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Potential Reliability Impacts of EPA’s Proposed Clean Power Plan Phase I

April 2015 (North American Reliability Council)

Executive Summary

The Environmental Protection Agency (EPA) issued its proposed Carbon Pollution Emission Guidelines for Existing Stationary Sources: Electric Utility Generating Units on June 2, 2014, commonly referred to as the proposed Clean Power Plan (CPP). The proposed rule is issued under Section 111(d) of the Clean Air Act and establishes limits on CO2 emissions for existing electric generation facilities. The proposed rule is currently anticipated to be finalized during summer 2015.

In its role as the Electric Reliability Organization in the United States, NERC has responsibility under Section 215 of the Federal Power Act to conduct periodic assessments of the reliability and adequacy of the nation’s bulk power system (BPS)—the high-voltage transmission and generation system (as opposed to local distribution facilities). NERC’s single focus is BPS reliability. NERC fulfills its responsibility in the public interest through conservative analyses and assessments that highlight reliability risks resulting from various possible future circumstances, given the severe consequences of an operationally unreliable or inadequate BPS for public health, safety and well-being, and our nation’s economy and security.

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On August 14, 2014, NERC’s Board of Trustees directed NERC staff to develop a series of special reliability assessments to examine the potential risks to reliability that may arise from the implementation of the CPP rule and potentially accelerate the transformation of the resource mix in North America. NERC began development of this series of reports with its Initial Reliability Review,4 published in November 2014, which examined the approach outlined in the proposed CPP and provided a high-level view of potential reliability risks.

NERC maintains a reliability-centered focus on the potential implications of environmental regulations and other shifts in policies that can impact the reliability of the BPS. Reliability assessments conducted while the EPA is finalizing the CPP can inform regulators, state officials, public utility commissioners, electric industry leaders, and other stakeholders of potential resource adequacy concerns, impacts to system characteristics (such as the straining of essential reliability services (ERSs)), and areas that may require transmission enhancements to ensure reliability.

This report is NERC’s Phase I special assessment. It provides an analysis of scenarios and identifies the potential risks to reliability resulting from the resource transformation called for in the proposed CPP. This assessment and its findings do not: (1) advocate a policy position in regard to the environmental objectives of the proposed CPP; (2) promote any specific compliance approach; (3) advocate any policy position for a utility, generation facility owner, or other organization to adopt as part of compliance, reliability, or planning responsibilities; (4) support the policy goals of any particular stakeholder or interests of any particular organization; (5) represent a final and conclusive reliability assessment; or (6) represent an actual system expansion plan.

NERC’s Phase I assessment consists of a three-part analysis: (1) a scenario and sensitivity analysis driven by gas prices and state or regional implementation approaches to identify resource adequacy and the range of potential timelines associated with reliability reinforcement needed to meet CPP requirements; (2) a transmission adequacy analysis to determine a comparable range of transmission needs along with lead times required to build that transmission (natural gas pipeline reinforcements are also examined); and (3) summaries of existing studies by NERC reliability authorities (such as Reliability Coordinators, Transmission Planners and Operators, and Regional Reliability Organizations) related to the potential impacts of the CPP rule, with a focus on the relevant reliability impacts. NERC leveraged key information from these studies to identify cumulative impacts on a region-wide or interconnection-wide basis. Throughout this special assessment, a stakeholder advisory group formed by the NERC Planning Committee provided advice, input, and vetting of the underlying assumptions and publicly available data.

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Goals and Objectives

The goals and objectives of this assessment are to: • Provide a resource and transmission adequacy evaluation given a number of potential scenarios that are driven by gas prices and state (as well as potential regional) implementation plans using different models to understand possible outcomes. • Identify potential reliability risks and implications resulting from the projected resource mix changes to ERS characteristics, the increase in variable resources, the concentration of resources by fuel type (especially natural gas), the impacts on transmission requirements due to increased and potentially large power transfers, and other reliability characteristics, including Regional Entity planning reserve margins. • Determine potential lead-time constraints associated with the electric and gas infrastructure enhancements needed to support the implementation of the proposed CPP. • Assess industry analysis and studies from NERC reliability authorities (such as Transmission Planners and Operators and Reliability and Planning Coordinators) to determine if unique reliability issues may occur as a result of implementing the CPP requirements. • Provide an independent assessment of reliability that informs policy discussions on risks to BPS reliability and related emerging issues.

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Qualification

Significant uncertainty remains in the parameters of the final CPP rule, including compliance timeline flexibility; CO2 targets and target calculation modifications; determination of whether groups of states (in addition to the Regional Greenhouse Gas Initiative (RGGI) states5) are able to coordinate to develop timely regional plans; details and coordination of the specific state implementation plans; federal model implementation plans or regional implementation plans; impacts of state selection of mass-based or rate-based limits; inclusion of regulatory reliability assurance mechanisms within the rule, etc. NERC recognizes that changes to any one of these parameters will have an effect on the analysis and results presented herein. As these uncertainties are resolved, further reliability impact analyses and assessments will be necessary to assess potential reliability implications.

