Page 1243 – RTO Insider

November 27, 2017

Company	Market Cap ($ billions)	Revenue Q3 2017 ($ billions)	% change vs. 2016	Net Income Q3 2017 ($ millions)	% change vs. 2016
AEP	$37.67	$4.10	-11.77%	$544.7	-171.1%
Alliant	$10.22	$0.91	-1.91%	$168.8	31.5%
Ameren	$15.27	$1.72	-7.32%	$288.0	-22.0%
Avangrid	$15.79	$1.34	-5.43%	$99.0	-9.2%
Berkshire Hathaway Energy	NA	$5.28	3.75%	$1,068.0	3.1%
Calpine	$5.42	$2.59	9.81%	$225.0	-23.7%
CenterPoint Energy	$12.56	$2.10	11.06%	$169.0	-5.6%
CMS Energy	$13.93	$1.53	-3.78%	$172.0	-7.5%
Consolidated Edison	$26.87	$3.21	-6.03%	$457.0	-8.0%
Dominion Energy	$52.87	$3.18	1.50%	$665.0	-3.6%
DTE Energy	$20.20	$3.25	10.83%	$270.0	-20.1%
Duke Energy	$62.04	$6.48	-1.43%	$954.0	-18.9%
Edison International	$26.11	$3.67	-2.52%	$470.0	11.6%
Entergy	$15.41	$3.24	3.81%	$398.2	2.6%
Eversource Energy	$20.22	$1.99	-2.51%	$260.4	-1.9%
Exelon	$40.13	$8.77	-2.59%	$824.0	68.2%
FirstEnergy	$15.23	$3.71	-5.18%	$396.0	4.2%
Great Plains Energy	$7.39	$0.86	0.05%	$3.4	-97.4%
NextEra Energy	$73.00	$4.81	0.06%	$847.0	12.5%
NiSource	$9.11	$0.92	6.47%	$14.0	-48.5%
NRG Energy	$9.25	$3.05	-10.87%	$171.0	-57.5%
OGE Energy	$6.97	$0.72	-3.64%	$183.4	-0.1%
PG&E	$27.72	$4.52	-6.09%	$550.0	41.8%
Pinnacle West Capital	$9.98	$1.18	1.41%	$276.1	5.0%
PPL	$24.83	$1.85	-2.33%	$355.0	-24.9%
PSEG	$26.03	$2.26	-7.63%	$395.0	20.8%
Sempra Energy	$29.82	$2.68	5.44%	$57.0	-90.8%
WEC Energy Group	$21.54	$1.66	-3.21%	$215.4	-0.7%
Westar Energy	$7.96	$0.79	3.88%	$158.3	2.3%
Xcel Energy	$25.66	$3.02	-0.76%	$492.1	7.5%
Totals	$669.2	$85.4	-1.57%	$11,146.8	5.3%

Regulators Fear Cross-Border Tx Risks ERCOT’s FERC Exemption

By Tom Kleckner

Texas regulators are concerned that transmission projects along the U.S. border with Mexico may threaten their exclusive jurisdiction over ERCOT.

ERCOT FERC — PUC of Texas Chair DeAnn Walker (left) confers with Commissioner Brandy Marquez | © *RTO Insider*

In a Nov. 16 memo to Commissioners Brandy Marty Marquez and Arthur D’Andrea, Public Utility Commission Chair DeAnn Walker said a pair of recent developments could place the electrical separation between ERCOT and the rest of the country “in jeopardy” by allowing energy to flow between Texas and other states through Mexico’s national grid. ERCOT has several synchronous (alternating current) and asynchronous (direct current) ties with the Mexican grid.

Walker pointed to Nogales Transmission’s application for a presidential permit to build an HVDC interconnection between Arizona and Mexico (OE PP-420). The project would consist of a 150-MW substation in Tucson Electric Power’s service territory, capable of being expanded to 300 MW; a 138-kV transmission line on the Arizona side near the city of Nogales; and a 230-kV line across the border that would connect to the Mexican grid. Nogales Transmission is a subsidiary of Dallas-based Hunt Power.

ERCOT Texas Mexico border — | *Mexico Ministry of Energy*

Walker also is concerned about an HVDC line linking the Mexican state of Baja California with the country’s central grid. That project, in the advanced planning stage, would provide a major tie between Mexico and California, which already has two connections with Baja California with a total capacity of 800 MW. In addition, California’s Imperial Irrigation District (IID) signed an agreement with CENACE, Mexico’s grid operator earlier this year, to study the exchange of up to 600 MW of energy with Baja California. IID has said the two have plans for a pair of interties to be completed in 2019 and 2020.

