Page 1320 – RTO Insider

May 16, 2017

MISO Market Subcommittee Briefs

CARMEL, Ind. — MISO last month called on load-modifying resources for the first time in 10 years after it declared an unusual mid-spring maximum generation emergency in the southern part of its footprint.

Unseasonably high loads coupled with a large number of generation and transmission outages precipitated the April 4 event in MISO South, RTO officials said in an emergency review.

The region lost almost 1,500 MW of generation just after midnight when a large unit unexpectedly went down. MISO issued a maximum generation alert around 8 a.m., and by 1 p.m., all resources were in use, with LMRs called up about two hours later. To compound conditions, temperatures topped 80 degrees Fahrenheit, exceeding April averages by about 8 degrees and driving unexpectedly high load.

MISO Market Subcommittee cost recovery gap — Benbow | © *RTO Insider*

“What we saw is temperatures that were more typical for May,” Rob Benbow, senior director of systemwide operations, said at a May 11 Market Subcommittee meeting.

Transmission outages were also higher than normal, with some lines down from earlier severe weather and seasonal maintenance, stranding generation in some cases. Spring maintenance season also sidelined a large number of generators.

All told, MISO called up about 730 MW of LMRs in MISO South to cover a projected 447-MW energy shortfall, marking the first time the RTO has relied on the resources since 2007.

“It’s the first time we’ve deployed load-modifying resources in quite some time,” Benbow said. “This isn’t unusual where you’ve got a lot of maintenance outages and high load in shoulder times.”

MISO forecasts a 79.3% probability that it will again call up LMRs this summer. (See MISO Slims Summer Reserve Prediction.)

Benbow said MISO’s new emergency pricing floors were initiated during the event and worked as intended. By about 9:30 p.m., emergency operations were lifted.

“I fully support overdoing it,” ITC’s Ray Kershaw said. “When you hit the button, you’re not sure how many peakers are going to show up. … You did your job, that’s for sure.”

MISO is still collecting meter data from the event and will evaluate the performance of the LMRs, Benbow said. Stakeholders asked whether operators of those resources are required to respond to run requests from MISO outside of summer peak conditions, an issue RTO staff said they would investigate.

Benbow credited successful management of the emergency event to MISO’s extensive drills. “You only get this through training,” he said.

MISO Officially Expands ELMP

MISO this month expanded its extended locational marginal pricing (ELMP) program to allow online units with one-hour start-up times to set prices.

The program — now entering its second phase — was previously available only to 10-minute fast-start resources.

The move means that 58% of MISO’s capacity is eligible to qualify as peaking resources, compared with 8% beforehand.

FERC accepted MISO’s filing to expand ELMP in an April 20 letter order (ER17-1081).

Twelve newly eligible resources participated in ELMP price-setting during the first day of implementation, said Concong Wang, MISO market design engineer.

MISO’s second phase of ELMP fell short of its Independent Market Monitor’s recommendation that price-setting be extended to all resources with a two-hour minimum run time. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)

Wang said MISO will present a post-implementation analysis at the December MSC meeting, after collection of about six months’ worth of data.

Additionally, the RTO is planning to discuss a potential new trading hub in Mississippi at the June 8 MSC meeting, Director of Forward Operations Planning Kevin Sherd said.

Proposal Would Address Cost Recovery Gap

MISO will revise its Tariff to address two possible gaps in cost recovery when units are manually redispatched offline.

The new language will allow generators to recover start-up costs and day-ahead margin assistance payments during required minimum down times following an RTO-ordered decommittment.

“We currently don’t allow for recovery of start-up costs when a resource is taken offline,” said MISO Market Quality Manager Jason Howard.

When MISO decommits a day-ahead resource, the day-ahead margin assurance payment does reimburse the resource for minimum down times or start-up costs. (See “Potential Cost Recovery Gap in Manual Redispatch,” MISO Market Subcommittee Briefs.)

MISO will file the language by the end of May and seek a next-day effective date, Howard said.

He also said he would have to follow up on a question by Customized Energy Solutions’ Ted Kuhn, who asked if MISO enforces any limits on a resource’s minimum downtime.

MISO, PJM in ‘General’ Agreement over Pseudo-Tie Congestion Remedy

MISO and PJM are in “general” agreement about using an interim rebate program to handle their overlapping pseudo-tie congestion charges, according to MISO Director of Forward Operations Planning Kevin Vannoy.

Vannoy said PJM is still reviewing a slight modification to the original agreement: that the RTOs exchange information about firm flow entitlements a day before a flow date to better predict the effect of congestion on pricing.

The RTOs proposed the rebate solution in early March as a stopgap. A longer-term solution will involve scheduling pseudo-ties in the day-ahead process. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.) They have postponed their ambitious June 1 implementation date for the program to early September. Staff from both will review the solution again at the May 23 Joint and Common Market Initiative meeting held at MISO’s Carmel, Ind., headquarters.

— Amanda Durish Cook

May 16, 2017

Overheard at the IPPNY Annual Spring Conference

ALBANY, N.Y. — About 200 industry stakeholders and state and NYISO officials discussed carbon policy, zero-emission credits, and other pressing and contentious issues at the Independent Power Producers of New York’s 31st Annual Spring Conference last week. Here’s some of what we heard.

