CARMEL, Ind. — MISO’s membership has elected to keep Directors Phyllis Currie and Mark Johnson while also approving the somewhat controversial installment of current Minnesota Public Utilities Commission Chair Nancy Lange.
MISO Senior Vice President and Board Secretary Stephen Kozey announced the Board of Directors elections results at a Nov. 15 Informational Forum. Voting opened Sept. 27 and concluded Nov. 2.
Each candidate received a majority of membership votes, the RTO revealed. Kozey said the eballot performed “soundly” with no outages from election vendor VoteNet.
“It was not hacked,” Kozey joked, a tongue-in-cheek reference to the recent fear of cyberattacks on the midterm elections.
Kozey said 96 of 139 members voted, well above the 35-member quorum required.
Members voted Lange to the board despite concern by some stakeholders over a sitting commissioner being appointed to the oversight body. Stakeholders said MISO should consider requiring the same one-year moratorium for regulators in the RTO’s states that it requires of directors coming from member companies. MISO’s bylaws require a yearlong cooling period for “directors, officers or employees of a member, user or an affiliate of a member or user.” (See MISO Members Uneasy over Board Nomination.)
This is the first time the RTO has elected either a sitting commissioner or a commissioner from one of the states in its footprint to the board.
Stakeholders noted that Lange made decisions about the grid on behalf of Minnesota customers and utilities up until her election.
Lange will fill the seat vacated by retiring Director Michael Curran, who has served on MISO’s board since 2007. The trio will begin their three-year terms on Jan. 1. Lange’s term at the Minnesota commission doesn’t expire until Jan. 7. Kozey has said Lange will avoid overlap by resigning her post at the regulatory agency early.
Kozey said MISO has requested that its board address whether the moratorium should apply to regulators.
“Because of the issue raised by stakeholders, we’ve asked the Corporate Governance and Strategic Planning Committee [of the Board of Directors] that the applicability of the stay-out be an item that they address,” Kozey said.
The RTO’s Advisory Committee will also discuss the issue at its Dec. 6 meeting during Board Week.
In a release, CEO John Bear said MISO is “fortunate to have an exceptional depth of experience across our Board of Directors.”
After reporting on election results, Kozey announced that he would be retiring from MISO by the end of the year.
“Thank you for putting up with me and my attempts at humor over the years,” Kozey said, choking up. Kozey was one of the RTO’s 21 original employees in 2000. (See “MISO Looks Back at 15,” MISO Changes to Queue, Auction, Cost Allocation to Dominate 2017.) Kozey founded the RTO’s legal department 18 years ago and served as chief legal officer until 2016.
“We have accomplished so much together, and we are now at a good point for me to transition to retirement. I will miss MISO, the people and working with all of our members, but after a fulfilling and satisfying career, it is time to think about the next stage of my life. I can leave the RTO without hesitation that we have the right leadership in place to take this organization into the future,” Kozey said later in a press release.
MISO said it has a succession plan in place and will announce Kozey’s successor later.
ORLANDO, Fla. — The National Association of Regulatory Utility Commissioners’ annual meeting attracted about 1,000 regulators, industry representatives, consumer advocates and other stakeholders.
Attendees participated in discussions on the energy-water nexus, physical and cyber challenges to the nation’s critical infrastructure and EPA’s Affordable Clean Energy Rule proposed in August.
PJM CEO Andy Ott referred to his RTO as a “referee,” balancing resource adequacy requirements with other states’ integrated resource plans.
“Somebody has to step up and say there’s a cost shift here, and unfortunately, now that seems to fall on us,” Ott said. “The big debate is when you start to have competitive states take action to preserve competitive generation or favor certain generation, the crowd on the other side says, ‘Hey, I’m putting my money at risk. It’s unfair.’
“One of the big disappointments of the past year was our proposal to accommodate states and still have competition and integrity in the market. Folks are taking that proposal as being against green, anti-environmental, which is absolutely not the case. We’ve got to create a balance and make sure states’ interests are accommodated or respected.”
“We’re policy takers, not policymakers,” MISO COO Clair Moeller said. “All of the states maintain their statutory obligation to resource adequacy.”
Moeller said MISO’s problems are different from PJM’s because MISO’s residual capacity market is less volatile.
“The economics are between the asset owner and the regulator, predominantly,” he said. “The policy of whether we retire this coal plant or don’t is policy-driven. The predictability of those retirements is better because of that regulatory compact. It’s less volatile on the capacity side because the states maintain that obligation. Our obligation is to maintain the assets people bring to the market.”
Kathleen Spees, a principal with The Brattle Group, said she saw another mission for grid operators: help the states achieve their policy objectives.
“First and foremost is a carbon-free policy. Every decision the markets make helps or doesn’t help the state meet those goals,” Spees said, referring to Moeller’s comment on RTOs being policy takers. “I didn’t hear a solution for how you guys can use the markets to achieve the states’ objectives. Markets have proven to be really effective in achieving reliability.”
“We had a successful tranche of transmission construction to accommodate renewable portfolio standards,” Moeller said. “No one should confuse the construction to achieve those standards with what got built. What got built was to achieve the economic goals of those states. We’re charged with doing things in the public interest. It’s not up to us to pick between generation owners and the states. It’s up to us to decide this is the best path forward in the consumers’ interest.”