The Baja California system is part of the Western Electricity Coordinating Council (WECC) and not interconnected with the rest of Mexico. Sempra Energy also has a presidential permit that allows it to import renewable energy from Baja California, helping make up for the loss of the San Onofre Nuclear Generating Station.

“Those are issues that will occur outside of the United States for which the [Texas] commission will likely have no notice or participation opportunities,” Walker told Marquez and D’Andrea.

The chairwoman said FERC staff contacted the PUC “to convey concern” that the Nogales interconnection could affect FERC’s jurisdiction over ERCOT. A FERC order in 2007 noted that electricity generated within ERCOT and transmitted across a Sharyland Utilities DC tie to Mexico could not flow into WECC territory “because the Baja California system is not interconnected with the national Mexico grid,” she said.

“I’m very, very concerned about it,” Walker said. “Even if they take care of the issues in Arizona, I still have concerns about the impacts in California. We need a solution. This isn’t something we’re going to sit back and wait for it to happen.”

Nogales Transmission has asked the Department of Energy to delay processing its presidential permit until it can obtain “the necessary FERC disclaimer” of jurisdiction, Walker said.

Walker noted in her memo that FERC could exert its jurisdiction over ERCOT through the Commerce Clause of the U.S. Constitution “if the commingling of power between ERCOT and the rest of the United States occurs.”

Because ERCOT administers the Texas Interconnection — located solely within the state and not synchronously interconnected with the rest of the U.S. — FERC generally does not have jurisdiction over the ISO. There are several DC lines between Texas and other U.S. states; developers of these lines must seek a declaratory order from FERC saying they will not affect ERCOT’s independent status.

Under the Federal Power Act, FERC has no jurisdiction over transmission lines that cross international boundaries if they don’t also cross U.S. state lines.

Walker has already met with the leadership of AEP Texas, CenterPoint Energy, Oncor and Sharyland to discuss the situation. AEP and Sharyland own the state’s three DC ties with Mexico.

Walker noted the Nogales project would transmit from Arizona to the Mexican transmission system, to which Sharyland is already connected. “The change of circumstances suggests that Sharyland, ERCOT and other market participants should seek an order from FERC that they will retain their nonpublic utility status” under the FPA, Walker said.

ERCOT’s independence “is not only a source of pride, but it makes our market work so well,” Marquez said during the commission’s Nov. 17 open meeting. “We have to explore every opportunity to preserve and protect our jurisdiction.” She said she would be working with ERCOT staff to see “what types of mechanisms we can use” to protect the ISO’s independence.

November 22, 2017

California PUC, Customers Fight SCE Rate Hike

By Jason Fordney

State regulators and transmission customers of Southern California Edison last week urged FERC to reject the utility’s requested rate hike for 2018, saying it is excessive and unwarranted.

The California Public Utilities Commission on Nov. 17 filed a protest after SCE last month asked FERC to approve a $1.2 billion revenue requirement, including an increased return on equity, enhanced depreciation rate and an adder for its membership in CAISO.

“The CPUC opposes SCE’s proposed formula rate, which eliminates the minimal ratepayer protections contained [in] its current rate and only benefits the company’s shareholders,” the PUC said. “This proposed formula will result in unjust and unreasonable rates in 2018 and beyond and should be rejected.”

cpuc southern california edison sce cpuc rate hike — Southern California Edison asked FERC to approve an increased return on equity for its transmission facilities.

SCE requested a return on equity of 11.57%, calculated from a base ROE of 10.3%, compared with its current base ROE of 9.3%. The PUC said the utility did not provide evidence that the hike is needed and argued that its return should actually be reduced.

The state commission also disputed SCE’s claim that California is a risky investment environment, and said the 0.5% adder for participating in CAISO is a “windfall” for investors. The utility is required to be in the ISO by state law, the PUC noted.

In its application to FERC, the utility cited the growth of distributed energy resources as a challenge, and said growth in renewables — particularly at the distribution level — has driven the need for new transmission service. It also proposed an increase in its depreciation rate from about 2.54% currently to 2.73%.

