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October 19, 2017

ERCOT IMM: ‘Fat and Happy’ Times Ending with Coal Closures

By Rich Heidorn Jr.

ERCOT will face higher prices and lower capacity margins following Vistra Energy’s retirement of 4,100 MW of coal-fired generation, Independent Market Monitor Beth Garza told the ISO’s Board of Directors on Tuesday.

ERCOT coal Vistra Energy Market Monitor — Garza | © *RTO Insider*

Assuming ERCOT’s analysis of the pending retirements doesn’t identify local reliability concerns that would result in reliability-must-run contracts for any of the units, Garza said, “We’re looking at a much different situation going into the summer of 2018 than the fat and happy times … of the last couple of years.

“We’ve had really two years of clearly unsustainably low prices with high reserve margins,” she continued. “I think I’ve been saying it in those terms for the last couple of years, and I think we’re now seeing evidence of that unsustainability.”

Since Oct. 6, Vistra Energy’s Luminant unit has announced retirements of the two-unit Big Brown generator north of Houston (1,150 MW); the two-unit Sandow, northeast of Austin (1,137 MW); and its three-unit Monticello plant in East Texas (1,800 MW). The retirements will leave the company with just two coal plants totaling 3,850 MW. (See Vistra Energy to Close 2 More Coal Plants.)

In addition, the Texas Municipal Power Agency announced in July that it will put its 470-MW Gibbons Creek unit in seasonal mothball status, operating only from June through September.

Garza said the announcements were no surprise given that coal units’ fuel costs have been consistently above combined cycle gas units since the beginning of 2015 and coal units were likely unprofitable in 2016.

Although the trends have been clear for some time, Garza said the timing of the Luminant announcements forced her to revise her presentation to the board.

Her presentation showed a 15% reserve margin for 2018. But that could fall to 12% because of the new retirements, she said. She cautioned that her data did not reflect changes in the interconnection queue since ERCOT’s last Capacity, Demand and Reserves report in May.

“It seems to me like the market’s working and folks are responding to appropriate market incentives,” said Director Peter Cramton. “And now it’s time for us to let the market work.”

“I would echo that,” Garza responded. “Generators have a fairly low barrier to entry to the market. Along with that, I think it’s important to have an easy exit as well.”

“You’ve been rubbing the dark side of your crystal ball here pretty good,” Director Karl Pfirrmann pressed Garza. “Now let’s start rubbing the other side a little bit. Tell me, what is it in our marketplace that’s going to correct this problem?”

Garza said the retirements are likely to push forward prices higher, creating pressure for load-serving entities. “If I were a load-serving entity, I would be a little more anxious about the surety of supply going into the forward years than I am right now,” she said. “So, you might see contracting opportunities for new generators that haven’t been there in the past.

“I’m hopeful … that we won’t try to keep units in the market longer than they would like to be there,” she continued. “We just have to be comfortable with what that means — likely higher, more volatile prices going forward than what we’ve experienced in the last couple of years.”

Cramton, an economist at the University of Maryland, agreed. “If we let the market work, it will be a higher forward price — and especially the forward prices many years out. There’ll be pressure on the demand side.”

But he said he feared the transition could be interrupted by “regulatory uncertainty around large subsidies for keeping guys in the market that shouldn’t be there.” It was an apparent reference to Energy Secretary Rick Perry’s call for price supports for coal and nuclear units, although his proposal is limited to FERC-jurisdictional RTOs and ISOs.

“That’s what’s going to damage the market,” Cramton added. “So, I would urge everyone to tell their congressmen to stop that.”

October 19, 2017

Chatterjee Outlines Goals for FERC Tenure

By Rory D. Sweeney

WASHINGTON — Neil Chatterjee, FERC’s recently appointed interim chair, already has plans for shaking up the 40-year-old commission.

FERC Neil Chatterjee EBA Energy Bar Association — Chatterjee | © *RTO Insider*

Speaking Tuesday at the Energy Bar Association’s midyear conference, the former energy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) tallied off six objectives for revising FERC’s regulatory posture.

They ranged from streamlining project review for natural-gas and hydropower projects, to determining a “just and reasonable” return on equity for transmission projects; from changing FERC’s interpretation of de novo review and revising the Public Utility Regulatory Policies Act, to addressing cyber threats. Chatterjee said he also wants to ensure the industry doesn’t outrun itself with technology advancements.

Reliability

But although it was buried deep in his speech, his timeliest goal appears to be maintaining grid reliability “during a time of rapid change,” which comes in light of the Department of Energy’s recent Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants.

