Wheeling fees are small today, but reforming them could help renewable development
Two bills in the legislature seek to change how we pay for electricity transmission
Everyone’s top concern about Railbelt electricity right now is where we’re going to get it from, given the Cook Inlet gas crisis (see our analysis of the supply gap in this post). But another conversation that’s been going on for years is how we should move it around most efficiently. There are two separate bills in the legislature that change how we might pay for electricity transmission (SB 217/HB 307) and (SB 257). The two bills have a similar solution to allocate transmission costs, but the management of that transmission system would be quite different, which I’ll cover later in the post.
Right now, utilities generally own and pay for for the transmission lines in their territories. If other utilities move energy across those lines, they pay the owner a “wheeling fee” based on the amount of energy transferred. These proposals would change that to a system where all the costs are pooled, and each utility pays based on their proportion of the total electric load.
So I did the math to see what impact that would have on the various Railbelt utilities. The short answer is that transmission is a tiny piece of current costs, and changing how we allocate them would only shift things a little bit -- no utility would see more than a 1% total change in revenue.
So why does it matter?
The costs to operate a transmission line don’t increase if you move more power across it, but wheeling fees are charged based on the amount of power transmitted. They create a strong disincentive for a utility to buy power from another utility’s territory, even if that would otherwise be the cheapest and most efficient option.
That doesn’t matter much under our current system. Almost all of the energy transfer that happens is either required by law or saves so much money that it almost doesn’t matter what the fees are. MEA and Chugach are required to pool their generation, and don’t pay wheeling fees for power transferred back and forth in that pool. GVEA and MEA both pay wheeling fees to Chugach to receive their share of power from Bradley Lake, but since Bradley Lake produces some of the cheapest power on the Railbelt, it’s well worth it. Bradley Lake also has special agreements that exempt it from wheeling fees in HEA territory -- any other power moving off the Kenai Peninsula could be subject to two sets of fees. Similarly, GVEA’s oil-fired generation is so expensive that gas power from the south is worth buying, even with wheeling fees.
Wheeling fees could have a big impact on the price of renewable power
Wheeling fees discourage all sharing of energy between regions. This matters for renewables particularly, because renewables are the only energy we’re likely to want to share. There isn’t enough extra gas to ship more gas power north, and there isn’t much to be gained sending gas power back and forth from the Kenai Peninsula to Anchorage. Wheeling fees would probably increase the price of new renewable energy by over 10% for each utility territory it passes through. Wheeling already adds more than that to the price of Bradley power for MEA and GVEA. It costs literally zero extra dollars to ship this new power over existing lines (and we can transfer a lot more power over our existing lines if we have reason to do it). It’s just a fee.
A utility buying energy from elsewhere still pays just as much to maintain its own transmission system as it did before -- plus some extra to other utilities. Therefore, there’s an incentive for utilities to want any new generation in their own territory, even if there are better resources in other areas, if a single large renewable project would be cheaper than a bunch of smaller ones, or if buying power from multiple different renewable projects in different places would help smooth out the spikes and valleys in generation.
In 2021, Railbelt utilities paid around $32 million total in transmission costs, 3.6% of their total revenues. This includes operations, maintenance, and depreciation. Depreciation is how the initial cost of a piece of infrastructure is spread out over time. That figure also includes the costs utilities pay to run the Alaska Intertie running between Southcentral and Fairbanks, which is owned by the state. It doesn’t include the costs of the transmission infrastructure that’s part of the Bradley project, but that’s small, and is already paid for in proportion to each utility’s load. In total transmission costs add up to around three quarters of a cent per Kwh sold. Individual utilities costs range between 0.55¢ - 0.85¢ per Kwh.
In contrast, when utilities charge wheeling fees, they charge more -- more than the costs of building, operating, and maintaining the infrastructure. Wheeling isn’t charged on a simple per Kwh basis, and varies depending on where the electricity is coming from and going. But in 2021, Chugach charged between 0.88¢ and 1.2¢ per Kwh for wheeling on its system -- substantially more than overall transmission costs. Near term solar and wind power is likely to cost around 7.0¢ to 8.5¢ per Kwh. If that power had to move through more than one utility, the cost would be at least 20% higher by the time it reached the other end of the system -- possibly rendering it uneconomic. Pancaking wheeling rates are parasitic on the system, letting utilities profit off each other based on geography, or worse, preventing good projects from getting built at all.