“Integrating distributed generation with SCE’s transmission system is capital intensive and complicated, but it is necessary to achieve operational flexibility,” the utility said. “This energy revolution provides great opportunities but also presents a significant amount of uncertainty.”

Also asking FERC to reject the rate hike was a group representing 27 public agencies that hold contracts with the California Department of Water Resources to supply water for drinking, commercial, industrial and agricultural purposes. The group challenged SCE’s “proxy group” — a collection of similarly positioned electric companies — used to determine fair rates, as well as the base ROE.

rate hike SCE southern california edison cpuc — California water agencies are protesting Southern California Edison’s proposed transmission rate hike.

The state water contractors said that a large number of the capital investments for which SCE wants to recover costs “have been unilaterally approved by SCE management in contravention of the requirements of [FERC] Order No. 890 to develop local transmission plans in an open and transparent planning processes.”

The group asked FERC to establish hearing and settlement procedures over SCE’s request.

The Los Angeles Department of Water and Power filed a separate protest saying the ROE is “dramatically overstated.” The ROE should be no larger than 8%, the agency argued in its protest. The department also protested that the utility’s proposal allows for executive bonuses to derive from transmission rates.

Other parties opposing the rate hike include the DWR; the City of Santa Clara and MSR Public Power Agency; and the cities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside.

November 22, 2017

New York Works to Frame Carbon Policy

By Michael Kuser

ALBANY, N.Y. — The planning for pricing carbon into NYISO’s markets should be more clearly defined, stakeholders told ISO and New York state officials Monday.

A good starting point: clarify the charter for the state’s Integrating Public Policy Task Force (IPPTF), some stakeholders contended.

“The problem we’re trying to solve is related to the Clean Energy Standard and trying to get 50% of [electricity] consumption from renewables, and one component of that is to incentivize clean generation. That’s what carbon pricing is doing,” said Anthony Fiore, director of energy regulatory affairs for New York City. “The other part is then to actually get that generation where the load is, which I think would be solved by a different set of tools.”

NYISO new york carbon pricing — Carbon Pricing Process | *NYISO*

Stakeholders shared their views Nov. 20 at a third public hearing stemming from carbon pricing proposals set out in The Brattle Group report, and the second meeting of the IPPTF, a joint effort established by NYISO and the New York Public Service Commission in October to explore the carbon pricing issue. About 60 people attended the meeting, including PSC Commissioner Diane Burman. (See New York Stakeholders Question Carbon Pricing Process.)

Co-chairing the session was Nicole Bouchez, NYISO’s principal economist of market design, who said the purpose of the IPPTF is “to facilitate dialogue on market design alternatives” able to harmonize the ISO’s markets with the state’s carbon policies.

“That’s the goal. It is not a broader review of the [CES]. It is a fairly defined topic for the task force,” Bouchez said.

Fiore had a more expansive take of the IPPTF’s possible role.

“I understand that we can narrowly focus this task force, but I think it’s a mistake and a missed opportunity if we don’t lay out what the bigger issue is that lies behind this, because this is not the whole thing,” he said.

Erin Hogan of the Utility Intervention Unit at New York’s Department of Public Service shared Fiore’s concerns.

“If we had a defined goal of what we are trying to achieve, it would help develop the criteria to have an alternative analysis of the market design concepts,” she said. “As an analogy, in western New York, we had various transmission proposals and one party was advocating that their larger carbon reduction was a better option than the lower-priced transmission and also increased operability. So by not having those clearly defined criteria, it’s going to make it a little challenging to evaluate the alternative market design concepts.” (See Public Policy Tx Project Wins Key NYISO Endorsement.)

New York City Deputy Director for Infrastructure Susanne DesRoches said, “Our comments to the charter speak to needing to fully identify what the parallel processes are. For instance, how does transmission play into this conversation? We don’t want to be in a position to be pricing power in one part of the state higher than the other because we can’t get low-carbon power to the downstate region.

“Before we can go to the granular level of the questions on the table, we need consensus around what is the objective that we are trying to solve and how our other processes get us to that resolution as well.”

IPPTF co-chair Marco Padula, DPS deputy director for market structure, said, “You should identify those other processes and we should add them to this list. If you believe there are other processes that need to be studied, please, let’s add them.”

Preventing Leakage

The hearing’s agenda listed 15 recommended topics, starting with carbon leakage and resource shuffling.

