FERC last week declined to grant Ameren additional transmission incentive rates for portions of the company’s 500-mile Grand Rivers project in Illinois and Missouri.
Ameren sought a 100-basis-point incentive adder for the return on equity for the Illinois Rivers and Mark Twain components of the project, which is intended to create a continuous 345-kV path from Iowa to Indiana. The company also requested authorization to assign the incentive to any affiliate that undertakes the development, construction or ownership of those portions of the project.
Grand River Project | Ameren
The commission said the segments were already too far developed to be considered risky enough for incentive rate treatment (ER18-463).
“We find that, due to the late stage of … development, including the substantial completion of the Illinois Rivers component, Ameren Transmission has failed to demonstrate that the remaining risks and challenges associated with the components warrant the requested ROE incentive,” the commission sad. “A project that is further along in construction and thus closer to completion typically faces fewer remaining risks and challenges, and we find that is true here.”
FERC agreed with the contention by the Organization of MISO States and the Missouri Public Service Commission that Ameren had already spent 77% of its cost estimate on the two lines when it asked for the rate incentive in mid-December, when permitting risks were minimal and already covered by a previously approved abandonment incentive. Ameren had argued that the two lines face “unprecedented” risks that are not covered by its other rate incentives.
The commission has previously granted several incentives for the Grand Rivers Project, including 100% construction-work-in-progress recovery, abandoned-plant recovery, a hypothetical capital structure and the authority to assign incentives to affiliated entities.
New generators seeking interconnections must be equipped to provide primary frequency response, FERC ruled Thursday (Order 842, RM16-6).
The commission said the requirement that generators have governors or other equipment to respond automatically to frequency disturbances must be included in the pro forma generator interconnection agreements (GIAs) for both large (20 MW+) and small generators.
The rules will apply to new generation and existing generators that seek a new interconnection agreement because of “material modifications” to their facilities. The commission declined to order existing generators to retrofit their facilities to provide the service, saying it would be “prohibitively expensive” for some.
The final rule makes only small changes from the commission’s November 2016 Notice of Proposed Rulemaking, which cited concerns by NERC and others that frequency response has declined with the loss of traditional synchronous generation and the increase in asynchronous renewables. (See FERC: Renewables Must Provide Frequency Response.)
The commission cited a 2010 NERC survey that found only 30% of generators in the Eastern Interconnection provided primary frequency response and that only 10% provided “sustained” response. The commission said the existing pro forma large GIA — which required primary frequency response from only synchronous generating facilities — does not reflect technological advances allowing nonsynchronous generation to provide the service.
The commission set operating requirements of a maximum droop setting of 5% and a deadband setting of ±0.036 Hz.
“We find that the establishment of minimum uniform operating requirements for all newly interconnecting generating facilities is preferable to the fragmented and inconsistent primary frequency response settings currently in place throughout the Eastern and Western Interconnections,” FERC said. ERCOT already has minimum frequency response requirements, FERC noted.
FERC agreed with recommendations by the Edison Electric Institute and the Western Interconnection Regional Advisory Body that it modify the rule to explicitly prohibit interconnection customers from blocking their governors’ ability to respond to frequency deviations.
“One of the commission’s concerns with the current lack of clear, uniform primary frequency response requirements is NERC’s finding indicating that a number of generator owners/operators have implemented operating settings that have effectively removed the availability of their generating facilities from providing timely and sustained primary frequency response (e.g., wide deadband settings, uncoordinated plant-level controls). The reforms adopted in this final rule, to be applied uniformly to new generating facilities, are intended to eliminate these practices.”
The commission disagreed with the National Rural Electric Cooperative Association’s (NRECA) contention that the rule is premature, saying “adopting these requirements now is more prudent than waiting until the lack of primary frequency response undermines grid reliability, a point acknowledged by NERC’s Essential Reliability Services Task Force.”
Headroom, Compensation
The commission rejected EEI’s proposal that generators be required to maintain headroom — allowing them to increase output in response to low frequency — and receive compensation for doing so. “If future conditions necessitate a headroom requirement, we will then consider any appropriate compensation,” it said.
FERC also said it would consider on a case-by-case basis requests from transmission providers seeking to impose a headroom requirement “in a particular factual circumstance” that includes a compensation mechanism.
The commission said compensation is not necessary because “the cost of installing, maintaining and operating a governor or equivalent controls is minimal.” FERC estimated the cost of adding governors to new wind and solar generators would average $3,300/MW, about 0.2% of total capital costs for wind and solar.
FERC also rejected requests that it order compensation for traditional generators that provide inertial response. “No commenter asserts that inertial response trends on the Eastern and Western Interconnections are approaching levels that could threaten reliability. In addition, because inertial response is provided automatically by the rotating mass of synchronous machines as system frequency deviates and is not controllable, synchronous generating facilities do not incur additional incremental costs to provide inertial response,” the commission said.