Chatterjee has already said he supports investigating the issue. (See FERC Chair Praises Perry’s ‘Bold Leadership’ on NOPR.) On Tuesday, he suggested that those baseload resources may be needed to avoid changing the generation fleet too much, too quickly.

“Reliability is and will continue to be our foremost priority,” he said, listing off several of FERC’s responsibilities related to reliability. “In my view, the DOE NOPR fits comfortably within those efforts. … We must ensure we don’t find ourselves coming to regret not having asked hard questions like these amongst all the changes in the energy industry.”

He also said that news of attempts by Russia and North Korea to hack the grid highlight other reliability needs.

“It’s clear that defending our nation from international cyber threats is one of the most serious challenges of our time,” he said.

Streamlining Review

Chatterjee also voiced support for streamlining the review process for natural gas pipeline and hydropower projects.

“The FERC review process continues to get longer and longer, due in large part to increased participation in the process by stakeholders, including numerous legal challenges,” he said. “FERC owes both sides an opportunity … to receive a timely up-or-down decision.”

Chatterjee dismissed suggestions that FERC depart from its “longstanding” reliance on customer agreements to gauge the economic need for a project “in favor of weighing a broad range of economic, social and aesthetic values.” Gas subscriptions on pipelines are “clear, unequivocal statements of economic need by the market itself.” (See FERC Chair: Court Ruling Won’t Change Pipeline Reviews.)

He blamed project delays on incomplete applications, negotiations with federal and state agencies and the “sheer number” of comments, saying “FERC is most definitely not the principle source of those delays.” He urged applicants to use FERC’s prefiling process and said he hopes to “pursue understandings that can be reached on an agency-to-agency basis” to improve response time. There is no way to speed up comments or responding to them thoughtfully, he said.

Additional Issues

With the generation fleet changing and transmission constraints raising prices, consumers stand to benefit from developing additional transmission infrastructure, Chatterjee said. The “most critical near-term piece” is finding the right financial incentives for enticing project investment, which will involve determining “what represents a just and reasonable return on equity for transmission projects.”

Courts have rejected FERC’s interpretation of its de novo review authority five times, he said, so the commission must develop a “proper scope” that is “fair and legally defensible.” FERC has been chastised by Congress in the past for not properly handling enforcement cases. (See FERC Enforcement Process Under Fire in House Hearing.)

Finally, Chatterjee indicated he plans to address FERC’s implementation of PURPA, specifically the “1-mile rule” for qualifying facilities. FERC has ruled that QFs located within 1 mile of each other are considered to be “located at the same site” and that wind farms of 20 MW or larger within ISO/RTO regions are presumed to have access to competitive markets and thus ineligible for PURPA’s must-purchase obligation on incumbent utilities. However, stakeholders have complained that QF developers are circumventing the 20-MW cap by creating separate corporate entities for individual turbines or small groups of turbines, or disaggregating large projects by siting turbines more than 1 mile apart. (See Witnesses Offer Alternate Realities on Need for PURPA Reform.)

October 19, 2017

Storage Integration a Complex Process, Western Panel Says

By Jason Fordney

RENO, Nev. — Energy storage can provide many benefits to the Western electricity grid, but it will require complex and costly modeling to be integrated properly, a panel of regional energy experts said this week.

The power industry, and its regulators, will require a long-term effort to accurately analyze the benefits and costs of storage, the panel of utility representatives and others said during an Oct. 17 joint meeting of the Committee on Regional Electric Power Cooperation (CREPC) and the Western Interconnection Regional Advisory Body.

western electricity grid energy storage — The CREPC-WIRAB Meeting in Reno Was Well-Attended | © *RTO Insider*

Sector participants must study what ancillary services and sub-hourly and locational benefits storage resources can offer along with the range of other uses being explored for the technology.

Fully modeling the impact of energy storage across the existing utility system “is going to be a very difficult nut to crack” and a big computational problem, said Elaine Hart, a Portland General Electric power analyst.

Oregon-based PGE has been using software tools to model storage, Hart said, utilizing a production cost model for its integrated resource plan (IRP) that simulates the electricity system and dispatch over 20 years and 30 different potential future scenarios based on gas prices, resource output, energy prices and other factors. The effort requires significant computing power and lengthy running of software programs to model possible outcomes.

“We are really lucky that we had this tool when we started evaluating energy storage,” Hart said. To reduce computational time, timelines for modeling could be expanded to every few years instead of every year, for example, and other adjustments could be made, she noted.

Getting it Right

The Washington Utilities and Transportation Commission is working to help that state’s investor-owned utilities integrate energy storage into their IRPs, commission energy adviser Jeremy Twitchell said. The regulator has directed utilities to improve their analysis of energy storage options, an initiative launched after it observed activities at FERC and in California, New York and around the country.

