A MISO Board of Directors committee has advanced a $2.7 billion transmission development package that includes 353 new projects — including one divisive line proposed for Texas.
The System Planning Committee of the Board of Directors last week allowed MISO to move ahead in recommending its 2017 Transmission Expansion Plan for full board approval in early December, with RTO staff acknowledging that the plan’s only market efficiency project and competitive bidding candidate has drawn stakeholder ire.
MISO Vice President of System Planning Jennifer Curran said the $129.7 million, 500-kV line and substation in southeastern Texas underwent additional vetting to address concerns about the project’s costs. The RTO hired an additional consultant who verified its estimate, she said.
“As a result, we’re comfortable with the cost estimate for the competitive transmission process,” Curran told the committee during a Nov. 16 conference call.
| MISO
MISO’s Transmission Owners sector last month submitted an unsuccessful motion asking for a six-month delay of the project — one of the priciest in MTEP 17 — until the RTO addresses late modeling changes and a shifting cost estimate on the project. (See MISO Sectors Mull Texas Project Delay for MTEP 17.)
Xcel Energy had questioned the process behind the cost estimate, while Entergy submitted comments expressing concern about MISO overstating the benefits of the project and questioning modeling assumptions used to determine generator commitments in future system planning models.
“We disagree with the comments and continue to recommend that the project go forward,” Curran said. She added that the RTO would have risked reliability issues if it granted a delay of the project. The project is meant to alleviate constraints in MISO South’s West of the Atchafalaya Basin load pocket area straddling Texas and Louisiana.
Director Todd Raba asked what recourse Xcel and Entergy have available after MISO rebuffed their concerns. Curran said the companies could approach the board with their concerns and can pursue the RTO’s dispute resolution process.
MISO South Getting More Attention
Curran said more than half the projects in MTEP 17 are baseline reliability projects, most of which are concentrated in MISO South.
“Some of it is just the general lumpiness of upgrades … based on when projects need to be undertaken. Some of it is the continued load growth in the South that is not happening in other parts of our footprint,” Curran said.
BALTIMORE — More than 1,300 regulators and other stakeholders attended the National Association of Regulatory Utility Commissioners’ 129th Annual Meeting and Education Conference at the Hilton Baltimore Inner Harbor, where the theme was “Infrastructure, Innovation and Investment.” The National Association of State Utility Consumer Advocates (NASUCA) attracted more than 200 to its annual meeting at the same hotel.
FERC Commissioner Robert Powelson said it will take a while for the commission to move forward on rulemakings that languished during its six months without a quorum.
Powelson and Neil Chatterjee joined Cheryl LaFleur on the commission in August, restoring a quorum. Two other commissioners, Kevin McIntyre and Richard Glick, are waiting to be sworn in after being confirmed by the Senate on Nov. 2.
“It’s kind of hard to calibrate around some of these high-level decisions that need to be made. It’s critical that people have a little bit of patience as we get back up and running,” he told NASUCA.
Powelson said he expects FERC to act on its November 2016 Notice of Proposed Rulemaking on electric storage within the next three months. (See FERC Rule Would Boost Energy Storage, DER.)
Powelson said he is using the Department of Energy’s NOPR for coal and nuclear plants as an “inflection point to see what’s working and what’s not working in the organized markets. What I know is working hyper-efficiently is wholesale power prices have dropped and that’s a darn good thing. … Let’s not screw that up.”
The commissioner said he also wants to explore “friction” between RTOs and their market monitors, an issue he said was raised by Virginia State Corporation Chairman Mark Christie at a recent conference.
Christie said in an interview later that he was raising a “structural issue that applies across all RTOs.” (See Order 719: FERC Balanced MMU Independence Against RTO Autonomy.) “What constitutes truly independent market monitoring?” Christie asked. “As the regulator of RTOs, FERC is the appropriate forum to tee up the issue and air it out.”
“I don’t want to go back to the old days,” Powelson said. “I really believe in the independence, and protecting the sanctity of that compact for these independent market monitors. I think they should have the ability to file [with FERC]. And I get a sense that Big Brother RTO wants to say, ‘Yeah, you can be seen and heard when it’s appropriate.’ That’s not a good thing in this world of transparency that we live.”
Powelson expressed skepticism that Order 1000 has resulted in competitive transmission development, saying it is another subject worthy of a “conversation” to determine “what’s working and not working” under the order. “I’m not saying we’re going to amend FERC Order 1000, but I think we owe it to ourselves to have that conversation,” he said.