“We’ve tried to ensure we’re not putting up barriers to what state policies are trying to achieve,” said Anne George, ISO-NE’s vice president of external affairs. “The states have seen a lot of their environmental policies achieve what they were hoping to achieve. Because they had success, now we’re looking at more aggressive targets. They’re taking actions to move forward. Our job is to look at the marketplace and see how we have the market facilitate what the states are looking to achieve, and to see that others’ part of that regulatory compact have the revenues to provide reliability to the region.”
In the end, Ott said, maintaining confidence in the markets is the best way to ensure open competition.
“If we can’t have a viable market, then Plan B is to flip back to something like competitive procurement, where it’s almost like a synthetic reregulation at a regional level,” he said.
Panel: Flexible Resources not Being Fully Used
Speaking on a panel on flexible resources, Grid Strategies Vice President Michael Goggin said grid operators are not benefiting from all the capabilities renewable energy and distributed generation offer. Were RTOs to remove barriers to full market participation, he said, flexible resources would be able to provide ancillary services and operating reserves.
“All U.S. ISOs have rules that are either directly or indirectly preventing wind and solar from providing services they never thought they were capable of doing,” Goggin said. “Capacity markets are not ideal for bringing out the best of these resources. They’re focused on megawatts, not procuring flexibility. Real-time incentives, through operating reserves and ancillary services and energy markets, provide a much better way of procuring that service when it’s needed. Self-scheduled resources aren’t fully participating in the centralized dispatch, an impediment to bringing about the full capability of these resources.”
David Nemtzow, director of the Department of Energy’s Building Technologies Office, suggested buildings provide another resource that can be tapped. He noted there are 124 million buildings, 118 million of which are homes, in the U.S. They account for 40% of the country’s energy usage, at a cost of $380 billion per year.
“Buildings are an integral part of the electric system. The challenge is to make them flexible without any degradation of the services they provide,” Nemtzow said. In addition to reducing demand through LED lighting and sophisticated sensors that adapt cooling/heating systems and lighting to the number of people present, buildings can be “interoperable, integrated systems … that are grid-responsive,” he said.
“Buildings can signal the utilities, so when the system is stressed or needs resources, a signal can be sent to the building owner or operator and they can make voluntary decisions and participate with the grid,” Nemtzow said.
Ric O’Connell, executive director of GridLab, said the two most significant trends he sees in the industry are the adoption of large, central renewable generation by utilities and policymakers, and the adoption of distributed energy resources by customers.
“The real question is, how do these two major changes interact?” he said. “Do they complement each other, or do they frustrate each other?”
Answering his own question, O’Connell cited a paper he recently published that found the two trends do complement each other. “Part of that is because DERs add flexibility to the grid and enable the addition of more renewables,” he said.
“On a utility-scale system, think of wind and solar as must-take. Sometimes, the rest of the system needs to be there for them. DERs are that thing your system operators are constantly grumbling about. This technology isn’t actually that new. We’re just allowing these resources to expose these characteristics.”
O’Connell referred to Minnesota, where he said modeling revealed that DERs’ flexibility is key to unlocking higher renewable penetrations, and that limiting DERs would dramatically increase the cost to decarbonize the system. “We have to start thinking about how we connect these new technologies,” he said.
Minnesota Public Utilities Commission Chair Nancy Lange, speaking on a separate panel, said the state is doing just that.
Quoting Wayne Gretzky’s strategy of skating to where the puck will be, not where it’s been, Lange said that in distribution planning, the commission thinks it knows where the puck is going.
“We have 4,500 [electric vehicles] in Minnesota. Are we going to have 10,000 in a year, or 7,000 in a year, or 20,000?” she asked. “Those are some of the skate-to-where-the-puck-is-going questions.”
Commissioners Share Their Market Concerns
During an Electricity Committee devoted to market issues, Western regulators shared with their peers the latest developments in the Western Interconnection: CAISO’s expansion of its real-time balancing market; CAISO’s and SPP’s offerings of reliability coordination services as Peak Reliability enters its last year of business; and SPP’s life-support effort to integrate some of the Mountain West Transmission Group.
Utah Public Service Commissioner David Clark quoted NERC CEO Jim Robb, the former Western Electricity Coordinating Council CEO: “The transition that will occur in reliability coordination services in the West is the single most important reliability coordination effort facing the U.S. in the next two years. We have our eye carefully on this transition process.”
Clark said Western states outside of California are concerned about CAISO’s “further extension” of market services.
“The principal challenge for many is the area of governance,” he said. “In Utah, we have a great desire to retain our self-determination, with respect to our energy policy. If we ever become involved in a market being served by vertically integrated utilities, we would want a voice in the government. We would want the operations of that market to be transparent.”
“There’s still skepticism with states and utilities in the West when it comes to take that step to join an RTO,” New Mexico Public Regulation Commissioner Cynthia Hall said. “There’s a growing concern relative to the problems created by seams issues. There’s a reticence to becoming a[n RTO] member. The reasons are multiple, not the least of which is if they have to pay to play — they would have to pay a greenhouse gas adder in California.”
Illinois Commerce Commissioner John Rosales discussed his problems with PJM’s capacity market construct, which he said has succeeded in lowering wholesale prices and the cost of operating reserves.
“What’s been somewhat contentious are the parts that don’t work well, which is pretty much everything else,” he said. “For me, it’s inherently flawed and extremely complex. The capacity construct is constantly being revised. … There have been well over 30 revisions, which becomes very frustrating for the states. We don’t call it a market, because there are so many features that are administratively determined … price caps, the cost of new energy fluctuates, performance requirements. Most of us agree that generally, this construct fails to send the proper price signals to ensure the proper fuel mix.”