“The key takeaway as we looked around was there were niche storage applications at the time: There were cost-effective applications in a limited scope,” he said. The commission knew utilities needed to be more flexible and that technology costs were dropping, but its modeling capabilities were inadequate.

The commission felt that if it got the modeling right, utilities would integrate the technology in a cost-effective way, Twitchell said. It held workshops to identify challenges, bringing in national laboratories to provide modeling advice and finding that storage can perform well as frequency support and fast response. He also said storage should also be studied for its impact on the transmission and distribution grid, and not just as an IRP resource.

The UTC earlier this month issued a policy statement saying that the absence of an organized market in the West is creating many of the challenges of integrating energy storage, but Twitchell said that perspective is changing because regulated utilities can still capture the benefits of storage without relying on wholesale market outcomes.

FERC in January issued its own storage policy statement “to provide guidance regarding electric storage resources seeking to receive cost-based rate recovery for certain services while also receiving market-based revenues for providing market-based rate services.” According to FERC, the main issues around integrating storage relate to protecting cost-based ratepayers from the potential for double-recovery of costs, preventing adverse market impacts, and maintaining RTO and ISO independence from market participants.

Commissioner Cheryl LaFleur dissented against the policy statement, which was approved by former Chairman Norman Bay and former Commissioner Colette Honorable, saying she disagreed that the issue should be split off from a Notice of Proposed Rulemaking that FERC issued in November 2016.

Price Discovery

Travis Kavulla, CREPC co-chair and Montana Public Utilities Commissioner, asked the panel how more “price discovery” could be incorporated into the modeling process. He said that storage has generally been implemented in two ways: as a “mandate backed up with technocratic guess-work shoved into the rate base,” or with ISOs designing products that let batteries compete in markets.

Tucson Electric Power’s Lee Alter said that IRPs covering all resources could discover pricing and compare different technologies, and that studying storage “jibes really well with the IRP process.” He said his utility is beginning to model energy storage, including sub-hour modeling that serves to study not just integration of batteries, but other impacts from the Western Energy Imbalance Market, pumped storage and other resources.

The discussion made clear that modeling the impacts of energy storage, identifying the benefits and turning energy storage services into a consistent revenue stream will be an ongoing challenge for utilities, regulators and other stakeholders.

October 18, 2017

Stakeholders Debate Limits of MISO Energy Storage Task Force

By Amanda Durish Cook

While stakeholders are still deciding what topics MISO’s Energy Storage Task Force must take on to prepare the RTO for integrating a revolutionary technology, they must also recognize which are off-limits in order to avoid intruding on state jurisdiction.

The new task force has been charged with creating a list of detailed storage issues to be assigned to other MISO stakeholder groups. The RTO in August already floated its suggestions on how to dole out the work. (See Progress Builds for MISO Energy Storage Effort.)

MISO FERC energy storage Invenergy — Invenergy’s 31.5 MW Grand Ridge Energy Storage project | *BYD*

Invenergy’s John Fernandes, the task force’s chair, doesn’t want his group to simply provide MISO’s Steering Committee “a laundry list of issues and wish them luck.” That committee is responsible for assigning specific storage-related issues to other stakeholder committees.

“I don’t want to leave things open-ended,” Fernandes said during the group’s first conference call Oct. 16.

He said the task force should identify in what ways existing market rules might impede participation by storage resources, while also providing the committee with a recommended course of action. That would include helping to determine how to assign issues across committees and identifying which parts of the Tariff require revision.

Clarity from Complexity

The task force’s draft charter stipulates that the group consult storage experts to sort out issues that arise from market integration “that may introduce complexity to the footprint.”

MISO liaison Joe Gardner said the RTO’s goal for the task force is to identify possible near- and long-term changes and additions to market rules.

“Getting as much clarity and consensus now will behoove us in the long run … for planning, reliability and markets,” Gardner said. MISO has set aside funding to conduct storage-specific planning studies, he added.

However, stakeholders attending the task force meetings are at odds over the specifics of discussions.

Minnesota Public Utilities Commission staff member Hwikwon Ham cautioned that the task force should not interfere with state jurisdiction, saying stakeholders can explore whether MISO should create potential market products if states decide to allow aggregators to offer storage, but they should steer clear of deciding rules for interconnection.

“We have to have a discussion about what we can do within the law,” Ham said.

“I have no interest in treading on state jurisdiction,” Fernandes said, adding that the group will also steer clear of retail tariffs and distribution rules. “But the industry is going to force our hand,” he warned, predicting a future influx of storage participation that will require market rules.