Stefanie Brand, director of New Jersey’s Rate Counsel, asked Powelson if he was aware of concerns by industrial customers and others about the rising cost of supplemental transmission projects, which are not required by FERC or NERC reliability rules. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
“Yes, it is something we’re looking at,” Powelson confirmed without elaboration.
Resolutions on Solar Tariffs, Tax Policy OK’d
NARUC’s Committee on Electricity approved a resolution urging the U.S. Trade Representative “to carefully weigh the harm that could result to energy customers from increasing the costs of solar inputs across the country, and the potential challenges to achieving state renewable energy and greenhouse gas goals that may result from higher solar energy prices.” (See Federal Trade Panel Recommends Solar PV Quotas.)
It also approved a measure asking Congress not to restrict state regulators’ ability to determine how any reduction in corporate income tax rates are addressed in utility rates. The resolution said any reductions in taxes on state-regulated investor-owned utilities “should result in a direct benefit to customers, so long as it is captured in the state ratemaking process.”
NARUC members formally elected Connecticut Public Utilities Regulatory Authority Vice Chair John W. “Jack” Betkoski III as its new president for a one-year term. Betkoski has been serving as president since August, when Powelson, a former Pennsylvania regulator, vacated the post to join FERC.
Ellen Nowak, chair of the Wisconsin Public Service Commission, was elected first vice president, and Edward S. Finley Jr., chair of the North Carolina Utilities Commission, as second vice president.
NARUC also named Andreas D. Thanos, of the Massachusetts Department of Public Utilities, the winner of the 2017 Terry Barnich Award. The award, which recognizes commissioners and staff who promote international cooperation among utility regulators, is named for the former chairman of the Illinois Commerce Commission, who was killed in 2009 while working for the U.S. State Department in Iraq. Thanos was named in recognition of his work in Europe, Latin America and elsewhere.
HOUSTON — It’s a sign of the Mexican electricity market’s growing strength that at least some industry experts expect little change after the country’s presidential elections next year.
The country’s constitution limits presidents to single six-year terms. That means every six years, a new president and administration — usually from the Institutional Revolutionary Party (PRI) — is guaranteed to take power, leading to months of transitory uncertainty for the energy sector.
Derek Woodhouse, a partner with Woodhouse Lorente Ludlow, has been advising Mexico’s Energy Ministry (SENER) on implementing the wholesale market and drafting the geothermal energy law and regulations. He expects 2018 to be different.
“Regardless of who wins the election … they’re not going to be able to dramatically change what’s being done,” Woodhouse said during a Gulf Coast Power Association luncheon last week.
For one, Woodhouse said, market reform was written into Mexico’s constitution three years ago. “Second, because the market rules have been put in place, and can only be changed now by the market itself. It will be hard for them to mess up things,” he said.
“I think in many ways, that’s why it was assigned this way, so it can support political changes, and political changes will not affect dramatically what is going on.”
Continuity or Inertia?
Woodhouse would know. In the late 1990s, he was part of a team drafting the country’s initial market reform proposal. When Vicente Fox ended 71 years of PRI rule with his surprise victory in the 2000 election, it put a halt to the market reforms.
“When Fox won the election, nothing happened — not for 12 months,” Woodhouse said. “That’s a political risk of having a new party [in control], because then you cannot have the same teams running the show.”
Woodhouse said the difference now is the nearly three dozen market rules that have been — or soon will be — put in place since new industry laws and regulations were passed in 2014. They govern everything from financial transmission rights auctions to market registration and outage scheduling. A code of conduct and operating guidelines and procedures are among those rules yet to be developed.
Still, further changes will only be expedited if the PRI manages to replace incumbent President Enrique Pena Nieto with another one of its own, Woodhouse said.
“Then you have continuation. At the end of the administration, people … probably know they’re not going to be here, so why take any risk? Why start something you’re not going to end? That triggers a year of nobody doing anything,” Woodhouse said.
Continuity does reign within the Energy Regulatory Commission (CRE), an independent body from the state-owned Comision Federal de Electricidad (CFE) that has long controlled Mexico’s electricity business. CFE is currently being restructured into separate generation, transmission and distribution businesses.
Woodhouse said inertia during the transition between administrations can still be a problem, however.
