NewEnergyNews: Monday Study – Getting New Energy On The Grid

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    THINGS-TO-THINK-ABOUT WEDNESDAY, July 28:

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  • The Fight For Tomorrow’s Grid Gets Bigger

    Monday, July 05, 2021

    Monday Study – Getting New Energy On The Grid

    How Transmission Planning & Cost Allocation Processes Are Inhibiting Wind & Solar Development In SPP, MISO, & PJM

    Julie Lieberman March 2021 (Concentric Energy Advisors)

    Executive Summary

    Concentric was engaged by the American Council on Renewable Energy (“ACORE”), in coordination with the American Clean Power Association (“ACP”)1 and the Solar Energy Industries Association (“SEIA”) to produce a Report, based on interviews with industry stakeholders to investigate the extent to which transmission planning processes in the Midcontinent Independent System Operator (“MISO”), the Southwest Power Pool (“SPP”), and the PJM Interconnection (“PJM”) have deficiencies that are resulting in the under-development of cost-competitive renewable energy projects. This report outlines transmission planning processes in these three regions and presents insights from market participants based on their recent experiences with these processes. This report summarizes deficiencies in Regional Transmission Organization (“RTO”) planning processes that were identified by market participants in each of the RTOs as well as possible remedies.

    The availability of backbone transmission capacity (generally 345 kV and above) is essential to the efficient and least cost deployment of U.S. solar and wind resources. Renewable generation has grown exponentially over the last decade and is expected to continue its ascent as state renewable standards and policies increasingly limit carbon dioxide and methane emissions from electric generation resources. Fifteen U.S. states and territories have adopted mandates to achieve 100 percent carbon-free renewable energy – with some as early as 2030.2 Beyond state clean energy mandates, electric utilities have also made their own clean energy commitments, and corporate buyers are increasingly making voluntary commitments to purchase renewable energy. The rapid cost declines of utility-scale wind and solar (and projections that those cost declines will continue) often make these resources the least-cost new power option.3 Moreover, the U.S. Energy Information Administration projects that solar energy, wind energy, and battery storage will comprise 80 percent of the new capacity installed in 2021.4 Together, these factors suggest that renewable energy will be the principal source of electric generation in the future. Yet, existing transmission planning processes have been insufficient in preparing the electric grid for this future resource mix. Transmission construction involves long lead times, typically between 7 and 10 years, and the window may be closing to develop the needed transmission expansion to enable optimization of clean energy, meet state clean energy objectives, and other “voluntary” demand for low-cost renewable energy.

    The focus of transmission planning processes in SPP, MISO, and PJM has been on developing solutions to meet the current reliability and economic needs of the system.

    Those processes were not designed to identify the necessary transmission expansion to enable future renewable energy development. Transmission development in recent years has primarily focused on reliability and low voltage projects, the majority of which fall outside regional planning processes, and the needed backbone transmission development has been essentially stalled. In most RTOs, local reliability planning, performed by the load serving transmission owners, occurs outside regional reliability planning processes and serves only as an input to baseline regional reliability planning models.5 According to a recent Americans for a Clean Energy Grid (“ACEG”) report, annual regionally planned transmission investment is declining, while total annual transmission investment remains relatively robust,6 suggesting that transmission constructed outside regional planning processes, such as local reliability planning, has been increasing. The report goes on to state that between 2013 and 2017, “about one-half of the approximately $70 billion of aggregate transmission investments by FERC-jurisdictional transmission owners in ISO/RTO regions [was] approved outside the regional planning processes…”7

    The effects of this lack of transmission planning for the future generation resource mix is plainly visible in the generator interconnection queues where prospective generators are confronted with extremely high network upgrade costs to interconnect to the transmission system – sometimes in the hundreds of millions of dollars.8 High network upgrade costs and cost uncertainty in the generator interconnection queues have resulted in bottlenecks and significant delays (in some cases as long as 4 years) that have prevented hundreds9 of renewable energy projects from reaching commercial operation. There were 734 GW of proposed generators waiting in interconnection queues nationwide at the end of 2019, almost 90 percent of which were renewable and storage resources.10

    The current cost allocation practice for interconnecting generation projects in MISO, SPP, and PJM is that interconnecting generators are considered to be the “cost causers” and bear most, if not all, of the network upgrade costs even if other transmission customers or load may benefit from the upgrade. Generator interconnection cost allocation practices were addressed in FERC Order No. 2003, which established a default rule that network upgrade costs that are “at or beyond” the point of interconnection would initially be paid by the interconnecting generator.11

    Accordingly, generators in the interconnection process are looking for the most cost-effective point of interconnection.