Competitive markets have a supporter in Michigan Public Service Commission Chair Sally Talberg, who said, “Whether deregulated or fully regulated or something in between … at the end of the day, we want affordable, reliable service. We all have a common goal in fostering those competitive environments. I feel like we’re dancing around with a patchwork of dos and don’ts at the state level, and that creates uncertainty.”
Indiana Utility Regulatory Commissioner Sarah Freeman said her concern is with a rapidly changing fuel mix. She said her state expects four coal-fired units to retire by 2023, and she noted there are no new builds on the horizon.
“If it’s happening in Indiana, it’s happening bigger and faster somewhere else,” she said. “Once RTOs become involved, we need to maximize our cooperation and avoid any protectionist tendencies we have.”
Seams issues topped Illinois Commissioner Sadzi Oliva’s lists of concerns. She said market inefficiencies show up on the seam, “typically as a result of incompatible market rules.”
“This increases the ultimate cost to the ratepayers,” Oliva said. “The seam between MISO and SPP will be the concern for the majority of us. Illinois’ concern is receiving an unwarranted cost allocation.”
Amid an uptick in spending on transmission infrastructure that has attracted increased scrutiny from those paying the bills, customers and developers met Thursday for a workshop on how to get to the grid of the future.
The Department of Energy convened the daylong session at the National Rural Electric Cooperative Association’s conference center in Arlington, Va., to gather information for the department’s 2019 electric transmission congestion study.
Tatum wasn’t alone in his call for transparency. Traci Bone, an attorney with the California Public Utilities Commission, took issue with transmission projects that receive little or no RTO review. Known as supplemental projects in PJM, they are usually developed by incumbent transmission owners within their own zones to address their own planning criteria. (See FERC Upholds PJM TOs’ Supplemental Project Rules.)
She noted FERC’s rejection in September of a complaint by the CPUC and others who argued that Pacific Gas and Electric and Southern California Edison are violating Order 890’s transparency provisions because much of their transmission planning is done without stakeholder input or review. (See ‘Asset Management’ not Subject to Order 890, FERC Rules.)
It’s “very concerning” that FERC has taken “such divergent views” from ratepayers, she said.
During audience questions following Bone’s panel, Exelon’s David Weaver criticized it as “a very one-sided panel” and said the decision to spend on resilience and security upgrades is not as straightforward as addressing reliability criteria.
“I think it can be perceived that wrong investments are being made,” he said.
“Not so much that they’re making the wrong investments, but we don’t know what investments they’re making,” Bone responded. “We need to have a say in that.”
LS Power’s Sharon Segner, who was also on the panel, argued for increased competition for transmission projects. Following a stakeholder campaign led in part by Segner earlier this year, PJM has begun considering developers’ cost-containment guarantees as part of its analysis of competitive transmission proposals. (See Cost Containment Clears MC Vote Despite PJM Plea.)
Segner noted that eight states — North Dakota, South Dakota, Minnesota, Oklahoma, Nebraska, Alabama, North Carolina and Indiana — have passed right of first refusal laws “to thwart Order 1000” and FERC’s efforts to introduce competition. Order 1000 eliminated ROFRs from FERC-approved tariffs and agreements, but the commission says it is powerless to block states from enacting such laws to protect incumbents’ monopolies.
Public Engagement
The workshop also looked at the importance of public engagement in getting large interregional projects completed. Dan Belin, of engineering firm Ecology & Environment, compared the permitting processes of the Great Northern Transmission Line — to link Minnesota with Manitoba’s hydro resources — and Northern Pass, which would have delivered Quebec hydropower into New England.
Great Northern “had a very robust public-involvement program” that included engagement with the Minnesota Department of Commerce prior to submitting its application, Belin said. The project was approved within the state Public Utilities Commission’s statutory 15-month timeline.
Northern Pass held no meetings prior to submitting its application. The filing attracted 9,000 public comments, and the seven-year review eventually ended in rejection by New Hampshire.
“That significantly draws out the process,” Belin said. “The public involvement piece was a big differentiator between the two projects.”
“What we saw in Minnesota is not typical and it should be more typical,” said Rich Sedano, president of the Regulatory Assistance Project.
He described transmission development as “a public process that is largely shielded from the public” and advocated for improving transparency and public engagement. The process should also remain within state authority, and the industry should “accept the stress it’s going to cause,” he said.
Bess Gorman, assistant general counsel with National Grid, suggested involving the public in the tangible benefits of projects, such as finding ways to include them in benefiting from cost savings.
“As much as you can do,” she said of the need for public engagement. “That’s how you’re going to get the project through.”
Rob Gramlich, president of consulting firm Grid Strategies, credited transmission expansions such as MISO’s multi-value projects, highway/byway projects in SPP and ERCOT’s Competitive Renewable Energy Zones with precipitating the growth in renewables.
“I don’t think we would have half of the wind industry that we have without these plans in the middle of the country,” he said.
Culture Change
Others discussed difficulties winning approval for interregional projects. EDF Renewables’ Omar Martino described a “quadruple hurdle” for one project that required satisfying individual criteria of MISO and SPP and their mutual criteria in addition to securing local approval. The host utility vetoed the project, he said, because it preferred to use an operating guide.
