Regulations, reserve margins, resource mix are biggest reliability challenges
NERC determined that the most significant threats to reliability will be downward trends in reserve margins, uncertain impacts of environmental rules and an ongoing resource mix transformation,
In an examination of the U.S. bulk power system through 2024, the North American Electric Reliability Corp. has determined that the most significant threats to reliability will be downward trends in reserve margins, uncertain impacts of environmental rules and an ongoing resource mix transformation, according to TransmissionHub.
NERC on Nov. 12 released the findings in its 2014 Long-Term Reliability Assessment (LTRA), a broad perspective on the adequacy of the generation, demand-side resources and transmission systems necessary to meet bulk power system reliability needs over the next decade.
NERC examined indicators for resource adequacy over the planning period, including load forecasts, expected resources, and transmission additions, and recommended the three challenge areas as a focus for industry, regulators and policy makers in the near future.
According to the report, reserve margins are trending downward in some assessment areas because of ongoing generation retirements, despite low load growth. In addition, a large amount of existing conventional generation may be vulnerable to retirement as a result of pending environmental regulations.
In its recommendations, NERC said that it will raise awareness of resource adequacy challenges, support ongoing initiatives to address declining reserve margins, and use its 2014 probabilistic assessments to offer in-depth understanding of the interplay between resource availability and projected hourly demand.
NERC conducts biannual probabilistic assessments to supplement the LTRA to provide a common set of probabilistic reliability indices and recommendations. The probabilistic metrics used in the assessment are annual loss-of-load hours, expected unserved energy, and expected unserved energy as a percentage of net energy for load for two common forecast years.
The assessment found that fossil-fuel generation is under high risk from existing and proposed environmental regulations. According to the LTRA, existing regulations and lower gas prices contributed to the retirement of about 39 GW of generation from coal and other fossil fuels between 2011 and 2013, and natural gas grew to 40 percent of the on-peak generation mix, up from 28 percent in 2009.
Pending regulation from the Environmental Protection Agency could lead to additional coal-fired generation retirements beyond NERC’s reference case of between 47 GW and 68 GW by 2025. NERC said that these retirements would further reduce reserve margins and accelerate the nation’s reliance on natural gas and variable energy resources, such as wind and solar.
To combat these conditions, NERC recommended that the industry conduct an ongoing assessment of generation and transmission adequacy plans to respond to existing and pending environmental regulations.
The LTRA also noted that changes to the bulk power system will require new approaches to assess reliability.
According to the report, federal and state environmental regulations, coupled with lower natural gas prices, have caused the current shift away from conventional capacity to increasing amounts of natural gas, wind and solar resources. As part of its recommendation to address issues related to this shift, NERC said that the electric and gas sectors should coordinate efforts to understand system reliability needs and determine if more transportation or resource capacity is needed.
In addition, these sectors should integrate fuel availability and deliverability into resource adequacy assessments. NERC further urged its Essential Reliability Services Task Force to continue efforts to develop additional metrics for measuring the reliability impacts of a resource mix that is increasingly dependent on variable resources.
As a supplement to these three main reliability issues, NERC identified transmission siting, permitting, and other right-of-way issues as areas that could warrant special assessment in the future. Citing the 7,400 circuit miles of transmission line currently under construction, 20,622 circuit miles of planned lines, and 7,360 miles of conceptual lines, NERC recommended that resource planners recognize the long planning cycles necessary for transmission development.
NERC said that aging infrastructure also presents potential ongoing risks to reliability. According to the report, investment in new transmission infrastructure by investor-owned utilities has increased substantially over the past 15 years but varies significantly across NERC regions. NERC noted that although capital investment, engineering resources, and labor resources for infrastructure replacement are in short supply, the industry is committed to ongoing grid upgrades and maintenance.
The LTRA includes reliability findings, transmission outlooks and system enhancements for 15 assessment areas.
According to the report, the Midcontinent ISO (MISO) could lose 23,000 MW of coal capacity and subsequently increase natural gas generation within its footprint. MISO may need to modify its tariff to minimize potential reliability impacts of growing demand and supply/transportation constraints of natural gas.