The Independent Power Producers of New York’s 31st Annual Spring Conference was held at the new Albany Capital Center, where the IPPNY logo was displayed in lights in the ceiling. | © *RTO Insider*

New Venue, Tighter Security

IPPNY demand curve carbon policy — Donohue | © *RTO Insider*

This year’s conference was held at the new Albany Capital Center. IPPNY CEO Gavin Donohue is chairman of the Albany Convention Center Authority, which built the $78 million project a block from the state capitol.

Event organizers ordered tighter security than in years past. No one without a registration badge was allowed near the event.

“You know what happened at the last conference,” recounted Donohue, referring to the May 2016 event at the Desmond Hotel, when anti-pipeline protesters took over the stage as then-FERC Chair Norman Bay was speaking.

Energy Policy Under Trump

In a panel on energy policy under President Trump, attorney Steven Croley, a partner with Latham & Watkins who served as general counsel for the Department of Energy under President Barack Obama, led the audience in a “thought experiment” comparing Trump’s energy policy with that of a fictional third Obama term.

Croley said Trump will have a smaller impact than some critics fear, calling the policy differences between the two administrations “susceptible to exaggeration,” Croley said.

For example, he said the scale of LNG exports will be driven by world demand, not any new federal policy.

Neither Trump nor Obama would back federal funding of utility-scale solar projects. The Obama administration funded five such projects, but the falling prices of solar technology made additional federal support unnecessary, he said.

Croley acknowledged that Trump has substantial discretion over how aggressively to enforce existing environmental rules but said that states or environmental groups will likely sue if they believe Trump’s EPA is ignoring major violations.

“[Non-governmental organizations], states [and] state regulators are all important drivers of national policy too. They will fill what is perceived to be a regulatory gap or regulatory inaction to some extent,” he said. “Every White House will create its antibodies. Believe me, that’s how it works.”

Indeed, Kit Kennedy, director of the energy and transportation program for the Natural Resources Defense Council, said her organization has increased its litigation team, which has filed 10 lawsuits against Trump’s efforts to roll back environmental policies. She said the organization is also increasingly looking to state and local governments for leadership.

She was more alarmed than Croley, saying “what the president says and does really matters.”

“We’re seeing an onslaught on bedrock environmental safeguards and laws from President Trump today that we’ve never seen before,” she said. “The situation is fundamentally different” from the Reagan and Bush administrations.

Kennedy engaged in a more vigorous debate with James Taylor, an adviser to the presidential campaign of Energy Secretary Rick Perry and president of the Spark of Freedom Foundation, which promotes natural gas, hydro and nuclear power as “affordable” and “environmentally friendly” sources.

“Renewable is not synonymous with green,” Taylor said, citing the environmental impact of mining for rare earth minerals used in solar panels — which he said is worse than uranium mining.

“Wind turbines kill 1.5 million birds and bats each and every year in this country, including many endangered and protected species. It also requires hundreds of square miles of wind turbines to replace a single conventional power plant. For conservationists, that should trouble us.”

He said federal policy should be based on “full spectrum” environmental impact analyses “that [go] beyond the renewable and non-renewable definition and looks beyond carbon dioxide emissions.”

Problems with New Demand Curve

IPPNY Chair John Reese, senior vice president of Eastern Generation, celebrated the completion of NYISO’s demand curve reset but criticized FERC’s decision to not include the costs of environmental controls for the proxy upstate unit.

“It takes about two years to go through that process and lots of pain and suffering and gnashing of teeth. I think IPPNY did a great job in representing the needs of generators and what it takes to get market investment,” he said.

But he said FERC erred in its January order, which rejected requests by IPPNY and the ISO to assume selective catalytic reduction (SCR) emissions controls for the proxy unit for zones C and F.

In its prior reset, NYISO proposed that the New York Control Area peaking plant operate under an annual operating hours limit in lieu of installing SCR. FERC said that assumption still holds, despite the ISO’s contention that peakers without the controls risk not obtaining necessary air permits. FERC rejected as “speculative” IPPNY’s contention that the state’s Siting Board is likely to require tougher controls in the future. (See FERC OKs NYISO Demand Curve Reset.)

“If you’ve done business in New York — if you have developed projects — to imagine that you could build a fossil generator in upstate New York without State of New York controls is just foolishness,” Reese said. “It just cannot be done.”

IPPNY filed a rehearing request on the issue in February (ER17-386).

May 16, 2017

PJM Differs with Monitor in State of the Market Response

By Rory D. Sweeney

While PJM and its Independent Market Monitor agree that its markets “work” and are competitive, they disagree on what might make them better.

Those differences were highlighted last week when the Monitor released its first quarterly State of the Market report of the year, followed by the RTO’s response to the Monitor’s 2016 report.

The quarterly update revised just two of the Monitor’s existing recommendations for Incremental Auctions. It added a proposal that PJM should hold only one IA annually, three months prior to the start of the delivery year.

It also recommended that the RTO release cleared capacity at those auctions “only in cases where the combination of quantities released and associated prices would increase the welfare of capacity market resource owners and load” with consideration for both capacity and energy market benefits.

In response to the Monitor’s original recommendations, PJM agreed “that the structure and format of Incremental Auctions should be reviewed” and pointed to the recently created Incremental Auction Senior Task Force to address those concerns.