“Something is just not right,” he said. “There’s a gap that needs to be fixed.”
He and others called for culture changes at decisional bodies throughout the process.
“You have to create these programs … inside utilities, inside the RTOs. You also have to have the right culture, the right leadership, the right guidance,” he said.
Gramlich said “the concepts are generally in Order 1000” for interregional planning, “but it didn’t get the job done,” and decisions since then have “weakened” it.
“Nobody wants to pay for something they don’t benefit from, so there’s a healthy skepticism in the RTO process,” he said.
On Nov. 9, the Governors’ Wind and Solar Energy Coalition wrote a letter to FERC advocating for unifying the Eastern, Western and Texas interconnections via ultra-high-voltage lines. The coalition, which includes 19 state governors, compared the proposal to creating the nation’s interstate highway system 60 years ago and the $315 billion grid China is building today.
The coalition cited a study by Iowa State University that estimated the impact of two transmission expansion scenarios: a $40 billion investment in transmission that could allow renewable penetration to rise to 40% nationwide, and an $80 billion investment that could push renewables to 50%.
Cost Allocation
Determining how much transmission is needed and who’s going to pay for it are also obstacles to such ambitious proposals.
In the first morning panel, PJM’s Ken Seiler said that reliability has vastly increased from earlier in his career when “we were hanging on by our fingertips” daily during late-afternoon summer peaks.
Tatum, who shared the panel with Seiler, agreed that there’s no clear measure to “know if we’re over- or under-building” the grid. But he said that it is clear that developers are now making up for a “dearth of investment” in previous years. He noted that PJM is on track to add $7 billion to its Regional Transmission Expansion Plan this year, which would be the biggest addition in the plan’s history.
And then there’s the question of who picks up what portion of the tab.
“Everything goes really, really well until you get in to the concept of cost allocation,” Seiler said. “Once you start talking about money … that’s when the discussion gets really, really tough.”
Participants and audience members cited several examples of cost allocation fights, notably the ongoing debate over the Artificial Island project, PJM’s first competitive project under Order 1000. (See Del. Group Seeks to Block Artificial Island Project.)
“It’s really all about the cost allocation, but if you can solve that, the rest of this stuff is easier,” Gramlich said.
He advocated for broad, beneficiary-pays allocations in which many stakeholders shoulder smaller portions of the bill. Still, that won’t solve everything.
“There is no perfect solution for cost allocation except [to] pay a lot of lawyers for a lot of litigation,” Exelon’s Steve Naumann said.
MISO will soon file a proposal with FERC to relieve its overfilled generation queue by implementing more stringent site control requirements and increasing the milestone payments imposed on project owners.
The proposal is down to a final review from the Planning Advisory Committee, stakeholders learned during the committee’s Nov. 14 meeting. MISO Resource Interconnection Planning Manager Neil Shah said the RTO will file the queue changes before the end of the year.
“Why is MISO revising its queue again when it just did a queue redesign two, three years ago? And the answer is, yes, the queue reform implemented in 2017 is working, but there are areas that we need to tweak because MISO’s queue is getting clogged with numerous projects,” Shah said.
Staff say the changes will encourage stalled projects to withdraw from the queue earlier in the process. (See “MISO to File Queue Changes,” MISO Queues up Interconnection Options.)
Shah said MISO currently conducts unnecessary definitive planning phase (DPP) studies because unready projects enter the first phase of the queue without first securing a location and are nevertheless studied. He said such projects often withdraw too late in the DPP process, affecting other projects and complicating their subsequent studies. The RTO wants to make the queue easier for projects that have site control, are viable “and have done their homework.”
MISO will now define site control as 50 acres/MW for wind generation, 5 acres/MW for solar generation, 0.1 acre/MW for battery storage and 10 acres for other resource types. An interconnection customer that wants to secure less land than required will now have to hire consultants to prove their project does not require the full amount of space.
Documentation of exclusive site control will now be due 90 days before MISO begins queue studies. The RTO will also no longer accept a $100,000 cash fee in lieu of site control. Shah said 75% of the projects entering in the April 2018 cycle and 62% of the projects entering in the August 2017 cycle elected to pay the $100,000 fee instead of demonstrating site control.
However, MISO will still allow interconnection customers experiencing regulatory holdups to submit a refundable, $10,000/MW fee along with detailed documentation and affidavits demonstrating the restrictions. It will also change the first milestone payment from a $4,000/MW fee to 10% of the average network upgrade cost from the RTO’s last three DPP cycles. The second and third milestone fees will remain unchanged at 10% and 20% of network upgrades costs found in system impact studies, respectively.
MISO will now withdraw a project before the queue’s second decision point if the customer fails to demonstrate exclusive site control.
The proposal also alters MISO’s current practice of refunding 100% of the first and second milestone payments at the two decision point “off ramps” embedded in the queue, where projects can drop off without risking the most recent fees. The RTO will now only refund 50% of the first milestone payment at the first decision point and 75% of the second milestone payment if a project withdraws at the second decision point.
Shah said MISO is expecting another heavy round of queue entrants in the first quarter of 2019 and that the changes will help in the long term to limit the number of projects that enter and trigger multiple studies. The queue currently contains nearly 80 GW worth of generator projects.
Multiple stakeholders thanked MISO for researching and proposing the queue changes.
