Transmission Bids for Green Spending at DOE

Originally published for customers February 14, 2024

The Department of Energy (DOE) has recently issued a call for bids as part of a $1.2 billion initiative aimed at expediting the expansion of electric transmission infrastructure through capacity contracts, with the DOE acting as the "anchor customer." This marks the second Request for Proposals (RFP) of its kind, following the initial round which led to the selection of three transmission projects receiving $1.3 billion in funding.

The national conversation about obstacles to constructing new electrical infrastructure in the U.S. frequently focuses on complex permitting and local opposition. But permitting is just one wobbly leg of a three-legged stool. The other two—comprehensive planning and funding incentives—are equally vital. So when Uncle Sam steps in with $2.5 billion dollars to help stabilize that third wobbly leg, it is worth examining the winning projects, their potential grid impacts, and how developers plan to navigate these challenges.

While the projects selected in the first round are interstate, they do not bridge the gap between the three major grids or traverse the boundaries of regional entities responsible for grid reliability regulation. This is likely due to the ongoing challenges in constructing true interregional transmission lines. The projects that are “ripe” must avoid as much controversy as possible to be “picked” by DOE. Hopefully, DOE will find true interregional projects in the second round, but it will probably select more projects in other regions (Northwest, Midwest, Southeast) that minimize the permitting burden and can connect additional renewables.

The No Plan Plan - U.S. Transmission Planning Background

Source: Energy Information Administration

“Everybody has a plan until they get punched in the face” is one of Mike Tyson’s most famous quotes, but the part “Then, like a rat, they stop in fear and freeze” is often left out, and aptly characterizes the current state of interregional electric transmission planning in the U.S. — stagnated in inaction. The absence of a cohesive plan is exacerbated by the lack of a unified national grid. Instead, there are three distinct grids — one in the West, one in the East, and one in Texas — with minimal interconnection and power exchange between them.

Further complicating matters, these grids are fragmented into a mosaic of operators with divergent interests and varying levels of initiative in conducting long-term transmission assessments and regional planning. Approximately two-thirds of these operators are Regional Transmission Organizations (RTOs) — nonprofit entities responsible for maintaining the grid and planning new transmission lines. The remaining third comprises individual utilities, sometimes loosely grouped in regional transmission planning associations, in traditional wholesale markets primarily in the Southeast, Southwest, and Northwest. Utilities in these markets are frequently vertically integrated – they own the generation, transmission and distribution systems used to serve electricity consumers — and some include federal systems (like the Tennessee Valley Authority), which are not under state or FERC jurisdiction.

There is one collection of entities focused on reliability worth mentioning. While the grids themselves may be functionally distinct, the North American Reliability Corporation (NERC) delegates the authority to enforce reliability standards to six regional entities (RE): Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), ReliabilityFirst (RF), SERC Reliability Corporation (SERC), Texas Reliability Entity (Texas RE), and Western Electricity Coordinating Council.

This fractured marketplace of competing interests and jurisdictions makes it hard to build the long-distance power lines needed to transport wind and solar nationwide. This is not to say there are no attempts at unity. In April 2022, FERC proposed a new rule to extend regional planning entities' transmission system mapping to 20 years instead of 10, aiming to better anticipate "changing generation mix, shifting demand patterns, and extreme weather." Chairman Phillips has emphasized finalizing this rule as a top priority, but even if it is finalized, it might not help much in those areas governed by planning assemblies as opposed to RTOs, which are more formally organized with their own staffs and boards of directors.

So just how hard is it to build transmission in the United States? To answer this question we looked at canceled and delayed transmission projects from NERC’s Electricity Supply and Demand database. As you can see in the chart below, of the 24 canceled projects in the data set, economics is most often the reason cited, including for the two largest projects. Unsurprisingly, permitting challenges are the most frequently cited source of delays.

DOE’s Transmission Facilitation Program

Against this backdrop, the Infrastructure Investment and Jobs Act created DOE’s Transmission Facilitation Program, which allows DOE to use $2.5 billion dollars in a revolving fund to support the development of “shovel ready” transmission projects in three ways: capacity contracts, loans, and public-private partnerships. DOE’s most recent request for proposals (RFP) will use capacity contracts whereby DOE will serve as an “anchor customer,” buying up to 50% of the planned capacity for up to 40 years, then selling the contract to recover costs. Greenfield projects must meet a minimum capacity of 1,000 MW to qualify for the program and DOE set a threshold of 500 MW for projects that enhance existing transmission lines or construct new lines within established transmission, transportation, or telecommunications infrastructure corridors.

This is the second RFP of its kind. DOE announced the first RFP in 2022, and in October of 2023, it selected three transmission lines for $1.3 billion in funding that will add 3.5 GW. This second RFP follows a two-part process where applicants submit an initial project proposal illustrating how it will contribute to the program’s transmission, climate goals, and social goals. The second part involves a more detailed application and if the project gets the green light, then it's on to negotiating capacity contracts.

