Page 1169 – RTO Insider

May 1, 2018

SPP Board of Directors/Members Committee Briefs: April 24, 2018

KANSAS CITY, Mo. — SPP’s Board of Directors was last week forced to table the appeal of a rejected revision request, cutting short the discussion when they realized the supporting documentation was not included in the background materials.

The Tariff change (MWG-RR272) requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period. It failed to receive the Markets and Operations Policy Committee’s (MOPC) endorsement by a handful of votes. (See Vote to Make Variable Resources Dispatchable Falls Short at MOPC.)

SPP board revision request — April’s Board of Directors/Members Committee meeting. | © *RTO Insider*

However, additional information on the measure was not part of the 638 pages of background material for the Apr. 24 meeting, leading Director Phyllis Bernard to move to table the measure “until we have further background information in front of the Members Committee before we vote.”

The Members Committee agreed with Bernard. Oklahoma Gas & Electric abstained from the vote.

The rejection was appealed by members, SPP staff and the Market Monitoring Unit (MMU).

Director Larry Altenbaumer, in one of his final comments before assuming the board’s chairmanship, told directors and members to plan on making a decision during their next meeting in July.

“If you have ideas to improve the process, you’ve got a quarter to make that decision,” he said.

In bringing forward the revision request, the Market Working Group said it would increase reliability and market efficiency through the reduction of manual out-of-merit energy orders to mitigate constraints.

The proposal applies to about 6 GW of NDVERs, which are generally older wind resources. However, it exempts about 2 GW of resources that don’t have direct interconnection agreements with SPP or are registered as qualifying facilities under the Public Utility Regulatory Policies Act (PURPA).

MMU Executive Director Keith Collins argued for the change, saying it’s a “global market efficiency issue” and would help reverse the recent growth of negative real-time pricing in SPP’s markets.

“To the extent resources are not flexible and capable of availing themselves to the system, we see an increase not only in frequency but [also] the magnitude of prices when we are unable to dispatch those resources,” Collins said. “Operators have to skip over the NDVER and find another resource.”

He pointed out that recent SPP analysis has found that dispatchable resources classified as non-dispatchable have “significant effects on the market congestion we’re seeing.”

The measure found resistance from stakeholders with renewable interests who said the rule change would add costs to existing power purchase agreements.

“If we can address the rule change, we’re taking a negative from the system, and that has a lot of global benefits,” Collins said. “We don’t deny some resources will face increased costs, but we believe the whole market can benefit from that.”

SPP Operations Vice President Bruce Rew said the rule would lead to a more efficient market through better management of congestion.

“It’s a much smoother operation for us to be able to dispatch those resources that may be down at the time, rather than the generator making that decision when to come on and off,” Rew said.

Directors Approve Previously Tabled Sponsored Upgrade

While the board was forced to table one voting item, it took another one off the table when it approved a sponsored upgrade of an OG&E transmission line that MOPC was unable to take action on.

OG&E requested MOPC delay a vote until it could address its concerns about the upgrade with SPP. The project is sponsored by EDF Renewable Energy, which wants to upgrade terminal equipment and rebuild an 11-mile, 138-kV line near Ponca City and its 154-MW Rock Falls wind farm, which became operational in December. (See “OG&E Raises Concerns over Third-party Tx Line Upgrade” in SPP Markets and Operations Policy Committee Briefs: April 17, 2018.)

SPP answered all 23 of the questions submitted to it by OG&E, but the utility said it still has questions about the project’s cost allocation and asked for additional time to get answers.

“This is a small project, in and of itself. It’ not going to break the bank for anybody,” OG&E’s Greg McAuley said. “The precedent here is what some of the [transmission owners] are concerned about. If you had a $100 million to $200 million project, you would see a much different amount of concern. We’re continuing to work to close the gaps in the Tariff we think exist, so we still ask for additional time to get those questions answered.”

