PJM Markets and Reliability and Members Committees Briefs

Members Prepped for Problem Statement on Settlement Intervals, Shortage Pricing

WILMINGTON, Del. — The PJM Markets and Reliability Committee will be asked to approve a problem statement on first read next month regarding rule changes to comply with FERC Order 825, which requires RTOs to align their settlement and dispatch intervals and implement shortage pricing during any shortage period.

PJM has until Jan. 17 to file its compliance with the June 16 order, PJM’s Adam Keech said. After that, the RTO has four months to implement shortage pricing provisions and 12 months for settlement provisions.

While FERC did not order the changes be implemented simultaneously, members may consider requesting coincident start dates because the issues are related, he said. (See FERC Issues 1st RTO Price Formation Reforms.)

Charter for Underperformance Risk Management Senior Task Force Presented

Members heard the first reading of a draft charter for the Underperformance Risk Management Senior Task Force. The committee will be asked for its approval at the July meeting.

The charter reflects two separate issue charges. The first, managing the risk of underperformance under Capacity Performance, was approved in December. (See “Ways to Mitigate Risk in CP Market to be Studied,” PJM Markets and Reliability Committee Briefs.) The task force will seek to develop ways that CP resources can manage their risk during performance assessment hours.

The second, concerning external CP enhancements, passed in May. (See MRC Approves Charter for Seasonal Capacity Effort.) The group will seek to better align the requirements for internal and external resources.

PJM’s Rebecca Carroll said the task force is looking to implement changes for the 2020/21 Base Residual Auction next May. The task force expects to return to the MRC with recommendations by September.

On a related issue, CEO Andy Ott urged the Seasonal Capacity Resource Senior Task Force to be realistic about changes to allow seasonal resources to participate in CP. In particular, he discouraged them from moving to a seasonal product from an annual one.

“We need to work on aggregation, work on verification standards,” he said. “But to try to completely revamp the definitions would distract from the goal of trying to make change that is attainable,” he said.

More Flexible PLS Process Approved

The MRC approved a proposal to make the parameter-limited schedule exception process more flexible.

With the change, generators can request exceptions after the Feb. 28 deadline. They also will be permitted to seek extensions of a temporary exception (to a period or persistent exception) after that date.

It also gives PJM and the Independent Market Monitor more time to review requests and respond to market sellers. (See “More Flexible Parameter Limited Exception Process Approved,” PJM Market Implementation Committee Briefs.)

PJM Delays Endorsement of Manual Changes

PJM delayed an endorsement vote on two manual changes in response to members who wanted more time to discuss the issues.

Regarding Manual 14C: Generation and Transmission Interconnection Facility Construction, the tie line issue will be lifted out and returned to the Planning Committee for discussion, PJM’s Jason Shoemaker said. The changes were sought to support the inclusion of Order 1000 processes.

As for proposed revisions to Manual 15: Cost Development Guidelines, PJM delayed asking for endorsement to give members more time to discuss aspects related to the fuel cost policy approval process. The issue is expected to return to the Market Implementation Committee next month before being presented again to the MRC.

Manual Changes

Members unanimously endorsed the following manual changes:

Manual 7: Protection Standards. Clarifications were recommended by the Relay Subcommittee as part of its biennial review of the manual.
Manual 10: Pre-Scheduling Operations. Changes make clear that outage reporting rules apply to both capacity and energy resources.
Manual 11: Energy & Ancillary Services Market Operations. Conforming changes align with Manual 12: Balancing Operations (rev. 34), adding attachment F.
Manual 14B: PJM Region Transmission Planning Process. Critical Energy Infrastructure Information section of the introduction is replaced.
Manual 14B: PJM Region Transmission Planning Process. Updates light load and winter peak reliability analyses to align with current practices, among other updates.
Manual 18: PJM Capacity Market. Changes are the result of a periodic review; conforming changes relate to Capacity Performance and the “deploy all resources” action.
Manual 28: Operating Agreement Accounting. New details, clarifications are the result of a periodic review.

Members Committee

Members Committee Adopts Project Queue Submittal Changes, Elects Finance Committee Member

The Members Committee approved Tariff revisions requiring earlier submittal of documentation in order for projects to secure a place in the interconnection queue.

