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.)

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 website 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.

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 Resilience 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