Carbon leakage is defined as an increase in emissions in states parallel to one reducing them. Resource shuffling refers to the practice of utilities scheduling their lowest-emission generators to serve areas with emission caps, while letting heavier polluters simultaneously serve customers in neighboring regions.

Bouchez emphasized the task force was looking more for questions than answers at this point, and that it would address the leakage issue more fully at a Dec 11 technical conference.

She identified questions arising from the group’s prior hearing, which included:

How would a carbon charge be applied to interregional transactions?
Should specific charges be applied to each neighboring region, or should the same charge be applied to all?
Would crediting the carbon charge on exporting interregional transactions create incentives to sell power out of state?
Will the biggest emitters see this as an incentive to export more energy from New York?

Mark Younger of Hudson Energy Economics said the question of whether to apply a carbon charge to resources under 25 MW or to any fossil-fuel backed distributed energy resource also has leakage implications.

“In other words, not applying to those examples is a form of leakage,” Younger said. “You can take a relatively efficient wholesale generator, and because you’re adding a carbon charge to it, [you’re] making it look like it’s [more] desirable to run a sub-25-MW, much-less-efficient resource rather than take power from there. And that’s the same thing we’re talking about with external areas as well.”

Miles Farmer of the Natural Resources Defense Council said that leakage is a retail — as well as wholesale — market issue. “As we’ve heard, there’s DER leakage, potentially, leakage to other sectors, and then I think there’s also a role for DPS in setting the policy in regard to leakage that then NYISO could implement,” he said. “To some extent, that’s a substantive question that I imagine different stakeholders will have different views on.”

Pricing Carbon Affects Everything

Stakeholders said many of the topics were interrelated, such as whether locational-based marginal prices should transparently reflect carbon charges, how to apply the cost of carbon to generator emission rates ahead of delivery, how to allocate carbon revenues, and the possible effects of a carbon price on the capacity market.

NYISO Senior Manager for Market Design Michael DeSocio said, “If you take a DER that is a combination of renewable and non-renewable, I’m not sure when we aggregate those two pieces up to a single resource that we will know exactly how to apply that cost of carbon, but we certainly know after it runs what it did and how much to charge it.” He said the carbon charge might be an opportunity cost-based process in which a resource will be charged after the fact but will need to determine beforehand what cost to incorporate into its offer.

“Or do we need to figure out all the permutations of every configuration of every facility to then apply a cost up front directly into the offer?” he said. “There are some pros and cons to both sides. We first start to think about this with generator fuel blends, but then you take it down the path where we had discussions this morning about DERs, and it gets even more complicated.”

Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said that pricing carbon would not change the dynamics of New York’s grid, where lopsided load balances create transmission constraints between upstate and downstate, particularly around New York City and Long Island.

“Thinking about changes and what’s needed in the capacity market, we’ve said look at what New England has been talking about and what PJM has been talking about,” Joseph said. “They’re talking about moving towards a two-tiered clearing market where you have resources that are brought on because of state policy, and that’s highly likely to continue here even if you price carbon because of this transmission issue. … Even if we price carbon, what we do in the capacity market has to be a big part of this discussion.”

Howard Fromer, director of market policy for PSEG Power New York, asked how the sector will determine the social cost of carbon.

“We can’t have a situation where we define the problem at $45 but our solutions are multiples of that,” Fromer said. “I don’t know how you sell that to the public and explain to them why you should pay more than what you said the problem is worth. That doesn’t work too well.”

DeSocio said NYISO planned to use a Dec. 5 joint Market Issues Committee and ICAP Working Group meeting to brief stakeholders on what other RTOs are doing to integrate public policy in wholesale markets.

Bouchez said the task force would hold a technical conference Dec. 11, but that it was unclear whether it would be necessary to hold the public hearing scheduled for Dec. 18, given its proximity to the holidays. Regardless of what meetings take place in December, the task force still plans to issue an initial work plan to stakeholders by the end of January, she said.

November 21, 2017

October Brings MISO Lower Prices, Wind Record

CARMEL, Ind. — MISO set an all-time wind output record and experienced lower demand and prices during a relatively cool October, the RTO said last week.

Load peaked for the month at 89 GW on Oct. 9, and averaged 70 GW, 6 GW lower than in September, beginning the “seasonal transition to cooler weather conditions,” MISO Senior Director of Systemwide Operations Rob Benbow said during a Nov. 14 Informational Forum meeting.