EDF has said it will seek cost recovery through SPP’s Attachment Z2 revenue crediting or incremental long-term congestion rights. Attachment Z2 of SPP’s Tariff assigns financial credits and obligations for sponsored transmission upgrades, with directly assigned Z2 network upgrades allocated to SPP’s base plan.

“A project like this, if it just remains between EDF and OG&E, I don’t think it will have impacts,” said Nebraska Public Power District’s Paul Malone, who chairs the MOPC. “But to the extent this project qualifies for Z2 credits, we’re all going to end up paying for that. Thus, the vested interest.”

Attorney Dan Simon represented EDF and said he saw no legal reason for members to delay their endorsement of the project.

“We’ve gone through the process as dictated by the Tariff and the staff,” Simon said. “We understand OG&E has a number of important questions,” but “all of those questions are things that are already dictated by the current language in the Tariff,” and therefore do not provide a justification to delay the request.

Simon said EDF worked with OG&E to develop a cost estimate before it submitted its official upgrade request to SPP, noting OG&E did not raise concerns until the MOPC meeting.

“It’s been based on that information that we’ve continued to proceed through the transmission process to submit this request. We don’t think it’s appropriate to allow these questions coming so late in the process to delay our upgrade request,” he said.

“This project is time-sensitive. The sooner this gets placed into service, the sooner it will relieve congestion, and we all realize economic benefits from that,” Simon said.

The measure passed the Members Committee by a 14-3 margin, with OG&E, American Electric Power and the Omaha Public Power District voting in opposition. The Oklahoma Municipal Power Authority abstained.

MMU Shares Draft of State of the Market Report

Collins shared the MMU’s draft of its annual State of the Market Report with the board and members. He declared the market to be “competitive and efficient,” citing low energy prices, declining mitigation and make-whole payments, along with declining levels of excess online capacity and the alleviation of a congestion bottleneck.

Collins said total market costs last year approximated $24/MWh, a 7% increase from 2016, driven by a 14% rise in natural gas prices. As an example, the MMU pointed to the Panhandle hub, where the average gas price increased from $2.32/MMBtu in 2016 to $2.65/MMBtu in 2017.

Wind resources accounted for about 70% of the SPP footprint’s 2.2 GW increase in nameplate generation capacity last year, but the rate of new additions has declined significantly. SPP added about 11.4 GW of generation in 2015 and 3.9 GW in 2016.

“Even so, wind generation continued to increase as it represented almost 23% of system generation, up from 18% in 2016 and 14% in 2015,” the MMU said. In contrast, coal-fired units saw their share of total generation continue to slide, from 55% or more before 2016 to 46% last year.

Collins said SPP has a reserve margin of about 30%. “That can contribute to the high levels of competition we see,” he said.

He noted several issues that bear watching in the months ahead:

Self-commitment has declined but is still high overall.
Wind generation is under-scheduled in the day-ahead market.
The frequency of negative prices has doubled.
Real-time price volatility has increased.
Congestion has increased significantly.
Very few resources are being retired.

The final report will be released later in May.

Director Josh Martin, who chairs the Oversight Committee that oversees the MMU, said the monitor is fully staffed “for the first time in a long time.” The MMU added CAISO’s Adam Swadley as its lead economist to reach its full staffing level.

Finance Committee Looks to Engage Stakeholders

Finance Committee Chair Larry Altenbaumer told the board and members the committee has been studying a recovery mechanism that “appropriately” reflects the administrative fee as it tries to maintain a simple rate-design structure.

The committee has determined membership’s “full engagement” is necessary, Altenbaumer said, and will work with MOPC’s leadership in July to involve a broader stakeholder group.

The board unanimously approved three recommendations from the Finance Committee:

Accepting BKD’s 2017 financial audit, which noted “no issues or material/significant weaknesses.”
Engaging BKD to perform the 2018 financial audit and Thomas & Thomas to audit the employee benefit plan’s financial statements.
Taking out an $80 million bank loan with a 5-year maturity and floating rate pricing on outstanding balances under the guidance line.

