno u ncing its competitive renewable subsidiary, AEP Clean Energy Resources, had completed the purchase of Sempra Renewables for $1.05 billion. The deal includes Sempra’s 724-MW portfolio of operating wind generation, battery assets and development staff.

Sempra Renewables’ Boulder Solar II project | *Sempra Renewables*

Asked during a conference call with financial analysts why AEP is buying, and not building, wind and solar, CFO Brian Tierney said the deal takes the company to “the next level.”

“We’re very selective in the assets we looked at, looking for high-quality contracted assets with creditworthy counterparties,” Tierney said. “What this opportunity brought with it was a lot of wind, some battery, contracted with high-quality counterparties, but it also brought a team with it, and that team is something that we didn’t organically have from a development standpoint. So we got not just a team, but also development projects in the pipeline that we wouldn’t have had otherwise.”

The acquisition means AEP has now spent $1.5 billion of the $2.2 billion it has committed to renewable energy projects.

“We’re looking at opportunities as they become available,” Tierney said.

CEO Nick Akins did not participate in the call. AEP said Akins was not “feeling well,” but he expects to be back at work “soon.”

The company’s share price rose from its $83.52 open on Thursday to close the week at $84.71. It is up 32.1% since reaching its nadir of $64.11 in June.

— Tom Kleckner

April 26, 2019

PJM Stakeholders OK Risk Management Task Force

By Christen Smith and Rich Heidorn Jr.

VALLEY FORGE, Pa. — PJM stakeholders approved a charter on Thursday for a senior task force dedicated to implementing market rule changes in the wake of the 890 million-MWh GreenHat Energy default.

“The board message is quite clear that it’s not going to happen again,” Vince Duane, PJM’s general counsel of law, compliance and external relations, told the Markets and Reliability Committee. “If we are going to offer products that present this kind of risk, we need to be robust and confident that we can manage the risks associated with it.”

The Financial Risk Senior Management Task Force will assemble beginning May 2 to consider changes to credit and risk management requirements, market rules, membership qualifications and the stakeholder process in response to an independent probe of the default that uncovered structural flaws. PJM wants stakeholders to form solutions and make recommendations for Tariff and Operating Agreement revisions to the MRC and Board of Managers by the end of year.

“It’s not lost on any of us at PJM that this is going to be an investment of time and resources, and we want to make sure it’s efficient and that we are risk-managing products that are being used and are valuable,” Duane said. “If it doesn’t meet that litmus test, I think we have to ask why we are doing it.”

The PJM Board of Managers released the independent review of the GreenHat debacle in March. The report concluded naive staff and weaknesses in the RTO’s credit rules allowed the small trading company to amass the largest portfolio of financial transmission rights in PJM history without the financial resources to cover its losses. The latest estimates suggest the default will cost members up to $430 million. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)

CEO Andy Ott told the Market Implementation Committee on April 10 he will oversee organizational and procedural changes within the RTO but will rely on stakeholders to guide the process for market rule changes. Some of those internal changes include hiring a chief risk officer and replacing CFO Suzanne Daugherty, who retired before the release of the board’s report. The search for both is ongoing, Ott said Thursday.

Stakeholders endorsed the charter with just two objections and three ostensions. But several stakeholders expressed concerns about moving forward with the overhaul without the guidance of a CRO or CFO, noting the report’s recommendation to incorporate expert knowledge into the reforms.

The MRC delayed a vote on two proposals to allow surety bonds as a form of collateral until PJM hires the CRO and CFO. (See “Surety Bonds,” PJM MRC/MC Preview: April 25, 2019.)

“I think there are serious questions that should be reviewed,” said Susan Bruce, on behalf of the PJM Industrial Customer Coalition. “Maybe the answers become obvious. We have a responsibility to make sure that all of the products are delivering a value for this physical market. Retail customers shouldn’t end up being the insurance or backstop for products that aren’t delivering value.”