Energy prices averaged $28/MWh in the day-ahead market and $27/MWh in the real-time market for the month, a 10% decline from September. Natural gas prices lingered around $2.84/MMBtu, lower than September’s $2.94/MMBtu average. Real-time make-whole payments fell by more than half, from just more than $13 million to $6.5 million.

Propelled by the windier shoulder season, MISO’s wind energy output spiked during the month, setting a new peak wind output record of 14.3 GW on Oct. 30, 0.6 GW higher than the previous record set in December 2016.

Benbow said the increased output was primarily driven by an increase in installed wind capacity throughout 2017. MISO’s registered wind capacity currently stands at about 16.8 GW.

— Amanda Durish Cook

November 21, 2017

FERC Affirms WestConnect Cost Allocation Ruling

By Jason Fordney

FERC last week upheld a previous ruling covering transmission cost allocation in the WestConnect planning region, adding further explanation of its reasoning after a federal court remanded the issue back to it for more information.

The issue stems from an October 2012 compliance filing that WestConnect utilities submitted in response to FERC Order 1000, the 2011 rule governing regional transmission planning and cost allocation. The group’s planning region covers Arizona, California, Colorado, Nevada, New Mexico, South Dakota, Texas and Wyoming.

The utilities’ initial compliance filing included a provision stipulating that costs for projects selected in a regional plan would be allocated only to beneficiaries who agreed to participate in those projects. Other WestConnect members participating in the planning process would not be obligated to pay for those projects’ costs, a measure designed to avoid discouraging nonpublic utility transmission providers from participating in planning.

FERC found that WestConnect’s “non-binding” process did not comply with Order 1000, which prohibits any planning participants from claiming an exemption from cost allocation merely by asserting they receive no benefits from the resulting transmission infrastructure. The commission noted that the “fundamental driver” of Order 1000 was to minimize “free ridership” within the system.

In response to FERC’s rejection, the utilities submitted a second compliance filing containing a new proposal to create separate categories of transmission providers eligible to participate in the WestConnect process: “enrolled” transmission owners subject to the entirety of the Order 1000 process, and “coordinating” TOs — nonpublic utility providers — not subject to regional cost allocation but able to participate in planning. FERC denied a rehearing on that plan and two subsequent proposals that the commission found were similarly deficient in meeting Order 1000 cost allocation requirements. In November 2014 and May 2015, El Paso Electric petitioned the 5th U.S. Circuit Court of Appeals to review the compliance orders.

The 5th Circuit remanded the orders in August 2016 for “additional factual findings” on WestConnect’s planning process, saying the commission’s mandates regarding the role of nonpublic utility transmission providers were arbitrary and capricious, and that FERC had not shown its orders would not produce unjust rates.

FERC last week declined to change its original finding, saying it “continues to conclude that the approach it ultimately accepted in the compliance orders satisfies Order 1000 while taking into account the uniquely integrated nature of public and nonpublic utility transmission systems in the WestConnect transmission planning region” (ER1375-011, et al.).

The commission determined that its original decision “appropriately” considered the “unique characteristics” of the WestConnect region when determining how to address the participation of nonpublic utility transmission providers in the region’s planning process. It noted that some public utilities in the region are connected together by transmission wholly or partially owned by nonpublic providers and that regional planning would be “hampered” without the participation of the latter.

“We find no basis in the record to conclude that, if presented with [the] choice, any nonpublic utility transmission provider in the WestConnect region would voluntarily choose to enroll and subject themselves to binding cost allocation,” the commission said. “Their decision not to enroll would mean that, under this approach, WestConnect would not conduct transmission planning to meet the nonpublic utility transmission providers’ transmission needs.”

While the outcome of WestConnect’s initial approach would comply with Order 1000, it would also “undermine” the order’s goals, the commission said.

The WestConnect utilities included Arizona Public Service; Black Hills Power; Basin Electric Power Cooperative; Powder River Electric Cooperative; Black Hills Colorado Electric Utility; Cheyenne Light, Fuel, & Power; El Paso Electric; NV Energy; and Xcel Energy Services on behalf of Public Service Company of Colorado, Public Service Company of New Mexico, Tucson Electric Power and UNS Electric.