SPP RE Tying Up Loose Ends

“As you all know, we’re going out of business,” said Dave Christiano, chairman of the SPP Regional Entity’s board of trustees, as he delivered what is likely to be the final RE update to the board.

Christiano said the RE will cease its compliance and enforcement activities by the end of June and be officially dissolved by September. The RE has already successfully transferred 25% of its data to NERC, the Midwest Reliability Organization and the SERC Reliability Corporation, he said, but it still has a number of loose ends to resolve.

“It’s pretty complicated, as you can guess,” Christiano said

SPP said last July it would dissolve the RE, ending a reliability oversight role that has been a source of concern at NERC and FERC. NERC approved the dissolution in February. (See NERC Board Approves Dissolving SPP Regional Entity.)

The RE’s staff of two dozen has dwindled to 17 employees, with all but five either having already found work within the RTO and other organizations or having decided to retire.

Christiano also recommended members read a joint report from the FBI and Department of Homeland Security, “Russian Government Cyber Activity Targeting Energy and Other Critical Infrastructure Sectors.”

SPP’s 2017 Annual Report: ‘Focus’

As it does every April, SPP handed out copies of its 2017 annual report during the meeting.

The report, titled “Focus,” highlights the “people, milestones, accomplishments, and challenges that made 2017 another exceptional chapter in [SPP’s] story.”

The report includes comments from a broad section of SPP staffers and how they work with their members.

Last Board Meeting for Westar’s Harrison

The board meeting was the last for Westar Energy’s Kelly Harrison, who represents public transmission-owning members on the Members Committee.

Harrison, who is nearing 60 years of age, said he is taking advantage of the Westar-Great Plains merger to take retirement. He said he would miss the SPP meetings, as well as the people who attend the meetings — who treated Harrison to a standing ovation.

“I, for one, am extremely appreciative of the care and the intellect Kelly has brought to the Members Committee,” Brown said, singling out Harrison’s financial acumen and participation on the Oversight Committee. “I couldn’t begin to count all the task forces and working groups Kelly has worked on over the years. Thank you, Kelly, from the bottom of my heart.”

Consent Agenda Clears Sponsored Upgrade, 7 Tariff Changes

Members unanimously approved the consent agenda, which included the re-baselining of a Nebraska Public Power District 69-kV and 161-kV project from $37.8 million to $27.5 million; a sponsored upgrade with the addition of a second 161/69-kV transformer at City Utilities of Springfield’s (Mo.) James River Power Station; funding the SPP retirement and post-retirement healthcare plans; and seven revision requests.

GIITF RR267 eliminates the “standalone scenario,” which considers each interconnection request by itself, from the definitive interconnection system impact study process. This will free SPP resources to focus on binding cluster study results, permitting their earlier availability. Staff will provide the standalone equivalent study models through existing confidentiality provisions to customers seeking to conduct a standalone scenario of their own.
MWG RR252 assigns an out-of-merit energy (OOME) cap and/or floor, allowing staff to economically dispatch the resource down or up within the ranges.
MWG RR259 modifies the market settlement posting and dispute timelines being implemented with the new settlement system, reducing the number of resettlement postings and manual processes resulting from revisions to meter and bilateral settlement schedules.
MWG RR273 automates several of the market settlement system’s charge types that are not yet part of revenue neutrality uplift processing, resulting in rounding/residual amounts that must be manually processed and distributed through miscellaneous charges. The new system is scheduled to go live in May 2019.
ORWG RR268 clarifies or removes outdated language from the operating criteria, improving SPP’s ability to perform reliability coordinator, balancing authority, transmission service provider and reserve sharing group functions.
ORWG RR269 clarifies language and removes antiquated and redundant language in SPP’s operating criteria and describes the existence of multiple standalone documents.
ORWG RR270 converts the operating criteria Appendix OP-2 to a standalone document, clarifies language and adds formatting improvements.