Greg Poulos, executive director of the Consumer Advocates of PJM States, mentioned his members’ interest in investigating the role of surety bonds, forfeiture rules and other FTR product specifics.

“Having the CRO in place is a critical component of leading these things … their perspective on surety bonds would be very helpful,” he said.

Members of PJM’s board at the April 25 MRC, with CEO Andy Ott (right) | © *RTO Insider*

‘Action Plan’

Later Thursday, Ott gave the Members Committee a briefing on his “action plan” for responding to the default, which includes the creation of two new departments (Markets Risk Modeling, and Market Analytics and Surveillance); the realignment of the Law, Compliance and External Relations Division “to improve communication and coordination”; and the creation of a Risk Oversight and Markets Surveillance Committee to be chaired by the CRO with executive-level representation from Finance, Markets and Legal.

Ott said his goal is for PJM to improve its ability to identify “changes in behavior” by market participants to prevent future defaults. “I, for one, want my organization to get better,” he said.

The RTO would seek input from the Independent Market Monitor on tracking market participants’ positions, he said, but the IMM would not be involved in evaluating players’ credit and collateral.

Bruce Bleiweis of DC Energy questioned giving IMM Monitoring Analytics a role, saying market participants had warned the Monitor that GreenHat’s FTR position was “growing dramatically auction after auction. Yet we’re still where we are today.”

“You have no idea what went on, so don’t draw conclusions about things you don’t know,” Monitor Joe Bowring responded to Bleiweis. “It is our job … to monitor all parts of the market.”

Bowring said the default resulted from the failure to assess the risk posed by the interaction of GreenHat’s increasing positions and its “gaming” of the RTO’s credit requirements by adding FTRs in the opposite direction of its existing positions.

Greg Carmean, executive director of the Organization of PJM States Inc., said the RTO should consider whether it should take on a “financial regulator role” or whether it should allow another entity to sell FTRs and other financial products. If PJM retains the responsibility, he said, it should ensure that the cost of the expanded staff is borne by the “cost causers.”

Ott acknowledged PJM may rethink its “can-do culture,” which has led the RTO to take on new duties at stakeholders’ requests. “We can’t be all things to all people,” he said.

April 26, 2019

Big Prospects for Offshore Wind in PJM

By Christen Smith

PHILADELPHIA — New research suggests that offshore wind farms offer huge potential for capacity gains in PJM’s footprint — but it will take a significant buildout of transmission to unlock that possibility.

University of Delaware professor Willett Kempton said a hypothetical buildout along the Eastern Coast from New Jersey to North Carolina could add approximately 80 GW to the grid.

“If we are going to do carbon-free generation, this is a really large resource that could do that,” he said while presenting his findings at Raab Associates’ Energy Roundtable in the PJM Footprint on Wednesday. “It would add 44% to today’s generation mix and it can all be carried to shore using only today’s transmission equipment.”

Kempton and his co-author, Elpiniki Apostolaki-Iosifidou, analyzed the impact of building an HVDC system with nine points of interconnections. The researchers estimated the system would have a 50% capacity factor, resulting in a 40-GW output on average. The conservative capacity estimates could be boosted through improved weather forecasting, more access to storage technology and PJM rule revisions, Kempton said. The new gigawatts would account for 43% of total PJM capacity, he said.

Other panelists said PJM must proceed with caution when planning such systems, noting the many pitfalls that come with securing proper permits, navigating seafloor access and attracting transmission developers.

“It’s a complex regime,” said Clint Plummer, head of U.S. market strategies and new projects for Orsted. “There’s opportunity for savings and reliability benefits by getting transmission policy on this right. There are real problems if it’s not done right.”

Norway-based Orsted bills itself as the world’s largest developer of offshore wind, with 5.6 GW of operational farms in the U.S., Europe and Taiwan. He said mistakes in Germany’s planning process taught developers that an integrated and streamlined approach to construction and operation works best, though it costs more upfront.

