Maine regulators to reconsider certain safe harbors in relation to transmission planning

 

The Maine Public Utilities Commission, in an April 1 order, reopened a proceeding to reconsider its February 2013 Transmission Planning Order to reconsider certain safe harbors.

As noted in the order, the Maine Office of the Public Advocate (OPA) in August 2018 filed a petition seeking to amend an order issued in the docket (Docket No. 2011-00494) in February 2013, in which the commission established standards for local transmission system planning for each of Maine’s investor-owned transmission and distribution (T&D) utilities.

The 2013 order – or the Transmission Planning Order – also evaluated the reasonableness of the utilities’ modeling practices, including the assumptions used in developing their base cases – including generation dispatch, load forecast/energy efficiency, maintenance outages, and interface transfers – and elsewhere in the planning process.

As a result of that evaluation, the April 1 order added, the commission established “safe harbors” that serve as benchmarks of reasonable planning practices that may be used by T&D utilities to avoid the case-by-case determination of reasonable planning practices that had occurred in transmission line certificate of public convenience and necessity (CPCN) proceedings.

The Transmission Planning Order also distinguished between local and regional reliability planning. The commission determined that because of the different purposes of regional and local transmission planning, the local transmission system “need not be designed, and therefore need not be tested, to the same degree of stress as the bulk transmission system.”

The April 1 order added that the Transmission Planning Order further allows a T&D utility on a case-by-case basis to propose more stringent standards if it provides a cost-benefit analysis to establish that the benefit of the additional level of reliability is justified given the cost of implementing the practice.

Specifically, the Transmission Planning Order states, “In specific cases, utilities would be free to advocate for a practice that would deliver additional reliability but would be tasked with providing a cost-benefit analysis to establish that the benefit of the additional level of reliability is justified given the cost of implementing the practice. We would not reject out-of-hand a utility’s enhanced standards but rather would give the utility the opportunity to demonstrate that these practices may be in the best interests of its customers. For example, a utility could make a benefit/cost demonstration by comparing the risk (i.e. probability of failure times cost of failure) of not addressing the criteria violation compared to the cost (and reduced risk of system failure) of addressing the need identified by testing beyond the safe harbor.”

The April 1 order added that ISO New England (ISO-NE) has made significant changes to how it conducts system planning studies since the issuance of the Transmission Planning Order, including the adoption of some probabilistic planning methods that establish a more uniform level of probability among the different planning studies.

Discussing changes to generator dispatch, the order noted that ISO-NE has established a probabilistic threshold for choosing generator outage contingencies. Prior to adopting that change, generator contingencies were chosen randomly by the transmission planning engineer resulting in studies with varying levels of statistical probability.

ISO-NE developed its “same probability” curve method of selecting generator dispatch to address that issue, the order added, noting that the same probability curves combine the statistical probability of load levels with the probability of some level of megawatt outage. That approach allows ISO-NE planning staff to choose a curve that represents a specific probability level and based on that probability, choose a level of megawatt out for any given load level, the order said. That has enabled ISO-NE staff to achieve greater statistical uniformity among 11 “key study” areas of New England, the order said. The transmission security probabilistic threshold chosen by ISO-NE was the same level used to plan system resource adequacy need to a loss of load expectation (LOLE) of one day in 10 years, the order said, adding that one day in 10 years is the same as 0.1 days per year.

Noting that there are 85 days each summer in which ISO-NE could experience a peak day, the order noted that the probability level chosen for transmission studies by ISO-NE was chosen to be 0.1 day divided by 85 or 0.0012.

The order also noted that ISO-NE in 2014 changed its methodology for determining shoulder loads, adding that ISO-NE determined that using 75% of a 50/50 load forecast overestimated shoulder loads, i.e., loads that occur in the spring and fall. ISO-NE’s intermediate load level includes peak shoulder loads and off peak hours during the summer. The order added that the intermediate load level was developed by reviewing actual system loads for three years – 2011-2013 – and approximating a value system loads were at or below 90% of the time. The resulting fixed intermediate load level of 18,000 MW is adjusted down to properly account for the manufacturing loads, the order said.

The order also noted that over the last 10 years, outage coordination between ISO-NE and New England Transmission Owners (TOs) has improved significantly. The percentage of outage requests submitted into the long-term process has increased from 59% in 2009 to 82.1% in 2017. The order added that an April 2017 report issued by ISO-NE states that through the long-term process and in coordination with the TOs, local control centers and adjacent reliability coordinators, “the ISO-NE will continue to reposition transmission equipment and generator outages as necessary to ensure the continued reliable operation of the New England transmission system and minimize economic impact.”

The order noted that in its petition, the OPA requested that “the commission alter or amend its order to allow for all participants in a CPCN proceeding to present evidence regarding alternatives to the ‘safe harbor’ planning practices or assumptions that should instead be relied upon in that proceeding.”

The OPA states that allowing the utility to make a showing that additional reliability beyond that provided by the safe harbors may be in the best interest of the utility’s customers, while not allowing parties to make a showing that assumptions other than safe harbors are in the best interest of ratepayers “provides the potential for an unjust and unreasonable outcome by precluding the admission of evidence that compels the consideration of different assumption from a party that is not the utility,” the order said.

