Page 1325 – RTO Insider

September 30, 2018

MISO to Create NOLA Cost Allocation Zone

By Amanda Durish Cook

MISO said last week it will approve New Orleans’ request to make the city a cost allocation zone but is deferring action on an interregional cost-sharing plan advanced by transmission owners.

In a letter signed by City Councilmember Helena Moreno, New Orleans asked MISO to create a standalone cost allocation zone for the city, pointing to FERC’s policy that project costs be allocated “roughly commensurate” with estimated benefits and that non-beneficiaries not be required to pay for them.

“MISO’s analysis has demonstrated that cost allocation on a more granular level within the state of Louisiana will improve the alignment of benefits and costs, consistent with MISO’s objectives for cost allocation reforms,” the city said.

miso nola cost allocation zone — Jesse Moser | *© RTO Insider*

The request involves creating an Entergy New Orleans transmission pricing zone. Director of Strategy Jesse Moser said the zone will not contain overlapping regulatory jurisdictions.

MISO conducted analyses to determine whether a New Orleans zone would contain enough generation and load to calculate benefits and result in better alignment of the costs and benefits for economic projects under the Transmission Expansion Plan.

“The short answer is ‘yes,’” Moser said during a Sept. 27 Regional Expansion Criteria and Benefits Working Group meeting. He said example calculations show MISO can isolate benefits and costs for New Orleans.

“We do plan to make a filing some time in the middle of October … to effectuate this change,” he said.

How Small?

Stakeholders asked MISO how small it’s willing to make cost allocation zones, with some saying they thought the RTO favored larger cost allocation zones.

MISO hasn’t established how small is too small, Moser responded.

“We could have something that’s too small. I don’t think we’ve put any definition around that yet,” Moser said. “It’s going to be incremental steps, and I think this [New Orleans] zone is a step in that direction.”

The current 11 cost allocation zones, based on the historic grouping of transmission pricing zones by state jurisdiction, resemble the 10 local resource zones used in the annual capacity auction. MISO earlier this year separated its Texas territory into a distinct cost allocation zone at the request of regulators.

Moser said MISO’s smallest cost allocation zone currently contains about 300 to 400 MW of generation. He added that while the RTO will not create any new cost allocation zones beyond New Orleans ahead of its planned cost allocation filing with FERC, it may revisit the possibility of creating new, smaller zones in the future.

“I think it’s something we’re going to come back to. I don’t think we’re done with this level of granularity,” Moser said.

As part of its cost allocation overhaul, MISO said it would look into the possibility of more specific zones. The RTO has proposed eliminating a footprint-wide postage stamp rate and lowering its current threshold for market efficiency projects from 345 kV to 230 kV. It will also add new benefit metrics to judge a project’s eligibility for cost allocation, including consideration for projects that defer or avoid other reliability transmission projects and a benefit for projects that reduce flows on the contract path on SPP transmission linking MISO’s North and South regions. (See MISO Recommends Cost-Sharing for Sub-345 kV Tx.)

Speaking before the Board of Directors in September, MISO Vice President of System Planning Jennifer Curran said the RTO’s cost allocation proposal had determined a good way to estimate regional benefits considering the “various interests of stakeholders.”

“This is a very thorny issue here. You’re talking about money,” Director Mark Johnson said. “The entire MISO team needs to be commended for this effort.”

Alternate Interregional Proposal

However, most members of MISO’s Transmission Owners sector are seeking an alternative to the RTO’s plans for interregional project cost allocation.

A majority of TOs, including those with Section 205 filing rights, have formally requested that MISO consider their alternative approach for projects developed jointly with SPP and PJM.

The proposal stipulates that for interregional projects located in both RTOs through tie lines — or wholly within MISO — MISO would allocate costs to each RTO based on adjusted production cost benefits outlined in joint operating agreements. To allocate interregional costs within MISO, benefiting cost allocation zones would share costs for projects 230 kV and above, and the transmission pricing zone where the project is located would take on costs of projects below 230 kV down to 100 kV.

For interregional projects located wholly outside of MISO in either SPP or PJM, RTO costs would be divvied up according to adjusted production cost, with MISO’s allocation spread across benefiting cost allocation zones for projects 230 kV and above. However, for 100- to 229-kV projects, costs would be divided based on a line outage distribution factor (LODF) to determine the local transmission prizing zone beneficiaries. A LODF measures the change in flow on a facility stemming from the outage of a new project facility.