“Germany’s segmented approach didn’t work well because grant awards were mismatched between transmission and generation,” he said. “There were hundreds of millions of dollars of cost that accrued to us as developers of offshore wind … and then the transmission wasn’t there. We were basically paying the mortgage on that wind farm without any income coming in.”

One way to mitigate the costly risks of building an offshore wind networked transmission system is to secure permits before specific facilities are procured through state requests for proposals and ensure planning of every aspect before construction begins, said Theodore Paradise, senior vice president of transmission strategy and counsel at Anbaric. This means accounting for the unique challenges of the seafloor, including ocean trenching and navigating the limited points of onshore interconnection.

“Permitting can take significant time,” Paradise said, noting that securing those components ahead of time could be used as a “de-risking” tool. “It’s important you do it the right way.”

State legislatures in Maryland, New Jersey and Virginia have set goals of procuring a combined 6,700 MW of wind power over the next decade. So far, developers have contracted for less than 6% of those targets.

Cynthia Holland, director of federal and regional policy for the New Jersey Board of Public Utilities, said the state’s push to 3,500 MW of wind will make significant progress over the next five years. Bids for 1,100 MW have already been received, with a second 1,200-MW solicitation planned for summer 2020 and third scheduled for July 2022.

The first round of wind farms will likely use generation lead lines that connect onshore, though the BPU remains open to using networked transmission systems or HVDC lines for future projects.

Ken Seiler, PJM’s executive director of planning, said the RTO sees significant potential and benefits to the grid in offshore wind, but it remains hesitant about building transmission without committed generation. PJM staff is working with stakeholders to examine this process in further detail in the Merchant Transmission and Offshore Wind Task Force. (See “PC Moves Forward on Offshore Interconnection Rights,” PJM PC/TEAC Briefs: Feb. 7, 2019.)

“We recognize the interest and we recognize the value of offshore wind,” he said. “‘Build it and they’ll come’ — we aren’t sure that’s the best approach for integrating offshore wind with the existing grid.”

April 25, 2019

PG&E Departure Leaves EIM Vacancy

By Hudson Sangree

The CAISO Energy Imbalance Market’s Governing Body will search for a candidate to replace former member Kristine Schmidt after she resigned earlier this month to join embattled PG&E Corp.’s board, EIM leaders said Wednesday.

Schmidt was selected April 3 to sit on PG&E’s 13-member board along with her onetime boss at FERC, former Commissioner Nora Mead Brownell, who was named chair. The board appointments are likely to be approved at PG&E’s next in-person shareholder meeting, probably in June. (See Former FERC Commissioner Brownell Named PG&E Chair.)

EIM Chair Valerie Fong said at Wednesday’s Governing Body meeting that Schmidt had to resign from the EIM because “she would be conflicted. She couldn’t be on both boards.” Schmidt resigned April 1, Fong said.

Governing Body members thanked Schmidt for her service and wished her well. Schmidt joined the body’s teleconference briefly and also expressed her gratitude.

An EIM nominating committee will seek to fill the seat.

Also, at Wednesday’s meeting, Fong and colleague John Prescott were both re-elected by the only two members allowed to vote — Carl Linvill and Travis Kavulla. Normally, Fong and Prescott would have been asked to leave the room for the vote, but they were only requested to cover their ears.

After extensive stakeholder input, CAISO’s Board of Governors appointed the EIM’s first Governing Body — which included Schmidt, Fong, Linvill and Prescott — in June 2016. The EIM allows real-time interstate trading of electricity and has been widely hailed as a success, saving its participants an estimated $565 million since it began in November 2014.

PG&E Corp. and its utility subsidiary Pacific Gas and Electric filed for Chapter 11 bankruptcy reorganization in January, citing the potential for billions of dollars in wildfire liability.

The company is going through a board “refreshment” process after two years of deadly and catastrophic fires. It has faced political pressure to include more utility and safety experts on its board.