Generation or Transmission?

Indianapolis Power and Light’s Lin Franks said the task force should be clear that it will not consider storage as it pertains to transmission planning, instead focusing on how to get it unfettered access to the wholesale market.

Fernandes responded that the group should not limit its consideration of possible storage benefits. “Storage as transmission is a very viable business model,” he said.

“Storage is not wires. It’s a substitute,” Franks countered.

Fernandes said storage-owning stakeholders have “been having the discussion with MISO on storage acting as wires” and the group should consider all storage, whether it functions as a generation or transmission asset.

“Storage as a transmission asset should be on the table … and very much front and center in MISO because it’s envisioned by FERC,” American Transmission Co.’s Bob McKee said. “FERC has already said storage should be recognized as transmission.”

MISO stakeholders also debated whether the group should only tackle grid-scale storage issues, leaving distributed energy resources unaffected. Fernandes said he had concerns with ignoring DER “considering it’s a grid-scale storage developer that signs my checks.”

The task force will meet again in late November to finalize a charter and agree on topics, while most of its substantive work will occur next year. Stakeholders will weigh in on the group’s draft charter through Nov. 3. The task force is slated to meet through the end of 2018, when stakeholders will determine whether the group will be retired or extended.

October 18, 2017

NRG Signals Pull-out on Proposed Puente Plant

By Robert Mullin

NRG Energy on Monday asked the California Energy Commission to suspend its review of a proposed 262-MW gas-fired plant in Oxnard, likely closing the book on a project that met with stiff resistance from community and environmental groups.

The company’s request came after Commissioners Janea Scott and Karen Douglas earlier this month issued what they acknowledged was an “unusual” notice recommending denial of the Puente Power Project. They wrote that it would be “inconsistent with several laws, ordinances, regulations or standards and will create significant unmitigable environmental effects.” (See CEC Members Recommend No-Go for Puente Plant.) The commission is responsible for issuing construction and operating permits for new generating plants.

Scott and Douglas, who together constituted the committee preparing the commission’s decision on Puente, said they made their recommendation so early in the process because they saw a need to study alternatives to the plant after CAISO filed comments contending that the economic feasibility of preferred — or non-emitting — resources could only be established through a new request for offers. While Southern California Edison selected Puente through a standard procurement process, CAISO pointed out that costs for preferred resources have since declined enough to warrant a new RFO. The ISO also noted that cost should not be the only factor driving the decision.

“An economically feasible option need not be the least expensive option, especially given the environmental and performance issues that are unique to each portfolio,” the ISO said.

The commission also received hundreds of comments opposing construction of the plant.

In its Oct. 16 filing with the commission, NRG said it is still considering whether to fully withdraw its application for certification (AFC) for Puente.

“Granting this motion [to suspend the proceedings] will ensure effective use of resources of the committee and the parties to these proceedings in the event that the applicant determines to withdraw the AFC,” NRG said.

CAISO NRG Puente — The Puente plant would have been built on the site of the Mandalay Generating Station in Oxnard (shown), where NRG plans to shut down two existing steam turbine units to comply with California’s once-through cooling restrictions. | *NRG*

The company proposed to build the plant on the site of its Mandalay Generating Station, where it will shut down two existing gas-fired steam turbine units that don’t comply with California’s upcoming regulations restricting once-through cooling. About 2,000 MW of generation in the area is due to retire by 2020 because of the regulations.

The fast-ramping Puente plant would have been capable of reaching more than 95% of its capacity within 10 minutes, helping to integrate renewable resources and ensure reliability in the state’s Ventura/Moorpark subarea, a load pocket that imports much of its electricity through a single substation, the company has said.

The California Public Utilities Commission has already authorized SCE to enter into a long-term resource adequacy contract with the plant, which was slated to begin operating in 2020.

October 18, 2017

SPP Tx Owners Take Zonal Placement Concerns to FERC

By Tom Kleckner

LITTLE ROCK, Ark. — Kansas City Power & Light is making good on its promise to take legal action against SPP for how the RTO allocates costs to network customers after a new transmission owner joins an existing transmission zone.

The utility has joined with 11 other TOs to file a Section 206 complaint with FERC against a “loophole” in SPP’s Tariff that forces customers within an existing zone to pay a share of the legacy costs for transmission lines newly integrated into the zone. That practice, the complainants say, runs counter to the “no legacy cost shift” protections SPP has established to prevent cost shifting between zones.

The Oct. 13 complaint says SPP’s Tariff is unjust and unreasonable and suggests the RTO modify its rules to ensure that facility costs are borne by customers for whom the facilities were planned.