The RTO has said it wants consistency in project requirements along its seams with SPP and PJM, citing that reason in June when it proposed cost sharing 100-kV and above interregional projects along both the PJM and SPP seams. At the time, more than 20 MISO TOs said they opposed the 100-kV cost sharing threshold on SPP interregional projects because the MISO-SPP seam is lengthier with sparser load density than PJM. They also argued the seam is a better fit for higher-voltage projects, which can carry electricity farther. (See MISO to Lower SPP Interregional Project Thresholds.)

Moser said MISO is not yet taking a stance on the TOs’ proposal, waiting until it can work out numerical examples for hypothetical projects under the proposal. He said the RTO might not take an official position until early November.

“We appreciate the work of the owners,” Moser said. “It’s not everyone in the TO community, but it does represent a [Section] 205 filing majority, notwithstanding other filing rights that could be exercised in that community.”

Speaking for the TOs, attorney Wendy Reed thanked MISO for considering their proposal and said members hope they can negotiate with the RTO to avoid filing a competing cost allocation proposal with FERC.

Stakeholders at the meeting appeared divided on the proposal. LS Power’s Pat Hayes and Northern Indiana Public Service Co.’s Clark Gloyeske said they still supported MISO cost sharing down to 100 kV on interregional projects, though Mississippi Public Service Commission Counsel David Carr expressed support for the TO proposal. MISO asked for written stakeholder feedback on the proposal through Oct. 16.

September 30, 2018

MISO Queues up Interconnection Options

By Amanda Durish Cook

MISO last week announced plans to update its interconnection queue procedures to allow multiple projects to interconnect at one point on the system. It also said it will study ways to bring hybrid projects into the process.

At the same time, the RTO is receiving stakeholder pushback on previous proposals to increase the queue’s milestone fees and merge its Interconnection Process Task Force (IPTF) with the Planning Subcommittee.

Speaking at a Sept. 25 IPTF meeting, MISO engineer Tim Kopp said the RTO now thinks multiple projects can share a single interconnection point, but it wants a shared-use agreement struck early in the process and separate metering for each interconnecting facility. He said MISO plans to make Tariff changes that will go before the Planning Advisory Committee.

miso interconnection queue iptf — 2 projects 1 POI | *MISO*

MISO’s current policy allows only one project per point of interconnection, but market participants have contended they can decrease costs by sharing a single point of interconnection.

The RTO’s plan would require interconnection customers to signal their intention of a multiparty arrangement when they submit applications to join the queue. Before entering the queue, the customers, transmission owner and MISO itself would sign an agreement that would be referenced in the projects’ generator interconnection agreement. Kopp said the agreement is needed to prevent customers from changing use arrangements while advancing through the queue.

“We don’t want to introduce delays with this process because we’re waiting on interconnection customers to negotiate” use agreements, Kopp said.

MISO expects joint requests to increase in the future as smaller projects that only use a small amount of interconnection service proliferate on the grid, he said.

Hybrids in the Queue

MISO staff said minimal revisions to the Business Practices Manuals are required to accommodate hybrid interconnection configurations within the queue study process.

The RTO expects it will most commonly study storage alongside wind and solar generation, as well as wind and combined cycle configurations and wind and solar configurations. Wind and solar have somewhat complementary roles in the MISO footprint; wind tends not to kick up full-force during the sunniest periods of the day.

MISO also said it would consider other configurations at stakeholder request.

“We’re open to review on what stakeholders are going to address,” said Neil Shah, MISO manager of resource interconnection.

Draft rules show MISO would largely use its existing BPM language for other resource types, though it said it will evaluate hybrid fuel dispatch predictions, used in its five-year-out power flow analysis, on a case-by-case basis in ad hoc meetings.

During a Sept. 24 Energy Storage Task Force meeting, Xcel Energy and NextEra Energy proposed that MISO phase in hybrid formats involving storage over time, with hybrid market rules created in the short term. In the longer term, the RTO should devise plans for optimizing charging, which would be handled either by the RTO or market participants, the companies said. Beyond that, MISO would create a flexible participation model where hybrid unit owners can toggle among which ancillary and energy services they provide.