    The cost of network upgrades assigned to interconnecting generators has been a major factor contributing to projects withdrawing from the interconnection queues…

    The problems in the generator interconnection process have also led to the understatement of renewable forecast scenarios, or “Futures,” in the regional transmission planning models since RTO transmission planners often consider only future generation that has secured an executed generator interconnection agreement for inclusion in baseline transmission planning models…

    Additionally, planning models do not reflect the network upgrades that are contemplated to be assigned in the generator interconnection process when there is not an executed generator interconnection agreement. There is a disconnect between the transmission planning and the generator interconnection process, where a generator may be assigned a network upgrade that is later identified through the transmission planning process. The planning process also does not analyze the need for solutions in the timeframe necessary to serve the needs of future renewable generators. The result is gridlock…

    As a result, transmission planning has been occurring haphazardly through piecemeal transmission projects and on the backs of interconnecting generators through network upgrades assigned in the generator interconnection process…

    Important and encouraging steps have been undertaken by the RTOs to address some of these issues…

    Major Findings

    1-“Centrally coordinated” planning at the interregional and RTO levels is needed to identify the geographic areas where untapped renewable energy resources exist and develop optimal and cost-efficient paths for transmission infrastructure development to deliver low-cost renewable resources to load centers.

    Centrally coordinated planning should incorporate realistic estimates of future renewable energy production and provide for advanced technology solutions where appropriate. Ideally, an effective centrally coordinated planning framework would employ a unified planning model for interregional transmission planning, would integrate and/or coordinate interregional, regional, local, and generator interconnection planning processes; and would consider the system holistically for optimal, cost effective performance when selecting solutions. Indeed, this would require a “grand bargain” among stakeholders to achieve a fully integrated, holistic, fully optimized, centrally coordinated planning approach. If such a model is beyond immediate reach, the following substantial components would each individually serve to improve the transmission planning processes and allow constrained renewable energy development to move forward.

    2- Interregional transmission planning should rely on either a unified national interregional planning model or regional models that have sufficiently aligned planning objectives, assumptions, benefit metrics, and cost allocation methodologies to properly assess benefits and costs of interregional transmission projects.

    Joint planning between RTOs has been largely ineffective and has not resulted in the necessary interregional transmission projects to export renewable resources across RTO seams. Market participants have voiced concerns over the use of separate RTO planning models that rely on different and often incompatible assumptions, benefit calculations, and cost allocation methodologies across RTOs and the extent to which they hinder interregional transmission development. Lack of alignment in planning models has led to the inability of interregional projects to pass each RTOs’ benefit-to-cost analysis. Interview respondents were in favor of harmonizing planning models to eliminate modeling disparities. Some advocated for a national policy for interregional development.

    3- Reasonable expectations of renewable resource expansion should be integrated into “Futures” assumptions in transmission planning studies. This should include reasonable forecasts for future storage, renewables and gas generation additions, as well as fossil fuel plant retirements.

    Interview respondents overwhelmingly cited the persistent under-forecasting of renewable energy resources in the alternative Futures assumptions used in planning models to be a significant obstacle to transmission development. The issue is partly due to the rapid expansion of renewable generation outpacing even the most aggressive transmission planning Futures forecasts, and partly due to the inclusion of only planned generation that has secured firm interconnection commitments in baseline planning models. As such, planning models are not identifying the transmission needs of future generation in their baseline models. When RTOs do provide for high renewable Futures scenarios, the assumptions used have not kept pace with actual renewable development. Interview respondents emphasized the need to plan proactively and look beyond projects with executed interconnection agreements to third party projections of renewable development for baseline planning models.

    4- Benefit metrics used to assess the comparable benefit of projects relative to their costs should be expanded and standardized across regions to the extent possible.

