As the U.S. electric industry increasingly is being driven by decarbonization and its related impacts on the traditional grid, the expansion of renewable energy is changing how investment dollars are allocated across the system. With it comes a particularly challenging issue: how does this change ripple back to the multibillion-dollar buildout of renewable generation?
That’s abundantly clear in Black & Veatch’s 2020 Strategic Directions: Electric Report, where nearly four in 10 respondents — 39 percent — said the growth of renewable energy will be the key driver of new transmission investment over the next five years. That handily outdistanced resiliency and reliability, congestion, interregional coordination and the retirements of fossil fuel-powered plants.
Across the U.S., from the PJM Interconnection in the East to large utilities in the Midwest and PacifiCorp out West, transmission-owning utilities and transmission organizations continue to be deluged with transmission interconnection requests, most tied to remote utility-scale renewable generation. Such demand isn’t expected to decline any time soon, and it could be further enlarged should proposed offshore wind power projects off the East Coast move ahead to construction.
Demand across the country for transmission projects linked to renewable energy remains robust, with survey respondents from the Midwest and West seeing the strongest demand for transmission investment tied to the growth of renewable energy.
Long transmission lines are the necessary connection to deliver renewable energy from the remote places where it is generated to load centers where it ultimately is used. As more and more utilities take a “green pledge” to decarbonize their fuel mixes — whether prodded or not by their constituents or regulators — more transmission lines will be needed to satisfy those goals. With increasing challenges to transmission access, existing lines at brownfield fossil sites, etc., will play a vital role as interconnect points for storage, green power, reactive power and/or largescale renewable with several notable examples occurring in the industry over the past year.
Industry leaders continue to voice concerns about integrating renewable generation into the transmission system, but that uneasiness gradually appears to be diminishing, particularly as more renewable generation comes online. Utilities and developers have found an orderly, safe and cost effective way to add thousands of megawatts of new renewable generation to the nation’s grid.
The industry’s planned spending surge in “local renewables” will help drive increased investment in distribution systems. But with continued investments in large-scale renewable and the potential for expansion of the electrical vehicle fleet forecasted, investment decreases in transmission aren’t evident in the survey results. Investment in a reconfigured transmission infrastructure to serve a changing generation portfolio is not the only, or in many cases, the prime issue. Another key challenge is managing current transmission assets to ensure resiliency and reliability — a tricky endeavor that requires much-improved asset condition monitoring, more sophisticated failure analyses and targeted predictive maintenance investment. Some utilities are investing in these requirements. Climate change also is driving investment, with severe weather incidents such as Superstorm Sandy in 2012 and Hurricane Harvey in 2017, and multiple hurricanes this year (Islais and Laura) having caused and will continue to result in many utilities investing heavily to “harden” their transmission and distribution (T&D) systems. In the West, destructive wildfires also are accounting for transmission upgrades, both to rebuild lines damaged or destroyed by flames or to find more resilient, reliable ways to keep the lights on.
Nearly four in 10 — 38 percent — respondents still said they have increased plans to invest in transmission projects more than last year. Approximately half said they have not changed their transmission investment plans over 2019.
All the while, nearly half of those who plan to reprioritize capital spending to existing assets will direct those investments to their transmission and distribution systems. But there’s a distinct drive to digitization among those who plan to divert spending to existing infrastructure. A significant number of respondents said they would invest in some type of technology upgrade, including automating operations (35 percent), increased remote monitoring and diagnostics (23 percent) and conversion of analog systems to digital systems (20 percent).
Of course, upgrading T&D systems also could have a digital dimension, as substation and transmission upgrades often include migration to microprocessor-based technology, fiber optic communication and enhanced monitoring of assets to ensure existing assets are utilized effectively. Digital substations also are being deployed with some northeastern utilities moving from pilot projects to large-scale implementation of digital substations.
Site permitting remains the biggest hurdle to new transmission investment, along with evolving incentives policies and return-on-equity determinations for new transmission construction. President Donald Trump’s July decision to streamline the National Environmental Policy Act (NEPA) to make it faster and easier to construct more energy infrastructure could address these concerns, though the new rule is widely expected to be litigated.
Respondents overwhelmingly found that FERC’s Order 841, which introduced battery energy storage systems (BESS) to the wholesale energy markets, would have a positive impact on transmission investment over the next five years. That order recently was upheld by a federal appellate court. While some market participants see BESS as a partial alternative to efforts to build new transmission, it won’t be a one-for-one replacement for resolution of all transmission constraints. However, recent acceptance by FERC of MISO’s proposed modification of their OATT for storage as a transmission only asset (SATOA) certainly opens up additional interest in BESS’s role in the transmission marketplace.
On the subject of bulk electric supply security, which the Trump administration sought to make more secure with a May 2020 executive order, more than one-third of respondents — 36 percent — said they were taking a wait-and-see approach until the Department of Energy issued a proposed regulation. Slightly less than one third said they actively were auditing equipment directly purchased from vendors, while roughly one in five said they were auditing the supply chains of contractors.
But there remains considerable uncertainty over what equipment is included in the executive order along with what definitive action will be required once the supply chain impacts from “adversarial” countries are understood.
There also are additional potential impacts to the transmission supply chain with a Section 232 investigation to be conducted under the authority of the Trade Expansion Act of 1962. Preliminary reports said the Section 232 inquiry would focus on grain oriented electrical steel (GOES), which is a key component in transformers that have a substantial lead time. The potential outcome of this investigation may be tariffs on GOES to ensure continued viability of domestic manufacturing capability.
Finally, nearly half of respondents — 48 percent — said they were not considering and probably would not convert any of their AC transmission lines to high-voltage direct current (HVDC) ones. Such lines offer an advantage over AC counterparts in that there are fewer line losses, but making the conversion is greatly expensive. Typically, such a transition only pencils out if the owner wants to move a large amount of power across a large geographic footprint.
Conversions do have a place, particularly larger entities with a larger geographic footprint, as shown by the 10 percent of respondents that have considered and implemented conversions. Should offshore windfarms get built, HVDC may be the transmission option of choice, noting its implementation on projects in this market in Europe.
About the Authors
Kevin Ludwig is the global transmission technology portfolio manager for Black & Veatch’s power business. Ludwig has more than 20 years of experience in the power industry. In his present role he is responsible for monitoring technology changes, development of solutions and solution specific resource management for the transmission market.
James Hendrickson is a senior managing director in Black & Veatch Management Consulting. With more than 30 years of experience in power and gas consulting, Hendrickson is considered a driving for in the industry, assisting clients in assessing, develop next generation business and capability models and deploy new technologies ranging from DER to digitalization and analytics across competitive and regulated markets.