In other decisions last week, FERC:

Western Energy Imbalance Market Participants | CAISO

Accepted APS’ compliance filing for its participation in the Western Energy Imbalance Market (EIM) operated by CAISO. The utility revised its tariff to address directives by FERC in a Sept. 26 order. The commission accepted APS’ proposal to allow external resources to participate in the EIM via dynamic scheduling, subject to a further compliance filing, and the utility’s proposal to reflect payments and charges from CAISO in a future rate proceeding (ER16-938).
Rejected a complaint filed by transmission customers of Pacific Gas and Electric over a proposed rate increase. Complainants said the utility’s stated costs were not justified and argued for a rate decrease, but FERC said they had not met the burden for a complaint and did not introduce any new evidence over the rates approved by the commission in a November 2016 settlement. Complaining parties included the Transmission Agency of Northern California; the city of Santa Clara, Calif.; the M-S-R Public Power Agency; the State Water Contractors; the California Public Utilities Commission; the Modesto Irrigation District; and the Sacramento Municipal Utility District (EL17-59)

November 21, 2017

FERC OKs SPP’s ‘Instantaneous Load Capacity’ Term

FERC on Thursday accepted SPP Tariff revisions replacing the defined terms “head-room” and “floor-room” with “instantaneous load capacity,” effective June 27, 2017 (ER17-1482).

The commission said the changes “more accurately” describe the purpose, scope and functionality of the ramp capacity requirements the RTO needs in order to manage instantaneous load changes that occur during each operating interval.

ferc spp instantaneous load capacity — | GE

Westar Energy and Golden Spread Electric Cooperative protested the revisions. Westar said SPP failed to provide any specific insight on how it accounts for the differences caused by the operational uncertainties, such as generation deviations, load forecast errors, net schedule interchange deviations and erroneous forecasts for intermittent generators.

Golden Spread argued SPP’s addition of the term “operator input” to its reliability unit commitment (RUC) determinations should only apply to extraordinary circumstances. The co-op said instantaneous load capacity should generally be procured by SPP through normal competitive offers based on forecasts.

FERC countered that a degree of operator discretion, “not limitless and consistent with SPP’s existing processes, is inherent in reliability commitment processes.” It dismissed Golden Spread’s and Westar’s remaining comments as being beyond the proceeding’s scope.

The commission did agree with Golden Spread, however, that it had raised issues SPP should consider exploring through its stakeholder process.

— Tom Kleckner

November 21, 2017

FERC Approves NYISO Reliability-Must-Run Plan

By Jason Fordney

FERC last week approved NYISO’s tariff revisions to implement a new reliability-must-run program but directed the ISO to make another filing with certain revisions to the initiative (ER16-120, EL15-37).

NYISO submitted a compliance filing Sept. 20 to implement revisions to its RMR proposal, including adding a 365-day notice period for a generator to tell the ISO it plans to retire. FERC had accepted an earlier compliance filing but in April 2016 directed NYISO to make further changes.

ferc nyiso reliability-must-run — R.E. Ginna Nuclear Plant

The commission rejected a request by the Independent Power Producers of New York and Electric Power Supply Association to shorten the RMR notice period to 270 days. The groups contended that a full year was unnecessarily long. They also made other requests regarding deactivation time and suggested certain incentive payments as part of the program.

In last week’s order, FERC directed NYISO to make another filing that clarifies that a generator can propose solutions to a reliability need that are not market-based and can involve generators that are already mothballed or in a forced outage.

The ISO will also require generators to repay revenues that exceed going-forward costs for RMR service and allow units receiving an availability and performance rate (APR) to retain other incentives. FERC’s order also asked NYISO to clarify what reliability solutions it will use as its base case to determine reliability needs.

NYISO will also have to “revise the requirement to repay above-market revenues to require repayment of only the above-market revenues that exceed an RMR generator’s going-forward costs for RMR service, and to allow RMR generators that accepted an APR to retain their availability and performance incentives.”

The ISO must also revise the repayment periods for capital expenditures and above-market revenues to require repayment either within 36 months or twice the duration of the applicable RMR agreement, whichever is shorter.

NYISO must make an additional compliance filing with further revisions by Dec. 16.

November 21, 2017

MISO Defers Retirement Process Changes

By Amanda Durish Cook

CARMEL, Ind. — MISO will delay until next year its proposal to implement a more open-ended approach to its generator retirement process while it looks into possible modeling implications stemming from the change.