The transmission outlook for MISO includes a $1.48 billion transmission expansion plan through 2023. Transmission lines in that plan are:
· Petersburg to Francis Creek to Hanna 345-kV line
· Monroe County to Council Creek 161-kV
· Kokomo Highland Park to Tipton West 230-kV line rebuild
Mid-Continent Area Power Pool
The LTRA determined that there is a potential for minor instability issues for the Mid-Continent Area Power Pool (MAPP) region from localized growth in northwestern North Dakota and in Rochester, Minn., but there are no foreseeable reliability or resource adequacy issues for the area during the assessment period.
The transmission outlook for the region includes several transmission projects that are expected to be completed during the assessment period, all of which are intended to increase the reliability of the MAPP transmission system. Rochester Public Utilities is a joint owner of the Hampton to North Rochester to LaCrosse portion of the CapX2020 project, which has a planned in-service date of 2016. Although it has experienced some delays, Minnkota Power Cooperative’s Center to Grand Forks line was scheduled to be completed by July 2014, which will improve reliability with additional wind resources coming online.
ISO New England
According to the report, ISO New England (ISO-NE) is working to create a forecast of all future photovoltaic (PV) resources in the region to help address the interrelated questions of exactly how much additional PV is expected in ISO-NE’s 10-year planning horizon and what impact this future PV could have on the regional power grid
The transmission outlook for the region includes the Maine Power Reliability Program and the New England East-West Solution. In addition, new smart grid technologies, such as FACTS, are being used in New England to improve the electric power system’s performance and operating flexibility.
New York ISO
The LTRA determined that for the NYISO region, state and federal regulatory initiatives cumulatively will require considerable investment by the owners of New York’s existing thermal power plants, and as much as 33,200 MW in the existing fleet will have some level of exposure to the new regulations.
The transmission outlook for the region includes the Transmission Owner Transmission Solutions (TOTS), which consist of three transmission projects in central New York, downstate New York, and New York City. TOTS is part of the Con Edison and the New York Power Authority filing in response to a November 2012 order from the New York Public Service Commission that recognized the significant reliability needs that would occur if the Indian Point Energy Center were retired.
According to the report, the PJM Interconnection is investigating gas supply and transportation risk by considering the potential correlation with extreme weather (and high winter loads) and the potential for the loss of multiple units due to gas transportation disruptions. Gas supply and transportation risks are captured in PJM’s resource planning studies to the extent they affect generator forced outage rates.
The transmission outlook for PJM includes a 2012 transmission rights analysis that identified 16 thermal constraints in Commonwealth Edison’s zone and nine PJM-MISO market-to-market constraints. Transmission planning analysis in 2013 also identified a number of thermal constraints similar to those identified in 2012, confirming the need for the Byron to Wayne 345-kV line in 2017.
PJM sought proposals from April 29, 2013, through June 28, 2013, to improve operational performance on facilities in the southern New Jersey Artificial Island area, the site of Public Service Enterprise Group’s (NYSE:PEG) Salem 1 and 2 and Hope Creek 1 nuclear generating plants. Seven different sponsors submitted 26 separate proposals.
PJM expects to make a recommendation to its board in 2014 that comprises adding a second Hunterstown 230/115-kV transformer and reconductoring the existing Hunterstown to Oxford 115-kV line. In addition, PJM’s regional transmission plan includes 500-kV transmission line rebuild projects over the next eight years by American Electric Power (AEP) and Dominion Resources (.
Western Electricity Coordinating Council
The LTRA determined that for the Western Electricity Coordinating Council (WECC) region, more than 4,700 MW of thermal generation was retired, and 9,500 MW was added. WECC is studying the impacts of potential planning and operational reliability impacts associated with the retirement of large thermal generating units alongside the impacts from higher levels of variable resources and natural gas supply and transportation conditions.
The transmission outlook for WECC allows for the future use of special protection systems or remedial action schemes in lieu of costly transmission facility additions. Whether these schemes will be permanent or temporary additions will depend on as-yet undetermined system conditions.