But the RTO disagreed with many of the Monitor’s other recommendations, including how to handle demand response resources and uplift. PJM said the EPSA v. FERC Supreme Court case ruled that DR should receive full LMP payments and — despite the Monitor’s recommendation that “any generation component of their retail rate” be subtracted from DR payments — doesn’t plan to challenge the ruling.

PJM state of the market report — | *PJM*

On uplift, PJM said many of the Monitor’s recommendations were considered by the Energy Market Uplift Senior Task Force, which debated the issue for several years before coming to a consensus on a three-phase plan that was endorsed by members — despite ongoing controversy — during April’s Markets and Reliability Committee meeting. PJM is waiting to submit the plan for FERC approval until the commission has a quorum. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)

The largest rift between the Monitor and PJM seems to be whether to allow inflexible units to set LMPs. The Monitor opposes the idea, but PJM argued that “allowing inflexible units to set [LMP] would create an outcome in which [LMP] increases more consistently as load increases.”

PJM believes that — along with the addition of a load-following product — allowing inflexible resources to set LMP would reduce uplift, increase system flexibility and promote enhanced gas-electric coordination.

The changes would also benefit what appears to be PJM’s goal of increasing its energy market prices. In its response, the RTO raised concerns about steadily declining prices thanks to cheap, efficient gas units, increasing renewables and stagnant demand growth partially attributable to energy-efficiency improvements.

Recent low prices, combined with hesitancy to invest in the market and public-policy actions in order to address socioeconomic concerns, “test market price formation and long-term viability,” PJM said.

The effects of units not properly incentivized to follow PJM’s dispatch signals, along with an increasing role for the capacity market in resource entry/exit decisions, “accumulate over the longer term to create unintended bias toward low capital-cost resources with high operating costs,” it said.

Low prices have created a recent rush to subsidize unprofitable generation, such as through the creation of zero-emission credits in New York and Illinois. PJM and the Monitor agree that’s ill-advised.

“Although some state subsidies may intend to address the financial problems that some generators face due to declining energy prices, paradoxically, the subsidies actually may make the problem worse because they further depress market prices, causing needs for more subsidies,” PJM said. “As the 2016 State of the Market Report indicates, however, subsidies are contagious and could spread. If subsidies do become more widespread, they could deter new entry while the suppressed price could artificially raise demand, causing supply shortages in the long term.”

Instead, PJM suggests pricing carbon at the state level if necessary, or implementing its “capacity market repricing” proposal that would allow subsidized resources to be counted toward PJM’s installed reserve margin without impacting the capacity clearing price.

While PJM and the Monitor remain at odds on the role of inflexible units in the market, the RTO is working toward some of the Monitor’s recommendations. The RTO will bring a problem statement to the Market Implementation Committee or the MRC to create comparable flexibility of the operating parameters in the cost-based offer and price-based parameter limited schedule (PLS) with the non-PLS price-based offer. It will also address the Monitor’s recommendation that market participants have at least one cost schedule with the same fuel type and parameters as that of their offered price schedule.

May 16, 2017

Stakeholder Soapbox: Organized Markets for the Future

By Rob Gramlich

As soon as new commissioners are seated at FERC, they will have fundamental and controversial market design questions to resolve.

mandatory capacity obligations FERC technical conference — Gramlich

Some of those questions will be decided in states in terms of the benefits of those policies to those states, and some will be decided by courts in terms of their legality. For their part, the new commissioners will need to choose sides in the never-ending supplier vs. customer debate on capacity obligations and markets.

Or will they?

The Great Divide

The FERC technical conference on potential conflicts between state policy and RTOs/ISOs on May 1 and 2 revealed the same splits as in 2013 and previous commission reviews of capacity markets. Suppliers believe prices should be higher to attract and retain needed resources, while wholesale customers believe capacity markets fail to serve their needs. The main outcome of the 2013 review, which was to improve price formation, has helped a little, and more can still be done there to reflect scarcity in prices.

Carbon pricing was endorsed by many participants as the best economic policy solution for current market challenges, but that doesn’t seem to be a silver bullet either, as putting it in FERC-jurisdictional tariffs was not widely embraced by states. Searching for a third way, ISO-NE and PJM introduced proposals to raise capacity market prices. But explicitly discriminating between supply sources in terms of eligibility and pricing based on someone’s determination of what is “subsidized” and by how much seems hardly like a way to reduce litigation. The higher capacity prices will also lead to further unneeded entry on top of today’s generation surplus that customers will not be happy about paying for.

So this customer-supplier divide remains. And PJM’s recent Capacity Performance changes, now in litigation, created more capacity market enemies by preventing renewable energy resources from selling their capacity value. No wonder there was so much frustration at the conference.

What if we re-evaluate the fundamental objectives of capacity obligations? Do some of the debates become moot?

Mandatory Capacity Obligations No Longer Necessary?

When FERC reluctantly accepted mandatory capacity obligations on load-serving entities in the early 2000s, it was for three reasons that may no longer exist: 1) “resources take years to develop,” 2) “spot prices that are subject to mitigation measures may not produce an adequate level of … investment” and 3) “regional resources are made available to all regional load-serving entities” with no ability to curtail those customers who failed to procure enough.^[1]

Point 1 is no longer true, with demand response and batteries now able to enter markets and provide peak energy within six months. Point 2 can be fixed with scarcity pricing and raising offer caps. Point 3 may not be true any longer either, with improvements in metering, control and scarcity pricing. So maybe capacity markets are only fighting the last battle and failing to solve future challenges.