Joining with KCP&L are American Electric Power (on behalf of subsidiaries Public Service Company of Oklahoma and Southwestern Electric Power Co.); City Utilities of Springfield, Mo.; KCP&L Greater Missouri Operations; Nebraska Public Power District; Oklahoma Gas & Electric; Omaha Public Power District; Southwestern Public Service (SPS); Sunflower Electric Power; Mid-Kansas Electric; Westar Energy; and Western Farmers Electric Cooperative.

The companies contend SPP’s zonal integration decisions create unjustified rate increases in the form of cost shifts between customers. Their complaint says the Tariff is unduly discriminatory because the cost shift burden is not evenly distributed and the disparate rate treatment is not based on any differences in service or the customers.

The cost shifts are contrary to FERC’s policies on transmission pricing, cost allocation and RTO membership, the utility said.

Fairness Issue

SPP zonal placement — Buffington | © *RTO Insider*

“This is a fairness issue,” said KCP&L’s Denise Buffington, the utility’s director of energy policy and corporate counsel. “You should not decouple the costs from the decision to build for a specific set of customers.”

The recent creation or expansion of multi-owner zones has highlighted various notice and equity issues that did not exist in historical single-owner zones, Buffington said. She suggested modifying SPP’s license plate rate design to address the increasingly common integration of smaller TOs into existing zones.

Buffington first introduced a Tariff revision request in 2016 to address the gap she said exists between the zonal placement decisions for new TOs and the cost effects of those decisions.

After receiving pushback from SPP and members, she revised her proposal to establish a mechanism holding customers of an existing zone harmless from network integration transmission service (NITS) rate increases of more than 2% or $1 million (whichever is lower). The Markets and Operations Policy Committee and the Board of Directors rejected the proposal in July. (See SPP Board Rejects Changes to Tx Zonal-Placement Rules.)

“You can be sure it will be argued about at FERC,” Buffington warned at the time.

The complaint suggested to FERC that SPP maintain separate NITS rates for the new and existing TOs upon integration. Customers of the new entity would pay its annual transmission revenue requirement (ATRR), and customers of the existing TO would continue paying the same rate previously paid based on the existing ATRR.

Public power entities have consistently opposed the transmission-owning members’ suggestions, saying it would discourage smaller entities from building transmission and getting cost recovery. FERC is already considering several cases involving cost shifts (ER16-204, ER17-2020).

“We’re still reviewing the 87-page filing, but it appears similar to the proposal KCP&L made in the SPP stakeholder process … and addresses a topic already under review by FERC,” said Brett Hooton, vice president of South Central MCN, which is involved in one of the dockets. “The proposal included in the complaint is discriminatory, anti-competitive, and undoubtedly unjust and unreasonable.”

The Missouri Public Service Commission on Monday intervened in the docket (EL18-20).

Z2 Complaints

Also last week, Xcel Energy on Oct. 10 filed a Section 206 and 306 complaint against SPP on behalf of SPS, its Texas-based utility. The complaint said SPP had violated its Tariff by assessing Attachment Z2 credit payment obligations to SPS in a manner that is “inconsistent with the SPP Tariff, violates the filed rate doctrine, is inconsistent with SPS’ network transmission service agreements with SPP and is otherwise unjust.”

Xcel requests that FERC find as unjust and unreasonable SPP’s $12.8 million net assessment to SPS for historical revenue credit payment obligations (CPOs) and ongoing monthly charges of approximately $485,000 for current CPOs and amounts uplifted. The company is seeking to have SPP recalculate the CPOs for SPS’ transmission service reservations, recalculate the historic and ongoing Z2 charges, and provide refunds to SPS with interest.

KCP&L, American Electric Power and Westar Energy have all intervened in the proceeding (EL18-9).

SPP’s process for assigning financial credits and obligations for sponsored upgrades under Attachment Z2 of its Tariff has bedeviled the RTO and members for almost two years. Last year staff identified about $200 million in revenue credits to be collected for transmission upgrades under its Tariff’s Attachment Z2, which details how to reimburse network upgrade sponsors. The bills covered eight years of credits and obligations for 2008-2016, when staff failed to apply credits, complicating the task of trying to accurately compensate project sponsors and claw back money from members with debts for the upgrades. (See “Z2, Two Other Task Forces Expire,” SPP Board of Directors/Members Committee Briefs: July 25, 2017.)

October 17, 2017

Ameren Calls for Milder MISO Response to Uninstructed Deviations

By Amanda Durish Cook

CARMEL, Ind. — ‎Ameren Missouri is urging MISO to scrap a newly proposed process for identifying when generators deviate from dispatch instructions, asking the RTO to instead take a more lenient approach.

