Report urges Eastern Interconnection policymakers to consider market structures, policies

An Eastern Interconnection States’ Planning Council (EISPC) report urged policymakers in the Eastern Interconnection to consider whether and how market structures, federal and state policies and transmission incentives affect private investment and grid planning, the National Association of Regulatory Utility Commissioners (NARUC) said June 21.

While the report, done by Christensen Associates Energy Consulting for EISPC, did not recommend or prefer a particular market structure, it recommended that EISPC address questions that will help guide the states in policy decision-making, including:

  • What are the incentive effects on transmission investment of different planning rules and market structures?
  • What will be the likely impacts of FERC Order 1000 on state renewable portfolio standard (RPS) and energy efficiency resource standard (EERS) policies, state authority over transmission projects and state authority over integrated resource plans?
  • What will be the likely effect of the Environmental Protection Agency’s environmental regulations on state RPS and EERS policies and on state implementation of integrated resource plans?
  • How can state integrated resource and long-term planning processes benefit from taking a broader view of resource development in the Eastern Interconnection?

Report limited to information compilation

The report noted that it is limited to the compilation of information, a comparison of market structures and an explanation of how differences in those structures are likely to affect private investment and states’ approaches to planning and resource development.

The Eastern Interconnection, which covers the eastern United States and Canada, has two different market structures for electricity supply: the traditional structure, which is built around vertically integrated utilities that offer generation, transmission, distribution and system operation services as part of a single package, and the regional transmission organization (RTO) structure in which RTOs coordinate generation commitment and dispatch, as well as transmission planning.

The report also said that transmission rights confer the ability to transfer a specific quantity of power from one or more source – generation – locations to one or more sink – load – locations under terms and conditions – including price – that are known with a fair degree of certainty in advance.

In non-RTO regions, transmission rights are “physical” in the sense that transmission customers taking firm service have the right to use the underlying physical transmission capacity. In RTO regions, transmission rights are “financial” in that the transmission rights owner will be financially compensated for uncertain transmission prices. In RTO regions, transmission price uncertainty stems from the fact that the RTOs essentially allocate transmission capacity, a day ahead, to the highest bidder, according to the report.

The report further noted that throughout the Eastern Interconnection, transmission owners are responsible for assuring that their systems meet NERC planning criteria and FERC planning requirements, but there are various arrangements under which groups of transmission owners share in the responsibility to maintain reliable power systems.

Participants in planning processes in RTO regions include transmission-owning utilities that may prepare initial plans for transmission enhancements and transmission-dependent utilities that must buy transmission services from other utilities in order to serve their own loads.

In non-RTO regions, planning occurs in integrated resource planning processes and as a result of requests for transmission service under the open access transmission tariffs (OATTs) of transmission providers in those regions. Participants in individual integrated resource planning processes adjudicated at state commissions tend to be parties directly affected by the rate changes caused by such plans, including retail customers.

Planning processes for RTOs distinguish between “reliability upgrades” that assure reliable power system operation and “economic upgrades” that reduce power system costs, including transmission congestion costs.

In non-RTO areas, the report added, transmission planning is mainly driven by resource and load requirements as identified in state-regulated integrated resource planning and request for proposals processes, as well as by long-term firm transmission service commitments made by the utility’s customers under the OATTs.

Alternatives to transmission investment in RTO and non-RTO areas generally include large central-station generation, renewable energy – local and remote – distributed generation, storage, demand response and energy efficiency.

The report also said that transmission investors are mainly incumbent vertically integrated utilities in all regions. There are a few transmission-only firms that build significant transmission infrastructure in the Eastern Interconnection and there are some firms that have built, or proposed to build, transmission in certain opportunistic situations.

Furthermore, the report discussed mandated transmission investment, noting that to the extent that authority is granted to the RTO by their transmission owner members, the RTOs can mandate investment in transmission facilities that are needed to assure reliability. On the other hand, RTOs tend to have limited authority to mandate investment in transmission facilities that improve or relieve congestion and thereby improve market efficiency, but transmission owners may have to make good faith efforts to build projects approved in their RTO’s regional plan, including economic projects.

Among other things, the report noted that transmission cost allocation rules are set by FERC orders that specify that transmission providers must offer transmission service on a non-discriminatory basis.

Doug Nazarian, EISPC president and Maryland Public Service Commission chairman, said in NARUC’s statement that the paper will be a “living document” that will be updated as state and federal policies change, adding that interested parties engaged in the EISPC process are invited to submit market-structure changes as they occur.

“A better understanding of the interactions between the wholesale and retail power markets is essential to influencing policy decisions that will benefit the states that comprise the [EISPC],” he said.

About Corina Rivera-Linares 3286 Articles
Corina Rivera-Linares was TransmissionHub’s chief editor until August 2021, as well as part of the team that established TransmissionHub in 2011. Before joining TransmissionHub, Corina covered renewable energy and environmental issues, as well as transmission, generation, regulation, legislation and ISO/RTO matters at SNL Financial from 2005 to 2011. She has also covered such topics as health, politics, and education for weekly newspapers and national magazines.