Exceptions and Accommodations
The commission exempted or offered accommodations to some classes of resources:
Combined heat and power (CHP) generators that are sized to serve onsite load and have no ability to export power to the grid will be exempt from the operating requirements but must install a governor “in the event that there is an increased need in the future for primary frequency response capability.”
Energy storage will only be required to provide frequency response within specified operating ranges representing minimum and maximum states of charge. The commission said the accommodation would prevent the premature degradation of storage resources.
Distributed energy resources will be required to provide frequency response only when they are allowed to ride through disturbances, the commission said in response to Xcel Energy’s concern that dynamic frequency response at the distribution level can interfere with anti-islanding protections. The rule does “not supersede a generating facility’s ride-through settings or require an interconnection customer to override anti-islanding protection or any protective relaying that has been set to disconnect the generating facility during certain abnormal system conditions,” the commission said.
Nuclear generators are exempt from the rule because their licenses with the Nuclear Regulatory Commission often restrict providing frequency response.
No Exemption for Wind, Small Generators
Wind generation must comply with the requirement, the commission said, rejecting an exemption request by Sunflower Electric Power and Mid-Kansas Electric.
“Unlike certain CHP or nuclear generating facilities, the record does not indicate that there is an economic, technical or regulatory basis for a generic exemption for newly interconnecting wind generating facilities,” FERC said. “In particular, we are persuaded by [the American Wind Energy Association’s] assertion that the proposed primary frequency response capability requirements can be met at low cost for new wind projects, and that newly interconnecting wind facilities should not have difficulty complying.”
Small generators also will not be exempt. The commission said the rule will not result in “unduly burdensome” costs or create a barrier to entry, noting that PJM has not seen a decrease in small generator interconnections since it required nonsynchronous generation to install enhanced inverters with frequency response capability. “We are persuaded by commenter assertions that that small generating facilities are making up a growing percentage of the generation resource mix, and that as the market penetration of small generating facilities increases, there will be a growing need for primary frequency response from these generating facilities,” FERC said.
The commission rejected NRECA’s request that individual balancing authorities be permitted to seek waivers from the rule but agreed that “unique circumstances or needs of some individual regions or areas may warrant different operating requirements.” FERC said it would consider variations based on Regional Entity reliability requirements; variations that are “consistent with or superior to” the final rule; and “independent entity variations” filed by RTOs and ISOs.
The revised GIAs are due 70 days after publication of the rule in the Federal Register.
ISO-NE could see substantial “spillage” of renewable energy and large price separations because of transmission constraints under scenarios considered in the RTO’s 2017 Economic Study, officials told the Planning Advisory Committee on Wednesday.
The study was requested by the Conservation Law Foundation to evaluate scenarios for meeting Massachusetts and Connecticut climate laws and the Regional Greenhouse Gas Initiative’s emission caps.
The study was based on the “Renewables Plus” scenario from the 2016 Economic Study, which modeled the year 2030 — the only scenario in the 2016 study to meet the RGGI cap. (See Study: New Resources Could ‘Crowd Out’ Old in ISO-NE.)
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Under Renewables Plus, the generation fleet met existing renewable portfolio standards, and new renewable or clean energy resources were added above existing RPS requirements.
The new study looked at three additional scenarios:
“EE + Offshore”: Added more energy efficiency and offshore wind while reducing imports from Canada by 1,000 MW.
“Onshore Less EE/PV”: A variation on the business-as-usual base case from the 2016 report, with onshore wind boosted to 7,000 MW (nameplate capacity) from 4,800 MW in the reference case.
“Wind Less Nuc”: Assumes the Millstone nuclear plant retires by 2030, five years ahead of its license expiration, with the gap filled by renewable/clean energy resources.
The study found all three scenarios met projected demand, even with transmission constraints based on the “as-planned” system’s internal and external transfer limits.
If transmission constraints are not relieved, the RTO would see “spillage” of wind power north of the Surowiec-South interface, leading to lower prices in Northern Maine than southern New England. For example, under the constrained scenarios, 7 to 18% of renewables would be spilled, with 22 to 89% of the spillage north of Surowiec-South.
In the constrained Wind Less Nuc scenario, average LMPs would range from $13.78/MWh in the Bangor Hydro Electric subarea in northeastern Maine, to $38.71/MWh in the NH subarea (which includes most of New Hampshire, eastern Vermont and southwestern Maine) and $37.18/MWh in Boston.
Only one scenario, EE + Offshore, is as good as the Renewables Plus scenario in meeting the RGGI 2030 emission targets. | ISO-NE
Electric production by natural gas plants fluctuates with assumptions regarding plant retirements and price-taking offers ($0/MWh) by renewable resources. EE + Offshore has the least gas-fired energy, while Wind Less Nuc has the most gas production, especially when the transmission system is constrained.
