PJM interregional planning activities in 2013 encompass continuing study efforts with MISO, ISO-NE, others

In its first white paper in a series that PJM Interconnection intends to publish throughout the 2013 regional transmission expansion plan (RTEP) process, the RTO provided the status of approved backbone transmission lines, including the Susquehanna-Roseland 500-kV line, which has an in-service date of June 1, 2015.

That line has a required in-service date of June 1, 2012, but regulatory process delays have pushed the expected in-service date, PJM said.

Pennsylvania and New Jersey state regulators approved the line in February 2010 and April 2010, respectively. The line received final approval in October 2012 from the National Park Service (NPS), which issued a record of decision on Oct. 2, 2012, affirming the route chosen by PPL subsidiary (NYSE:PPL) PPL Electric Utilities and Public Service Enterprise Group (NYSE:PEG) subsidiary Public Service Electric and Gas (PSE&G). PJM also said that the NPS issued a special use (construction) permit on Dec. 12, 2012.

PJM will continue to operate to double circuit tower line limits in real-time operation until the new line is placed in service. The project’s Hopatcong – Roseland segment is expected to be in service by June 1, 2014.

During its 1Q13 earnings call in May, PPL reported that its portion of the project would cost about $630m, a $70m increase from the $560m cost estimate referred to during the company’s 4Q12 earnings call.

PJM also noted that the 2011 RTEP analysis identified a required in-service date for the 500-kV Mount Storm-Doubs line rebuild of June 2020, but recognizing the urgency of upgrading those aging facilities, Dominion (NYSE:D) and FirstEnergy (NYSE:FE) have indicated their intention to complete the reconductoring project by June 1, 2015, PJM said.

To that end, the rebuilt line’s capacity – with a rating 65% higher than the original – will be reflected in PJM’s 2015, 2016, 2017 and 2018 power flow case modeling.

The first white paper describes the input data, assumptions and scope associated with the body of analytical work comprising the second year of PJM’s 24-month RTEP process and the 2013 12-month process. The 24-month approach, implemented on Jan. 1, 2012, allows PJM to incorporate two conventional 12-month bodies of work, as well as a 24-month process, to consider the need for and efficacy of longer lead-time backbone transmission facilities, PJM added.

PJM’s RTEP process considers the aggregate effects of many system trends, including long-term growth in electricity use as well as the impacts of demand resource and energy efficiency programs.

PJM also noted that it addresses transmission expansion planning from a regional perspective, spanning transmission owner zonal boundaries and state boundaries to address the comprehensive system-wide impact of myriad upgrade drivers.

“Driven by a confluence of growing industry trends (particularly generation), regulatory mandates and FERC Order No. 1000 compliance, PJM continues to enhance its decision-making process so that the right RTEP upgrades are triggered at the right time,” PJM said.

While reliability and market efficiency requirements will continue to be a fundamental part of the RTEP protocol, decision-making has been expanded to examine public policy scenarios and variability in the factors that have traditionally driven transmission expansion, PJM said.

PJM’s 2013 RTEP process near-term analysis focuses on a five-year forward, 2018 case year, which provides sufficient lead-time to permit identified transmission upgrades to be built and placed in service.

Transmission upgrades approved by the PJM board through Dec. 31, 2012, and expected to be in service by June 1, 2018, have been modeled in PJM’s 2018 study year power flow base case. 

PJM also said that its January 2013 load forecast covered the 2013 through 2028 planning horizon. The 2018 RTO summer peak is forecast {per AP style) to be 168,813 MW, including the load of FirstEnergy’s American Transmission Systems Inc., Duke Energy’s (NYSE:DUK) Duke Energy Ohio and Kentucky and East Kentucky Power Cooperative, a Touchstone Energy Cooperative.

The forecast summer peak for 2013 is 155,553 MW and is projected to grow to 177,439 MW in 2023, a 10-year increase of 21,886 MW.

From a power flow modeling perspective, the 2018 summer peak from that January forecast – at an overall RTO demand of 168,813 MW – was the basis for developing PJM’s 2018 base case power flow model bus loads. Doing so, PJM added, will reflect that PJM now projects its RTO summer normalized peak to grow 1.3% annually over the next 10 years, down from 1.4% annually in the 2012 forecast.

PJM also discussed NERC standards, noting, for instance, that once NERC reliability criteria violations are identified, PJM works with all impacted parties to develop transmission plans to solve those violations.

The RTEP process 15-year planning horizon exceeds the scope of that required by NERC criteria and allows PJM to identify potential reliability criteria violations, the transmission solutions for which may require longer implementation lead times. PJM is able to determine if larger-scale, longer lead-time solutions can be identified to address groups of violations collectively.

On generation deactivations, PJM noted that they alter power flows that often yield transmission line overloads and, given reductions in system reactive support from those generators, can undermine voltage support.

After a formal deactivation request is received, PJM conducts reliability studies to identify reliability criteria violations caused by the deactivation and develop transmission solutions to solve them, PJM added.

“As part of this year’s 2013 RTEP cycle PJM will review – as it does every year – transmission plans developed in earlier years to determine whether, as a result of changing assumptions, previously approved transmission upgrades are still required and, if so, whether they are still required in the year originally identified,” PJM said.

Among other things, PJM said interregional planning is not new to it, and its RTEP process integrates interregional planning initiatives that have become more complex and expansive in light of emerging public policy issues and market dynamics.

Interregional planning activities in 2013 will encompass continuing study efforts with systems across the U.S. Eastern Interconnection, as well as with Midcontinent Independent System Operator (MISO), ISO New England (ISO-NE), New York ISO and the North Carolina Transmission Planning Collaborative.

The Eastern Interconnection Planning Collaborative (EIPC) stakeholder process for 2013, for instance, will differ from the stakeholder process developed and used for EIPC’s prior work, PJM said, adding that the continuation of EIPC efforts will be funded by participants and governed by a new regional-based stakeholder process.

PJM will also conduct a stability analysis on a jointly coordinated model to evaluate transient fault conditions in the ISO-NE system and subsequent impacts on the PJM system due to the Northern Pass transmission project. The analysis, PJM added, will focus on determining if faults in the ISO-NE system cause worst transient conditions in PJM than faults within PJM itself.

Northeast Utilities’ (NYSE:NU) wholly owned subsidiary Northern Pass Transmission recently proposed a new route for the project, partially underground and taking into consideration concerns about potential visual impacts and property rights, in the northernmost section of the project area in New Hampshire’s North Country.

PJM also said that is continuing coordinated planning activities with MISO this year under the terms of the joint operating agreement. A key aspect of the 2013 study process will include the development of a joint interregional production cost model for market efficiency simulations, marking the first time both regions will use a single, coordinated database.

PJM added that the study will examine 2017, 2022 and 2027 study years, with three generation expansion scenarios studied in each model year. One of the scenarios, for example, will model sufficient wind resources for PJM and MISO to satisfy combined states’ renewable portfolio standards requirements with about 40% of PJM’s needs imported from MISO, PJM said.

About Corina Rivera-Linares 2986 Articles
Corina Rivera-Linares, chief editor for TransmissionHub, has covered the U.S. power industry for the past 15 years. Before joining TransmissionHub, Corina covered renewable energy and environmental issues, as well as transmission, generation, regulation, legislation and ISO/RTO matters at SNL Financial. She has also covered such topics as health, politics, and education for weekly newspapers and national magazines. She can be reached at clinares@endeavorb2b.com.