“I really appreciate MISO making these changes to progress the queue and not allowing it to reach a stalemate. I really hope this will make things better so we can do our job at the state level,” Minnesota Public Utilities Commission staff member Hwikwon Ham said.
Additional work on the queue will continue in 2019. The Interconnection Process Task Force (IPTF) will work early next year to propose rules that allow hybrid generation interconnections and two generators to share one point of interconnection.
The IPTF may also begin work on several stakeholder suggestions currently on hold. They include:
Reducing phase one of the DPP by 30 days;
Cutting down the generation interconnection agreement timeline from 150 to 90 days;
Putting a megawatt limit on the total number of projects that can enter a queue cycle; and
Reviewing how many projects submit cash versus a letter of credit for milestone fees, possibly opening the credit practice to changes.
Freshly Minted Interconnection Working Group
MISO will also be providing the IPTF with a facelift after agreeing to convert the task force into a more permanent working group.
The IPTF was set to sunset in January. In MISO’s stakeholder structure, working groups are more permanent than task forces, which have an expected sunset date.
The Steering Committee approved the move by general consent on Nov. 15, adopting the October consensus from the PAC. MISO’s eight voting stakeholder sectors voted 5.33 in favor, with 0.67 opposed and two abstentions, to convert the task force into a working group. (See MISO Stakeholders Rally to Save Interconnection Group.) MISO sectors are allowed to split their votes based on differing organization and company opinions within a sector.
Seeing the “overwhelming” vote in favor of the move, MISO Director of Planning Jeff Webb said the RTO will now support the move, despite initially opposing the change. MISO had initially recommended the IPTF merge into the Planning Subcommittee, because both deal with technical issues of modeling and study processes used in its annual Transmission Expansion Plan.
Webb said the RTO believed that a group merger was “pretty consistent with … MISO’s stakeholder redesign,” which discourages duplicate discussions across stakeholder groups. However, he said MISO will be able to continue to provide staff, liaisons and meeting space for an Interconnection Process Working Group.
PAC Chair Cynthia Crane said it was important for MISO to recognize the strong stakeholder consensus to preserve a working group.
Additionally, the Steering Committee adopted additions to the Stakeholder Governance Guide that clarify rules around sunset dates for MISO groups. The committee added language that parent committees and the Steering Committee “should be diligent in the review and manage of entity sunset dates” of task teams and task forces. The language also specifies that motions for retirement should originate in the groups in question, with the Steering Committee “charged to review and manage sunset dates if applicable.”
Parent entities will be responsible for bringing retirement recommendations before the Steering Committee. The revisions also specify that the Advisory Committee can vote to “uphold or modify” Steering Committee retirement recommendations, particularly if the Steering Committee, the group in question or the parent entity disagree on whether to retire the group.
MARLBOROUGH, Mass. — ISO-NE last week kicked off its formal annual review of the transmission system to delineate zones for Forward Capacity Auction 14, which will be held in February 2020 to cover the 2023/24 capacity commitment period.
Al McBride, the RTO’s director of transmission strategy and services, told the Planning Advisory Committee that “we’re coming out of a significant backlog of interconnection requests in Maine.” He noted that FERC’s approval last year of clustering has enabled the queue to move forward. (See FERC Approves ISO-NE Queue Clustering.)
Potential capacity zone construct for FCA 14. | ISO-NE
The first cluster of more than 600 MW is proceeding through the system impact study process, as is an external elective transmission upgrade of 1,200 MW, which are collectively driving the creation of a Maine capacity zone, he said. The RTO is not proposing a Northern Maine capacity zone because the deliverability standard requires new resources in the state to be deliverable throughout the Maine load zone.
“That’s a significant number of new resource additions,” McBride said. “Maine used to be export-constrained, particularly from north to south, but after the Maine Power Reliability Program upgrades, there has been headroom. This headroom would more than be used up by the projects moving forward in the system impact study process.”
The trigger to model an export-constrained zone is based on the quantity of existing and proposed new resources compared with the maximum capacity capability in the zone.
Zone formation is a two-step process: First, identify the potential zonal boundaries and associated transfer limits to be tested for modeling in the Forward Capacity Market; then use objective criteria to determine whether or not the zone meets the trigger to be modeled for the capacity commitment period.
To form capacity zone boundaries, the RTO considers significant changes over the past year, including new transmission upgrades, resource retirements and new capacity resources.
Boundary Specifics
ISO-NE does not expect transmission upgrades in the Southeastern Massachusetts and Rhode Island (SEMA/RI) area to change the boundaries of that area or the Southeast New England zones, McBride said.
Most of the SEMA/RI Reliability Project upgrades have not yet been certified for use in the FCM, and certifications for FCA 14 will be known in January 2019. However, if the SEMA/RI Reliability Project upgrades are certified, planners will assume they will be in place for the 2023/24 period.
| ISO-NE
Mystic 7 will be retiring with the start of the 2022/23 period. The RTO has previously analyzed different potential future retirement scenarios, including the loss of Mystic 7 and other units, and did not expect such retirements to drive a change in capacity zone boundaries.
Capacity interconnection requests as of Nov. 1 are more than 700 MW from West/Central Massachusetts, with the rest, all nameplate, being more than 4,100 MW from New Hampshire/Vermont; more than 6,200 MW from Maine; more than 7,700 MW from SEMA/RI; and more than 2,700 MW from Connecticut.