EE + Offshore had the lowest total production costs, coming in 28% below the Renewables Plus reference case assuming transmission constraints. Onshore Less EE/PV had the highest costs, 77% above the constrained reference case.
Only one scenario, EE + Offshore, is as good as the Renewables Plus scenario in meeting the RGGI 2030 emission targets.
CLF staff attorney David Ismay said the two emission-reduction targets, which were also used in the 2016 study, were intended to “bracket” the goals RGGI might embrace in its latest program review. RGGI’s emissions cap declines by 2.5% annually through 2020. The group announced in August that it would seek an additional 30% reduction in emissions from 2020 levels.
“We expressly worked … to design all three scenarios to meet [RGGI] emissions targets,” Ismay said.
“We’re starting to get a better picture of what the grid needs to look like in order to meet our climate laws and emission regulations that are already on the books,” he explained in an interview later. “We really need a grid that’s different from what we have now. I think that will give legislators, regulators and the ISO information on the kind of mix we need to comply with these laws. … It’s really helpful to see the impact of adding 1,000 MW of EE or 1,000 MW of wind.”
Stakeholders have until April 2 to submit requests for additional economic studies. Requests should be emailed to PACMatters@ISO-NE.com.
MISO is embarking on a review of its entire economic planning process in an effort to more accurately capture the benefits of cost-shared transmission projects.
“This is not about MISO saying the existing process is broken or flawed,” Matt Ellis, of the RTO’s Economic Planning Users Group, told stakeholders at a Feb. 13 Planning Subcommittee meeting.
Ellis said MISO is looking forward to FERC-level discussion on best practices for planning and that it will continue to talk about economic models throughout 2018.
MISO especially wants to take a fresh look at:
The economic impacts of transmission outages;
Voltage and local reliability resource commitments, especially in MISO South load pockets where performance has lagged;
MISO’s emergency energy supply and how it’s being valued in economic models when it defers transmission and generation investment or prevents scarcity pricing and loss-of-load events;
Accounting for likely import and export flows in adjusted production costs; and
Forecasted renewable resource ownership and which members will actually purchase the energy and benefit when considering renewable portfolio standards.
Further, the RTO plans to hold stakeholder discussions through June on other possible measurable benefits that could be valued in the modeling of market efficiency projects. It could consider such benefits as the deferral of reliability projects; savings that could arise from opening up it contract flow path with SPP that bridges MISO South and Midwest; reduced transmission energy losses; reduced ancillary services costs; and deferral of capacity expansion stemming from increased capacity import/export limits.
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Ellis asked for member companies’ engineers to come forward with other ideas about overlooked benefits of market efficiency projects that could be assigned a monetary value.
Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that renewable standards are set by state legislatures and can be changed. Ellis responded that MISO is looking for that kind of information and other input.
He also said timely changes to MISO’s modeling could affect how it judges potential projects in its annual Market Congestion Planning Study for the 2018 Transmission Expansion Plan.
“We are fully aware that having a process review in parallel with having the process is not an ideal situation. It introduces a lot of ‘what-ifs,’” Ellis said. He promised that MISO would test any projects affected by an economic model change using both the old and new models and that it could delay implementing the new aspects of economic modeling.
MISO announced its plan the same week it proposed to lower the voltage threshold for market efficiency projects to 230 kV, and two weeks after FERC ordered a technical conference on how PJM, MISO and SPP coordinate generator interconnection studies after developer EDF Renewable Energy complained that the RTOs’ modeling standards violate the FERC requirement for transparent open access interconnection service. (See FERC Orders Review of PJM, MISO, SPP Generator Studies.)
Consolidated Edison’s fourth-quarter net income increased 144% to $505 million ($1.63/share) from $207 million ($0.68/share) in 2016, the company said last week.
Total revenue for the quarter increased 9.38% to $2.961 billion.
The company reported 2017 net income of $1.525 billion ($4.97/share), compared with $1.245 million ($4.15/ share) in 2016. Total revenue was down slightly in 2017 but remained above $12 billion.
Con Edison Composition of Regulatory Rate Base as of Dec. 31, 2017 | ConEd
Con Ed said its adjusted earnings for 2017 excluded the remeasurement of deferred tax assets and liabilities upon enactment of the federal Tax Cuts and Jobs Act, the effects of the gain on the sale of a solar electric production project, and the net mark-to-market of Con Edison’s clean energy businesses.
The company’s earnings presentation showed the new law reduced the net deferred tax liabilities for its Con Ed of New York, Orange and Rockland Utilities and Rockland Electric subsidiaries by more than $5 billion collectively.