PG&E said Monday it had reached an agreement with Blue Mountain Capital Management, a major shareholder that opposed its initial board choices. The company said it would appoint one of Blue Mountain’s preferred candidates, Fred Buckman, the former CEO of Consumers Energy and PacifiCorp. Buckman will replace Richard Kelly, who resigned from the board. PG&E also said it was hiring Christopher Hart, former chairman of the National Transportation Safety Board, as a special independent safety adviser.

April 25, 2019

NERC Standards Retirements Go to Final Ballot

By Rich Heidorn Jr.

A NERC standards drafting team (SDT) has opened a final ballot on the elimination of all or parts of 18 reliability standards as Phase 1 of the organization’s standards efficiency review (SER) nears its conclusion.

Ballot pool members will have until May 2 to vote on the changes: the withdrawal of one proposed reliability standard, the complete retirement of 10 standards and the elimination of certain requirements for seven standards. (See chart.)

All the proposed retirements received 88 to 99% support in segment-weighted voting in the initial ballot that closed April 12. “They all passed at pretty high percentages,” observed NERC’s Laura Anderson, standards developer for the SDT at a team meeting April 17.

NERC’s ballot body, representing its 10 industry segments, currently has 525 members.

Proposed retirements that clear a two-thirds segment-weighted threshold on the final ballot will proceed to final approval by NERC’s Board of Trustees, likely at the board’s May meeting. Votes from the initial ballot are automatically included in the final ballot, although voters can change their positions.

Pruning the Rules

The Standards Efficiency Review Retirements effort (Project 2018-03) was created to take a second look at the rules that have been created since FERC certified NERC as the electric reliability organization (ERO) in 2006.

Three teams — representing real-time operations, long-term planning, and operations planning — identified for elimination requirements that were duplicative, obsolete or that were administrative and did not provide reliability benefits. Many of the standards to be retired relate to commercial business practices governed by the North American Energy Standards Board (NAESB) Wholesale Electric Quadrant (WEQ).

NERC last month closed the comment period on Phase 2 of the SER project. The phase involves considering changes in six areas of the organization’s operations and planning (O&P) and critical infrastructure protection (CIP) standards, including evidence retention time frames, moving requirements to guidance, simplifying training requirements and consolidating data exchange requirements. (See “Chair Urges Comments on Standards Efficiency Review,” NERC Standards Committee Briefs: March 20, 2019.)

The comments on the Phase 1 recommendations indicated how much the industry has changed since NERC became the ERO and gained enforcement authority.

For example, Black Hills Corp. said requirements 16 and 17 of standard TOP-001-4 provide no reliability benefit. The rule is intended to ensure prompt action to prevent or mitigate instability, uncontrolled separation or cascading outages.

The requirements direct transmission operators and balancing authorities to provide their system operators with authority to approve planned outages of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels.

The requirements “don’t even align with most, if not all, standard business processes,” Black Hills’ Maryanne Darling-Reich said. “The outage coordinator, [supervisory control and data acquisition emergency management system], IT networking and communications departments determine the impacts of all ‘planned’ outages of telemetry equipment. Most system operators do not even have the technical knowledge to make a substantiated decision to delay or postpone this work.”

MOD Standards

Eight of the 18 standards proposed for retirement were from NERC’s modeling (MOD) family of rules. The SDT proposed the elimination of seven of the MOD standards, including those on calculations of capacity benefit margins, transmission reliability margins and transfer capability — requirements incorporated in NAESB standards.

The standard authorization request (SAR) that initiated the SER project said that available transfer capability (ATC) and available flowgate capability (AFC) are “commercially based values used to facilitate a market for unused transmission capacity in an open access environment and that the values do not directly control the operation of the [bulk power system]. … [Transmission operators] are ultimately responsible for operating the grid in a reliable manner consistent with system operating limits, not ATC/AFC values.”