SEMA/RI 2028 Needs Assessment
ISO-NE’s SEMA/RI 2028 Needs Assessment Scope of Work study assumes the complete retirement of the 2,274-MW Mystic plant and includes analysis assuming that Vineyard Wind and the New England Clean Energy Connect (NECEC) projects will be in service, according to Kannan Sreenivasachar, ISO-NE’s transmission planning technical manager.
Sreenivasachar told the PAC on Thursday that the study for the 10-year horizon will be using data from the 2018 Capacity, Energy, Loads and Transmission (CELT) report to determine the forecasts for the peak load levels evaluated.
All transmission and generation facilities operating as of June 1, 2018, are included in the base cases, and the 34,092-MW 90/10 summer peak load includes 5.5% transmission and distribution losses.
The study evaluates reliability performance and identifies reliability-based needs in the SEMA/RI study area for the year 2028 while considering future load distribution, resource changes based on FCA 12 results, and the 2018 solar and energy efficiency forecasts, Sreenivasachar said.
The study assumes that resources without an obligation (typically through the FCM) cannot be relied upon to resolve a reliability need and are therefore not considered in the steady state analysis. However, they do contribute to the available short-circuit current, as they may be in service as part of the energy dispatch of the system, he said.
The study bases its short-circuit base case on the expected topology in the 2023 compliance steady state base case. No significant project is expected in the 2023-2028 time frame, and hence the 2023 case was considered acceptable, Sreenivasachar said.
Asked about future generation selected in state solicitations, Director of Transmission Planning Brent Oberlin said there were two options.
He said if the RTO finishes the study ahead of final approval of those projects, the identified needs will be based on conditions without the generation in place. Upon approval of the generation, the needs will be changed to those associated with the scenarios that included the generation. If the generation is approved prior to the completion of the study, the needs associated with scenarios that do not model the generation can be ignored.
Stakeholders should submit comments on the study to pacmatters@iso-ne.com by Dec. 2. The RTO plans to post the draft study and intermediate study files in the first quarter of next year before completing the study area 2028 Needs Assessment and presenting it to the PAC by Q2 2019.
The RTO’s next steps will be to review transmission certifications for FCA 14 with the Reliability Committee in January, and to further discuss the potential capacity zone boundary construct at the PAC in the first quarter of 2019.
Moody’s Sees Region in Good Economic Shape, for Now
Moody’s Analytics Director Ed Friedman told the PAC that New England is leading the Northeast in economic development, particularly job growth, which is not typically the case, as that occurs more frequently earlier in an economic expansion or business cycle.
“That’s been a good development over the past year, but probably not sustainable over the long term,” Friedman said.
Massachusetts and New Hampshire have led the region in new hiring since last October, both outpacing the national average, with Rhode Island very close to the U.S. figure of about 1.7% in employment growth.
“The drivers are the booming tech sector in Boston … and in and around the Seaport district,” he said.
New England leads the Northeast in employment, according to Moody’s Analytics.
New England is unfortunately hampered by a generally weak and aging demographic outside places like Massachusetts, which holds back labor force growth, he said. “Very good job growth just cannot go on forever” without a growing population to feed the labor force.
The better than 3% wage gains posted in most of the region’s six states over the past year — only Connecticut and Rhode Island fell below that level — will likely continue over the coming year, but consumer confidence in New England is lower than in any other part of the U.S., Friedman said.
FERC ruled last week that an existing Montana wind farm awaiting a new interconnection is exempt from a recent commission order requiring all new generators to be capable of providing primary frequency response.
The commission’s Nov. 15 ruling said Order 842 does not apply to NaturEner’s Glacier Wind Farm II, which has been in the queue for Enbridge’s Montana-Alberta Tie-Line (MATL) since 2013 and currently the only resource to request to join the 214-mile, 230-kV AC line extending from Lethbridge, Alberta, to Great Falls, Mont. (ER18-1788). The wind farm began operating in SPP in 2009.
Order 842 requires all new generators to be capable of providing primary frequency response as a condition of interconnection. The rule has been in effect since May.
MATL | Enbridge
Enbridge’s U.S. operating subsidiary for the line, MATL LLP, asked the commission to clarify that Order 842 does not apply to the pending interconnection request, saying the wind farm applied for interconnection and was studied before the rule was issued. The company said requiring frequency response service would “cause significant equipment installations and system restudies that would cause unduly burdensome delays and expenditures.” MATL estimated that restudies would cost anywhere from $15,000 to $20,000 and take three to six months.
FERC assured the company that the rule does not apply to the existing generator. The commission pointed out that MATL’s pending request involves a generator that has already been in operation under another interconnection agreement for about nine years and has been lined up for interconnection for five years, well before the issuance of the final rule. FERC also said the wind farm has not taken “any action that requires the submission of a new interconnection request.”
MATL noted that its has nearly completed the associated interconnection studies with NaturEner and expects to proceed with the negotiation of an interconnection agreement in the near future.
MISO now has a fifth wintertime waiver of its $1,000/MWh offer cap in hand after FERC approved the RTO’s request on Nov. 16 (ER19-27).
The commission allowed a waiver with conditions identical to the last four. (See FERC Grants MISO 4th Winter Offer Cap Waiver.) The waiver is effective from Dec. 1 through April 30, 2019.