Resource Adequacy Responsibility in the Future

The commission appropriately wants to make sure someone is responsible for generation meeting load at all times. As with any market in any sector, primary responsibility should be put on customers to procure the supply they need. Wholesale customers today have a range of preferences in terms of resource types, fuel price risk management and environmental attributes.

Some LSEs will be guided or required by states in their resource planning. Either way, their resource choices should be respected and supported to do most of the resource planning work. They have newfound abilities to cover themselves now that batteries can be deployed in six months with exactly as much as is needed, along with DR, in contrast to the past when they had to plan three or more years ahead for lumpy generation assets.

Reliability when Scarcity Conditions Arise

When it comes down to real time, and scarcity exists, RTOs and FERC still need to make sure the system can be balanced. Scarcity conditions may occur at very different times of day and year than in the past, as we are seeing in California and other markets, given different load and supply stack shapes. Reliability during these scarcity conditions can be satisfied if either a) pricing prevents LSEs from demanding more power than is available, or b) the system operator can physically curtail loads that caused the shortage.

We should allow for the possibility that efficient real-time energy markets with today’s pricing and control systems will do the job. RTOs could define short-term products purely according to system requirements and allow all sources to compete on a level playing field. Technology neutrality would help attract batteries, different demand sources and other new technologies to enter to serve system needs. ERCOT is closest to this market vision at this point, though it isn’t fully there.

Completing the Transition

With primary reliance on bilateral contracting for resource adequacy and RTOs focused on their core mission of bid-based security-constrained economic dispatch in real time as a backstop, we can take the competition training wheels off and support a bright, clean, efficient and reliable future power system. We can accommodate rather than work against state policies. We can pull back on RTO mission creep and thereby encourage greater participation in the efficient regional energy markets that are needed for clean energy development in the non-RTO parts of the country. Let’s see if we’re ready to move past the old debates and design the RTO markets of the future.

Rob Gramlich, founder of Grid Strategies LLC, was Economic Advisor to FERC Chairman Pat Wood III in 2001-2005 and Senior Economist in the PJM Market Monitoring Unit covering capacity markets in 1999. Most recently, he was Senior VP for Government and Public Affairs for the American Wind Energy Association.

^[1]SMD NOPR, July 2002, par.461, citing Power System Economics by Steven Stoft.

May 16, 2017

Hydro, Solar Boost CAISO Summer Outlook; Aliso Concerns Remain

By Robert Mullin

CAISO should have sufficient generation to meet peak demand this summer, although questions still linger about the adequacy of Southern California natural gas supplies in the face of a heat wave.

The ISO’s 2017 Summer Loads and Resources Assessment, which describes the grid operator’s preparedness for California’s season of peak electricity usage, paints a generally promising picture. Under “normal” summer conditions, operating reserve margins will average 19.5%, compared with the 15% required by the Public Utilities Commission.

hydropower aliso canyon natural gas — The continued closure of the Aliso Canyon natural gas storage facility remains an issue for the summer readiness of the Southern California grid.

About 52,785 MW of capacity is expected to be on hand to meet this summer’s predicted peak load of 46,877 MW, which would be 0.6% more than the weather normalized peak for 2016.

“The slight overall demand increase is a result of projected modest economic and demographic growth over 2016, tempered by utility projections of new behind-the-meter solar installations over the past year,” the report said.

Summer peak demand could spike to 48,845 MW under conditions that occur only once every 10 years, CAISO said.

The ISO expects 3,090 MW of new generation will have entered commercial operation during the 12 months leading up to this June, 2,566 MW of which is in the southern part of the system — service territories controlled by Southern California Edison and San Diego Gas and Electric.

Nearly three-quarters of the new resources consist of solar (74%), followed by natural gas (23%), storage batteries (3%) and a fraction of a percent each for hydro and biofuel.

California’s hydro conditions have “vastly improved” over last year, the ISO noted. On April 28, statewide snow water content stood at 158% of normal for April 1, typically the peak date for Sierra Nevada snowpack. The state is also experiencing a near record year for precipitation.

“This abundance of rain has nearly all reservoirs near capacity and needing to spill water to make room for spring snow runoff,” CAISO said.

But uncertainty still looms over the outlook for Southern California, where gas-fired generators confront a second summer of fuel supply restrictions stemming from the closure of the Aliso Canyon storage facility. (See Aliso Canyon Gas Restrictions Cloud Summer Outlook.)

The ISO pointed out that its analysis is a “system level” assessment and does not account for gas curtailment risks associated with emergency restrictions on the pipeline system operated by Southern California Gas, owner of the facility north of Los Angeles.

“There are limitations in attempting to shift power supply from resources affected by Aliso Canyon to resources that are not affected because of certain factors such as local generation requirements, transmission constraints and other resource availability issues,” CAISO said in its report.

A joint agency report to be released later this month will address the ongoing risks to the grid posed by continued prohibition on gas injections into Aliso Canyon. The report’s authors include CAISO, the PUC, the California Energy Commission and the Los Angeles Department of Water and Power.