“You need to wait for the new panel to take over those positions, to learn what to do, and start doing it,” he said. “You have 12 to 18 months that nothing happens. It’s sad because it shouldn’t be like that. They have the tools to make changes, and they’re simply not using them.”
Growing Private Sector Role
SENER is implementing the wholesale market in phases through 2018. It consists of short-term markets (day-ahead, hour-ahead, real-time and ancillary services), medium-term auctions (three-year energy and capacity contracts), long-term auctions, FTR auctions, a capacity balancing market and the 20-year clean energy certificates market for instruments equivalent to 1 MWh of energy from clean sources.
The market’s third long-term auction last week set a new low for average prices at $20.57/MWh, bettering the $33.47/MWh average set in September 2016, according to preliminary results. Mexico will add 2.56 GW of capacity from 16 new projects, with a total investment of $2.36 billion by international players from Canada, China, France, Italy, Japan and Spain.
“We’re devising something that will allow them to look good politically but still incentivizes the private sector to negotiate contracts,” said Woodhouse, who has focused his career on private-sector participation in infrastructure projects traditionally reserved for the public sector.
“Hiring consultants would lengthen the process by 12 months, so we came with the idea of allowing them, from the top, to sit down and negotiate,” he said. “They’re not used to doing that. That was perceived as something corrupt. We are giving them that option because now, legally, they can do it. But they’re still very nervous. ‘Yeah, but how is it going to look if I sit down and discuss a contract with someone?’”
Woodhouse said the market is just awakening, with many players “just learning how to play the game.” Only five companies are listed as qualified suppliers, and a number of their contracts are in the 1- to 3-MW range.
“They’re testing the waters to see how their software runs,” Woodhouse explained.
FERC last week rejected NERC’s request to eliminate public posting of self-reported compliance exceptions and to expand compliance exceptions to include some moderate-risk violations.
“In most situations, information on NERC’s resolution of compliance and enforcement matters should be transparent and publicly available,” the commission said. The rejections came in an order in which the commission accepted NERC’s annual report on its Compliance Monitoring and Enforcement Program (CMEP) (RR15-2-005).
In February 2015, the commission allowed NERC to move to a risk-based approach to compliance monitoring and enforcement, which allowed low-risk violations of reliability rules to be recorded and mitigated without formal enforcement actions. It also allowed registered entities that passed a NERC review of their internal controls to self-log and mitigate minimal-risk violations, subject to periodic, rather than individual, reviews by the Regional Entity. (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.)
Incentive Lacking?
NERC said the commission “unintentionally removed an incentive for registered entities to participate in the program” when it required public logging, contending that it had reduced interest in the program.
| NERC
The Edison Electric Institute, the ISO/RTO Council (IRC) and MISO transmission owners were among those supporting NERC’s proposal to eliminate public posting. The IRC noted that only 59 of more than 1,200 registered entities participate in self-logging, saying that the incentives to participate were inadequate.
The American Public Power Association, Electricity Consumers Resource Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group opposed the elimination of public posting in a joint filing, saying the transparency was needed to educate the industry and preserve the credibility of NERC’s enforcement program. They said that because compliance exceptions are a significant percentage of noncompliance, the public disclosures allow registered entities to understand compliance requirements. They also said the public posting could help identify unnecessary or redundant reliability requirements.
The commission said it agreed with the commenters who supported continued public disclosure. “The value of maintaining the transparency of self-logged noncompliance continues to outweigh the asserted benefit that might accrue from increasing the incentive to participate in the program,” FERC said, citing the “minimal” burden of public posting and the benefits it provides in “educating industry and ensuring consistency across NERC’s and the Regional Entities’ compliance and enforcement programs.”
Find, Fix and Track Program
FERC also rejected NERC’s proposal to expand the compliance exceptions program to include moderate-risk noncompliance, although all commenters supported NERC’s request.
Moderate-risk violations that have been corrected are currently subject to the Find, Fix and Track (FFT) program, which allows NERC to process them through informational filings instead of the formal Notice of Penalty procedure.
“We are not persuaded that the claimed efficiency gains in processing certain moderate-risk violations as compliance exceptions, rather than as FFTs, are sufficient to outweigh our concerns with treating many moderate-risk noncompliances through a nonenforcement track,” FERC said. “While this approach may be appropriate for minimal risk violations, NERC has not adequately justified this limited approach for moderate-risk violations.”