Con Ed plans to meet its 2018 capital requirements through internally generated funds and the issuance of securities. The company’s plans include issuing between $1.3 billion and $1.8 billion of long-term debt at its utilities and additional debt secured by its renewable electric production projects.
The company also plans to issue up to $450 million of common equity in addition to equity under its dividend reinvestment, employee stock purchase and long-term incentive plans. The plans do not reflect the provision to utility customers of any tax law benefits that may be required by the New York Public Service Commission or the New Jersey Board of Public Utilities.
RENSSELAER, N.Y. — NYISO power prices surged to an average of $99.55/MWh in January, up 89% from December and 148% from the same month a year ago, Rana Mukerji, senior vice president for market structures, told the Business Issues Committee on Wednesday.
The ISO’s year-to-date monthly energy prices averaged $101.54/MWh in January, an increase of 142% from a year earlier. Average sendout was 463 GWh/day, compared with 444 GWh/day in December and 431 GWh/day a year ago.
New York natural gas prices jumped 136% for the month, averaging $17.94/MMBtu at the Transco Z6 hub. Prices were up 369% from a year ago. Gas prices peaked at $140.06/MMBtu on Jan. 4, near the end of a two-week cold spell.
FERC on Jan. 12 granted a waiver request enabling the ISO to consider incremental energy and minimum generation offers that exceed $1,000/MWh if the generator is able to demonstrate such costs. The waiver covers Jan. 4 to Feb. 28. (See FERC Grants NYISO ‘Cold Snap’ Offer Cap Waiver.)
Distillate prices gained 28.2% year over year, with Jet Kerosene Gulf Coast averaging $14.47/MMBtu. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $14.83/MMBtu, up from $13.91/MMBtu in December.
The ISO’s local reliability share was 59 cents/MWh, up from 9 cents/MWh the previous month, while the statewide share dropped 74 cents from the previous month to -$1.52/MWh. Total uplift costs were lower than in December.
Evaluation of Energy Market Offer Cap
Reviewing the Broader Regional Markets report, Mukerji highlighted NYISO’s ongoing effort to resolve differences between regional offer caps that may interfere with economic- and reliability-driven interchange scheduling.
FERC this month accepted NYISO’s Order 831 compliance filing, which requires the grid operator to cap incremental energy offers at the higher of $1,000/MWh or a resource’s verified cost-based offer, which in turn are capped at $2,000/MWh when calculating locational-based marginal prices.
Mukerji also noted that FERC last month accepted the ISO’s motion to terminate its obligation to submit annual informational filings on its implementation of interface pricing and congestion management and market-to-market coordination initiatives with its neighboring RTOs/ISOs.
The report also said the ISO has analyzed real-time commitment (RTC) and real-time dispatch (RTD) convergence and last month presented the Market Issues Working Group with recommendations to continue to aid the convergence this year. The ISO aims to improve modeling consistency between RTC and RTD and assess improvements to look-ahead evaluations to facilitate more efficient scheduling and price convergence.
NYISO also is working to clarify the minimum deliverability requirements for external capacity from PJM into the New York Installed Capacity (ICAP) market, Mukerji said. At the Jan. 17 BIC meeting, the ISO received approval for ICAP Manual revisions regarding the documentation requirements for capacity imports across the PJM AC ties, which will become effective May 1. (See “BIC Recommends ICAP Manual Revisions,” NYISO Business Issues Committee Briefs: Jan. 17, 2018.)
Day-Ahead Market Congestion Settlements
The BIC on Wednesday recommended that NYISO’s Management Committee approve revisions to Attachment N of the Tariff that provide a methodology to allocate day-ahead market congestion rent shortfalls and surpluses resulting from changes in transmission facility availability to the responsible transmission owner.
Operations Analysis and Services Supervisor Tolu Dina explained how the methodology uses a de minimis threshold to determine circumstances when allocations to responsible TOs are not calculated.
The threshold applies to day-ahead constraint residuals (shortfalls and surpluses resulting from changes in transmission facility availability) that are less than $5,000, provided the sum of all such residuals below the threshold is not greater than $250,000 or 5% of the sum of all residuals for the month. Attachment N currently requires the ISO to conduct certain informational calculations once a year to help in assessing whether the de minimis threshold level presents any concerns.
External Capacity Rights
The BIC approved revisions to the ICAP Manual to better define the amount of capacity that can be imported into New York from neighboring control areas for the 2018/2019 capability year.
Josh Boles, the ISO’s manager for ICAP operations, said the New York State Reliability Council regulates the amount of emergency assistance from neighboring RTOs and “we’re only allowing imports up to a level where we would violate the one-day-in-10 criteria.”