Mild conditions and a series of temporary ISO market measures helped the region’s grid to weather last summer without any major incidents related to constrained gas supplies. FERC last December approved an ISO proposal to extend those measures through November 2017. (See FERC OKs One-Year Extension for CAISO’s Aliso Canyon Gas Rules.)

The ISO last winter also said it would adopt a recently approved West-wide reliability measure to help ensure that it has sufficient capability to transmit power into Southern California via the Path 26 transmission line when needed. The new measure approved by Peak Reliability — the West’s reliability coordinator — allows a system operator to selectively relax a transmission network’s seasonal performance standards in response to “credible multiple contingences” under emergency conditions. (See CAISO to Rely on New Emergency Measure to East Path 26 Transfers.)

May 16, 2017

SPP Members Again Struggle with Solutions to Z2 Credits

By Tom Kleckner

SPP stakeholders’ effort to simplify the RTO’s complicated crediting system for transmission upgrades continues to spin its wheels.

Members once again discussed alternatives to SPP’s cumbersome Z2 process during an all-day meeting in Kansas City on Wednesday, but they adjourned without reaching any major decisions. (See SPP Z2 Panel Sees ILTCRs as Cure to ‘Mess of Complexity’.)

SPP z2 credits — Buffington | © *RTO Insider*

“It feels like we’re going over the same material every time,” said the group’s chair, Kansas City Power & Light’s Denise Buffington. “At some point, we have to get to where we can make a decision. We have to pull the trigger eventually, and it’s clear to me we’re not ready.”

The group did agree to schedule two additional meetings next month to improve its chances of presenting a recommendation in July to the Strategic Planning and Markets and Operations Policy committees.

The task force rehashed the pros and cons of two of the alternatives they have settled on: staff recommendations to replace Z2 credits with incremental long-term congestion rights (ILTCRs) or credit payment obligations (CPOs) under a Tariff schedule. Westar Energy’s Grant Wilkerson has proposed a third alternative, in which only upgrades that create transfer capability would receive credits under the Tariff.

Under Attachment Z2 of SPP’s Tariff, members are assigned financial credits and obligations for sponsored upgrades. The task force is trying to simplify the process while still meeting FERC requirements.

Several stakeholders raised concerns over using ILTCRs to replace Z2 credits, arguing that SPP’s transmission congestion rights (TCR) market is not yet fully functioning. Charles Cates, the RTO’s manager of transmission services, disputed that perception, saying the market is “working very well.”

“Seventy-eight percent of the load entities are fully hedged,” Cates said. “It’s a perception I do not agree with.”

“That’s not a perception OGE shares,” said Oklahoma Gas and Electric’s Greg McAuley, expressing a different viewpoint. “If you dilute a TCR market that’s not fully functional because you’ve never really used an ILTCR yet … I don’t know why you would do that intentionally.

“Z2 is functioning. Some people may not like it, but it’s doing the job it was designed to do. From OGE’s perspective, we’re getting credits for the upgrades that have been put in palace, and we’re also paying for upgrades that have been in place. We have a system that’s in place and working.”

“I’m hearing that we’re trading one set of problems for another set of problems,” NextEra Energy Resources’ Aundrea Williams said. “I want to make sure we don’t lose sight of the ultimate goal of simplification and transparency. I don’t want us to completely discount [that] Z2 can be improved, but the objective doesn’t have to be to get rid of it.”

Cates, who has been tasked with developing the ILTCR alternative, warned against changes to SPP’s market design, saying adding an auction revenue right mechanism connected to financial rights is a disconnect from the original purpose of the design.

“The unintended consequences of going this route could be profound — or not. It’s hard to say at this point,” he said to laughter. “If we’re not careful, the complaints I hear about the TCR market not working — which I personally don’t agree with — could get more loud.”

The moments of levity, while lightening the mood, did not diminish the difficulty of the task before the group.

“The problem I have now is every time I think I understand it, I don’t,” McAuley said. “I don’t have a problem going back to MOPC and saying this is a complicated animal. I don’t want to approve one of these [alternatives] and have a bigger mess on our hands because we didn’t understand it.”

May 16, 2017

MISO Resource Adequacy Subcommittee Briefs

CARMEL, Ind. — Capacity prices last month cleared at just $1.50/MW-day across MISO because of increased supply and low demand, John Harmon, MISO senior manager of capacity market administration, said during a post-mortem of the RTO’s April capacity auction. (See All Zones at $1.50/MW-day in 5th MISO Capacity Auction.)

Coal accounted for most of the auction’s 135 GW of cleared capacity at 53,332 MW, followed by natural gas (48,784 MW) and nuclear (12,885 MW).

A key factor in depressing demand and prices: the overall rise in self-scheduled offers and fixed resource adequacy plans (FRAPs), which increased by more than 10% in zones 4 and 8.

Speaking at a May 10 meeting of the Resource Adequacy Subcommittee, Harmon said changes in offering behavior flattened the offer curve compared with last year’s auction, which saw prices clear at $2.99/MW-day in MISO South, $19.72/MW-day in Zone 1 and $72/MW-day in zones 2, 3, 4, 5, 6 and 7.

Indianapolis Power and Light’s Ted Leffler pointed out that many offers in this year’s auction came in at less than a dollar, with some entered at just a penny.