The commission also raised questions about the FFT program, saying its staff had identified a compliance exception involving falsification of battery testing records by a registered entity’s employee that was disposed of via the FFT process. “The commission does not consider it appropriate to process instances of noncompliance involving falsification of records as compliance exceptions or FFTs,” it said. “Rather, such circumstances warrant a full Notice of Penalty.”
NOPR on Training, Coordination of Protection Systems
In a separate Notice of Proposed Rulemaking, the commission proposed reliability standards PRC-027-1 (Coordination of Protection Systems for Performance During Faults) to ensure protection systems used to detect and isolate faults operate in the intended sequence.
The NOPR also proposed the approval of reliability standard PER-006-1 (Specific Training for Personnel) to ensure that personnel involved in real-time operations are adequately trained (RM16-22).
FERC set a refund effective date of Sept. 30, 2016, the date NEPGA filed its complaint.
NEPGA filed a rehearing request asking the commission to apply the revised PER — and any resulting refunds to capacity suppliers — to an Aug. 11, 2016, scarcity event.
FERC on Thursday rejected the request, saying it would impose “an unforeseen and significant increase in costs” to load.
“Such application is inconsistent with the commission’s notice requirements under the [Federal Power Act],” FERC said. “We recognize that there is a lag between when the event occurs and when the billing to reflect the PER adjustment takes place; that lag in billing, however, does not satisfy the notice requirements under the FPA.”
The January order said the amount of the PER increase would be determined in an evidentiary proceeding if stakeholders were unable to reach a settlement.
On Aug. 31, Settlement Judge H. Peter Young certified an uncontested settlement requiring ISO-NE to increase the daily PER strike price for each hour “by the amounts that actual five-minute reserve shadow prices exceed the pre-December 2014 reserve constraint penalty factors (RCPF) values for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively).”
The revised strike price will replace the strike price value in hourly PER calculations for Sept. 30, 2016, through May 31, 2018. The settlement has not been approved by the commission.
NEPGA President Dan Dolan and ISO-NE officials could not be reached for comment.
FERC last week accepted network transmission service agreements between SPP and Kansas Municipal Energy Agency (KMEA) and Sunflower Electric Power, pending modifications to address the inconsistent treatment of a generation resource (ER17-889).
KMEA’s Jameson Energy Center | KMEA
The commission directed SPP to make a compliance filing within 30 days to resolve a modeling discrepancy in the power-flow analysis, which failed to account for a 9-MW gas turbine (Garden City 2) at KMEA’s Jameson Energy Center in Garden City, Kan.
SPP agreed to file revisions to KMEA’s service agreement to reflect the additional network resource, with an effective date of March 1, 2017, and to remove a reference to the unit that imposes revenue crediting requirements.
The RTO filed with FERC in January service agreements between it and KMEA as a network customer, and between it and KMEA and Sunflower as a network customer and host transmission owner, respectively. Commission staff tentatively accepted the agreements in March while FERC lacked a quorum.
Sunflower and its Mid-Kansas Electric owner, which also includes five co-ops and a not-for-profit electric company, intervened to point out the initial service agreement with KMEA excluded Garden City 2 but required the unit to pay revenue credits as a network resource. They requested FERC require SPP to remove the unit from the revenue credit payment or add Garden City 2 as a network resource.
SPP acknowledged its mistake and said it performed an additional analysis using updated model information, reposting the results in an aggregate transmission service study in February. It confirmed network service for KMEA used Garden City 2 as a designated network resource, effective March 1.
FERC last week approved cost responsibility assignments for 39 baseline upgrades recently added to PJM’s Regional Transmission Expansion Plan (ER17-2362).
The allocations were filed on Aug. 25. Thirty-five projects will be allocated to the transmission zone in which they are located, including five projects of less than $5 million each. Two projects will address Form 715 local planning criteria, and 28 involve circuit breakers and associated equipment. The remaining four projects are “lower voltage facilities” that are allocated based on the solution-based distribution factor (DFAX) method.
PJM’s control room | PJM
Old Dominion Electric Cooperative challenged two of the DFAX allocations, saying it was unable to replicate PJM’s analysis. It asked the commission to direct PJM to provide the detailed information “for the sake of transparency” and to determine whether the upgrades are appropriately allocated entirely to the American Electric Power zone. ODEC questioned PJM’s 100% allocation of another project to the American Transmission Systems Inc. zone, arguing that the results of the DFAX analysis produce a 1.32% allocation to ATSI.