Alternative Methods for Determining LCRs
The BIC recommended the Management Committee approve revisions to the Market Administration and Control Area Services Tariff to establish an alternative method for calculating locational minimum installed capacity requirements.
| NYISO
Zachary Stines, associate market design specialist, presented NYISO’s market design for determining locational capacity requirements (LCRs) for localities that minimize total cost of capacity at the level of excess condition while maintaining the reliability criterion and not exceeding transmission security limits.
The NYISO plan evaluates net energy and ancillary services revenue at different levels of installed capacity using data from the most recent of either the capability year after a quadrennial “demand curve reset” or the annual update.
The ISO has incorporated into the proposed Tariff revisions incremental revisions recommended by stakeholders at the Feb. 6 Installed Capacity Working Group/Market Issues Working Group meeting, Stines said.
BIC Rejects On Ramp/Off Ramp Changes
The BIC also voted against recommending that the Management Committee approve a market design proposal and related Tariff revisions for eliminating localities and revising the existing on ramp/off ramp rules to create a new locality.
Zachary Smith, manager of capacity market design, told the BIC that the proposed methodology is based on reliability planning principles developed to determine whether to create and eliminate localities.
Locality Boundaries | NYISO
The proposed design was intended to make locality price signals direct investment to supply that provides the greatest reliability benefit.
Mark Younger of Hudson Energy Economics called the proposal “a flawed market design.”
“It is attempting to use the transmission security test to estimate a resource adequacy requirement,” Younger said. “The result of the NYISO’s test as proposed is that it will understate the resource adequacy needs and would therefore result in creating localities too late and eliminating them too early.”
Mukerji said that while the ISO has fully mapped out its resources and budget for the year, stakeholders could choose to juggle priorities in a related working group to make room for reworking the on ramp/off ramp proposal.
PJM’s Board of Managers will ask FERC to choose between proposals by its staff and its Independent Market Monitor to insulate its capacity market from state-subsidized generation.
Rather than choose just one of the capacity reform plans on offer, the board instead voted Wednesday to direct PJM staff to file both the capacity repricing proposal it recommended and the MOPR-Ex proposal promoted by the Monitor.
“The board has decided that reform is necessary,” CEO Andy Ott wrote in a letter to stakeholders Friday. “The board has chosen a path that will definitively move the policy question to FERC while proposing a process that maintains opportunities for active, continuing involvement from stakeholders.”
Each proposal “represents a distinct, just and reasonable policy alternative to address the consequences of state intervention” in energy markets, Ott said.
“Deciding between these policy options requires a balancing of federal and state interests, raising questions of federalism and comity that have already presented themselves before the courts, including the U.S. Supreme Court.”
The board didn’t disclose its determination until Friday in order to develop an explanation for its decision. The vote came after a flurry of politicking over the past week from stakeholders, who sent seven letters to the board, almost all of which asking that the board not support PJM’s plan. Exelon was ambivalent about the RTO’s plan but asked that the board reject the Monitor’s plan.
The decision moves PJM another step closer to culminating the work of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) that dominated stakeholder activity in 2017. Stakeholders were at one point considering 10 different proposals, but the field eventually narrowed to proposals from PJM and the Monitor.
PJM said its plan would accommodate generator offers from state-subsidized plants by allowing them to bid into capacity auctions but ensure they don’t suppress competitive prices by removing those offers in a second “repricing” stage of the auction.
The Monitor’s proposal, known as MOPR-Ex, would extend the RTO’s minimum offer price rule (MOPR) to all units indefinitely, but in alternative versions it included carve-outs for states’ renewable portfolios and public power self-supply. Stakeholders, who saw the Monitor proposal as having the least impact on the current construct, backed it all the way to the Markets and Reliability Committee, but all of its different versions stalled there last month after Ott announced he would be recommending the RTO’s plan to the board no matter the outcome of the vote. (See “No Consensus on Capacity Revisions,” PJM MRC/MC Briefs: Jan. 25, 2018.)
The board’s decision represents a win for Monitor Joe Bowring, who had been maneuvering for months to navigate his proposal to stakeholder endorsement despite PJM’s clear indication that it would not support the proposal.
The board directed staff “to present the advantages and tradeoffs associated with each policy approach,” Ott said. Staff should make their preference known in the filing, but that “should the commission decide instead on a policy of mitigation, PJM believes MOPR-Ex would be effective in preserving competitive outcomes in PJM’s markets.”
The board also directed the filing to request “a time-bound settlement judge proceeding” after FERC chooses a proposal “with expectation that such a process will bring refinement, compromise and more consensus support for what ultimately will be presented to the commission later this year as a package of proposed rule changes.”
The board confirmed that the upcoming Base Residual Auction in May will proceed under the current capacity auction rules.
PJM transmission owners’ processes for developing supplemental projects violate Order 890’s transparency and coordination requirements, FERC ruled Thursday in a victory for customers — and, potentially, competitive transmission developers (EL16-71, ER17-179).