Consumers Energy crews this year | Consumers Energy
“MISO’s experiences during the 2014 polar vortex, as well as the cold weather events of January 2018, demonstrate that fuel costs can increase to a level such that the current $1,000/MWh offer cap prevents resources from submitting incremental energy offers that reflect their marginal production costs. If similar weather and natural gas supply conditions materialize in the 2018/2019 winter, some resources could face the untenable position of being forced to offer electricity at levels below their actual cost,” FERC said.
Last winter, MISO experienced extreme cold in its North subregion starting Dec. 27, with frigid temperatures hitting the entire footprint Jan. 1 to 6. In all, MISO said the cold snap lasted longer than the 2014 polar vortex. Less than two weeks later, MISO South faced another cold snap. The event is the subject of a joint FERC/NERC investigation, which was announced in early fall. (See FERC, NERC to Probe January Outages in MISO South.)
While MISO said published gas index prices did not hit the $67/MMBtu experienced during the polar vortex, “there were a few resources during late December 2017 that offered within a dollar of the $1,000/MWh energy offer price cap due to high intraday prices for procuring non-firm gas.” The RTO said its ongoing coordination work with neighboring balancing authorities and a lower outage rate kept prices below 2014 levels.
However, MISO said its fourth waiver was helpful in that it granted generator operators peace of mind that they could have recovered costs that inched above $1,000/MWh.
MISO has until Oct. 1, 2020, to implement a $2,000/MWh hard cap for verified cost-based incremental energy offers. (See MISO Granted Longer Deadline for Offer Caps.) The RTO is all but certain to request another offer cap waiver for the 2019/20 winter.
Entergy Arkansas crews in winter | Entergy
“After implementing the reforms required by Order No. 831, MISO will no longer require temporary waivers because these reforms are intended to provide for a long-term solution to the issues associated with MISO’s offer cap,” the commission said.
In its request for this year’s waiver, MISO said it couldn’t yet tell whether 2014-style price spikes could occur during the 2018/19 winter months.
This year, MISO is using forecasts of a warmer-than-normal winter in much of its footprint, though the RTO says it’s prepping for a 40% possibility of entering emergency procedures at least once during the season. (See MISO Foresees Manageable 2018/19 Winter.)
PJM’s highly anticipated re-evaluation of its largest-ever congestion-reducing transmission project reiterated staff’s analysis that the project’s economic benefits to the region exceed its costs.
The $366.17 million project proposed by Transource Energy — the Independence Energy Connection — would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border. One line would run between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; the other would run between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.
Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | PJM
The RTO published its findings in a white paper released Thursday that showed a final benefit-cost ratio of 1.4, down slightly from the 1.42 staff reported at the September meeting of the Transmission Expansion Advisory Committee.
The slight decrease is attributable to a roughly $8 million increase in the project’s 15-year annual revenue requirement to $505.85 million. The benefit — measured in decreased load costs — held steady at $707.29 million. The actual estimated project costs increased from $366.17 million at the TEAC meeting to $372.2 million in the white paper.
The 1.4 ratio is still higher than the previous 1.32 evaluation from February and well above the RTO’s 1.25 threshold to consider projects. The current analysis shows that without the project, reliability violations will materialize as early as 2023 on three 115-kV lines in Adams County, Pa., the 500-kV Peach Bottom-Conastone line and the 500/230-kV transformer at Three Mile Island.
The project will also increase the ability to import power into the Baltimore Gas and Electric locational deliverability area.
Opposition
Residents of the region where the lines are planned attended the September TEAC meeting to register their objections, but staff pointed them toward the ongoing project proceedings being held in both states. (See PJM Redirects Residents’ Protests of Tx Project to States.)
The inclusion of newly identified reliability benefits has done little to sway the residents’ opposition, who believe it’s a ploy to avert the project’s potential failure at the state level.
“Faced with near certain failure, PJM is trying to reposition the IEC as a reliability project,” Pennsylvania resident Barron Shaw wrote in a recent blog post. “This is a desperate assertion made by an organization that has no credibility remaining. … Why would anyone believe PJM’s assertion that this project was suddenly all about reliability? The load forecast for the target market is flat, and every year the forecast is decreased. New high-voltage lines in York and Harford County have been constructed and are operating at less than 50% capacity. Recent and pending upgrades to move power across the grid in Maryland have drastically cut electrical congestion. The project is simply not needed.”
Shaw also accused PJM of fixing the ratio analysis and decried the millions of dollars taxpayers and ratepayers are already on the hook for, whether the project ever gets built or not.
“PJM allowed Transource to announce their new cost estimates one month after PJM announced their recalculated benefits for the project, in effect giving Transource the ability to provide the ‘right’ answer and save the project from cancellation,” he said. “This project is dead, and it is time that PJM admits it and moves on … before people begin to question why PJM is needed at all.”
HOUSTON — ERCOT set a pair of demand records last week, establishing new marks for wind energy generation and November monthly demand as temperatures dipped below freezing in much of the state.
The grid operator recorded 17.9 GW of wind generation on Nov. 12, accounting for more than 40% of the generation in its footprint. That broke the old record 17.5 GW set on Feb 19.
ERCOT, which manages the grid for about 90% of Texas, has more than 21 GW of installed wind generation. It has another 40 GW of wind energy in its interconnection queue.
It twice set monthly demand records for November, reaching 55.3 GW the evening of Nov. 13 and 56.3 GW the next morning. That broke the old 2014 mark by more than 5.4 GW.
“We’re busting through these records,” ERCOT CEO Bill Magness said during a Gulf Coast Power Association luncheon. “We continue to see load growth in Texas.”