    Most RTOs rely on some form of adjusted production cost savings (“APC”) savings to evaluate project benefits, but standard APC savings calculations do not capture the full range of benefits of any given modern-day transmission project. Interview respondents were mixed on how to incorporate an expanded set of benefits into the benefit-to-cost assessments and the project selection framework. Responses ranged from the formulation of an all-inclusive benefit-to-cost metric, to expanding the APC calculation to include only additional benefits that are easily identified and quantified, to leaving the APC metric as is and considering other benefits outside the APC metric. For purposes of interregional transmission development, most agreed that benefit metrics should be standardized between RTOs to facilitate interregional transmission development along the RTO seams.

    5- Planning models and/or processes should better reflect the expected real-time operations and economic dispatch of generation resources.

    Several market participants voiced concerns over the ability of legacy transmission planning models to identify transmission solutions that reflect the likely dispatch of resources. Legacy planning models were developed to accommodate large central station baseload generation and electric systems and have traditionally been built to withstand “worst case” events, based on a fairly rigid set of deterministic conditions. Some reliability planning models dispatch generation resources based on firm transmission service to legacy generation units versus the economic dispatch that RTOs use to dispatch resources in real time. Planning models currently in use lack the sophistication and flexibility to accurately capture the specific characteristics of renewable resources and their probabilistic dispatch given weather conditions, or to identify opportunities to optimize geographically diverse resources through transmission solutions. Planning models should attempt to model the likely dispatch of resources and accurately capture resource characteristics, based on a market-based simulation in planning, where possible. Doing so would result in APC metrics that better reflect actual and expected market operation and dispatch.

    6- Competitive processes would benefit from more coordinated planning where resource zones are identified, and infrastructure solutions that address optimal paths to market are solicited.

    Competitive processes, as they exist today, lead to very little transmission grid expansion. Transmission owners and most RTOs have focused almost exclusively on local or reliability projects with short time frames. Most RTOs have held very few competitive solicitations. According to the previously referenced ACEG report, “relatively little has been built to meet the broader regional and interregional economic and public policy needs envisioned when FERC issued Order 1000 (“Order 1000”). Instead, most of these transmission investments addressed reliability and local needs.”17 Interview responses were mixed on how best to address competition, but many pointed to the Competitive Renewable Energy Zone (“CREZ”) initiative in Texas as a beneficial model of a successful competitive process that provided a coordinated assessment and simultaneous solicitations of generation and transmission.

    7- Cost allocation for generator interconnection upgrades should be shared with load or other interconnecting generators based on a fair allocation of benefits.

    Many renewable project developers commented that they cannot access the MISO, SPP, and PJM markets because of the high cost of network upgrades necessary for interconnection. Many of the upgrades benefit load as well as the interconnecting generator, but there is not a standardized methodology across RTOs for allocating costs of the upgrades required for generator interconnections to load.18 Currently, in each RTO the generator is charged for all or nearly all of the upgrade even though the upgrade will have benefits to other generators or load.19 Though most market participants agree that generators should have some share of network upgrade costs to connect, the prevailing view was in favor of the development of a more equitable cost sharing methodology

    Overview of Major Challenges

    Current regional, local, and interregional planning processes are not designed to identify optimal paths for getting the lowest-cost renewable energy resources to market. If optimization of transmission and low-cost renewable energy development is the goal, it is essential that planning reforms are implemented, emphasizing centrally coordinated and integrated planning processes to identify the cost-effective, backbone transmission system expansion necessary to achieve the renewable energy future set out in state energy plans across the nation. This planning should reflect the expected dispatch and likely interaction between energy resources, capture the full spectrum of benefits that renewable energy resources provide, and provide for an equitable cost sharing methodology between the transmission owners and load.

    Conclusions

    Centrally coordinated planning at the national or interregional level, and at the RTO level, is needed to identify where untapped renewable energy resources exist and develop optimal and cost-efficient paths for infrastructure development to deploy trapped renewable energy resources and bring resources to market. Centrally coordinated planning should provide for advanced technology solutions (where appropriate) and realistic estimates of future renewable energy production.

    Regional economic transmission planning processes, regional reliability transmission planning processes, local reliability planning processes, and generator interconnection processes should be integrated or at least consolidated and subject to a national planning standard

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