PJM stakeholders have been battling for years with TOs over the rules involving supplemental projects — transmission expansions or enhancements not required for compliance with PJM system reliability, operational performance or economic criteria. TOs can develop, build and seek reimbursement for such projects without the approval of PJM, which only reviews them to ensure they don’t harm reliability.
Since 2012, according to an analysis produced for American Municipal Power, PJM’s $11.6 billion in baseline and network upgrades have been exceeded by $12.7 billion of transmission owner-identified (TOI) supplemental projects.
“I’ve frequently spoken about my concern about … the amount of transmission spend[ing] that is directed to categories that are not subject to competitive bidding under Order 1000 and in some cases subject to very little planning that’s done privately by the transmission owners,” Commissioner Cheryl LaFleur said at Thursday’s open meeting. “It’s obviously our responsibility to make sure that if customers are paying for transmission, it’s needed; that regional needs are considered, that things aren’t done individually and that the process is fair and transparent, and I think today’s order is a part of that responsibility.”
LaFleur is the only member remaining from the commission that issued a show cause order over the TOs’ supplemental projects in August 2016, which followed a technical conference on the issue in 2015.
The order caused PJM’s Transmission Replacement Processes Senior Task Force to go on a 10-month hiatus that, even after it ended, has been slow to progress as TOs remained reticent to discuss issues involved in the order. (See PJM TOs, Customers Await Ruling on Supplemental Projects.)
Order 890 Inconsistencies
The TOs responded to the show cause order by contending they were already in compliance with Order 890 and proposing a new Tariff Attachment M-3 that they said spelled out their processes.
The commission agreed with the TOs’ request to move the supplemental project language from PJM’s Operating Agreement to Attachment M-3 but said the attachment fell far short of compliance with Order 890.
FERC found that TOs’ handling of supplemental projects violates both the transparency and coordination principles of Order 890. It said that both the level of detail in the supporting information provided by TOs and the timing of providing that information — often either just before or during meetings to discuss those projects — fails to meet the order’s requirements.
The commission cited Subregional RTEP Committee meetings on Dec. 1, 2016, in which AMP said TOs presented almost 100 transmission projects for stakeholder review, 80% of which were supplemental projects. Two of the projects presented were already complete, seven were under construction and 24 were already in the engineering phase, “at which point it is not possible for stakeholders to provide meaningful input,” the commission said.
“The record in this proceeding indicates that the PJM transmission owners often provide models, criteria and assumptions as part of the supplemental project transmission planning process that are vague or incomplete and do not allow stakeholders ‘to replicate the results of planning studies’” as required by Order 890, the commissioners wrote. “In addition, in some cases, the PJM transmission owners provide the models, criteria and assumptions to stakeholders at the same time as a proposed supplemental project, at which point that project is often at an advanced stage of development and stakeholder feedback is less likely to be meaningful or effective.
“As a result of these two factors — the quality of the models, criteria and assumptions the PJM transmission owners provide and the point in the transmission planning process at which they are provided — stakeholders frequently are not in a position to comment on the transmission planning studies or the resulting transmission needs before the PJM transmission owners take significant steps towards developing supplemental projects to address those needs,” the commission wrote. “The fact that there may be multiple criteria and considerations underlying the need for a supplemental project does not prevent the PJM transmission owners from timely posting a thorough description of those criteria and considering stakeholder feedback before identifying a particular supplemental project. Similarly, the fact that those criteria may vary among the PJM transmission owners also does not prevent them from timely posting each transmission owner’s different criteria.”
The commissioners said the TOs’ practice of simultaneously presenting both the problems and their proposed solutions discriminates against potentially better alternatives.
“The most obvious solution will not always be the best solution. In many cases, supplemental projects address facilities that have existed for several decades, during which time the topography of the electricity grid and the set of potential technologies available to address the underlying need may have changed considerably. As a result, rebuilding the facility that was the most obvious solution many years ago may no longer be the best solution today,” the commission wrote.
FERC also sided with customers that the current process doesn’t clearly define when they should receive critical information about criteria and proposals and when they can comment during the analysis and project development.
M-3 Revisions
The TOs did prevail in their request to move the procedures for planning supplemental projects from the OA — which requires a super-majority endorsement from PJM stakeholders to make changes — to Attachment M-3 of the Tariff. The TOs have exclusive filing rights under Section 205 of the Federal Power Act to make changes in Attachment M-3; to make any changes, stakeholders would need the PJM Board of Managers to file a complaint under Section 206.
However, the commission also ordered revisions to the new attachment, saying it “duplicates and otherwise relies heavily on the provisions … that we found above to be unjust and unreasonable.”
The commission ordered the TOs to revise M-3 and to hold three meetings on each proposed supplemental project: the first to discuss “the models, criteria and assumptions” used to plan supplemental projects, the second to address the needs identified and the third to discuss the solutions proposed to meet the needs.