NextEra’s Holly Carias said MISO and stakeholders would have to establish how to best optimize intermittent resource hybrids like wind and solar so they charge and discharge at the most economic times. MISO’s compliance with Order 841 will not involve storage optimization. (See “No Optimization Yet,” MISO Closing in on Storage Participation Plan.)

Energy Storage Task Force Chair John Fernandes said the issue could be ripe for a white paper. MISO’s Steering Committee this month recommended the task force focus on creating white papers for technical storage issues. (See New Direction for MISO’s Energy Storage Task Force.)

MISO to File Queue Changes

Stakeholders are skeptical about MISO’s final milestone modifications aimed at speeding up the slow-moving, 90-GW interconnection queue. While the RTO’s proposal for more stringent site control appears unchallenged, its plan to revise the milestone fee structure is drawing ire. (See MISO to Tweak Queue Rules on Site Control, Project Fees.)

The latest version of the plan calls for the last of three milestone payments in the queue to be reduced to 10% of network upgrades, down from an earlier proposal of 20%. However, MISO plans to raise its first milestone payment from $4,000/MW to $10,000/MW, and some stakeholders say the increase is too steep. They question the RTO’s reasoning for more than doubling the rate.

Tradewind Energy’s Derek Sunderman said MISO was unnecessarily focusing on the milestone fee structure when it should be working to expedite its own study process.

“I would argue that MISO really needs to focus on its study process because this is getting ridiculous. … I don’t think MISO is listening to stakeholders,” Sunderman said.

MISO Resource Utilization Director Vikram Godbole said the current low milestone fees don’t do enough to deter interconnection customers from entering speculative projects that could harm the economic viability of ready projects.

“Our record does not indicate good progress,” Godbole said of the 90-GW queue, arguing for the milestone change.

Other stakeholders said that the active queue will likely slow down after production tax credits for new wind generation expire in 2020.

But Rhonda Peters of Clean Grid Alliance (formerly Wind on the Wires) said the 35 GW of prospective solar generation currently in the queue suggests that solar will become the new resource that keeps the queue busy.

Shah asked for stakeholder feedback on the revised plan by Oct. 9. He said MISO expects to have a final version of the plan in time for review at the Oct. 17 PAC meeting.

In-house Model Development

Shah added that, contrary to some opinions, MISO is focusing on speeding up its study process.

One example: MISO will start building queue study models in-house, according to principal engineer Cody Doll, who noted the RTO currently hires third-party consultants to build the models used in the definitive planning phase of the queue.

“Currently, there seems like there are a ton of delays in our model building,” Doll said. “We’re doing this to gain control of the process.”

Doll said the new process will help MISO maintain better records of the queue process and should cut down on errors made when entering information. It should also shorten MISO’s current 30-day model review period, which can stretch into months depending on whether the RTO uncovers modeling errors.

“We’ll still have the review period, but we’re hoping it’ll be a week or so,” Doll said.

End of IPTF?

Meanwhile, MISO is proposing to end the IPTF and fold its discussions and duties into the Planning Subcommittee. The task force has largely completed its queue revisions, but some stakeholders say more work remains and pointed out that stakeholders attending the IPTF have voted to transform it into a working group. In MISO’s stakeholder structure, working groups are more permanent than task forces, which have an expected sunset date.

Several stakeholders said MISO didn’t provide enough warning to stakeholders before bringing the idea forward at the Sept. 26 PAC meeting, with some suggesting the RTO was trying to subvert the stakeholder process by not posting the discussion as an agenda item. WEC Energy Group’s Chris Plante said he did not have time to introduce the idea to the Transmission-Dependent Utilities sector ahead of the meeting and said he was “disappointed in MISO’s process.”

MISO Executive Director of Resource Planning Patrick Brown said moving the IPTF into the permanent Planning Subcommittee will cut down on identical presentations at the two groups and will result in more comprehensive discussion because interconnection topics will take place alongside transmission planning discussions. It will “enable a more holistic approach to planning,” Brown said.

“We’ll have a broad range of stakeholders involved in the conversation,” he added.

MISO staff promised more discussion in October on how to merge the IPTF’s charter into that of the PSC.

September 30, 2018

MISO Plan to Reduce Queue Studies Gets FERC Nod

FERC last week approved MISO’s plan to cut some duplicate analyses from the first phase of its generation interconnection queue.