FERC accepted PJM’s defense of its allocations. The RTO said because only ATSI had a DFAX percentage greater than 1% for project b2898 — reconductoring the Beaver-Black River 138-kV line — that zone was assigned the entire cost of the $20 million project.
PJM said it used “an appropriate substitute proxy” for the baseline projects, reactive power upgrades that can’t be addressed by DFAX analysis, which measures over transmission lines or transformers. PJM developed an “interface comprised of the lines and transformers that surround the entire AEP system,” a localization method PJM often uses “because the majority of reactive power upgrades are intended to provide local voltage support.”
ODEC has also asked the D.C. Circuit Court of Appeals to overturn FERC’s policy of allocating all costs from Form 715 projects to the zone of the transmission owner whose criteria triggered the upgrades. ODEC said the cost allocation for the two Form 715 projects should be subject to the outcome of its challenge.
FERC said last week it didn’t have enough information to decide on complaints that American Electric Power affiliates are raking in unreasonable returns for transmission projects in PJM and SPP, instead establishing hearing and settlement judge procedures.
In PJM, American Municipal Power, Blue Ridge Power Agency, Craig-Botetourt Electric Cooperative, Indiana Michigan Municipal Distributors Association, Indiana Municipal Power Agency, Old Dominion Electric Cooperative and Wabash Valley Power Association filed complaints that AEP’s current 10.99% base return on equity is excessive. They requested a base ROE no higher than 8.32% and asked for refunds with interest. The change would save them $142 million annually in transmission costs, they said (EL17-13).
The complainants hired a consultant to develop a peer-group analysis that included 25 utilities similar to AEP. That analysis found a “zone of reasonableness” of between 5.62 and 9.46% and that the median of the values, 8.32%, was more appropriate than the midpoint.
Multiple state agencies intervened to support the complaint, including the Indiana Office of Utility Consumer Counsel, the Office of the Ohio Consumers’ Counsel, the Virginia Division of Consumer Counsel, the Virginia State Corporation Commission and the Indiana Utility Regulatory Commission.
An ad hoc group of large commercial and industrial end-use customers also commissioned an analysis, which found an appropriate zone between 5.64 and 9.44%, recommending a base ROE of 8.22%.
AEP responded with its own analysis that found an appropriate zone between 6.41 and 11.71% and that using the midpoint of the upper half of the range, rather than the median, was consistent with FERC rulings.
FERC found the complaint compelling enough to explore further and called AEP’s argument that the current rate falls within the reasonable zone “unpersuasive.”
“The commission has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE,” the order said, setting a refund effective date of Oct. 27, 2016.
SPP Complaint
FERC also established identical procedures for East Texas Electric Cooperative (ETEC) in its complaint against AEP subsidiaries Public Service Company of Oklahoma (PSO), Southwestern Electric Power Co. (SWEPCO), AEP Oklahoma Transmission and AEP Southwestern Transmission, setting a refund effective date of June 5, 2017 (EL17-76).
The cooperative in June asked the commission to reduce the companies’ 10.7% base ROE to 8.36% within SPP’s AEP West pricing zone. PSO and SWEPCO’s current base ROE derives from a transmission formula rate settlement agreement filed Feb. 23, 2009.
ETEC contends the base ROE is no longer just and reasonable and that its ratepayers are currently overcompensating the AEP West companies by $36.6 million annually.
The companies countered that the 9.53% upper end of an ETEC consultant’s zone of reasonableness falls more than 100 and 80 basis points below the ROE that FERC previously approved for ISO-NE and MISO, respectively.
The commission said it was “unpersuaded” by the argument, saying “the relief [ETEC] seeks here is an ROE that falls well below the current ROE, based on different facts, risks, proxy companies and time periods” than those in previous decisions.
FERC on Thursday approved NYISO Tariff revisions ordering downstate residents to pay 90% of the cost of AC transmission projects stemming from public policy needs (ER17-1310-001).
The projects, which include the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, are intended to relieve downstate congestion by upgrading the AC transmission systems north and west of New York City.
| National Grid
The cost allocation was proposed by the ISO at the direction of the New York Public Service Commission, which said 75% of the costs should be allocated solely to the downstate load zones that will benefit from the congestion relief, with the remaining 25% allocated regionally based on load-share ratio. “According to the New York commission, this method will allocate approximately 90% of the transmission project’s cost to ratepayers in the downstate region, and about 10% to upstate ratepayers,” FERC said.