“There were no instances of mitigation for physical or economic withholding,” Harmon confirmed.

American Electric Power’s Kent Feliks wondered if MISO had to contact any resources in order to enforce a new rule that imposes a 50-MW physical withholding ceiling on affiliated market participants collectively, rather than on each affiliated company individually. The new rule won tentative FERC approval mid-March with forewarning that the rule may not be just or reasonable. (See FERC Staff OKs MISO Mitigation Changes; Refunds Possible.)

“There were a few phone calls, largely from late offers,” Harmon said, noting that some resources bid into the auction near the end of the three-day offer window.

“MISO acting as a conduit to affiliates makes us a little uneasy,” Feliks replied.

Some stakeholders have argued that FERC Order 697 already prohibits affiliates from colluding to dodge withholding mitigation and MISO and its Independent Market Monitor’s new rule is unjustified. (See MISO Plans Additional Capacity Auction Revamps for 2017.)

RASC Chair Chris Plante expressed surprise that stakeholders didn’t have more to say about the auction results, given the low clearing prices.

Stakeholders Won’t Debate Single Year of MISO-SPP Settlement

Stakeholders voted overwhelmingly to end debate about whether costs for MISO’s transmission use settlement with SPP should be allocated by capacity benefit to holders of transmission service requests above the 1,000-MW contract path linking MISO Midwest to MISO South.

Laura Rauch, MISO manager of resource adequacy coordination, said the RTO agreed that the allocation amounts in question were too small to warrant more presentations and feedback cycles.

The RTO had previously asked stakeholders about holding discussions about how to allocate costs for the 300 MW in requests for 2018/19 that exceed the current limit on the North-South interface. Staff warned that the cost split may be negligible, and the matter was put to a stakeholder vote last month via a motion prepared by the Load-Serving Entity Coalition. (See “Single Year of SPP-MISO Settlement Allocation on Ballot,” MISO Resource Adequacy Subcommittee Briefs.)

MISO to Keep Current OMS Survey Format

MISO will stick with using the existing format for its annual resource adequacy survey with the Organization of MISO States, while examining next year’s project estimate approach in light of a new interconnection queue process, RTO staff said.

Rauch said that while stakeholders had not reached consensus on how to display survey results, most believe the RTO should do more to emphasize a fuller range of capacity possibilities. Staff were considering a “floating” results format, but it failed to garner stakeholder favor. (See “MISO Still Tweaking OMS-MISO Survey Format,” MISO Resource Adequacy Subcommittee Briefs.)

MISO is still uncertain about how survey results will be affected by the roll-out of FERC-approved improvements to the interconnection queue, which could increase capacity counts through a quicker turnaround of project approvals. Rauch said it will continue to look into revising its project estimates in future surveys.

This year, MISO and OMS will count 35% of projects in the definitive planning phase of the queue toward future available capacity, in addition to the typical counting of all generation projects with signed interconnection agreements. The new approach was announced after multiple stakeholders voiced displeasure at what they saw as overly conservative results. (See OMS-MISO Survey Moves Ahead with New Calculation.)

Attorney Jim Dauphinais, speaking on behalf of Illinois Industrial Energy Consumers, said trade press and policymakers tend to take zonal capacity projections at their word and ignore the import capability of neighboring zones, which can solve capacity shortfalls.

“Those are negative amounts, and there is some concern with that, but import capability can solve that, and somehow that needs to come through so that policymakers aren’t left with the impression that this is a big problem,” Dauphinais said. “I think sometimes the press and policymakers miss” import capability. He also suggested that MISO post results by state rather than by local resource zones.

Ted Kuhn of Customized Energy Solutions said that even the scaling of the shortfalls versus surpluses on the findings graph is off, with shortfalls drawn visibly larger than their identical surplus counterparts in 2016 results. Rauch examined the graph and agreed that shortfalls were exaggerated in illustrations.

MISO and OMS will present results of the survey mid-June.

MISO to Study Effects of Extended Outages

MISO is still considering whether to bar resources on extended outages from participating in Planning Resource Auctions — or to make changes to capture the risk of such outages in its loss-of-load expectation (LOLE) analyses.

Harmon said the RTO will review its current LOLE study against actual recent outages and present results to stakeholders by mid-July.

MISO’s Tariff does not currently prohibit auction participation for resources on outages for 90 days up to the entire planning year. Staff last month asked stakeholders to suggest maximum outage lengths that would disqualify a resource from PRA participation. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)

May 15, 2017

Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say

By Rich Heidorn Jr.

ALBANY, N.Y. — NYISO’s plan to integrate carbon into its markets will test the independence of FERC under President Trump, speakers told the Independent Power Producers of New York’s 31st Annual Spring Conference last week.

The IPPNY gathering came one week after a FERC technical conference at which NYISO CEO Brad Jones outlined plans to respond to the state’s zero-emission credits for its upstate nuclear plants. Jones told FERC that the ISO has hired the Brattle Group to develop a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. PJM also is considering a similar mechanism for some of its states. (See NYISO Sees Carbon Adder as Way to Link ZECs to Markets.)

Speakers at the IPPNY conference disagreed over whether FERC under President Trump would approve the ISO’s proposal.