— Tom Kleckner

May 1, 2018

DTE Highlights Renewable Efforts, Wins Gas Plant Approval

By Amanda Durish Cook

DTE Energy is focused on plans to double its renewable energy capacity by the early 2020s and build a new, controversial $1-billion gas-fired plant recently approved by regulators, company executives told analysts during an earnings call last week.

First-quarter earnings fell nearly 10% to $361 million ($2.00/share) compared with 2017, but operating earnings jumped $20 million to $342 million. The utility posted revenue of $3.75 billion for the period.

During an April 25 call, DTE Energy CEO Gerard Anderson revealed more detail about the company’s plan to double its current renewable energy capacity primarily through new wind projects built over the next few years. DTE filed its plan with the Michigan Public Service Commission (PSC) last month.

“If approved, this will drive increased investment in new wind and solar projects,” Anderson said.

DTE last year said it would transition to cleaner energy sources and to reduce carbon emissions by more than 80% by 2050.

The company’s $1.7-billion proposes about 1 GW of new wind and solar projects in Michigan to be completed by 2022.

DTE Energy Earnings Q1 2018 Renewable Energy — DTE Pinnebog wind park in the Michigan thumb region | *DTE Energy*

“ …This plan is another significant step toward our carbon emission reduction goals, and those goals can be met in a way that continues to deliver reliable and affordable power for our customers as well,” Anderson said.

The plan includes two central Michigan wind farms providing 330 MW of new capacity: Pine River, set to be completed later this year, and Polaris, slated for completion by 2020.

Anderson said the two wind farms will be DTE’s largest and most efficient to date.

The plan also includes an additional 300 MW of new wind capacity by 2020 to support a new voluntary renewable energy program for DTE’s large business customers interested in reducing emissions, Anderson said.

Finally, DTE will complete another two wind farms in 2020/21 that will provide a combined 375 MW of capacity, Anderson said.

He also expects DTE to begin investing in more solar generation in the coming years.

“Along with the increased wind capacity, we’re also planning on adding 15 MW of solar power. Wind today is clearly lower cost than solar in Michigan, and thus we’re really concentrated on wind capacity in the near-term. But solar costs are improving, and we expect that by the mid-2020s, solar will be ready to play a more prominent role in our mix,” Anderson said.

He added that DTE plans to add more renewable energy generation beyond that outlined in the plan submitted with regulators.

Anderson’s comments on solar development come at a time when DTE has twice been accused of withholding interconnection data from independent solar developers seeking to connect new generation to DTE’s grid, as well as overcharging for studies requested to start on new projects. Both Cypress Creek Renewables and a Geronimo Energy subsidiary this month filed similar complaints with the Michigan PSC, claiming DTE’s responses violate a provision of the Public Utility Regulatory Policies Act (PURPA) that qualifying facilities have a right to interconnect with the host utility’s grid (U-20151, U-20156).

DTE representatives did not respond to a request for comment on the complaints.

Regulators Approve Controversial New Gas Plant

Still, DTE’s renewable plans will not match the output of its proposed $1 billion, 1.1-GW natural gas plant to be built in St. Clair County near the Canada border, which Michigan regulators approved Friday after concluding it “was the most reasonable and prudent means of meeting DTE’s future energy needs” (U-18419). The company wants to begin construction in 2019.

“DTE Electric’s recent and planned investments in energy waste reduction, renewable energy and energy storage, when coupled with this highly efficient gas plant, demonstrate that Michigan is a great example of an ‘all of the above’ strategy to meet our energy needs in a reliable, affordable manner that protects the environment,” Michigan PSC Chairman Sally Talberg said in a statement.

During the earnings call two days ahead of the approval, Anderson said he expected a “constructive outcome” in the proceeding.