Applications that have not cleared deficiencies by the close of the queue window will be terminated and withdrawn.

The committee also elected Gary Greiner of Public Service Enterprise Group to the Finance Committee. He will take the place of Frank Czigler, who retired from PSEG.

— Suzanne Herel

July 5, 2016

FERC Order Prods CAISO to Allow EIM Intertie Bidding

By Robert Mullin

FERC on Thursday rejected CAISO’s proposal to prohibit Energy Imbalance Market participants from implementing economic bidding at the market’s external interties until the ISO can develop “appropriate rules and procedures” to manage the transactions (ER16-1518).

The ISO’s Tariff currently stipulates that each balancing authority area (BAA) that joins the EIM can determine for itself whether to allow resources located outside the market to submit economic bids at the BAA’s transmission seams.

CAISO sought to change its Tariff in part because EIM participants PacifiCorp and NV Energy had expressed concerns that implementing the practice would add complexity to their initial participation in the market.

The ISO cited another reason for the change: “The CAISO’s experience with 15-minute bidding at its own interties suggests that the extent of the benefits from allowing such bidding is questionable,” it said in an April filing with FERC that included a raft of other EIM-related Tariff changes. The ISO cited the low liquidity in the 15-minute market at the ISO’s own seams — suggesting a lack of market interest — and the potential for EIM participants to incur increased transaction costs from external bids.

caiso eim ferc — EIM participants will continue to have the choice of allowing external intertie bidding along their seems in light of FERC’s ruling.

CAISO also envisioned a “problematic” scenario in which EIM transmission flows could shift as a result of only one EIM participant requesting economic bidding at its interties. While the market consists only of three BAAs today, Arizona Public Service and Puget Sound Energy are scheduled to begin participating later this year, while Portland General Electric will join next year.

The Western Power Trading Forum (WPTF) — an industry group representing power marketers — filed the only protest against the proposal, calling the revision an “attempt to codify” an “effective roadblock to market evolution” that discriminated against third-party participation in the EIM. The organization accused CAISO and the other EIM participants of resisting making the changes required “to incorporate external resources [into] the EIM with efficient, flexible market-based mechanisms.”

The group also criticized the open-ended nature of the Tariff change, asking the commission to dismiss the proposal until the ISO provided a plan to implement EIM intertie bidding by a specific date. The organization suggested that FERC direct the ISO to undertake an “open and transparent” stakeholder process to develop the necessary rules and commit to implementation within a year.

Although the WPTF didn’t win the one-year deadline it sought, the group’s arguments largely found support with the commission.

“As an initial matter, we find it inappropriate for CAISO to include in its Tariff an indefinite placeholder,” the commission wrote, referring to CAISO’s failure to propose a timeline for resolving the intertie issue.

While acknowledging that CAISO “identified issues that warrant further evaluation,” the commission ruled that the ISO had not “sufficiently described” those issues or met its burden under the Federal Power Act to alter the Tariff in a way that would remove from EIM participants the discretion for implementing intertie bidding.

“Moreover, WPTF raised concerns about unduly delaying the ability of external resources to participate — concerns that CAISO does not full address,” the commission said.

WPTF won another concession: The commission called for further discussion of the issue, directing FERC staff to convene a technical conference to gather information about the challenges of implementing economic bidding at the EIM’s interties — with an eye to determining how to overcome impediments. Details for the conference will be set out in a subsequent notice.

The commission’s June 30 ruling did approve CAISO’s other proposed EIM-related Tariff revisions, which included:

Modification of the ISO’s method for assigning congestion revenues to EIM participants to more accurately reflect those participants’ contributions to congestion at an intertie. The current rule allocates revenues based on the number of participants that share ownership of the intertie.
A provision allowing CAISO to submit outage information to the regional reliability coordinator on behalf of each EIM participant.
An alteration to the calculations underpinning the start-up/minimum load costs and default energy bids for EIM generators that would exclude CAISO’s grid management charge, which EIM-only generators do not pay. Instead, they pay EIM administrative charges, which they can continue to include in their costs.
A requirement that EIM participants accept approved, pending and adjusted e-Tags as the only valid means to convey an import/export base schedule to another participant for the purposes of imbalance settlement.