The petition states that there have been “significant and ongoing grid developments and operations that have had significant impact on the evolution of local transmission planning … that can be leveraged to provide the system data needed to advance effective non-wires alternatives, planning, operations, measurement and verification,” the order said.

The commission said in its order that it exercises its discretion to reopen the Transmission Planning Order, sua sponte, finding that it is in the public interest to reexamine certain safe harbor standards due to changed circumstances or additional experience with the application of those standards which raise questions about whether they should be altered or amended.

The commission said that it denies the OPA petition, noting that it finds that changing the Transmission Planning Order in the manner requested by the OPA would be contrary to the purpose of the Transmission Planning Order.

The commission said that it specifically finds that the main purpose of the safe harbors – to adopt standards for local transmission planning to reduce the case-by-case litigation of assumptions used in CPCN proceedings – would not be served by adopting the OPA-proposed amendment. The commission said that rather, it expects that such a proposal would bring the commission back to litigating standards on a case-by-case basis in each CPCN proceeding, which raises the question of whether there would be any benefit of having adopted safe harbor standards.

Commission: Safe harbor standards to be reexamined

Preliminary information demonstrates that it is in the public interest for the commission to reexamine the maintenance outage safe harbor provisions approved for Central Maine Power (CMP) and Emera BHD.

In its Transmission Planning Order, the commission accepted the maintenance outage standards proposed by Bangor Hydro, now Emera BHD, and CMP. The April 1 order added that Emera BHD models an additional transmission line out of service beyond the N-1 single element contingency, but with a load level of 75% of a 50/50 load forecast. The commission also accepted CMP’s planning practice of modeling an additional transmission line out, but with a load level of 85% of a 90/10 forecast. In addition, CMP’s safe harbor maintenance modeling allows a 60 MW loss of consequential load and assumes the availability and use of mobile transformers to resolve a violation.

The order added the OPA states, for instance, that CMP’s maintenance outage safe harbor has significantly increased costs for consumers, alleging that the maintenance outage standard in Docket No. 2011-00138 has increased costs to resolve Portland area transmission needs by $90m.

CMP states that the need for flexibility in scheduling routine maintenance has not changed since the issuance of the Transmission Planning Order and asserts that “CMP’s load level routinely exceeds shoulder 50/50 load levels on a monthly basis.” The order added that CMP contests the OPA assertion that the maintenance outage safe harbor was the major contributor to the cost increases in the Portland area project. Emera disagrees with the OPA that non-consequential loss of load should be allowed in modeling a maintenance outage, and states that avoidance “of non-consequential load loss is one of the key goals of performing transmission planning.”

The commission said that it finds that changed circumstances, as well as additional experience with the application of the safe harbor in transmission planning, warrant reopening of CMP’s and Emera BHD’s maintenance outage safe harbors. One change is the improvement in coordination of transmission outage scheduling, the order noted.

Another significant development is ISO-NE’s modified practice regarding calculation of shoulder loads, the order said, adding that ISO-NE’s new methodology, adopted after the issuance of the Transmission Planning Order, indicates that even a 75% of 50/50 load used by Emera BHD may overestimate the load level during shoulder periods, thus possibly increasing needs based on maintenance outage testing. Accordingly, the commission said, Emera BHD’s maintenance outage safe harbor will also be reexamined.

Among other things, the order noted that the safe harbor for wind is the same as that for CMP’s run-of-river hydro. Emera and CMP filed confidential reports on the output of the wind facilities using that methodology, the order said, adding that the aggregated data from CMP and Emera BHD respectively result in an output level for each utility of near zero, while aggregated data from Emera MPD result in an output level slightly below 5% of nameplate.

The OPA advocates reexamining the safe harbor for wind data, stating that ISO-NE uses a methodology for determining winter dispatch of wind “now accounts for a greater amount of wind energy production available for dispatch in the model.”

The order added that CMP states that there is no need to change the wind modeling technology, saying that any “potential improvements in wind generation availability will automatically be captured by this method as new wind generation utilizing improved technology interconnects to the system and its output is reflected in the historical output duration curve data.”

The commission said that the output data results in levels below the 5% of nameplate used by ISO-NE in its Transmission Planning Technical Guide, which suggests that this assumption is stricter than that of ISO-NE. Further, since the methodology selected by the commission was not discussed in the course of the proceeding for application to wind output, it would be reasonable to collect additional information on methodologies for determining the level of wind output for local transmission planning purposes, the order said.

About Corina Rivera-Linares 3058 Articles
Corina Rivera-Linares, chief editor for TransmissionHub, has covered the U.S. power industry for the past 15 years. Before joining TransmissionHub, Corina covered renewable energy and environmental issues, as well as transmission, generation, regulation, legislation and ISO/RTO matters at SNL Financial. She has also covered such topics as health, politics, and education for weekly newspapers and national magazines. She can be reached at clinares@endeavorb2b.com.