The team also proposed not implementing MOD-001-2, which has been awaiting FERC approval since February 2014 (RM14-7). It was intended to ensure calculations of available transmission system capability support reliability and that the methodology and data behind the calculations are disclosed to applicable registered entities.

The SAR said MOD-001-2 was not needed because although ATC and AFC values can influence real-time conditions, other standards, including subsequent improvements to TOP rules, ensure that real-time operations observe system operation limits. The “commercially based values and market related issues [regarding ATC/AFC] should not be addressed through NERC reliability standards,” it said.

The project team discussed the results of the preliminary balloting on the elimination of all or parts of 18 reliability standards during a meeting at NERC’s Atlanta headquarters April 17. | © *RTO Insider*

Despite the high level of support for the retirements, there were some forceful dissents.

Duke Energy, for example, said it could not support the elimination of the seven existing MOD standards if MOD-001-2 is withdrawn.

“We disagree with the commercial-based focus that the drafting team took in the technical rationale document,” Duke’s Kim Thomas wrote. “While these MOD standards (and ATC calculation) may have some commercial-based elements to them, they also put in place valuable boundaries that help promote consistency in how the industry calculates these values. Removing these boundaries does not promote reliability for the bulk electric system and introduces additional burden to the real-time system operator.”

Southern Co. took a similar position, saying that transferring the seven MOD standards to NAESB without enacting MOD-001-2 would upset the “appropriate balance of addressing reliability-related concerns, while incorporating any market related issues.

“Simply stating that ATC/AFC calculations are primarily commercially focused elements and that there are mechanisms in place to address reliability in real time is an oversimplification of the ATC/AFC concept,” Southern’s Marsha Morgan wrote. “Inaccurately modeling and assessing transfer capability which considers real physical transmission limits on both the host and neighboring systems can create extremely complicated situations in real time that can unduly burden system operators.”

PJM, which was neutral on the elimination of MOD-001-2, supported the proposal to transfer the other MOD standards to NAESB, saying “reliability components of congestion management are handled amongst Eastern Interconnect parties through various established coordination processes.”

It warned against additional revisions to the NAESB WEQ rules, “especially those driven by issues unique to particular seams or between specific entities, as those issues may not be realized by other parties.”

“Therefore, blanket revisions may unnecessarily impact reliability and/or market aspects for other entities,” PJM’s Preston Walker said.

INT Standards

Also proposed for retirement are four interchange scheduling and coordination (INT) standards relating to interchange coordination, dynamic schedules, pseudo-ties and transmission loading relief procedures.

The SAR said the standards are duplicative of NAESB rules and that two of them are unenforceable because the “purchasing selling entity” is no longer a NERC registered function.

Duke also opposed the retirement of requirements 3.1, 4 and 5 of INT-006-4.

“We are not confident that this issue is adequately covered in the NAESB standards. Unlike the NERC standards which aim to promote reliability, the NAESB standards are commercially focused, and are not viewed as essential to maintaining a reliable system,” Thomas said. “We believe that not having these conditions outlined could negatively impact reliability.”

Morgan disagreed, saying requirements 4 and 5 are duplicative of the NAESB e-Tagging specifications “and are not a reliability-related task performed by a NERC registered entity.”

April 25, 2019

MISO Stakeholders Weigh Restoration Pricing Options

By Amanda Durish Cook

A new MISO task team on Monday kicked off an effort to develop a scheme to compensate resources that deliver restoration energy in the event that the RTO’s wholesale market ceases to function.

“There’s no Tariff provisions for compensation during an islanding event,” MISO Director of Market Services John Weissenborn explained at the first meeting of the Compensation for Restoration Energy Task Team. He noted that MISO’s black start and NERC recommendation-based schedules are insufficient to cover all generation as it comes back online.

Stakeholders said having a restoration pricing structure in place may prevent yearslong legal battles over compensation following blackout conditions.