Getting rid of wheeling fees wouldn’t be a major harm to any utility. My graphs show how those costs are distributed now, and how that would change if they were instead allocated by ‘load ratio share’ (each utility’s percentage of total power sales), similar to what the two bills propose. The numbers are small, and the changes are also small. MEA would pay around $1.4 million more , and GVEA would pay around $1.5 million less, but the total change would be less than 1% of total costs for each utility.
Additionally, the Railbelt is poised to build a lot of new transmission in the coming years. HEA is the only utility with a large-scale battery right now. Its depreciation costs aren’t captured in the 2021 data I show, but it increased HEA’s transmission costs 1.8 times between 2021 and 2022. In the next few years, all the utilities will have batteries. A federal grant will build a new transmission line across Cook Inlet if the state provides matching funds. Changing how these costs are allocated will be easier while the numbers are small.
The two transmission bills put different groups in charge of future transmission
Both (SB 217/HB 307) and (SB 257) would likely allocate transmission costs in similar ways.
SB 217 uses load ratio share (what I used in my analysis) as the basic idea, but leaves the details to the RCA, which it directs to “gradually transition” to a cost recovery mechanism which “must take into account each load-serving entity's load in comparison to the total load on the integrated transmission system.” SB 257 uses similar language, but adds another possible way to calculate the proportions, based on maximum rather than annual energy flows: “The cost recovery methodology for the backbone transmission system adopted by the transmission organization must pool backbone transmission system costs and allocate those costs through certificated load-serving entities on a coincident peak or load ratio share basis, or a combination of both, as approved by the commission.” SB 217 includes all old transmission in the costs, but only includes new lines if they connect more than one new power project. SB 257 requires the organization it creates to determine which parts of the system are the “backbone” and which serve only one utility. Neither specifies whether depreciation is considered in transmission costs, but since depreciation represents the costs of actually building those lines, I think it should be.
But they differ dramatically in the ownership, management, and planning of the system as a whole
SB 217 leaves ownership and management of existing transmission infrastructure the same as today. Future planning is left under control of the Electric Reliability Organization (ERO, also RRC). The ERO was mandated by a bill a few years ago, and is currently only partly stood up. It includes both utilities and non-utilities in its governing structure, and is supposed to create both reliability standards, and an “integrated resource plan” for the whole Railbelt that includes both transmission and generation. The ERO doesn’t own anything, so the utilities and/or the state would still build and operate the transmission, but that transmission would have to fit within the integrated resource plan, either by being listed in the plan or getting pre-approval from the ERO.
SB 257 would create a new transmission organization, the “Railbelt Transmission Organization,” within the Alaska Energy Authority. This organization would actually own and manage all the transmission -- the utilities would be required to transfer all their transmission lines and batteries. The new organization would also be responsible for the grid-wide planning that currently is supposed to be the ERO’s job. It would be governed by the utilities, AEA, and one member from the ERO (which would still exist, but have fewer responsibilities). The main controversy over this proposal is the fact that this organization would be much more utility-controlled, without the consumer, independent power producer and independent board members the ERO has.
Both bills also do some entirely unrelated, and generally positive, things. SB 217 changes the tax structure for Independent Power Producers in a way that would put them on the same footing as utilities, substantially decreasing the price of renewable energy. SB 257 ensures that commissioners on the RCA meet stricter qualifications.
In conclusion:
Whichever organization ends up doing the Railbelt planning, we should fix the problem of wheeling fees soon, rather than waiting years for that plan to get made. No one loses anything significant if we reallocate current costs slightly. But independent power producers are negotiating renewable power contracts with utilities right now. These projects are the best thing we can do to reduce gas usage in the near term, as well as the cheapest power for the Railbelt in the longer term. Pancaking wheeling rates might significantly shrink the renewable projects they decide to build. If that happens, we all lose.