The approval means MISO can remove its dynamic stability, short-circuit and affected-system analyses from the first phase of the queue’s definitive planning phase (DPP) (ER18-2049). The RTO said the procedures are currently repeated once a project hits the second phase of the DPP.

MISO FERC interconnection queue transmission studies — | *© RTO Insider*

MISO staff have said the changes would help speed along the overbooked, 90-GW interconnection queue, a sentiment shared by the RTO’s Transmission Owners sector in comments on the filing. (See “Studies Reduction,” MISO Proposal Aims to Speed Up Queue Process.)

FERC agreed with that assessment: “We find that MISO’s proposed Tariff revisions will streamline DPP Phase I and likely reduce the duration of delays experienced by interconnection customers in MISO’s interconnection queue.”

The commission also noted some stakeholders’ position at an April technical conference that an affected-system analysis in each of the three DPP phases is a contributing factor to queue delays. (See Renewable Gens Face Off with RTOs at Seams Tech Conference.) MISO has also said that results of its first affected-system studies are often subject to change later, given the uncertainty of the early information.

Early last week, MISO’s Neil Shah said if FERC didn’t approve the changes, the RTO would continue using its current study process that includes the redundant studies.

— Amanda Durish Cook

September 30, 2018

NERC Chief: Inverter, Fuel Assurance Standards Needed

By Rich Heidorn Jr.

WASHINGTON — NERC CEO Jim Robb said Thursday he is pushing for new reliability standards to address fuel assurance concerns and ride-through settings for inverters on solar generation and storage.

nerc jim robb inverters fuel assurance — Jim Robb, NERC CEO (right) with Kimberly Mielcarek, senior director of communications. | *© RTO Insider*

“I think a standard will be called for” on inverters, Robb said during a press conference at NERC’s D.C. office marking six months since he took the organization’s helm. “I feel the same way about fuel assurance. But my eyes are wide open to the challenges in crafting those appropriate [requirements] and figuring out which entities should be accountable for them.” (See related story, New NERC Chief Not ‘Smartest Guy in the Room.’)

NERC has issued two alerts on inverters, one after the 2016 Blue Cut wildfire near Los Angeles caused transmission line faults and disconnected 1,200 MW of solar resources, and a second following a fire in spring 2018. Both were Level II alerts, which required registered entities to respond to NERC’s recommendations and answer questions about solar generation in their footprints and how they plan for the loss of the resources.

NERC is now finalizing a reliability guideline to ensure inverters are configured “so they play nicely with the rest of the system,” Robb said. “An inverter can do almost anything you want it to do. You just have to tell it what to do.”

Robb said the issue is a concern not only in California and the Southwest but also in North Carolina, Massachusetts and Texas, where solar penetration is rising. Battery storage also uses inverters and presents similar issues, he said.

“The issue around the standard that we’re currently struggling with is that right now all of our standards … are technology-agnostic and fuel-agnostic,” Robb said. “So, this would be the first that we would put in for a specific technology. And not everyone’s embracing that notion, so we have some work to do.” (See Solar Inverter Problem Leads CAISO to Boost Reserves.)

Fuel Assurance Standard

The shift from baseload coal and nuclear generation to variable resources and natural gas also justifies a reliability standard, Robb said.

“Loads are becoming much less certain than what we’ve had in the past. In fact, to be perfectly honest, we don’t know what the load curve of California looks like anymore because so much of it is masked by the distributed solar panels on peoples’ roofs,” he said. “We have a lot of tools and a lot of rules … we use to operate and manage and plan the system that are all largely based on a 1950s view of the world [that’s not] really true anymore.”

One of the challenges is aligning the natural gas industry’s infrastructure, scheduling policies and modeling to the real-time needs of the electric industry.

“Those [gas] power plant ramp rates are getting steeper and steeper” in the afternoons, when solar generation drops as loads peak, Robb said. “And effectively what we’re seeing is power plants were sucking gas out of the distribution system faster than pipelines could pack it in.”

Although pipelines can provide some storage by increasing pressure in their systems, “what we’re seeing in areas like the Southwest … is some of the pipeline corridors are running 90 to 95% of capacity. So they don’t have the same degree of flexibility they would have had five, 10 years ago.”

In addition, because of the way gas is regulated, “there is really no [one] who can solve these problems with the stroke of a pen,” Robb said.

