Transmission as a Capacity Resource

A case for allowing interregional transmission to offer into capacity markets and all-source procurements

The electric power sector is experiencing a moment of reckoning. Demand is rising at a pace we haven’t seen in decades, driven by electrification, AI data centers, and advanced manufacturing. At the same time, the traditional firm capacity resources we’ve long relied on, like natural gas CTs, are increasingly hard to come by and increasingly expensive. Whether due to public opposition, supply chain constraints, or policy-driven retirement trends, new gas capacity is no longer a guaranteed solution.

Meanwhile, utilities and grid operators are searching for alternatives to meet resource adequacy obligations. Battery storage is booming, but its capacity value is saturating. Demand flexibility, especially from large loads like data centers, is promising but still maturing. In short, we’re running out of options in the toolkit.

One option remains underutilized: interregional transmission, especially in the form of interregional HVDC lines; Not just for energy transfer or congestion relief, but as a capacity resource in its own right.

Rethinking What Counts as Capacity

Historically, we’ve defined capacity as the ability of a resource to be available “when and where” needed to meet peak demand and maintain resource adequacy. It’s not about nameplate size—it’s about effective contribution during risk periods. This is why wind, solar, and batteries receive capacity accreditation based on probabilistic methods like ELCC (Effective Load Carrying Capability), and why natural gas plants are increasingly evaluated for their fuel constraints and correlated outages during extreme weather events.

But the same logic can also apply to transmission. If batteries shift energy across time to when it is needed most, transmission shifts energy across space to where it is needed. An HVDC line importing power from a neighboring region during a local shortfall can provide similar resource adequacy benefits as a peaking plant or a battery. At the point of interconnection, it’s no different than any other inverter-based resource like wind, solar, or batteries.

Transmission Already Counts—But Not Enough

To be fair, the industry has long recognized the resource adequacy benefits of transmission. Most ISOs and vertically integrated utilities account for some level of external assistance in their planning reserve margin studies or capacity market requirements. These assumptions reduce the total amount of local capacity that needs to be procured. However, these benefits are often:

• Socialized, meaning no specific project or entity receives credit. Instead, it lowers the required amount of capacity required by the system, sharing those benefits across loads.

• Opaque, determined by planners and grid modeling, sometimes with long lead-times in analyses and with limited transparency.

• Passive, based on generic assumptions rather than tied to actual infrastructure or performance obligations.

This creates a mismatch between how we procure generation and how we account for transmission. Generators participate in open solicitations and capacity markets. Transmission—especially interregional projects—must navigate years of regulatory hurdles without a clear procurement path or compensation model. In other words, we’re good at procuring capacity, but the track record for new interregional transmission is dismal.

California, for example, has long benefited from the seasonal diversity and winter peaking  from the Pacific Northwest and likewise in transfers between Quebec and New York.

A Better Way: Let Transmission Compete

What can we do to facilitate interregional transmission and procure capacity, allow transmission projects, specifically HVDC interregional lines, to participate as supply-side resources in capacity markets and utility all-source procurements.

Here’s what that would take:

1. Capacity Accreditation for All Resources, including Transmission

   Just like a battery or solar plant receives a capacity value based on ELCC, an HVDC line should receive a capacity credit based on its ability to deliver power during risk periods. This requires running wide-area resource adequacy models across regions to evaluate the marginal resource adequacy benefits of the line. This can be done in both directions allowing transmission to supply capacity in both markets.

   
   

2. Alternative Participation Model

   Rather than relying solely on top-down planning or socialized benefits, developers of HVDC projects should be able to choose their participation mode; (1) they can either participate in the transmission planning process and receive long-term rate recovery, or (2) directly bid their resource into capacity auctions or all-source solicitations alongside generation. This would create a pathway for merchant or investor-backed transmission to compete directly with local generation.

   
   

3. Pay-for-Performance and Risk Transfer

   With a firm capacity accreditation, transmission developers would take on performance risk. If the line isn’t available when needed, penalties could apply, just like any other capacity resource. This aligns incentives and transfers risk off the ratepayer.

Why HVDC? Why Not All Transmission?

Not all transmission lends itself to this model. The unique advantage of HVDC is its dispatchability and clarity in MW injections and withdrawals. HVDC lines behave like generators from an interconnection and operational standpoint. They can deliver or absorb known MWs across an interface making it clear what the incremental transfer is at any point in time.

AC transmission, by contrast, increases transfer capability in ways that are dependent on system topology and dispatch. While AC lines absolutely provide RA benefits, they are more difficult to quantify precisely in isolation, especially as the network changes over time. These benefits are best captured through continued use of traditional transmission planning methods.

Showing by Doing, Precedent for Transmission as Capacity

This idea isn’t just theoretical. Our work with the ESIG and NERC, along with analysis conducted by Astrape Consulting have shown that HVDC lines between two regions can significantly reduce the need for new capacity on both sides. This is true even when assuming both sides start at an unreliable point (>0.1 days/year LOLE), proving that the benefits are not accrued simply by transferring capacity from a region of surplus to one of deficit. Simply put, weather and load patterns are not perfectly correlated, and well-placed interregional transmission takes advantage of that fact.

This concept isn’t relegated to study. In the UK, the National ESO explicitly assigns capacity value to HVDC interties with continental Europe. These values are bid into their capacity market and receive compensation, even without firm contracts on the other end. U.S. regions can follow suit.

What's Needed Next?

To enable this shift, we need to sharpen our pencils and make reforms:

1. Wide-area reliability studies that quantify the geographic diversity in load and resource availability across wide areas and can be used to calculate ELCC of transmission projects.

2. Consistent accreditation frameworks across resource types and ideally across regions.

3. Policy and market reforms that allow transmission to participate directly in capacity markets and all-source procurement.

Telos Energy Is Leading the Charge

At Telos, we’ve worked with our clients and partners - including system planners, developers, and other organizations - to expand how we measure reliability risk and procure capacity. We’re thinking about how transmission can be evaluated and compensated fairly, and we’re backing it up with rigorous analytics.

The grid is changing. Our approach to capacity needs to change with it. If you’re interested in supporting this work or want to explore the potential of interregional HVDC in your region, reach out. We’re just getting started.