In a keynote speech, acting FERC Chair Cheryl LaFleur, a Democrat, indicated she was open to the idea. But she would need to find allies among Trump’s four appointees to the commission to prevail.

Pushing the Boundaries

One IPPNY speaker, Romany Webb, a fellow at Columbia Law School’s Sabin Center for Climate Change Law, outlined a recent paper she coauthored that concludes FERC has the authority to approve a carbon charge adopted by a wholesale market operator such as NYISO.

“Obviously, the Federal Power Act doesn’t authorize FERC to price carbon, and it sort of approaches an area of environmental regulation that has traditionally been considered outside of FERC’s authority,” she conceded. “So it would really push the boundary of what has to date been the limit of FERC’s authority. But it would do so in ways that are consistent with that authority.”

She noted that FERC has traditionally shown deference to grid operators’ market designs, requiring only that they be just and reasonable. “When an ISO makes changes, it doesn’t have to show that the old rules were somehow deficient or the new rules are somehow superior.”

Webb said NYISO could argue that a uniform carbon adder is needed to “rationalize” New York policy because the ZEC program doesn’t apply equally to all generators. It could also say that the current markets are skewed by their failure to capture carbon externalities, including the risks severe weather from climate change poses to the grid.

“The validity of that kind of charge comes down to how it’s structured,” she said. Using the federal government’s social cost of carbon — calculated using a discount rate of 5% to limit the cost impact — would produce an initial carbon price of $12.82/ton.

‘Never Going to Happen’

nyiso carbon adder IPPNY — Gifford | © *RTO Insider*

“I agree with Romany that the most elegant solution is you price carbon into the market,” responded former Colorado regulator Raymond Gifford, a partner with Wilkinson Barker Knauer. “It’s never going to happen. … A fully constituted FERC is not going to sign off on a carbon imposition.”

In addition to being in conflict with Trump’s pledge to bring back coal jobs, Gifford said, a carbon price would be difficult to sell politically.

“If you look through our regulatory history, the best subsidies are the hidden subsidies. … Once you make that price signal transparent … the politics of sustaining it become damn near impossible. That’s where the elegant, economists’ solution runs into the political economy of regulation. And in that fight, the political economy of regulation will win 99 times out of 100.”

Reregulation

A more likely outcome, Gifford said, is a return to some form of reregulation by the states, “maybe continuing to exist uncomfortably in a regional wholesale market.”

“What we have now is an engineering model of the market that has been stressed past the breaking point,” he said. “When this many states are doing versions of the same things and some of them are red states and some of them are blue states, you clearly don’t have a consensus that markets are the way to do this.”

Gifford said he is hopeful that courts will rule on challenges to the state actions in a way that provides clarity to the markets and states — even if prior state-federal jurisdiction rulings have not done so. (See Court’s Reticence Frustrates Energy Bar.)

“Our best hope for a categorical and clear answer going forward is for a court to tell us whether or not these state actions are permissible,” he said. “Now, I know courts don’t always give you a categorical answer, but I think anything is better than the regulatory muddle that we have right now.”

Carbon Price a Political Question

The Brattle Group’s Sam Newell, who is leading the ISO’s effort to develop a carbon adder, said he’s “hopeful” that the ISO’s effort will win FERC approval. But determining the size of the charge is anything but straightforward, he acknowledged.

“The costs of carbon [are] not easily boiled down to a number. It’s not like we’re talking about a very simple externality where you’re harming somebody else’s property and its very immediate and quantifiable,” he said. “You have questions like, how do you deal with the global impact? How do you deal with impacts over centuries and discount them? Most importantly … how do you deal with if there’s a 10% chance of catastrophic outcomes? It becomes almost entirely a political question of how willing are people to support and pay for decarbonization?”

Trump Nominees Will Decide

Last week, Trump nominated Pennsylvania Public Utility Commissioner Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.), to fill two Republican vacancies on FERC.

The president can also nominate a third Republican and a replacement for Democrat Colette Honorable, who announced last month she won’t seek a new term when hers expires in June. Numerous reports have identified Kevin McIntyre, co-head of the energy practice at law firm Jones Day, as the third Republican nominee and likely chairman. (See Trump Nominates Republicans Powelson, Chatterjee to FERC.)

In a 2015 interview with Bloomberg Government, Chatterjee said that as the majority leader’s aide, he viewed all legislative proposals based on the impact on Kentucky, a coal state that is his home as well as McConnell’s.

“For anyone coming to our office to raise a policy issue, the first thing they have to explain is how this will affect Kentucky,” Chatterjee said. “Is this a proposal that will lead to job creation or economic growth in the commonwealth? Or is it going to adversely affect people in the Bluegrass [State]?”

McConnell bitterly opposed the Obama administration’s Clean Power Plan and urged state officials to refuse to comply with it.

Whether Chatterjee will carry his Kentucky-centric view to FERC is an issue Democrats will likely raise at his Senate confirmation hearing.

They also may challenge Powelson, who has been criticized by environmentalists as beholden to the natural gas industry in Pennsylvania, home of the Marcellus Shale.

“As to the political likelihood that FERC [under Trump] is going to approve carbon pricing, that is above my pay grade,” LaFleur told the IPPNY audience. “On a good day, I know what Cheryl LaFleur thinks. I don’t pretend to know what anyone else thinks. And I also don’t prejudge what individuals are going to come in and decide after they get there. But I do think a single-state ISO should have the best chance of reaching a negotiated solution … and I encourage the continuing efforts by the ISO and others to work on that effort.”