Natural gas problems are most acute in New England and Florida, which have limited pipeline infrastructure, and California, which has lost most of Aliso Canyon’s storage capacity. (See related story, CAISO Seeks to Extend Aliso Canyon Rules.)

Although NERC’s current standards address planning for contingencies, they are “relatively vague as to how to think about fuel as a contingency,” Robb said.

“So we’re talking through getting a guideline in place that would make clear that any particular entity ought to look at a major pipeline disruption for example [or] a problem on the rail system … and start to factor that into their operating and shorter-term planning.”

Still to be determined is which entities would be subject to a pipeline contingency rule. “The challenge in evaluating the gas system is you need to really look at it over a fairly wide area, probably a bigger footprint than a planning coordinator, certainly a bigger footprint than in individual utility. It might be something that might be best applicable to [a reliability coordinator] but the RCs aren’t really set up to do that kind of planning,” Robb said.

He acknowledged that the industry generally prefers guidelines over standards because the latter can result in enforcement actions. “I choose to think of them as providing great clarity around how things should be done, particularly around these very disparate resources around the system that can interact in ways that don’t contribute to the community event that we call reliability. But it will take us a while to get there.”

Robb also acknowledged that the issue has become politicized by the Trump administration’s efforts to provide price supports for money-losing coal and nuclear generators. “My goal is to make sure that our work remains technically unimpeachable so it’s there to inform people who are making important decisions around these issues but not get drawn into the political and ideological arguments around them.”

September 30, 2018

MISO Contemplates Storage as Tx Reliability Asset

By Amanda Durish Cook

MISO last week floated a relatively simple straw proposal for treating storage as a reliability asset in its annual transmission plan.

The proposal involves no interconnection queue entry, asset registration and day-ahead scheduling notices.

miso reliability asset energy storage — Jeff Webb | *© RTO Insider*

Speaking during a Sept. 26 Planning Advisory Committee meeting, Director of Planning Jeff Webb said the RTO hopes to get a final proposal in place in time for the 2019 MISO Transmission Expansion Plan cycle.

Webb said stakeholders have asked how storage projects providing reliability transmission services will be able to enter the MTEP.

“Well how does any other transmission project get in? It’s proposed as a solution in the planning process,” he said.

Webb explained the projects would be proposed in MTEP as either a baseline reliability project driven by NERC criteria and allocated to local pricing zones, or as an “other” reliability project not eligible for regional cost allocation. If the storage project solves the issue at the lowest cost, it will be included in the annual plan.

He stressed that MISO’s plan only serves to treat storage comparably to other transmission assets, clarifying that storage projects would not necessarily take priority over traditional wires projects because “storage has a lot of hurdles and costs” to overcome.

“There will be opportunities, I think, to use” storage, Webb added.

‘To Queue or not to Queue’

Webb said storage as transmission would not be required to enter the interconnection queue as long as the project will not participate in the energy and ancillary services markets. If a storage asset is planned for both reliability transmission services and market services, the asset must first respond to reliability needs in the transmission market. If MISO doesn’t need the asset for reliability transmission purposes, it would be free to participate in the energy market pursuant to MISO’s future Order 841 compliance plan, provided it has completed the interconnection queue.

The queue is required “if for no other reason than comparability with other resources that the project would be competing with in the energy market,” Webb said.

“There’s a lot of controversy; to queue or not to queue,” he said of stakeholder reactions. He also said opportunities for market participation by storage projects intended for transmission use will vary according to location, noting that, for example, storage located in rural Iowa with few generation options nearby will have different market opportunities than storage added in a large metropolitan area where generation is already abundant.

“So maybe the answer comes down to significance factors: Where and how big?” Webb mused.

Reliability storage projects will be required to complete asset registration to allow MISO to control the asset when it’s required to maintain system reliability. The asset will receive notice of need in the day-ahead schedule and be recalled as needed during the operations day. Like other transmission assets, the storage assets will be price-takers when under RTO instructions.

Webb said MISO hasn’t proposed rules to credit a storage asset’s market revenue against its transmission asset cost recovery. Some stakeholders have said that allowing the two revenue streams would incentivize dual-use storage to the point that transmission reliability is diminished.

