Order 1000, Part 2: An Attempt at Clarity in the Who-Should-Pay-for-Transmission Debate

Last week I wrote about the planning reforms contained in Order 1000, the Federal Energy Regulatory Commission’s landmark rule on transmission planning and cost allocation.  Today’s blog looks at Order 1000’s cost allocation implications – basically, how to figure out who pays for new transmission development.

Besides transmission siting issues, who should pay for a new transmission line or upgrade (an improvement to an existing transmission line or facility) has probably been the biggest obstacle to the development of new transmission over the last decade.  New above-ground transmission lines often cost between $1 and $2 million per mile as shown by these Eastern Interconnect Planning Collaborative estimates, so you can imagine things can get a little thorny when you’re trying to figure out who should pay for a new 150, 300 or 500+ mile line.

Who pays for new transmission lines today?

There are a variety of ways to pay for new transmission facilities.  A utility can build its own transmission line to meet new generator requests or solve a reliability or congestion issue.  With FERC’s approval, the utility can then pass the costs of the project through to its own customers.  Or, RTOs, ISOs and some other regions have existing, FERC-approved cost allocation rules that delineate how costs for different types and sizes of transmission projects should be shared among transmission owners and customers – NREL has a great report summarizing these regional allocation methods.  Or, a developer and/or potential customers can leave FERC out of it, in large part, and agree amongst themselves to share in the cost of a new transmission project and how to proportion that sharing – this is called “participant funding.”  Other than for participant funding, FERC must approve proposed cost allocation and cost recovery methods. 

In designing and reviewing transmission proposed methods, both the utilities and FERC tend to rely on the cost causation and beneficiary pays principles.  Very simply put, these related principles mean that both the folks that cause a transmission project to be built (say, a far-off renewable energy generator wanting to send power across one or more states or a big city utility that needs to decrease congestion on an existing line) and the folks that benefit from it (say, the customers who want to purchase renewable power or the urban customers who see lower transmission costs in their bills due to the decreased congestion) should pay for some portion of the facility costs.  The amount the causers and the beneficiaries pay should be roughly proportionate to the amount of benefits they each get from the line.  To date, transmission planners and FERC have usually interpreted “benefits” as increased system reliability or decreased line congestion that lessens transmission rates.  

FERC and the federal courts agree that there is some art to the science of dividing up costs among the various beneficiaries, as it is virtually impossible to determine to any level of precision the amount of benefits that one transmission customer receives from a new transmission facility compared to the value of the benefits the next customer receives.  It’s not to say people haven’t tried (those of you with a technical inclination should check out Bill Hogan’s recent paper on one way to go about it).  

Recently, the Seventh Circuit, in Illinois Commerce Commission v. FERC (ICC), recognized that the Commission doesn’t have to ensure that benefits are calculated “to the last penny, or for that matter to the last million or ten million or perhaps hundred million dollars” but they do have to make sure that individuals and companies that don’t get any benefit from a new transmission project don’t have to pay for it. In ICC, the Seventh Circuit determined that FERC had not required PJM to justify an allocation of costs for a high voltage transmission line across all customers in the 13-state region.  The Court said PJM hadn’t shown that customers in the Midwest part of PJM would receive benefits from the line, which was designed to bring new generation sources to customers in the East part of PJM, that were “roughly commensurate” with the costs the Midwest customers would face.  The Seventh Circuit did not determine that costs can’t be shared across a region, just that the costs customers are charged must be justified as roughly proportionate to the benefits they receive from the new project.     

Why are Order 1000’s cost allocation reforms good for renewables and other clean technologies?

If taken seriously by the utilities required to comply with it, Order 1000’s cost allocation reforms have the potential to make transmission cost determination projects easier and fairer, thus avoiding lingering disagreement and litigation over who should pay.  The reforms should also go a long way in facilitating the integration of renewable energy into the electric grid, and, if well designed, aid in the integration of demand response, energy efficiency and distributed generation as well.

First, the rule recognizes that transmission projects that help to facilitate public policies (like state renewable portfolio standards and energy efficiency programs, EPA clean air rules, and other existing and future laws as they are enacted) provide benefits worthy of cost allocation.  When transmission projects facilitate existing rules and laws, beneficiaries of those rules and laws should contribute to the costs of the line.  Some regions already recognize public policy benefits – the Midwest Independent System Operator, for example, has a good cost allocation method for Multi Value Projects, which are projects that help to facilitate public policy mandates or address multiple reliability or economic needs.  Hopefully requiring transmission utilities to develop cost allocation methods that account for the public policy benefits in advance will help to decrease uncertainty and pushback about whether particular customers are receiving any benefit from the facilitation of a public policy.

The rule could have gone further on this front – FERC didn’t include a list of public policies that all utilities must consider as a minimum, and it stopped at enacted rules and laws – there are lots of local, state and federal policies and goals that will impact the transmission grid, and proactively planning for them will ensure reliability and make their integration more cost effective in the long run.  My colleagues and I will work in the utility stakeholder proceedings coming out of Order 1000 to get these non-law but still important policies included as well.  

Second and also importantly, the rule ties cost allocation to the new-and-improved planning process in a way that ensures all benefits from a new transmission project will be properly accounted for and so more likely be fairly distributed. Although some regions have methods in place, most of the non-RTO regions do not.  All regions are required to devise cost allocation methods for transmission projects that solve reliability, congestion and public policy needs within their region, and they are required to work with neighboring regions to develop cost allocation methods for transmission projects that cross regional lines.

Some regions will be more amenable than others to including FERC’s public policy reforms in their new cost allocation rules.  Advocate participation in each of the regional stakeholder processes is critical to success in ensuring a robust list of public policies is included as transmission drivers worthy of cost allocation. 

What about non-wires alternatives?

Of course, all of this discussion makes you wonder how badly we really need new, expensive transmission, especially in light of the impacts new lines have on wildlife habitat and public lands.  Ideally, new transmission should only be built when the proposed project is the most cost-effective way to solve a given reliability, congestion or public policy need.  Often times, a non-wires alternative – like an industrial demand response program through which high-energy use companies like manufacturers agree to switch their power usage from periods of high demand like the middle of the day to periods of low demand like during the night shift – provides a lower cost and more effective way to meet a given need.  My next blog will focus on what exactly non-wires alternatives are, and how they may be incorporated into the wholesale transmission markets. 

About the Authors

Allison Clements

Senior Attorney

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