The revised M-3 must spell out a minimum number of days between each meeting, deadlines for posting the meeting materials beforehand and time frames for stakeholders to provide comments after meetings, the commission said.
“We also find that this additional transparency will help mitigate concerns that supplemental projects may be structured to avoid or replace regional transmission projects that would otherwise be subject to competitive transmission development under Order No. 1000,” the commission wrote.
FERC also ordered the TOs to detail what dispute resolution they plan to use, as the previous rules relied on the procedures in the OA. The commission also ordered PJM to make changes to its OA to ensure consistency with M-3 and compliance with Order 890. PJM and the TOs have 30 days to file the required revisions.
The commission shot down proposals by AMP and Old Dominion Electric Cooperative to require TOs to respond to stakeholder comments, greater PJM involvement in planning for and selecting certain supplemental projects, and PJM review and approval of TOs’ local transmission plans.
‘Encouraged’
AMP’s Ed Tatum said his company is still reviewing the order but is “encouraged by what we have seen so far.”
He pointed to the commission’s affirmations on transparency and coordination principles from Order 890, the need for meaningful input from consumers and the opportunity to replicate TO results.
“Since October 2016, the PJM transmission owners have been unwilling to move from their litigation position and fully engage absent an order,” he said. “Now that we have an order with clear direction, we are ready to roll up our sleeves and work with PJM and the transmission owners to implement the order and make sure consumers are getting the transmission system they need at right price.”
Representatives from Exelon and Public Service Electric and Gas did not response to requests for comment in time for publication.
Chairman Kevin McIntyre did not participate in the ruling.
CARMEL, Ind. — MISO is proposing to eliminate a footprint-wide postage stamp rate and change its rules for market efficiency projects to include regional cost allocation for transmission projects under 345 kV.
The RTO wants to lower its cost allocation threshold to cover 230-kV projects, a move that Director of Strategy Jesse Moser said will capture a reality in the footprint, where 230-kV lines are prevalent and transport a high volume of electricity.
Speaking at a Feb. 13 Organization of MISO States (OMS) board meeting, Moser pointed out that certain parts of the RTO operate at a maximum 230-kV rating, especially in MISO South. That voltage represents a “sweet spot for effective mitigation of congestion,” according to MISO.
“This puts essentially the whole footprint on an equal playing field in terms of getting a cost-shared project approved,” Moser said.
Postage Stamp Removal
MISO is also recommending that it scrap its footprint-wide postage stamp rate for market efficiency projects. The RTO currently allocates 80% of project costs to local resource zones based on expected benefits and recovers the other 20% via postage stamp allocation to all regional load. Instead, MISO wants to assign all costs to benefiting transmission pricing zones and work with stakeholders to create more specific benefit metrics. The move will make for “more granular, more targeted cost allocation,” Moser said.
MISO currently relies on the postage stamp rate as a means of recognizing both transmission benefits not currently quantified within its cost allocation and the changing nature of beneficiaries as the fleet evolves.
Currently, there is no regional cost allocation within MISO for transmission projects below 345 kV, and Minnesota Public Utilities Commission staff member Hwikwon Ham said if it were to abolish its postage stamp rate, it should detail a much more precise set of valued benefits.
In adding new benefit metrics for cost allocation, Moser said MISO may consider aspects such as deferred reliability projects and savings that could arise from opening up the contract flow path with SPP that bridges MISO South and Midwest.
“The benefit metrics discussion will continue,” Moser promised state regulators.
Wind on the Wires’ Natalie McIntire asked MISO to devise a benefit metric for projects that facilitate state renewable portfolio standards.
The RTO will also consider creating smaller transmission cost allocation zones for a more targeted cost allocation and will hold discussions with stakeholders, Moser said.
However, MISO will leave some market efficiency project requirements untouched, including the benefit-based allocation to all zones, a required benefit-to-cost ratio of at least 1.25:1 and the $5 million minimum project cost threshold.
The proposed changes would not apply to multi-value projects. Moser said stakeholders offered “a lukewarm response” to any possible changes to those projects.
MISO is seeking to draft a nearly final allocation proposal by June, with a FERC filing to follow in September or October. It hopes to get approval by the end of the year and introduce the new allocation in early 2019.
Entergy’s integration transition period, which limits cost sharing in MISO South, expires at the end of this year. The RTO has not revised its cost allocation rules since the integration of South in 2013.
‘Something You All Can Live With’
“We’re certainly zeroing in on some specific reforms,” Moser told stakeholders at a Feb. 15 Regional Expansion Criteria and Benefits Working Group (RECBWG) meeting. “We really tried to find areas where we could get broad support. We hope the overall package is something you all can live with.”