Notably, the approach to formulate internally consistent assumptions, which are then formed into key scenarios, is designed to provide benchmarks and guidance about potential reliability implications during the implementation of the CPP rule. The model results illustrate potential scenarios and outcomes at a specific point in time based on input assumptions also applicable to a specific point in time. Therefore, the results are representative of a range of potential outcomes used to assess potential reliability impacts, but may not be indicative of what will necessarily happen as other modeling based on different decisions or changes to the proposed rule would alter the results.

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NERC’s modeling is designed to mathematically solve for lowest cost options. It was conducted with the premise that new utility-scale generation will be constructed to replace existing generation and meet electricity demand in the future. From NERC’s perspective, the path to achieve the significant reductions in CO2 emissions is through resource mix changes on the BPS. NERC’s modeling is a conservative approach that does not rely on new technologies that are not yet widely integrated into the BPS or major changes in consumer choices and behaviors; however, NERC recognizes that significant additional conservation and distributed generation would have an impact on the results.

Assessment Approach NERC focused on providing insight and guidance about potential reliability aspects from implementing the proposed CPP and specifically did not assess effectiveness, desirability, or optimal alternative CO2 reduction methods. NERC’s role is to evaluate the composite framework of plans and implementation changes that can potentially impact the BPS, using technically sound long-term, seasonal, and special reliability assessments and known parameters, assumptions, scenarios, engineering judgment, and practicality based on historical performance. For its resource adequacy analysis, NERC used two generator dispatch models: AURORAxmp and IPM.6 For its transmission adequacy analysis, NERC used the static power flow models for the Eastern and Western Interconnections.

NERC retained three consultants to employ resources and transmission planning models to develop scenario results based on NERC’s input assumptions. The findings and conclusions are based on the independent analysis of NERC’s Reliability Assessment and Performance Analysis staff.

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Key Findings

A transformative shift in resource use (or energy) leads to the need for transmission and gas infrastructure reinforcements, which will require additional time beyond currently proposed targets. This transformative change in the reliability characteristics of the resources supplying bulk power electricity places much greater emphasis on the need for adequate ERSs to be in place. The following key findings are components of NERC’s overall assessment: 1. Consistent with NERC’s Initial Reliability Review, the proposed CPP is expected to accelerate a fundamental change in electricity generation mix in the United States and transform grid-level reliability services, diversity, and flexibility. The anticipated changes in the generation mix and modified dispatch of resources driven by the proposed CPP will require comprehensive reliability analysis to identify grid-level reliability needs to accommodate the resource mix and flexibility requirements. Generating resource changes that are already underway would be accelerated by the implementation of the CPP and are prompting the need for much greater understanding of the ERSs (e.g., frequency response, voltage support, and ramping capability) needed to support BPS reliability. Implementation of the CPP would accelerate an ongoing fundamental shift in the generation resource mix toward greater use of gas and renewables, which presents reliability challenges as new resources have different ERS characteristics than the current generation fleet. For example, the reliability characteristics of a synchronous coal-fired steam turbine vary greatly from those of asynchronous, inverter-based machines.

Importantly, this transformation introduces changes to operations and expected behaviors of the system.

Finally, extensive power system studies and planning analysis need to occur to address expected changes in power flows and large multi-regional transfers. The power flow changes represented in NERC’s analysis demonstrate the continued evolution of resource deployment and use of renewable and natural gas generation. Over the next several years, these resource changes will require more transmission to integrate the new resources, meet increasing electricity demand, and enable new exports and imports to accommodate a new resource mix. Consistent with NERC’s conclusion in its overall assessments, power flow changes represent a significant planning and operational challenge, and sufficient time and coordination is needed to determine region-specific solutions. 2. Industry needs more time to develop coordinated plans to address shifts in generation and corresponding transmission reinforcements to address proposed CPP CO2 interim and other emission targets.

NERC’s evaluations of the potential reliability implications of the proposed CPP and associated implementation plans by state or regional groups have identified fundamental changes in both the electric generation mix and corresponding transmission and gas pipeline infrastructure needed to accommodate these changes. Multi-regional and entity coordination is necessary to accommodate the long lead times for electric infrastructure and to ensure reliability during the implementation periods. A coordinated process not only ensures that stakeholders and consumers are provided sufficient time to review and respond to changes to the electricity grid, but it would also take into consideration NERC’s mandatory Reliability Standards and FERC orders on operation and planning coordination (such as FERC Order 10007).

Geographic and resource diversity and a complex regulatory environment present challenges to the longterm development of electric power infrastructure. The time required for new facilities to be developed and placed in service may likely exceed the CPP’s proposed compliance targets. Because the industry will be implementing plans simultaneously, it is uncertain whether adequate equipment (e.g., generators, solar panels, wind facilities, transformers, and conductors) and resources (e.g., engineering, procurement, and construction) will be available to support those plans.