FERC rejected a protest by four State Assembly members, who said the regional allocation of 25% was too low to account for “some of the financial and societal benefits to ratepayers statewide.”
The commission said the proposed allocation satisfies Order 1000’s requirement that it be “roughly commensurate” with the benefits that the load zones receive, citing a study published by the PSC that found 89.5% of the costs should be allocated to the downstate load zones.
However, the commission added that the ISO’s filing “does not prevent the selected transmission developer from submitting its own proposed cost allocation method for the AC transmission upgrades. The Tariff specifically provides that the selected transmission developer may also file, for the commission’s approval, an alternate cost allocation method or request that NYISO use the default cost allocation method (i.e., load-share ratio).”
ROE Settlement
In a related order, the commission approved a settlement with New York Transco — affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric — to decide questions regarding their potential compensation for the projects (ER15-572).
The settlement, which will apply only if NY Transco is selected as the developer, includes a 9.65% base return on equity and a 100-basis-point adder that will apply up to the cost cap, which was defined as the capital cost bid plus an 18% contingency and an inflation factor of 2% per year.
The commission said the settlement, which was unopposed and endorsed by both the New York PSC and FERC staff, “appears to be fair and reasonable and in the public interest.”
Cost Containment
FERC did not rule on state regulators’ proposed cost-containment mechanism, under which ratepayers would be responsible for 80% of any overruns above the estimated cost of the project and retain 80% of any savings.
The commission said it couldn’t rule because the ISO had provided only a description of the risk-sharing proposal without Tariff language. “As such, [the mechanism] is not properly before us,” the commission said. “NYISO states that it plans to file Tariff sheets for the 80/20 risk-sharing mechanism after concluding its stakeholder process.
“In regard to implementing the 80/20 risk-sharing mechanism, because the New York commission recognizes that [FERC’s] policy on cost recovery allows transmission developers to recover costs that are prudently incurred, it proposes to limit the selected transmission developer’s ability to recover costs associated with cost overruns by reducing the allowed return on equity for the transmission project,” FERC added.
Selection Process
NYISO received 16 proposed projects from six developers in response to a February 2016 solicitation for solutions to address the transmission congestion. In a January order, the PSC told the ISO it “should proceed to a full evaluation and selection, as appropriate, of the more efficient or cost-effective transmission solution to meet the” public policy transmission need.
NYISO spokesman Michael Jamison said the ISO hopes to release draft results of its analysis by the end of the first quarter of 2018. “Subsequent to that, the NYISO will select the more efficient or cost-effective project. At that time the NYISO will work out a developer agreement with the chosen party, and that party can initiate actions with the state under the Article 7 transmission siting process.”
WESTBOROUGH, MA — Boston leads large, northeastern cities in economic growth, outpacing both New York and Philadelphia in payroll employment, Moody’s Analytics economist Ed Friedman told the ISO-NE Planning Advisory Committee on Thursday.
| BLS, Moody’s Analytics
According to figures compiled by Moody’s from the U.S. Bureau of Labor Statistics, Boston posted better than 2% growth in payroll employment for the three months ending September 2017, compared to approximately 1.7% growth in Philadelphia and less than 1.5% in New York City.
“The job growth in Boston is quite strong and significantly above the U.S. pace, which is around the 1.5% mark,” Friedman said.
Friedman characterized New England job creation in the aggregate as “slow but steady” at 1% per year and said that housing price gains in the region are mostly keeping up with the national average of just more than 6% for the year ending in August 2017. Of the six states in the region, only New Hampshire and Massachusetts exceeded the national average; housing prices in Massachusetts, where health care remains a strong economic driver, increased by almost 7%.
| BLS, Moody’s Analytics
Both Connecticut and Vermont lost population in the past two years. Nonetheless, Moody’s expects economic growth in the region to continue in 2018 at about 1.3%, with “some deceleration consistent with the demographic challenge” of lost population, Friedman said.
RTO Readies Maine Resource Integration Study
ISO-NE on Thursday presented a draft of its Maine Resource Integration Study to the PAC, its first transmission planning study to employ queue clustering under Tariff revisions approved by FERC Approves ISO-NE Queue Clustering.)