The new process, which relies on a calculation formulated with help from the RTO’s Independent Market Monitor, would impose a “failure to follow dispatch” warning when a resource fails to move at least half its offered ramp rate over four consecutive dispatch intervals. Generators are currently flagged after they deviate by more than 8% from dispatch signals over four consecutive intervals. (See MISO Invites Feedback on Plan to Curb Dispatch Deviations.)

ramp rates — Ameren presentation at MISO | © *RTO Insider*

The utility is asking MISO to instead use an incremental percentage approach consisting of tightening tolerance bands over a period of time — or to delay the project altogether and only focus on generators that deviate from setpoint instructions for an hour straight.

MISO ameren ramp rates — Moore | © *RTO Insider*

“We understand the concerns with [day-ahead margin assistance payment] and the concerns about not following setpoint instructions,” Ameren Missouri’s Jeff Moore said during a presentation given at an Oct. 12 Market Subcommittee meeting. “However, we believe there should be further discussion on the topic to fully understand the goals of this effort, address concerns of generators that are making good faith efforts to follow setpoint, and possibly explore other alternative proposals.”

Moore suggested that MISO could decrease its 8% threshold to 7%, and then 6%, to test improvement at each stage. He said his proposal maintains the current practice already familiar to generators. He also added that MISO could drop a new calculation altogether and focus on generators that don’t respond to dispatch instructions for at least one hour.

“To us, 60-minute deviations are a bigger problem. They’re not making a good faith effort,” Moore said.

As it stands, MISO’s new calculation could penalize larger units with low ramp rates, he said.

Ramp rates offered by MISO are not always the same over the entire class of generation, Moore said, asking for a “reasonable allowance” for units to respond to setpoint instructions.

“Baseload coal-fired units are not precision instruments,” he said. “The system models are what they are, but I sometimes feel we’re trying to fit a ramp rate with an imperfect machine.”

Moore said large baseload issues can be inundated with “normal” delays: fuel quality issues, feed rates, or problems with valves that can consume ramp rate time and result in a failure to follow dispatch flags.

“These happen when you’re stopping and starting large pieces of equipment,” Moore said. “Some days it may sit there and hum perfectly, and it may only be 2 to 3 MW short.”

MISO ramp rates — Chiasson | © *RTO Insider*

Monitor staffer Michael Chiasson pointed out that MISO offers numerous ramp rates for generators to select. “You have 30 different ramp rates to choose from to avoid a homogenous ramp rate,” he noted.

“We aren’t interested in penalizing generators that make a good faith effort. Perhaps if we have examples of what a good faith effort looks like for this class of generator,” Chiasson said, asking large baseload generators to provide scenarios in which normal characteristics of the generator would slow down an otherwise faithful dispatch response. He added that the Monitor isn’t “fast and concrete” on its proposal and the calculation could be tweaked a bit, but argued against gentler treatment of large baseload generators.

“When someone offers a ramp rate, they’re saying they can move those number of megawatts, and MISO should expect it of them. I don’t think we should try and levelize this because, ‘It’s a coal/steam unit; don’t expect much out of it.’… That’s not a comparable standard,” Chiasson said.

He said it would be unfair to owners of fast-moving gas units to allow coal units a watered-down dispatch grace period.

“We’ve been recommending this for a half a decade,” fellow Monitor staffer Michael Wander reminded stakeholders.

MISO Market Quality Manager Jason Howard said the RTO will issue a more detailed uninstructed deviation proposal in November. He also said the RTO will review Ameren’s proposal and stakeholder comments.

October 17, 2017

Dynegy: MISO LSE Load Forecasts Require Tune-up

By Amanda Durish Cook

CARMEL, Ind. — After criticizing Ameren Illinois for miscalculating its summer peak load forecast, Dynegy last week called on MISO to develop a new process for verifying load forecasts produced by load-serving entities.

MISO LSE Dynegy summer peak — Volpe | © *RTO Insider*

Dynegy’s Mark Volpe said that while Zone 4 in Southern Illinois represents just 8% of total MISO capacity, it showed the largest under-procurement in the RTO’s Planning Resource Auction, when reserves came up 467.8 MW short of requirements when the summer peak occurred July 20.

The reason, according to Dynegy: Ameren’s portion of the Zone 4 load forecast for the July 2017 peak dropped 484 MW, or 6.4%, from the previous year to 7,069 MW. That led to an overall zone peak forecast of 8,925 MW, down 481 MW, compared with last year’s actual peak of 9,500 MW.