Webb said he expects MISO and stakeholders to discuss storage as reliability transmission services through the first half of next year. He noted that MISO could possibly schedule a workshop on the topic in response to stakeholder requests.

September 30, 2018

NERC Chief: Inverter, Fuel Assurance Standards Needed

NERC Chief Sees Need for Inverter, Fuel Assurance Standards

By Rich Heidorn Jr.

WASHINGTON — NERC CEO Jim Robb said Thursday he is pushing for new reliability standards to address fuel assurance concerns and ride-through settings for inverters on solar generation and storage.

“The issue around the standard that we’re currently struggling with is that right now all of our standards … are technology-agnostic and fuel-agnostic,” Robb said. “So, this would be the first that we would put in for a specific technology. And not everyone’s embracing that notion, so we have some work to do.” (See Solar Inverter Problem Leads CAISO to Boost Reserves.)

Fuel Assurance Standard

The shift from baseload coal and nuclear generation to variable resources and natural gas also justifies a reliability standard, Robb said.

One of the challenges is aligning the natural gas industry’s infrastructure, scheduling policies and modeling to the real-time needs of the electric industry.

In addition, because of the way gas is regulated, “there is really no [one] who can solve these problems with the stroke of a pen,” Robb said.

Although NERC’s current standards address planning for contingencies, they are “relatively vague as to how to think about fuel as a contingency,” Robb said.

September 28, 2018

MISO Utilities Float New Load Forecasting Approach

By Amanda Durish Cook

A new stakeholder-led proposal would require MISO load-serving entities to develop a 20-year base load forecast that includes monthly predictions for energy and non-coincident peaks.

The Coalition of Utilities with an Obligation to Serve in MISO (CUOS), an ad hoc group of MISO utilities and regulators, advanced the plan after the RTO earlier this month requested stakeholder ideas for improving load forecasting.

LSEs must currently provide just two years of monthly forecast data to MISO, but WPPI Energy economist Valy Goepfrich said long-term forecasts the RTO obtains from the Purdue University State Utility Forecasting Group — which are compared against LSE projections — so far “have confirmed the validity of the LSE base load forecasts.”

Under the CUOS plan, the LSEs’ base load forecasts would be applied to MISO’s base case Transmission Expansion Plan (MTEP) future, the “limited fleet change” future. The other futures include a continued fleet change future, an accelerated fleet change future and a future in which distributed and emerging technologies become more widely used in the MISO footprint.

“The CUOS proposal is leveraging the forecasts that LSEs already develop,” Goepfrich explained during a Sept. 26 Planning Advisory Committee meeting. She said the proposal is more cost-effective than continuing to pay Purdue for independent load forecasting.

MISO Planning Advisory Committee in June | *© RTO Insider*

The CUOS proposal would also direct LSEs to provide data on transmission losses, as well as demand served by energy efficiency planning resources, demand resources and behind-the-meter planning resources. LSEs would not be required to provide numbers on demand served by energy efficiency programs and other resources not classified as planning resources. Goepfrich said MISO can continue to use consulting firm Applied Energy Group for distributed resource data predictions in the three other MTEP futures.

The Parable of the Ox

miso lse load-serving entities load forecasting — Trip Doggett at the MISO Market Symposium in August | *© RTO Insider*

Goepfrich referenced an address at this year’s MISO Market Symposium in which RTO Director Trip Doggett cited “The Parable of the Ox,” a story included in James Surowiecki’s book “The Wisdom of Crowds.” The story recounts how in 1906, statistician Francis Galton studied a competition to guess the weight of an ox at a country fair, observing the average guess was accurate to within 1% of the actual weight of the 1,200-pound animal. Doggett used the story to illustrate that the RTO’s large stakeholder community is needed to lend their ideas about what shape the future grid should take.

Goepfrich said the story also applies to load forecasting. An average of many forecasts, she said, will be more helpful than a forecast designed by a few individuals.

“It doesn’t make sense to have a forecast that is divorced from the LSEs’ forecasts,” Goepfrich said. She added that MISO should be more transparent about the “behind the scenes” analyses that might lead it to prefer an independent load forecast over one originated by LSEs.

MISO Director of Planning Jeff Webb said the RTO will evaluate and respond to the load forecast proposal. The RTO committed to soliciting stakeholder opinions on load forecasting after taking a break this summer from ordering more independent load forecasts from Purdue. (See MISO Looks to Members for Load Forecasting Ideas.)

