ColumbiaGrid: Board of Directors approves 2019 BTEP

ColumbiaGrid on March 7 said that its board of directors in February adopted the 2019 Biennial Transmission Expansion Plan (BTEP), which provides details of ColumbiaGrid’s planning activities that occurred during the 2017-2018 planning cycle.

The BTEP noted that the culmination of all of the efforts is the biennial 10-year transmission expansion plan – 2019 BTEP – which lists such projects as the:

  • Estimated $110m “Eastside Project: Lakeside 230/115 kV Transformer and Sammamish-Lakeside-Talbot Line Rebuild to 230 kV” project in the Puget Sound region, sponsored by PSE, with a scheduled completion date of 2020. The project involves rebuilding the Sammamish-Lakeside-Talbot 115-kV lines, as well as energizing one at 230 kV and installing a new 230/115-kV transformer at Lakeside
  • Estimated $60m “Raver 500/230 kV transformer and a 230 kV line to Covington substation” project in Puget Sound, sponsored by BPA, with a scheduled completion date of 2020. The project involves adding a 500/230-kV transformer at Raver and a 230-kV terminal at Raver for a Raver-Covington 230-kV line
  • Estimated $30m “Longview-Kalama 230 kV line” project in the “Western” region, sponsored by Cowlitz, with a scheduled completion date of 2020. The project involves building a new 230-kV line from BPA Longview to Kalama

Discussing the 12 major studies and support services that were provided in the most recent planning cycle, the BTEP noted that a “System Assessment,” for instance, was conducted in each year of the planning cycle, with the main objective of the assessment being to identify “regional” needs; generally, the assessment in year-one identifies the problem areas and potential needs whereas, the assessment in year-two refines and reexamines the system, problem areas, and needs.

ColumbiaGrid produces two documents that outline the details of the system assessments, which include a “Study Plan” and “System Assessment Study reports,” the BTEP added.

Since the main objective of the system assessment is to identify “regional” needs, the assessment document has focused its reporting on potential issues in the “Joint Areas of Concern,” which can be identified as potential needs that involve multiple ColumbiaGrid members, the BTEP said. Those areas are identified when multiple parties had outages that caused overloads and/or had facilities that overloaded as a result of such outages.

The BTEP added that the 2017 and 2018 System Assessments identified 11 and eight joint areas of concern, respectively. However, the BTEP said, the issues in those areas are unlikely to be classified as regional needs since they are mostly local problems where mitigation plans have been developed, or they still require further evaluation by the affected parties. An area of concern in the 2018 system assessment was the “Oregon Coast,” the BTEP noted, adding that the concern was resolved as a “reduced load forecast in 2018 alleviated the issues.”

By comparing the joint areas of concerns that were identified in 2017 and 2018, a reduction in the number of identified areas was driven by several factors, including new load forecast. While the total load forecasts for the entire Northwest area are similar in 2017 and 2018, significant changes in load forecast were observed in some local areas, the BTEP added.

“Sensitivity studies” are conducted as part of the annual study program, as needed, and the scope of those studies can be varied, as well as depends on input from the planning participants. In 2017, the BTEP added, two sensitivity studies – which included the “N-1-1 Outage and High Renewable Studies” – were performed. In 2018, ColumbiaGrid combined the High Renewable Study with the “Economic Planning Study,” the BTEP said, noting that that resulted in only one sensitivity study in 2018.

The N-1-1 study, for instance, simulates the loss of a first element, followed by system adjustment, and then compounded by the loss of a second element. The BTEP added that a pared down list of contingencies is produced by using various tools and methods to evaluate the validity of the N-1-1 contingency combination; that method was used to study the 10-year heavy summer and 10-year heavy winter cases. The results were then processed to identify N-1-1 combinations that resulted in a more severe overload than the N-1 outages by themselves, unsolved combinations, and if the outage combination involved multiple data owners.

At that stage, the BTEP added, voltage issues were not tracked. That methodology assumes adequate voltage support adjustments are available after the first contingency. The BTEP also said that the contingency list, results, and summaries were posted for participants to review to determine if any additional study or action is needed to address the identified issues.

The primary change between 2017 and 2018 was the additional processing of the cases after the initial results to minimize invalid issues found in earlier N-1-1 studies, the BTEP said, adding that that most often included preventing shunts and static var compensators outside the area from oscillating for outage combinations outside their area, for instance.

The 2017 System Assessment in the “2027 Heavy Summer Case,” for instance, showed 25,852 total N-1-1 overloads, 862 total primary outages resulting in N-1-1 overloads, and 1,085 total unsolved outages. The BTEP also said that the 2018 System Assessment in the “2028 Heavy Summer Case,” for example, showed 11,621 total N-1-1 overloads, 124 total primary outages resulting in N-1-1 overloads, and 7,700 total unsolved outages.

Of the High Renewable Study, the BTEP said that the study was performed in 2017, focusing on analyzing potential impacts due to generation portfolio changes with large increases of renewable generation and lower usage of fuel-based generation across the west. It was determined that a spring day at about 4 p.m., with minimal exports to California was the most likely scenario for high renewable production in the Northwest with non-peaking load levels. The BTEP added that overall, the study showed few overloads and unsolved outages, primarily attributed to the reduced stress from the load profile.

Among other things, the BTEP discussed FERC Order 1000 activities, noting that the “Order 1000 Functional Agreement” requires certain tasks to be conducted as part of ColumbiaGrid planning activities, including allowing proponents of an Interregional Transmission Project (ITP) to submit their proposals to be evaluated by the “Relevant Planning Regions.”

During the 2018 ITP submission window, six proposed ITPs were submitted to the Western Planning Regions, including TransWest Express LLC’s TransWest DC project submitted to NTTG and WestConnect, the BTEP said.

ColumbiaGrid was not identified as a relevant planning region and did not receive any of those proposed ITP submittals into its regional transmission planning process for evaluation. The BTEP added that the relevant planning regions are evaluating those ITPs and that the scheduled completion time of that task is the end of 2019.

About Corina Rivera-Linares 2848 Articles
Corina Rivera-Linares, chief editor for TransmissionHub, has covered the U.S. power industry for the past 14 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.