Interconnections Seam Study
Through the Interconnections Seam Study, NREL joins national lab, university, and industry partners to evaluate the benefits and costs of options for continental transmission across the U.S. electric grid.
These interconnections would create a more integrated power system that could drive economic growth and increase efficient development and utilization of the nation's abundant energy resources, including solar, wind, and natural gas.
Strengthening the U.S. Power System
The three major components of the U.S. power system—the Western Interconnection, the Eastern Interconnection, and the Electric Reliability Council of Texas—operate almost independently of each other. Very little electricity is transferred between the interconnections due to limited transfer capacity.
This study quantifies the costs and benefits of strengthening the connections (or seams) between the Eastern and Western Interconnections to encourage efficient development and utilization of U.S. energy resources.
Modeling Approach and Preliminary Results
To evaluate the costs and benefits of potential enhancements of the U.S. interconnection seams, the study team analyzed a suite of power system futures. The study utilizes and analyzes results from three classes of power system models: long-term capacity expansion, year-long production cost, and power flow. The end result: in-depth insight on the economic, environmental, and reliability benefits of the study scenarios.
The study conducted a multi-model analysis that used co-optimized generation and transmission expansion planning and production cost modeling. Four transmission designs under eight scenarios were developed and studied to estimate costs and potential benefits. The results show benefit-to-cost ratios that reach as high as 2.9, indicating significant value to increasing the transmission capacity between the interconnections under the cases considered, realized through sharing generation resources and flexibility across regions.
The study results have been submitted to the journal IEEE Transactions in Power Systems for possible publication. Final results will be released when the journal article is accepted for publication. View a preprint of the article.
A slide deck is also available for download.
The video below and related videos on the NREL Learning YouTube Channel show system-wide generation and transmission flows at hourly time resolution for multiple scenarios and system conditions.
Two key models were updated and applied for this study: the Iowa State University CGT-Plan capacity expansion model and Energy Exemplar’s PLEXOS production cost model. CGT-Plan was used to design scenarios for a variety of grid conditions through the year 2038. PLEXOS was used to perform unit commitment and economic dispatch on the systems created by CGT-Plan.
CGT-Plan was used for a variety of different power system scenarios (including technology cost, gas price, transmission costs, and generation retirements) to model transmission and generation co-optimized for four different transmission designs. More details on the model are available.  These designs are shown in the figure below and include:
- Design 1 (top left): No increase in transmission capacity between the interconnections
- Design 2a (top right): Increasing capacity at existing back-to-back ties
- Design 2b (bottom left): Increasing capacity at existing back-to-back ties plus three long-distance HVDC ties between the interconnections
- Design 3 (bottom right): Nationwide HVDC
The study team used PLEXOS  to simulate the operation of the systems produced by CGT-Plan using a geographic decomposition method to estimate powerflows between regions (including both Eastern and Western Interconnections), then a region-specific day-ahead unit commitment for each region, and hourly economic dispatch for the entire grid. 
Pacific Northwest National Laboratory imported several selected NREL production cost model generation dispatch time periods into power flow models to perform initial contingency analysis for evaluating the reliability of each scenario.
The data and assumptions were kept as consistent as possible between the modeling domains and the interconnections. Some of the key data sources include:
- Transmission and Generation:
- 2012 Federal Energy Regulatory Commission Form 714 and Regional Transmission Operator websites
- Cost Assumptions:
- NREL Annual Technology Baseline for generating technologies
- WECC / Black and Veatch  for HVDC and alternating-current (AC) infrastructure
- Fuel prices from the Energy Information Administration's Annual Energy Outlook
National Renewable Energy Laboratory
Technical Review Committee
Representatives from utilities, power system operators, and industry organizations have helped guide this study by helping to define the study questions and methods and reviewing findings. Although these representatives have offered input throughout the study, the results and findings do not necessarily reflect their opinions or the opinions of their institutions. Representatives from the following entities have participated in our TRC process:
- Basin Electric Power Company
- Black Hills Energy
- Energy Exemplar
- El Paso Electric
- Electric Power Research Institute
- Electric Reliability Council of Texas
- Energy Systems Integration Group
- Great River Energy
- LS Power
- Midcontinent ISO
- Minnesota Power
- National Grid
- National Rural Electric Cooperative Association
- Public Service Company of New Mexico
- Solar Energy Industry Association
- Southwest Power Pool
- Tri-State Generation and Transmission
- Western Area Power Administration
- Western Electricity Coordinating Council
- Xcel Energy
Potential Future Work
Future work may include:
- Potential reliability and resilience assessment via AC power flow studies with steady-state and stability modeling (expanding on PNNL’s initial work on the topic)
- Consideration of system resilience and security requirements related to weather and extreme conditions
- Evaluation of natural gas delivery infrastructure and gas-electric operational coordination.
1. A.L. Figueroa-Acevedo et al., "Design and Valuation of High-Capacity HVDC Macrogrid Transmission for the Continental US," IEEE Transactions on Power Systems, DOI: 10.1109/TPWRS.2020.2970865.
2. See energyexemplar.com for PLEXOS description, and Beiter et al. 2020 for an example implementation (P. Beiter et al. The Potential Impact of Offshore Wind Energy on a Future Power System in the U.S. Northeast, Golden, CO: National Renewable Energy Laboratory. NREL/TP-5000-74191, 2020).
3. C. Barrows et al. "The IEEE Reliability Test System: A Proposed 2019 Update," IEEE Transactions on Power Systems, 35, 1, 119–127, Jan. 2020, DOI: 10.1109/TPWRS.2019.2925557.
4. M. Rossol et al. “An Analysis of Thermal Plant Flexibility Using a National Generator Performance Database,” Environ. Sci. Technol. 2019, 53, 22, 13486–13494, DOI: 10.1021/acs.est.9b04522.
5. Black and Veatch. Capital Costs for Transmission and Substations. Updated Recommendations for WECC Transmission Expansion Planning. B&V PROJECT NO. 181374. February 2014. https://www.wecc.org/reliability/1210_bv_wecc_transcostreport_final.pdf.