Dynegy said that none of the other zones in MISO showed a similar drop in load forecast.

“This raised our eyebrows at Dynegy,” Volpe said during an Oct. 11 Resource Adequacy Subcommittee meeting.

“We questioned MISO repeatedly on the reasonableness of the forecast, and MISO continually defended the Ameren Illinois load forecast as plausible and reasonable, given gains related to investment in energy efficiency programs, a decrease in commercial and industrial load, and an overall downturn in the economy,” Volpe said.

As required by its Tariff, MISO asks resources to provide forecasts of annual coincident, monthly non-coincident and local resource zone peak demand for use in producing annual load forecasts.

“MISO should have worked closer with Ameren to resolve what we see as an understatement of load forecast in Zone 4. Given the benefit of hindsight of the July 20 peak load … it seems to us that our concerns were pretty valid,” Volpe said.

Consumers Energy’s Jeff Beattie pointed out the Zone 4 planning reserve sharing group easily compensated for the 468-MW shortage.

“To me, that’s one of the benefits of being in an RTO,” Beattie said.

“You’re right — from a macro perspective, things are fine,” Volpe said, adding that he was more interested in the year-over-year changes to load forecasts.

Volpe said MISO does not currently have provisions to perform an after-the-fact examination of forecasts provided by LSEs. He suggested that an independent third party could provide a “look back” of the load forecasts to check for accuracy.

“None of us like penalties, of course, but I think we need to put on our thinking caps and find a way to review whether a load-serving entity came close to its planning reserve margin,” Volpe said. “We’re concerned with overall system reliability, and we have to realize that this impacts all connected to the transmission system.”

Minnesota Public Utilities Commission staff member Hwikwon Ham asked Volpe who would pay for the third-party review. Volpe said costs would have to be worked out if MISO pursues the proposal.

MISO Executive Director of Strategy Shawn McFarlane said the RTO will address the presentation at the November meeting. Kevin Sherd, MISO director of forward operations planning, said the RTO continues to support its existing load forecasting process.

“Quite frankly, we think the forecasts are good on a reasonable, one-year-out basis,” Sherd said.

Improving the Independent Load Forecast?

Volpe suggested that Purdue University — the same third party that produces independent load forecasts used to evaluate the MISO’s own predictions — could verify LSE load forecasts.

But MISO said last month that after three years of using forecasts prepared by Purdue, the process could use improvement, although it did not propose possible changes.

The university’s State Utility Forecasting Group generates forecasts for all 15 MISO states using public data from the Energy Information Administration. The forecast includes summer and winter values for annual energy use in MISO’s 10 local resource zones and aggregate, coincident and non-coincident peak demand predictions for each zone. MISO is nearing the end of a three-year contract with Purdue to provide the forecasts.

MISO said that after three iterations of the third-party forecasts, it has refined its methodology based on stakeholder wishes, leading to use of Applied Energy Group and electric generation expansion analysis system data to create predictions of generation and renewable growth, instead of simply relying state mandates and goals.

“We’ve used the forecast to date for comparison,” MISO Director of Planning Jeff Webb explained earlier this month, noting that the RTO first consults resource adequacy requirements under Module E of its Tariff, then compares the independent forecast against aggregated forecasts submitted by LSEs and transmission owners to determine reserve requirements.

October 17, 2017

3-Degree Forecast Error Triggered MISO September Emergency

By Amanda Durish Cook

CARMEL, Ind. — ‎MISO officials said a temperature forecast short by just 3 degrees Fahrenheit triggered a maximum generation event Sept. 22.

MISO maximum generation event — Aliff | © *RTO Insider*

Tim Aliff, MISO director of interconnection and planning, said that if the RTO misjudges its temperature forecast by even 1 degree, it either underestimates or overshoots its load forecasts by about 1 GW. On Sept. 22, it expected the footprint to top out at 89 F, instead of the actual high of 92 F, he said.

“That can be a big impact from a load perspective. Those 3 degrees might not feel like much outside, but it caused us to be off by about 4 GW,” Aliff said during an Oct. 12 Market Subcommittee meeting.

“Ninety degrees in September isn’t all that odd, but 90 degrees in late September is odd,” he added.

MISO emergency conditions Sept. 21-25 were the result of a combination of record temperatures, high load, and seasonal and forced generation outages. (See MISO Capacity Easily Exceeds Predicted Winter Peak.)

On the day of the maximum generation event, MISO had 4.6 GW of stranded capacity due to forced and planned outages and derates. Additionally, 1.1 GW of generation tripped offline suddenly. Aliff pointed out that during the emergency conditions, MISO South was still recovering from the impacts of Hurricane Harvey.