MISO has yet to make any decisions but is considering implementing either a dollar-per-megawatt filed rate or recovery based on verifiable costs. Multiple stakeholders said they preferred the latter over the former.

Weissenborn asked stakeholders to think about how an islanding event would interrupt the day-ahead market and how MISO might measure the imbalance and compensate afterward. He also pointed out the RTO would have to confer with state regulators to assess the implications of having a new rate schedule in place.

MISO would likely rely on an after-the-fact settlement to compensate resources, Weissenborn said, adding that the task team should examine how current settlement rules might apply to a restoration pricing structure and how normal settlements would resume after an event.

The system would not be able to price nodes within an area experiencing an islanding event, Weissenborn said, asking stakeholders to think about whether they would want to come up with a nodal price per load.

MISO has said it would complete all billing with no expectation that local balancing authorities calculate settlements. However, stakeholders asked how the RTO would ensure that prices are separated down to the LBA.

The RTO may use a five-year-old white paper on the subject as a starting point for the pricing structure. (See Old Analysis Could Guide MISO Restoration Pricing Effort.) In that paper, MISO proposed using either 110% of a FERC-approved rate or a $100/MWh price, whichever is greater. As FERC-filed rates include start-up costs, the RTO said a real-time revenue sufficiency guarantee would not apply.

Weissenborn said using a static, filed rate would be “a relatively simple solution,” and MISO could use the $100/MWh figure as a pricing floor. “We would have a filed rate, and we can come up with an output to multiply by,” he said. But he added that pricing should ensure that generators recover start-up costs, which are amortized over commitment periods in MISO’s usual energy pricing.

He also said that many generation owners and MISO staff involved in the 2013 white paper are no longer participating in the RTO. Using the white paper as a basis for a pricing structure without knowing the reasons behind the proposal might prove tricky when making a case to FERC, he said.

‘Extreme Event’

The task team will also have to consider how resource owners would establish eligibility for the new rate schedule, Weissenborn said.

Xcel Energy’s Kari Hassler said MISO might “glean” some aspects of pricing from recent emergency events. In the most recent maximum generation emergency in late January, emergency pricing floors defaulted prices to above $600/MWh.

“This is going to be more an extreme event,” Hassler reminded staff, saying a $100/MWh figure was probably too low considering the extraordinary circumstances of a system blackout and islanding.

Entergy’s Al Ralston said he remembered hurricanes that hit the company’s service territory in 2005 and 2008, causing “thousands of megawatts unable to be served” after several generators, substations and transmission went down. He said in those cases, Entergy — not yet a MISO member — used bilateral agreements to negotiate prices after the fact.

“We wanted to have prices that allowed generators to recover their legitimate costs and, at the same time, didn’t allow generators to gouge the load,” Ralston said. He asked MISO to devise a “reasonably” straightforward pricing method that would achieve both goals.

However, he also said plants must sometimes be evacuated or are difficult to reach because of flooding. He asked MISO about costs in excess of normal operations, such as to feed and board plant operators. He also warned that a restoration event can sometimes take weeks, and MISO may not want a static price in place that allows generators to make unchecked profits.

“This is not something that just happens and it’s over in a day,” Ralston said.

“I do agree with you. We have to have a good balance,” Weissenborn said as he took notes.

Stakeholders also suggested MISO put rules in place to create a temporary stakeholder group following a restoration event to educate resources on what they can and cannot submit in a verifiable cost-based offer. Some also suggested MISO’s Independent Market Monitor could work to verify offers after a restoration event.

Weissenborn also asked stakeholders to keep in mind that MISO would not be in control of dispatch as the system is restored.

“I think the harsh reality is we’re not energizing resources based on economic decisions as we restore the system. It’s based on ‘let’s start getting load back,’” Weissenborn said.

Ralston said the characterization was “exactly right.”

The task team will meet two more times, including on May 1, before presenting a pricing recommendation to the Market Subcommittee.