Xcel Energy’s Carolyn Wetterlin, chair of the RECBWG, reminded stakeholders that no allocation proposal will satisfy every stakeholder’s wish list.
“We’re getting into that phase where we really have to think about what we’re solid on and where we could give a little as we move toward a filing,” Wetterlin said.
Some stakeholders at the meeting asked for MISO to consider lowering the threshold further to 100 kV, given that some 100-kV projects are needed for reliability and provide economic benefits. Others pointed out that two years ago, FERC ordered a 100-kV minimum threshold for interregional market efficiency projects with PJM. But MISO has yet to propose a regional cost allocation for interregional economic projects down to 100 kV on the PJM seam.
MISO itself originally considered a 100-kV cost allocation threshold for market efficiency projects in a draft proposal issued last year.
Moser said 100-kV lines with solid business cases will still be eligible for local cost allocation, but the RTO prefers that costs for such low-voltage projects are not shared footprint-wide.
“We looked at all the perspectives we heard over the last year, and we view the 230-kV threshold as a reasonable compromise,” Moser added.
Since Entergy’s integration into MISO, the RTO has approved two 230-kV projects in MISO South that qualified under the “economic other” category, which are only eligible for recovery in zonal rates.
Other stakeholders argued for MISO keeping the 345-kV status quo, with one stakeholder saying lower voltage “Band-Aid projects” with limited footprint-wide benefits should not be allocated like higher-voltage “backbone” projects.
Last September, MISO Vice President of System Planning Jennifer Curran told the Board of Directors that the RTO anticipated a range of opinions among stakeholders on cost allocation approaches.
“It’s not surprising that we’ve heard a very large number of opinions,” Curran said at the time. “The one thing that holds true is that when MISO recommends transmission, we have to have a good, strong business case. We can’t recommend things that we don’t think will get passed.”
MISO will continue the cost allocation discussion with stakeholders at the March 15 RECBWG meeting.
ISO-NE is asking distribution utilities in the region to adopt interim ride-through requirements for solar PV inverters that it developed with Massachusetts stakeholders, the RTO told its Planning Advisory Committee on Wednesday.
The RTO said it needs to ensure solar PV generation can remain stable during voltage and frequency excursions because of its rapid growth in the region. The RTO’s 2014 forecast predicted about 1,750 MW of solar by 2022. By 2016, however, the RTO had almost 2,000 MW, and the 2017 forecast predicts 4,000 MW by 2022. Massachusetts, home to 60% of the RTO’s solar resources, is expected to double its PV capacity in the next decade.
| ISO-NE
The new rules are laid out in a source requirement document (SRD) ISO-NE developed with the Massachusetts Technical Standards Review Group, which includes representatives from developers, manufacturers, state regulators and utilities Eversource Energy and National Grid.
The SRD requires that solar inverters have voltage and frequency trip settings and ride-through capabilities and be certified under UL 1741 SA, the safety standard for inverters and interconnection system equipment used in distributed energy resources.
ISO-NE’s David Forrest said the SRD represents an effort to balance transmission and distribution system needs. “Ideally, we’d like DER to ride through any of these faults on the transmission system, [but] … we also have to look at issues on the distribution system,” he said. “So what the ISO is proposing is kind of a compromise between meeting the transmission needs and meeting the distribution needs.”
In Massachusetts, inverter-based solar PV projects greater than 100 kW will be subject to the new rules for interconnection applications submitted on or after March 1. Projects of 100 kW or less will be subject to the rule on June 1.
The RTO hopes utilities in all states will adopt the SRD, saying having one set of requirements for the region will minimize developers’ costs and simplify the modeling of DER in planning studies.
National Grid will require it in Rhode Island, and United Illuminating and National Grid are “looking at implementing the requirements” in Connecticut, Forrest said.
The Energy Policy Act of 2005 requires electric utilities to provide interconnection services based on the Institute of Electrical and Electronics Engineers’ (IEEE) Standard 1547 (Interconnecting Distributed Resources with Electric Power Systems).
ISO-NE said the SRD is “consistent with” Standard 1547 and can be met by all inverters certified under UL 1741 SA. “The key here is that we know that inverters meeting UL 1747 SA are available,” said Forrest.
The RTO sought interim rules while IEEE completes its work on a revised Standard 1547, he said. The institute hopes to complete Standard 1547.1 by late this year or early 2019. Once the revised standard is approved, UL 1741 SA will need to be updated to agree with the revisions, and it will take a year or longer for all inverter manufacturers to have their inverters tested and certified by safety company UL.
As a result, the RTO said it will be 2020 or later before utilities will be able to require use of the revised standard.
The SRD does not cover inverters for fuel cells, traditional generators or energy storage, although they may be covered in the future, Forrest said. “Down the road we may have to look at electric vehicles,” he added. “This isn’t a topic that is going to go away.”