ERCOT’s last capacity, demand and reserves (CDR) report indicated its load will grow from 71.7 GW in 2019 to almost 78 GW in 2023. The grid operator will release an updated CDR in December, but Magness said he expects the load projections to grow again.
Load projections in West Texas | ERCOT
Magness shared with his audience a slide of Culberson County in West Texas, where oil and gas exploration has driven demand through the roof. Eight studies have been conducted in the area since 2014, with a load increase each time.
“If you’re a planner, this will make your stomach hurt,” Magness said. “Every time we’ve done a forecast, it’s gone up dramatically.”
The demand record for November was the 10th the grid operator has set since January 2016. Only February and March have demand records that date back to 2015 or earlier.
MISO staff are seeking to advance the RTO’s full 2018 Transmission Expansion Plan despite stakeholder objections to two projects, board members heard last week.
Staff recommend moving ahead with all 442 projects currently spelled out in the $3.3 billion plan, but the Planning Advisory Committee endorsed only 439 of the proposals, Executive Director of System Planning Aubrey Johnson said during a Nov. 13 conference call of the Board of Directors’ System Planning Committee.
The two projects sparking concern at the PAC include the rebuild of the Wabaco-Rochester 161-kV line in southern Minnesota and American Transmission Co.’s Straits of Mackinac project to replace a 138-kV circuit connecting Michigan’s Upper and Lower peninsulas. Stakeholders have complained the costs for the Wabaco-Rochester project will shift from generator interconnection customers to local load customers and have said that an alternate solution would better suit the Mackinaw area.
The third proposal not receiving endorsement has stirred less controversy: ITC Midwest’s capacitor bank project at the Walters 161/69-kV substation in southern Minnesota, which was only held from endorsement to allow MISO to update the project’s details. (See MISO PAC Puts MTEP 18 to Vote, Removes 3 Projects.)
The 10 voting sectors of MISO’s Advisory Committee eventually voted 5.25 in favor of the nearly complete MTEP 18, with 2.75 opposed and two abstentions. MISO’s sectors can divide their single vote based on differing opinions between organizations and companies within the same sector.
MISO is openly defying the strong objections of at least some stakeholders by recommending that the Wabaco-Rochester line and Straits of Mackinac circuit rebuild move ahead as planned.
Johnson said MISO staff are recommending the $11 million Wabaco-Rochester project despite stakeholder concerns over cost allocation and Xcel Energy’s request to defer the project in favor of a larger solution later. The RTO said the project improves market efficiency and has benefits “well in excess of costs” at 6.8:1. Johnson said staff have studied alternatives to the project, including proposals submitted by Xcel.
“The area is experiencing congestion currently, and there are no generator interconnection customers identified as responsible for upgrading this circuit,” MISO said.
MTEP 18 breakdown | MISO
MISO also continues to recommend ATC’s $105 million plan to replace its underwater circuit linking Michigan’s Upper and Lower peninsulas, which was damaged last year when the cables were struck by a passing vessel.
While stakeholders agree that ATC’s damaged cables should be replaced, some are divided on whether the cables should be installed on the bottom of the lake or in an underwater tunnel. Stakeholders have raised the possibility of an interim solution if the more complex tunnel option is needed. Some have also proposed alternative or joint ownership of the replaced cables.
Johnson said MISO believes the best course of action is ATC “expeditiously” replacing the cables, which solves the immediate planning issue. He also pointed out that ATC has the right to replace its own equipment under the terms of MISO’s Transmission Owner Agreement.
Johnson added that MISO “does not address regulatory requirements governing the manner of placement of the cables within the straits, as that is a state siting issue.” The siting on the Mackinac project has not been finalized with the Michigan Public Service Commission.
The uncontroversial $11 million Walters substation project was originally proposed as a line and transformer project but has evolved into a capacitor bank installment to improve voltages in the area. The PAC withheld approval so the alternate project could be updated into the MTEP 18 list. MISO said it has since updated the project details and isn’t aware of any outstanding stakeholder issues with the project. Johnson said the issue was resolved prior to the close of the PAC meeting in October.
Stakeholder Pushback
During the call, Director Phyllis Currie asked for stakeholder reaction to MISO’s decision to move ahead with the Wabaco-Rochester project, but none offered opinions during the open comment period. It was later discovered that technical difficulties prevented stakeholders from getting a line opened on the operator-assisted call. MISO held a special comment period by phone on Nov. 15, and CEO John Bear that same day apologized to stakeholders for the mishap during an Informational Forum.
During the make-up call, stakeholders repeated criticisms of the two proposed projects.
Representatives of Wolverine Power Supply Cooperative said the company submitted an alternative proposal to the Mackinac project and said MISO staff may have been too quick to dismiss it.
But ATC’s Brian Drumm said MISO evaluated the project and alternatives properly. He also pointed to ATC’s contractual right to perform upgrades on its own equipment.
Dairyland Power Cooperative’s Terry Torgerson said MISO’s estimated savings on the Wabaco-Rochester line are overstated.
Xcel Energy’s Carolyn Wetterlin said Xcel and MISO also “ended on a disagreement” this year concerning the Rochester-Wabaco line. She said the proposed line only shifts congestion into another area. Wetterlin asked that MISO delay the solution until MTEP 19.
The board will vote on whether to approve MTEP 18 in its entirety at its meeting on Dec. 6.