A Renewable Shootout in the Wild West and a Great Northern Whale

You can learn more about the future by looking at the past. The three projects selected at the last round share some commonalities and may point to the sort of project that will be selected in DOE’s most recent round. Back to our stool analogy, all three have benefitted from extensive planning, particularly with respect to permitting, leaving the financing component as ripe for DOE investment. While they all serve a regional need for increased transmission capacity, grid reliability, and access to renewable energy, none crosses boundaries between the three major grids and all stay within the boundaries of the governing RE responsible for enforcing reliability standards in the region.

The Cross-Tie and Southline Projects

Two of the three projects selected in the first RFP will be in the American Southwest, sitting in the Western Grid and with WECC — the largest and most diverse of the six REs — enforcing reliability standards. The Southwest electric market is one of those complicated Western areas bereft of RTO leadership. It encompasses the Arizona, New Mexico, southern Nevada (AZ/NM/SNV) and the Rocky Mountain Power Area (RMPA) sub-regions of WECC. With a summer peak demand of approximately 42 GW, the region boasts around 50 GW of generation capacity, primarily consisting of coal and nuclear baseload and gas peaking generation. Both of these projects aim to bring renewables to these markets, which would fundamentally alter supply and demand dynamics and potentially create opportunities for coal displacement. To illustrate this dynamic, we overlaid the projects with the current generation footprint on the below map.

The Cross-Tie Project 500kV Transmission Line Project will be a new bi-directional, 1500 MW, 214-mile transmission line connecting Utah and Nevada's electrical systems. The project aims to enhance transmission capacity, improve grid reliability, and facilitate access to renewable energy sources, particularly solar generation in Utah, Nevada, and California, and wind generation in Wyoming and Idaho. Construction is set to begin in Q1 2025, with completion targeted for 2027 at an estimated cost of $750 million.

Most of the project will cross BLM and Forest Service land, but 14% will cross private land, which could be a hurdle. The project's permitting process has reached key milestones, with the anticipated release of the Final Environmental Impact Statement and Forest Service Draft Record of Decision in the summer of 2024, followed by additional Records of Decision expected in the winter of the same year. Once operational, the transmission line is expected to meet 14% of the mountain region's projected 2,300 GW-mi of new transmission capacity needs by 2030.

The proposed 175-mile, $800 million Southline Transmission Project stretching from New Mexico to Arizona is designed to deliver 748 MW of renewable energy from southern New Mexico to key markets in Arizona. This project is the furthest along and is entering its final stages of development, including engineering completion, land acquisition, and finalizing commercial arrangements. Scheduled to begin construction in the first quarter of 2025, the project aims to contribute 14% of the Southwest region's 935 GW-mi transmission needs by 2030. The first phase is expected to be operational by 2027 and the full project online by 2028.

From a permitting perspective, a significant portion of the project involves upgrading existing transmission lines, streamlining regulatory approval. The project developer has already successfully navigated a complex multi-year federal and state regulatory process - the final EIS was published in October 2015, followed by RODs from the Bureau of Land Management (BLM) and Western Area Power Administration (WAPA) in April 2016. State siting processes were completed in Arizona and New Mexico in February 2017 and August 2017, respectively.

Twin States Clean Energy Link

Switching focus to New England, the 1,200 MW HVDC bidirectional Twin States Energy Link project would sit in the Eastern grid, with the NPCC enforcing reliability standards. The project is envisioned to connect New England to Quebec, Canada at the cost of roughly $2 billion. Its goal is to bolster New England's grid capacity, enhance resiliency, and access clean energy from Quebec, including wind and hydropower imports. Additionally, the project aims to connect to developing offshore wind resources in New England. When complete, the DOE estimates that it would contribute 79% to the Northeast's interregional transfer capacity needs by 2030. Construction is slated to commence in Q3/Q4 2026.

This project is notable for its ingenuity in avoiding controversial permitting issues — it will cross beneath a river, be buried, and upgrade existing transmission lines. Specifically, it will cross below the Connecticut River at the Vermont-New Hampshire border, then connect to approximately 26 miles of new underground lines along a highway. From there, it is envisioned to upgrade 110 miles of existing transmission corridor.

Power generation in this region is controlled by the New England ISO (ISO-NE), serving six New England states: Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont. ISO-NE relies primarily on natural gas-fired and nuclear generation, accounting for 49% and 31% of the systems supply in 2016, respectively.

From a permitting perspective, the process involves upgrades and burial along existing transmission rights-of-way and state highways. This includes upgrading 110 miles of existing alternating current overhead lines and installing 50 miles of new underground lines along highways in Vermont, and 25 miles in New Hampshire.

Looking Forward

Like natural gas pipelines, electric transmission networks can experience congestion, and the construction of new lines can alter supply and demand dynamics, thereby influencing pricing. However, unlike natural gas, transmission infrastructure is neutral towards generation sources. As regions incorporate diverse forms of generation, the interplay of supply and demand becomes increasingly intricate, particularly when factors such as preference for renewable energy lead some consumers to pay a premium. By the time these projects are built, much will likely have changed in the generation mix. Consequently, predicting the effects of a new transmission line is as challenging as its construction. We will continue to monitor the progress of these projects and any others that DOE approves in this most recent RFP.