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The interim target date within the EPA’s CPP proposal requires notable reductions of CO2 (approximately 80 percent of the total reductions) by 2020. It is likely that infrastructure to support the required interim reduction in CO2 emissions at this pace will not be in service by 2020 for the following reasons:

Generation: Between 2015 and 2020, over 33.5 GW of generation capacity (e.g., coal, oil, gas, and nuclear) is expected to retire, based on NERC’s Reference Case from the 2014 Long-Term Reliability Assessment (2014LTRA). An additional 7 GW is expected to retire between 2021 and 2025. In NERC’s modeling of the CPP, State and Regional Cases yielded approximately 43 GW and 41 GW of retirements, respectively, between 2016 and 2020. Between 2020 and 2030, State and Regional Cases yielded an additional 42 GW and 44 GW of retirements, respectively. While replacement capacity may be able to repower coal to gas generation, others will require greenfield development, which on average will take between four and five years. From a Regional Entity perspective, areas with the greatest amount of resource retirements are ERCOT, SPP, NPCC, and MISO, with approximately 10, 7, 11, and 9 GW of retirements, respectively, between 2016 and 2020. Approximately 35 GW of non-hydro renewable energy (i.e., mostly wind and solar) is added due to the proposed CPP in all scenario results, in addition to planned variable energy resources (VERs).

Transmission: Based on NERC’s analysis, transmission-deficient areas have been identified. On average, transmission projects require between six and 15 years to engineer, site, permit, and construct, depending highly on the geography, length, and voltage class. From a Regional Entity perspective, areas needing the most transmission reinforcements are located in RF, NPCC, and the southwest area of WECC. As part of NERC’s CPP Phase I study, NERC requested information from industry on new generation and transmission facility construction lead times. The results represent perspectives from 110 different transmission and generation companies on timing requirements for additional new transmission and generation capacity. 3. Implementation plans may change the use of the remaining coal-fired generating fleet from baseload to seasonal peaking, potentially eroding plant economics and operating feasibility. A significant finding of the analysis points to an expected shift of existing coal-fired generation from baseload to seasonal peaking operations. According to NERC’s modeling analysis, between 14 and 22 GW of coal generation resources remain online through 2030; however, these units are considered at risk of retiring due to the plant economics associated with operating the units infrequently. To operate this capacity on a seasonal peaking basis, the approximate capacity factors—a measure of their utilization— would average between 11 and 19 percent after 2020. As capacity factors decline and operational functions transition from baseload to cycling, or peaking operations, maintenance and fixed costs to support a plant’s operation rise significantly.

Based on industry experience, very low capacity factors for traditionally baseloaded plants will significantly increase overall costs due to required upgrades, repairs, staffing needs, and expected increased forced-outage rates. Under these conditions, the eroding plant economics of such generation resources renders their continued operation at risk and subject to potential retirement. In a wholesale electricity market structure, generators may need additional incentives (e.g., capacity payments) to keep low capacity factor fossil generation economic and in service. 4. Energy and capacity will shift to gas-fired generation, requiring additional infrastructure and pipeline capacity. The implementation of the CPP final rule is expected to accelerate an ongoing shift toward greater use of natural-gas-fired generation. Increased dependence on natural gas use will require pipeline capacity, particularly during the winter season when natural gas use for electric power competes with residential heating. Approximately 60 GW of additional gas-fired capacity is estimated to be in service by 2020, and approximately 80 GW by 2030. The additional capacity plus the higher use of gas-fired generation is expected to increase gas demand in the United States from 39 Bcf/d to 50 Bcf/d—an increase of approximately 30 percent. Local and regional pipeline infrastructure will be needed to relieve pipeline constraints and fuel firming for the electric industry.

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Recommendations

1. NERC should continue to update and expand the assessments of the reliability implications of the proposed CPP and provide independent evaluations to stakeholders, states, regulators, and policy makers. NERC should continue to conduct a phased assessment strategy, recognizing that the proposed rule is not yet final and may change. These assessments will continue to provide insight and guidance as the CPP rule is finalized and state, regional, and federal implementation plans begin to materialize.

2. Coordinated regional and multi-regional industry planning and analysis groups should continue to conduct detailed system evaluations to identify areas of reliability concern and work in partnership with states, regions, and policy makers to provide clear guidance of the complex interdependencies resulting from the CPP rule’s implementation.

3. Policy makers, states, regions, and regulators (including the EPA) should develop implementation plans that allow for more time to address potential BPS reliability risks and infrastructure deployment requirements during the transition period.

4. The EPA should include a formal reliability assurance mechanism in the final rule that provides the regulatory certainty and explicit recognition of the need to ensure reliability during both the plan development and the implementation period through 2030—and potentially beyond. NERC has outlined a specific series of roles for providing reliability guidance and independent assessments, in the form of a reliability assurance mechanism.

5. State and regional plans should be developed in consultation with reliability authorities—Planning Coordinators and Transmission Planners—to review plans and demonstrate their reliability through established planning analyses and processes.

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