Let's remove the barriers to more NTAs

Monday, July 13, 2015 By Tom Stanton

Non-Transmission Alternatives are electric utility system investments and operating practices that can defer - or even possibly completely replace - the need for specific transmission projects, at lower total resource cost, by reliably reducing transmission congestion at times of maximum demand in specific grid areas. 

Yet with all those potential benefits, why are NTAs providing difficult to model, plan and implement?

The Federal Energy Regulatory Commission focused on NTAs in Orders 890 and 1000, to make sure NTAs would be given fair consideration.  In several locations around the U.S., lower-cost NTAs are already proving capable of deferring or displacing some needs for higher-cost transmission projects. Thus, there is growing interest about NTAs in state public utility regulatory commissions and among other interested parties. 

Important questions being addressed include:

  • What are the technical and economic potentials for NTAs?
  • Are there any particular identifiers, in the course of transmission and integrated resource planning, of important opportunities for NTA analysis? 
  • Who might be responsible for modeling and planning NTAs, and what will be the procedures for bringing information about possible NTAs into the relevant utility planning process(es) at either the state or regional levels?
  • How should potential developers plan, seek approval for, and implement NTAs?
  • What are the appropriate venues for NTA planning and approvals?
  • Are there appropriate roles for regulated utility companies in NTA analysis, design, operations, and management, or should third parties and customers assume those roles? 
  • How can system operators be certain that NTAs will prove at least equivalent to and as reliable as the transmission options they might postpone or replace?
  • How will NTA cost recovery and cost allocation be handled?


NTAs can be identified through least-cost planning and action, one geographic area at a time, considering any and all means available for managing electricity supply and demand, including demand response, distributed generation, energy efficiency, electricity and thermal storage, load management, and rate design. 

One critically important aspect of NTA analysis is timing. Transmission line development can easily take several years for all approvals, siting decision and construction.  During the delay between the time that a need for a transmission improvement is identified and when it could be completed, at least some NTA components can be developed and operated, enabling NTAs to demonstrate their capabilities. 

NTAs can also be developed gradually, organically and incrementally, in conjunction with ongoing changes in consumer demand. Thus, NTAs can buy time, producing positive option value, while planners observe longer-term changes in supplies and demands, compared to transmission investments that tend to require more lumpy, long lead time, go or no-go decision-making. 

Still, multiple barriers are preventing NTAs from receiving all the attention they might deserve though transmission planning processes. Those barriers include:

  • Transmission planning that is limited by a culture that traditionally puts transmission first and struggles to believe that NTAs can be equivalent.
  • No agreed-upon mechanisms for determining when an NTA is fully capable of postponing or permanently deferring a transmission project. 
  • Supplementary NTA benefits, especially distribution system and customer benefits, that are not typically valued in transmission planning.
  • No ready source of funding or cost allocation methodology for NTAs.
  • No entity with the obligation to propose or implement NTAs.


Related to all of these barriers is the challenge that NTAs might not fit neatly into an existing utility's business model, because the NTAs rely in part on customer-side options that might reduce the needs for traditional utility capital expenditures. NTAs are selected for implementation when they cost less than the transmission option, thus reducing a utility's opportunity to invest and earn a return on that larger investment. In addition, not all NTA expenditures lead directly to utility earnings: some, like energy efficiency improvements, will tend to decrease utility sales and earnings and others, such as DG or on-site storage, will sometimes provide opportunities for non-utility investments and earnings. 

These challenges leave state public utility regulatory authorities with the task of providing leadership to facilitate NTA modeling, planning, and implementation. Two states, Maine and Vermont, have legislation explicitly addressing NTAs, and related actions are under way in California, Connecticut, Maryland, Massachusetts, Michigan, Wisconsin, Minnesota, New Jersey and New York.

Still, more work is needed to ensure that utilities and interested parties have tools that are fully capable of modeling, with sufficient accuracy, the many potentially useful components that can serve NTA purposes, including energy efficiency, demand response, load management, DG, and energy and thermal storage. 

The tools need to be simple, inexpensive, and easy enough to gain reliable insights at reasonable cost, so that planners can readily:

(a) identify and quantify system needs;
(b) compare system needs with the different capabilities of each major type and size of potential distributed energy resource;
(c) decide which technologies to subject to more complete power flow modeling; and
(d) estimate the expected costs of meeting system needs using various combinations of the available technologies. 

Regardless of progress being made in modeling distribution systems and the effects of individual and combined NTA components, planning capabilities eventually need to be sufficiently valid and robust so that modelers can determine with adequate precision that an NTA will be capable of providing the same or more benefits, compared to a given transmission option.

With the possibility that NTAs could produce meaningful cost-savings for utility customers, it is worth some effort to enhance existing state procedures, or even develop new ones if necessary, to ensure opportunities for NTAs to compete. Until modeling results prove otherwise, planners would be well-advised to believe that every utility service territory has at least one specific location where ample distributed energy resources are accessible to develop a successful NTA. 

States can use integrated resource planning and certificate of need proceedings, requiring the rigorous analysis necessary to determine when NTAs can prove to be cost-effective choices, deferring or displacing transmission investments.


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Stanton is a principal energy and environment researcher at the National Regulatory Research Institute. He can be reached at tstanton@nrri.org.

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