Environmental advocates such as Sam Gomburg with the Union of Concerned Scientists have questioned the need for the plant, saying DTE’s commitment to the environment rings hollow when pushing such a large fossil fuel plant.

“There is plenty in the record to justify not approving this. [This was] a matter of how much backbone this commission has,” Gomburg said in a telephone interview with RTO Insider.

Gomburg said a combination of renewable generation and storage, energy efficiency measures and demand response could meet DTE’s needs more efficiently and inexpensively. He said DTE’s assessment in justifying the natural gas plant failed to explore alternatives.

“Even using their own tools, we find ways to meet their goal with cheaper options,” Gomburg said.

Gomburg warned about a future spike in natural gas prices or new regulations putting more emphasis on staving off the effects of climate change, making the plant costlier.

“I see a very high risk that ten years from now, as we’re paying this off, we’re [going] to regret this,” Gomburg said. “I see putting all your eggs into this billion-dollar basket as very risky.”

While Gomburg said DTE seems “disingenuous” in its goal to double renewable capacity while planning a large natural gas plant, he didn’t want to denigrate DTE’s goal of reducing emissions by 80% in little more than 30 years.

“I don’t want to say that the goal they’ve put forward is meaningless, but we can do more sooner. What matters is what carbon dioxide and mercury we emit now until 2050,” Gomburg said.

Power Up Michigan, a coalition of nine clean energy groups, said the plant is unnecessarily expensive, fails to create the level of jobs that new renewable sources could generate and is a “failure of innovation” to transition to clean energy sources.

However, in filings leading up to the approval, DTE said those who “suggest that there might be some other combination of resource options that might somehow be preferable from their self-interested perspective” ultimately failed to submit an alternative proposal.

“It again bears emphasis that DTE Electric presented the only specific proposal to meet the power need … established on the record,” the company wrote.

DTE said its analysis found that the gas plant would “appropriately” balance six characteristics, including reliability, affordability, cleanliness, compliance, reasonable risk and flexibility.

May 1, 2018

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

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

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

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

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

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

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

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

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

Winter Review Highlights Fuel Security Issues

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

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

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

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

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

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

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

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

Natural Gas Rules Home Heating in Northeast

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

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

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

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

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

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

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

Updating Needs Assessments to Reflect Latest Forecasts

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

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

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

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

Cost Recovery in Flood Hazard Areas

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

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

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

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

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

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

Eastern Conn. 2027 Needs Assessment Update

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

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

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

FCA 13 Zonal Boundary Determinations

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

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

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

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

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

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

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

Transmission Planning Technical Guide Update

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

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

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

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

— Michael Kuser

April 29, 2018

Calif. Legislation Shields Utilities from Wildfire Costs

By Jason Fordney

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

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

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

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

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

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

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

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

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

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

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

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

April 29, 2018

Stakeholders Oppose PJM PFR Mandate for Existing Units

By Rory D. Sweeney

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

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

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

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

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

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

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

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

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

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

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

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

Package Criticism

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

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

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

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

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

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

Next Steps

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

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

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

April 29, 2018

MISO Storage Group Begins Order 845 Consideration

By Amanda Durish Cook

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

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

MISO Energy Storage — AES battery storage | *AES*

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Process Holdup?

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

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

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

April 29, 2018

Dominion: ‘No Flexibility’ on SCANA Bid

By Rory D. Sweeney

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

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

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

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

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

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

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

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

April 29, 2018

PJM Stakeholders Clash Over “Heart” of Containment Provisions

By Rory D. Sweeney

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

April 29, 2018

SPP Regional State Committee Briefs: April 23, 2018

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

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

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

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

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

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

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

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

CAWG to Get Liaison with HITT

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

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

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

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

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

Committee Approves Triggers to Baseline Cost Escalation

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

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

— Tom Kleckner

April 27, 2018

EIM Body Approves Imbalance Conformance Rules

By Jason Fordney

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

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

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

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

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

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

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

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

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

Two Spots to Open

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

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

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

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