“It’s kind of unusual on a Saturday to get into a max generation situation,” Aliff said of Sept. 23, which also fell under the maximum generation warning. “Shoulder months can be challenging, so we continue to review what we need to do to reduce these challenges, if you will.”

Michigan Public Service Commission staffer Bonnie Janssen pointed out that by late September, school is in session, which contributes to load.

Xcel Energy’s Kari Clark asked whether MISO could make transmission constraints more visible to market participants during emergency conditions so generators can better understand if their megawatts are unlikely to be able to aid an emergency.

“If we know that we could help you, that would be helpful in our processes,” Clark said.

Aliff said Clark’s suggestion was useful and that he would take it back to his team.

Minnesota Public Utilities Commission staff member Hwikwon Ham asked if MISO has identified a possible transmission solution that would have moderated the situation. Aliff responded that it had not investigated but could look into it.

The September emergency marks MISO’s second maximum generation event of the year. On April 4, MISO called up load-modifying resources for the first time in 10 years in the face of a similar blend of unseasonably high loads coupled with a large number of generation and transmission outages. (See “Several Factors in Spring MISO South Maximum Generation Event,” MISO Market Subcommittee Briefs.) MISO did not have to shed load during the September emergency.

October 17, 2017

WEC Takes Stab at MISO Behind-the-Meter Definition

By Amanda Durish Cook

CARMEL, Ind. — WEC Energy Group uncovered a Tariff inconsistency while it was developing a proposal to improve MISO’s behind-the-meter generation participation rules, a company representative said last week.

WEC Energy Group behind-the-meter generation — Plante | © *RTO Insider*

WEC’s Chris Plante said MISO’s definition of what constitutes a network resource, defined in Module B of the Tariff, doesn’t recognize all capacity acquired under Module E, which covers the procurement of resource adequacy (RA).

Module B does not allow a network customer to generically claim the MISO energy market or capacity market as its network resource, thus technically excluding the customer from counting unregistered BTM generation — which does not have existing transmission service — toward RA requirements, Plante said during an Oct. 11 Resource Adequacy Subcommittee meeting. However, Module E currently allows those resources to be counted as capacity.

To reconcile the discrepancy, Plante suggested that MISO’s definition of “uppercase,” or registered, BTM generation be limited to the following categories:

Network resources behind the market delivery point;
Resources behind the market delivery point participating in the market; and
Resources behind the market delivery point that causes flow on the transmission system.

Plante proposed that any resource be required to register as a network resource with MISO before it can fulfill capacity obligations. The proposal aligns with a plan the RTO is already formulating through planned implementation of a one-time deliverability test for BTM generators that could trigger a requirement to acquire network service in an upcoming capacity auction. (See MISO Proposes Deliverability Rules for Behind-the-Meter Capacity.) Unregistered BTM generators currently enjoy identical treatment to those generators registered as a network resource without having to register with MISO, something the RTO aims to change.

Plante said MISO’s “lowercase” BTM generation — resources not required to register — should be limited to those resources located behind the retail meter and used by a retail customer only to manage load “at the same electrical location,” Plante said. Such resources would not have to respond to emergency conditions.

“We just want comparable treatment among all network resources,” Plante said. “We don’t believe just listing the MISO market as your network resource is appropriate,” according to Module B of the Tariff, Plante said.

Customized Energy Solutions’ Ted Kuhn asked if network customers would now have to enter the capacity auction with a resource already specified. “There would be no way to just go to the auction and say, ‘I’ll take what’s available,’” Kuhn said.

Kevin Murray, attorney for the Coalition of Midwest Transmission Customers, agreed that network customers aren’t currently following MISO’s Tariff as written but added that if they did, and had to identify resources before participating, the capacity auction would clear at near-zero prices “until the end of time.” Plante agreed.

Other stakeholders suggested it was time to re-examine Module B and update its network resource definitions to align with today’s emerging technology.

Plante said WEC wasn’t “wedded” to its proposal and asked stakeholders for more written feedback on the two types of BTM generation.

“This uppercase and lowercase BTMG personally drives me nuts,” said Planning Advisory Committee Chair Cynthia Crane during a Sept. 27 meeting of her committee. She suggested MISO instead use an “R” before the BTMG acronym to differentiate registered and unregistered BTM generation, instead of using the “uppercase” and “lowercase” designations.

MISO will continue to discuss market definitions for BTM generation at the November RASC meeting. Earlier this year, Manager of Resource Adequacy John Harmon said he thinks the energy industry will be focusing on BTM and distributed energy resource issues for years to come.