LaFleur said a carbon adder would be on firmer legal ground if it resulted from a Federal Power Act Section 205 filing by the ISO.

“I’m fairly certain that our ability to approve a proposal and prevail on appeal would be stronger if a proposal was brought to us under Section 205 and it was agreed upon and proposed by stakeholders in a region,” she said. “I can’t guarantee that would prevail, but I think that would put us in a much stronger position than if we imposed carbon pricing under Section 206, [which] I think would be far more vulnerable on appeal.”

FERC’s Independence

Former FERC and New Mexico Public Service Commissioner Suedeen Kelly said she saw a big difference between the independence of the two agencies.

“The concept of an independent commission … didn’t exist in New Mexico. And so the politics of the governor’s office and the Legislature have a lot of effect,” she said. “But FERC, historically has … been very independent.”

Gifford agreed that FERC has been “relatively insulated” from politics. “It’s certainly not the basket case of the [Federal Communications Commission], which is the prototypical lawless agency.

“But it is, I think, going to be very difficult for this — I know two of the folks who are headed [to FERC] pretty well — I think it’s going to be really tough in this kind of polarized environment for FERC to say to New York: ‘You want a carbon tax? Go for it.’”

May 15, 2017

MISO Exploring Multiday Market

By Amanda Durish Cook

CARMEL, Ind. — MISO is testing the waters for creating a multiday energy market that would keep generators with long start-up times switched on for more than one day.

The effort has strong backing from stakeholders, who last year assigned the introduction of multiday financial commitments a “high priority” in the RTO’s Market Roadmap. (See MISO Projects Reordered Following Stakeholder Frustration.)

MISO says the change will result in more cost-efficient unit cycling and more diversity in the selection of resources called up for commitment. Market participants have said that relying on the routine cycling of baseload units can lead to inefficient unit commitment and higher maintenance and capital costs when a slow-moving unit is repeatedly switched on and off to conform to a next-day schedule.

RTO staff will begin analyzing historical market data in order to assess the costs and benefits of committing units over multiple days, MISO Markets System Analyst Chuck Hansen said at a May 11 Market Subcommittee meeting. The existing day-ahead market is not designed to accommodate units with long lead times or high start-up costs, he said.

“For units with a long lead time, the day-ahead market is going to think that it’s not profitable to start that unit,” he said, adding that the day-ahead market does not typically commit units to serve reliability needs.

But MISO could stretch its market model to notify units days ahead of time when they will be needed.

Still, a multiday market raises the question of who pays for the risk of overcommitting resources. Hansen said that risk could either be assigned to market participants, or MISO could take on the risk with the creation of multiday revenue sufficiency guarantees, which could result in increased uplift payments. Stakeholders could even agree to eliminate the day-ahead market in favor of a multiday market, although it would be a huge undertaking, he said.

Wind units — forecasted only a day out — and forced outages could complicate how slow-response units are scheduled. Hansen also told stakeholders that the “potential to improve unit commitments may be limited” compared to self-scheduling. Resources with high production costs will almost never be committed, even in a multiday commitment market, Hansen said. On the flip side, resources with low production costs can self-commit and remain running.

A multiday market could be useful for even faster-ramping gas-fired units, which must complete their weekend gas reservations on Fridays, Northern Indiana Public Service Co.’s Bill SeDoris said.

MISO market engineer Shu Xu said the RTO would not include the elimination of the day-ahead market in its cost-benefit analysis because the scenario is impossible to test with current software.

That comment prompted DTE Energy’s Nick Griffin to ask if MISO’s impending market system overhaul would allow a multiday market to completely replace a day-ahead market. Dhiman Chatterjee, MISO’s senior manager of market analysis, responded that, given the target deadline for completing a cost-benefit analysis, the RTO could not wait on the development of an entirely new market software platform just to test for such a far-fetched scenario.

MISO hopes to complete its analysis late this year and produce a conceptual design for a new multiday financial commitment market during the first half of 2018.

May 15, 2017

ERCOT Sets New April Demand Record

ERCOT last month set a new record for April peak demand, registering a high of 53,420 MW during the hour ending 5 p.m. on April 28, easily exceeding forecasted demand of 51,622 MW.

That marked a 4.88% increase from the high for the same month last year, when the Texas grid operator recorded a peak of 50,932 MW.

ercot april peak demand — Panda Power’s 758-MW combined cycle power plant in Temple, Texas. | *Panda Power Funds*

ERCOT’s previous high for the month occurred April 18, 2006, when unseasonably high temperatures led to a peak of 51,800 MW.

The ISO generated more than 26 million MWh of electricity in April, bettering the forecast of 25,872,676 MWh. For the year, it has produced 102.4 million MWh, up from 100.5 million MWh through April 2016.

Coal last month surpassed natural gas as ERCOT’s primary fuel source for the first time since January, accounting for 33.57% of the ISO’s energy production. Gas accounted for 33.31% of energy produced and wind another 24.88%. Nuclear dropped to 7.08% of energy production, down from its previous 2017 low of 12.67% in March.

— Tom Kleckner