The Northern and Western Maine grid was built to serve the small loads in the area and lacks capacity for the more than 5,800 MW of proposed new resources, mostly wind, that have filed interconnection requests. The 5,800 includes duplicate requests.
The resource integration report will provide the basis for system impact and facilities studies, which will identify the upgrades required for resources that proceed to interconnection and their cost allocations, said Al McBride, ISO-NE director of transmission strategy and services.
Maine 2027 Needs Assessment Moves Forward
The RTO’s draft Maine 2027 Needs Assessment study is ready for stakeholder comment, Jinlin Zhang, ISO-NE lead engineer for transmission planning, told the PAC.
Comments and notifications by proponents of state-sponsored requests for generation should be submitted to pacmatters@iso-ne.com by Dec. 3.
The study identifies reliability-based needs in Maine for the year 2027, considering future load distribution, resource changes in New England based on Forward Capacity Auction 11 results, and 2017 solar and energy efficiency forecasts.
Planners look at reliability over a range of generation patterns and transfer levels, how the study coordinates with the New Hampshire Needs Assessment, and all applicable NERC, Northeast Power Coordinating Council (NPCC) and RTO transmission planning reliability standards.
The completed draft report and intermediate study files will be presented to the PAC in the first quarter of 2018.
RTO Begins Zone Planning for FCA 13
ISO-NE has begun assessing transmission transfer capability, generation retirements and new resources to set capacity zone boundaries ahead of FCA 13 for 2022/23.
The process includes evaluation of the zones as determined for FCA 12, McBride said.
| ISO-NE
Each year, the RTO must identify weaknesses and limiting facilities that could impact the transmission system’s ability to reliably transfer energy in the planning horizon. Any new boundaries require a filing with FERC, McBride said.
The process of certifying transmission projects begins in October and is coordinated with that month’s Regional System Plan (RSP) Project List update to ensure consistency. Transmission owners are required to provide models and contingency definitions. The RTO will determine certifications by January; the list of certified projects will be presented at the January Reliability Committee meeting.
Transmission upgrades identified for Southeast Massachusetts/Rhode Island (SEMA/RI) are not expected to change the boundaries of the area. Planners do not expect such upgrades to be fully certified for FCA 13, nor will transfer limits be updated in time for that auction in 2019.
Any major resource retirements received for FCA 13 will be considered in the zone formation process, McBride said. No major retirements were received for FCA 12.
Time-Sensitive Tx Needs Determination
Pradip Vijayan, ISO-NE senior transmission planning engineer, made a presentation on how the RTO identifies time-sensitive transmission upgrades — those required within three years and thus not subject to the competitive solicitation process.
RTO officials consider when an upgrade will be required after identifying improvements in a needs assessment.
Needs identified from a short-circuit analysis are considered time sensitive unless they are driven by future projects that have an in-service date beyond three years of the completion of the needs assessment.
Steady-state needs observed at off-peak load levels are considered time sensitive. Those seen at peak load levels may or may not be time-sensitive.
The RTO will add a document detailing the process to its Transmission Planning Technical Guide, Vijayan said.
Tx Planning Assumptions Update
ISO-NE is continuing to update the probabilistic methodology and minimum load level used in its transmission planning assumptions, Director of Transmission Planning Brent Oberlin said.
The generator dispatches used in base cases in his report showed the potential for a significant number of generators to be simultaneously unavailable, especially in the Eastern Connecticut (ECT) area. ISO-NE said in October that it would revise the scope of its 2027 needs assessments for ECT, Southwest Connecticut and New Hampshire over stakeholder questions about dispatch modeling assumptions. (See “Tx Planners Rethink 2027 Needs Assessment,” ISO-NE Planning Advisory Committee Briefs: Oct. 18, 2017.)
The ECT data showed that up to 488 MW of generation could be unavailable at peak load. The largest generator in the ECT study area is Montville 6 (413 MW), with 13 other generators totaling only 253 MW, which shows that the presence of a single large generator in an area with a low number of smaller generators can skew the results, Oberlin said.
The new methodology solves the issue by recalculating the upper limit of generation outages using the probabilistic method by excluding the large generator for dispatches in which it is assumed in service. By applying this method to ECT, the maximum amount of generation unavailable is limited to 115 MW in cases with Montville 6 in service.
The new methodology lowers the minimum load level to 8,000 MW from 8,500 MW, correcting an error on the handling of Maine mill loads (currently 320 MW) in the evaluations, Oberlin said.