Facing widespread stakeholder disapproval, MISO in June abandoned a proposal to have its 140-plus LSEs annually assemble four distinct 20-year load forecasts with hourly load shapes to align with each of the four futures in the annual MTEP. (See MISO Nixes LSE Load Forecas t Plan.)

September 28, 2018

FERC Upholds PJM TOs’ Supplemental Project Rules

By Rich Heidorn Jr.

FERC on Wednesday rejected a rehearing request over PJM Transmission Owners’ revised processes for planning supplemental projects, ruling it in compliance with Order 890.

The commission denied a request by American Municipal Power, Old Dominion Electric Cooperative and others seeking rehearing of the commission’s Feb. 15, 2018, ruling that the TOs’ processes for developing supplemental projects fell short of Order 890’s transparency and coordination requirements. FERC also approved PJM’s and the TOs’ compliance filing in response to the February ruling (ER17-179, EL16-7 1 -002).

PJM’s Transmission Replacement Processes Senior Task Force meets earlier this year. | *© RTO Insider*

PJM stakeholders have long complained about 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.

The Feb. 15 order approved a proposal to move the TOs’ process for planning supplemental projects from the Operating Agreement to Attachment M-3 of the Tariff but required PJM and the TOs to make changes to the attachment and the OA. (See FERC Orders New Rules for Supplemental Tx Proje c ts in PJM.)

The commission said the rehearing request “largely repeats arguments” made earlier in the docket. “We are not persuaded that the commission erred in the February 15 order, which we believe appropriately responds to these concerns.”

AMP, ODEC and others argued the commission erred in permitting Attachment M-3 because it circumvented the division of filing rights in PJM, including the supermajority vote of the Members Committee required for changes to the Operating Agreement. They also said the commission should have required the TOs to respond to stakeholder comments under the supplemental process.

“Order No. 890 requires that stakeholders be afforded the opportunity to provide meaningful input, and that public utility transmission providers ‘craft a process that allows for a reasonable and meaningful opportunity to meet or otherwise interact meaningfully,’” the commission said. “Its requirements are not so prescriptive as to dictate whether and how the PJM Transmission Owners must respond to that input. While we encourage the PJM Transmission Owners to be as responsive as possible to stakeholder comments, we also realize that not all comments may require answer.”

In addition to AMP and ODEC, those seeking rehearing and challenging the March 19 compliance filing were the Delaware Division of the Public Advocate, PJM Industrial Customer Coalition, Illinois Citizens Utility Board, Office of the People’s Counsel for the District of Columbia and Public Power Association of New Jersey, which FERC named the “Load Group.”

“The Load Group’s requests for various additional provisions go beyond what the commission required in, and constitute requests for rehearing of, the February 15 order,” the commission said. “We therefore find these requests to be outside the scope of the compliance proceeding, and were we to consider them as requests for rehearing, would deny them.”

September 28, 2018

FERC OKs New MISO Retirement Process

FERC on Tuesday approved MISO’s plan to replace its retirement notification process with a more general three-year generation suspension period.

MISO’s proposal places all generation owners submitting an Attachment Y retirement notice into a catch-all three-year suspension period, with suspended units maintaining interconnection rights for the full three years unless they formally decide to retire (ER18-1 636). Units that do not return to service after three years are presumed retired and their interconnection rights dissolved. The changes became effective July 16, 2018.

After FERC issued a July deficiency letter on the proposal, MISO said the new suspension process would still allow it to designate resources seeking suspension as system support resources needed to keep operating for reliability reasons. (See FERC Seeks Details on Proposed MISO Retiremen t Rules.) The RTO also explained its old suspension process wasn’t working as intended, saying that out of 77 suspensions over the last five years, only eight generators returned to service at the end of the originally designated suspension period.

For modeling purposes, MISO will treat approved suspensions as unavailable resources with no specified date of return service. MISO also said its proposal requires no notice from a generation owner should it want to change its suspension status into a permanent retirement anytime during the three years.

FERC said MISO’s proposal that modeling not anticipate suspended units will return to service “better reflects the inherent uncertainty of planning.”

” … We agree with MISO that its current requirement to provide a return-to-service date in Attachment Y Notices to suspend may at times create an illusion of certainty that does not actually exist,” the commission said.