MISO adviser Joe Reddoch last week said the RTO will file the plan with FERC in March instead of by the end of the year, giving it time to evaluate whether the more flexible retirement rules will affect its generator availability modeling assumptions used in planning studies.

miso generator retirement — Reddoch | © *RTO Insider*

Reddoch said the new process is “designed to address both temporary and permanent shutdown scenarios,” and asked for stakeholder opinions on the plan through Dec. 5.

Under the proposal, MISO would announce retirements and rescind interconnection rights only after a generator fails to return from a 36-month suspension period or if an asset owner announces a retirement date before the three years are up, Reddoch said during a Nov. 15 Planning Advisory Committee meeting. Owners will also no longer be required to supply the RTO with an estimated return-to-service date when suspending their units. Suspensions lasting fewer than two months and planned generator outages will not be subject to the new process.

Earlier this year, MISO proposed to reduce its Attachment Y process to a catch-all “economic shutdown” status that no longer recognizes temporary suspensions. The RTO has since dropped that term and tripled the amount of time granted for changing a retirement decision, but it still proposes to combine its separate suspension and retirement procedures into a single process. (See “MISO Moves Toward Singular Attachment Y Status,” MISO PAC Briefs: June 14, 2017.)

The RTO last month received two retirement notices under the existing process, representing more than 1,000 MW of capacity. The RTO typically receives a maximum of four retirement and suspension notices per month, and the combined requests rarely exceed 1,000 MW. MISO has already approved the retirement of 735 MW of capacity for the first five months of 2018. Since 2005, MISO has approved 164 retirement notices and issued 10 system support resource agreements.

November 21, 2017

NARUC Panelists See Need to Define, Price Resiliency

By Rory D. Sweeney

BALTIMORE, Md. — While panelists discussing baseload price supports at the annual meeting of the National Association of Regulatory Utility Commissioners last week didn’t find much common ground, they did agree that energy markets should put a price on the attributes the grid needs.

naruc grid resiliency doe nopr — NARUC Panel left to right: Brighton, Bailey, Durbin, Herling, Barrón and moderator Ellen Nowak, Chair, PSC of Wisconsin | © *RTO Insider*

The discussion revolved around the U.S. Department of Energy’s Notice of Proposed Rulemaking, which urged FERC to adopt price supports for generators that can maintain a 90-day fuel supply. The proposal has been criticized for ostensibly focusing on coal and nuclear units, but discussion has not focused on what qualities the grid requires to be reliable and resilient.

naruc grid resliency doe nopr — Herling | © *RTO Insider*

Steve Herling, PJM’s vice president of planning, attempted to narrow it down.

“We probably have the best fuel mix in the industry,” he said. “If this is all about fuel mix, this is not PJM that’s the problem.”

naruc doe nopr grid resiliency — Durbin | © *RTO Insider*

“The proposal on the table is a solution in search of a problem,” said Marty Durbin, the executive vice president and chief strategy officer for the American Petroleum Institute, which supports oil and natural gas interests. “We’ve earned the market share that we have.

“The polar vortex keeps coming out, and I want to grab my red challenge flag and throw it on the floor,” Durbin said, referring to arguments that gas-fired units don’t have enough fuel security to maintain the reliability of the grid. The severe cold snap in the winter of 2014 created a reliability scare after as much as 22% of PJM’s generators were unable to run when dispatched and gas prices spiked.

The NOPR referenced that situation as an example of why larger units with onsite fuel are necessary, even if they are uneconomic.

“Wyoming’s interest in the NOPR is really about our customers and our coal, not about coal generation,” Wyoming Public Service Commissioner Kara Brighton said.

Define and Value

“We have never viewed the FERC NOPR as a subsidy for coal,” said Paul Bailey, the CEO of the American Coalition for Clean Coal Electricity. “We view this as a way to value a resilience attribute.”

Other panelists agreed.

“We need to decide what’s important and put a value on them,” Durbin said. “That’s really all this is about.”

“This has to be solved holistically,” Herling said. “Infrastructure alone isn’t going to solve the problem. Fuel security alone isn’t going to solve the problem. … Resilience is a rest-of-career conversation.”

“Before we conclude that the markets aren’t supporting these resources, we should ask the question: ‘Do we have the right market rules?’” said Kathleen Barrón, senior vice president for competitive market policy at Exelon, the nation’s largest nuclear operator. “What are the risks that we’re facing, both from manmade and natural sources, to those sources of fuel supply? We probably should get some input from [federal departments] that are experts in security … and have those organizations provide input to the RTOs.”