— Amanda Durish Cook

September 28, 2018May 8, 2025

Appeals Court Upholds NY Nuclear Subsidies

By Rich Heidorn Jr.

The 2nd U.S. Circuit Court of Appeals on Thursday upheld New York’s zero-emission credits (ZEC) for nuclear generation, rejecting claims they intrude on FERC jurisdiction (17 ‐26 5 4 ‐cv).

“We conclude that the ZEC program is not field preempted, because plaintiffs have failed to identify an impermissible ‘tether’ under Hughes v. Talen Energy Marketing between the ZEC program and wholesale market participation; that the ZEC program is not conflict preempted, because plaintiffs have failed to identify any clear damage to federal goals; and that plaintiffs lack Article III standing as to the dormant Commerce Clause claim.”

In upholding a district court’s dismissal of the complaint by the Electric Power Supply Association and others, the appellate court said its finding was “consistent” with the 7th Circuit’s Sept. 13 ruling upholding Illinois’ own ZEC program. (See 7th Circ u it Upholds Ill. ZEC Program.)

EPSA on Thursday as k e d the 7^th Circuit to rehear its ruling, alleging the court had made legal and factual errors. “The panel overlooked or misapprehended three key legal arguments under which appellants would prevail,” EPSA said.

Threading the Needle

The New York Public Service Commission created the ZEC program in August 2016 as part of its Clean Energy Standard (CES), which set a goal of reducing greenhouse gas emissions by 40% by 2030. The PSC said it crafted the program to avoid the issues behind the Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets. (See NY Attempts t o Thread Legal Needle with Clean Energy Standard, Nuke Incentives.)

The court said that ZECs, like renewable energy credits (RECs), are certifications of an energy attribute separate from the purchase or sale of wholesale energy. Although the ZEC program “exerts downward pressure on wholesale electricity rates, that incidental effect is insufficient to state a claim for field preemption under the FPA [Federal Power Act],” the court said.

The court said the PSC avoided the defects of the Maryland contract for differences, which required the generator to participate in PJM’s capacity market.

“Plaintiffs point to nothing in the CES Order that requires the ZEC plants to participate in the wholesale market,” the court said. “ … As the district court concluded, a generator’s decision to sell power into the wholesale markets is a business decision that does not give rise to preemption concerns.”

“Until 2019, the ZEC price cannot vary from the social cost of carbon, as determined by a federal interagency workgroup. After 2019, the ZEC price is fixed for two‐year periods, and does not fluctuate during those periods to match the wholesale clearing price,” the court said.

The court also said the ZEC program was permissible under the dual federal/state regulatory system over electricity because it “does not cause clear damage to federal goals.”

The PSC approved the program to prevent the premature retirements of three New York nuclear power plants, Exelon’s FitzPatrick, Ginna and Nine Mile Point.

Nine Mile Point Nuclear Plant | Constellation Energy Nuclear Group

EPSA and the other plaintiffs — the Coalition for Competitive Electricity, Dynegy, Eastern Generation, NRG Energy, Roseton Generating and Selkirk Cogen Partners — claimed they were harmed because the ZEC program allows “favored New York power plants to prevail in interstate competition against” their generation by underbidding them in the wholesale electricity markets.

“If the PSC awarded ZECs in a non‐discriminatory manner to out‐of‐state nuclear plants (as it may do in the future under the terms of the CES order), there would be no abatement in the injury plaintiffs claim to suffer from the general market‐distorting effects of the ZEC program. In short, plaintiffs’ injuries ‘would continue to exist even if the [legislation] were cured’ of the alleged discrimination,” the court said. “Because plaintiffs’ asserted injuries are not traceable to the alleged discrimination against out‐of‐state entities, but (rather) arise from their production of energy using fuels that New York disfavors, they lack Article III standing to challenge the ZEC program.”

Win for RECs?

“The decision is a win for both ongoing state efforts to preserve existing nuclear plants — New Jersey regulators expect to finalize a ZEC program by the end of the year — and long-standing renewable energy policies,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. “The panel held that renewable energy credits (RECs), instruments that are used for compliance with renewable portfolio standards, are legally indistinguishable from ZECs. Today’s decision thus implicitly concludes that RECs are not preempted under the FPA, an issue which no court has ever squarely addressed.”