July 5, 2016

MISO Market Subcommittee Briefs

Monitor’s State of the Market Report Seeks Changes to MISO ELMP.)

The Monitor reiterated his suggestion that MISO and PJM scrap pseudo-ties in favor of firm flow entitlements, advice that PJM has recently turned down.

“I don’t know how anyone who understands dispatch could think this is a good idea, but there seem to be a lot of people on the other side of the border that think this is a good idea,” said Patton, who added he’d be interested in checking in with PJM “in a few months” to see if their footprint is weary from high prices.

Dynegy’s Mark Volpe asked Patton if MISO’s pseudo-ties “far from the seam” are a main contributor to higher congestion.

“The farther you are from the seam, the more constraints you’re going to impact, and it’s harder for PJM to model all those constraints,” Patton said. He said MISO’s $302.2 million worth of real-time congestion in the first quarter is up 51% from winter but still down 17% from spring 2015.

Stakeholders asked if MISO could list all pseudo-tied units. Jeff Bladen, executive director of market services, said the RTO doesn’t publicly post information on which resources are pseudo-tied, but market participants could access the nonpublic information using MISO’s commercial model, which provides inputs to the real-time and day-ahead markets.

miso market subcommittee — Patton © *RTO Insider*

Patton also told stakeholders the RTO should “close some loopholes” in the Planning Resource Auction design by applying physical withholding thresholds on a company basis, rather than a market participant basis, to address companies with affiliates.

Stakeholders asked if the recommendation would break up local resource zones; Patton said that would be an entirely different recommendation.

Patton also suggested MISO apply a “reasonable” transfer capability in the next PRA. He said the binding transfer constraint of 874 MW between MISO South and Midwest used in the April auction caused the uniform $72/MW-day clearing prices in zones 2, 3, 4, 5, 6 and 7. Patton wants the limit set “based on the expected ability to reliably transfer power in real-time operations.”

Subcommittee Chair Kent Feliks said the session was the beginning of stakeholders’ review. “I think the point of this today was to get the recommendations on the table to start picking them apart,” he said.

MISO, Monitor Seek Change to Contingency Reserve Selection

MISO may change the economic selection and dispatch behind contingency reserves in an effort to reduce uplift charges.

Akshay Korad, an engineer with MISO’s market evaluation and design department, told stakeholders MISO historically experiences “significant uplift” when contingency reserves are deployed. The current logic seeks to minimize scheduling costs and not production costs.

Type I demand response providing spinning reserves received about $900,000 per year in uplift charges from 2010 to 2015 because of high curtailment costs — which are not accounted for when the RTO selects the resources.

Offline supplemental generators deployed for contingency reserves were paid an average of $275,000 per year in uplift from 2010 to 2015, with last year’s costs totaling $720,000. Korad said offline resources are selected based solely on their reserve capacity offer. “Minimum runtime and commitment costs are not considered in the selection,” he said.

MISO and the Monitor are proposing different solutions, but both would add deployment-cost considerations.

The Monitor advocates the creation of a supply curve for contingency reserves with a deployment risk adder for each resource. The approach would require a Tariff change to ban negative contingency reserve offers.

MISO proposes adding deployment cost considerations to its scheduling logic.

Thomas Sikes of WPPI Energy asked if MISO could offer deployment cost historical data with its proposal. Korad said such information hadn’t been collected. Other stakeholders pointed out that work on dispatch of contingency reserves has consistently been rated a low priority on MISO’s project selection process.

Stakeholders were asked to provide input on the two proposals within a few weeks.

MISO Moving to 3-Hour Clearing Window by November

MISO’s David Savageau said the RTO is on track to “consistently” solve the day-ahead market within three hours.

The RTO is reducing the clearing window from the current four hours in order to post day-ahead results earlier under FERC Order 809. (See FERC Orders MISO to Shift Electric Schedule.)

Savageau said work will continue on the day-ahead and reliability assessment commitment software over the next four months. MISO is “confident it will meet the three-hour window in November,” he said.

MISO Sends Out Customer Survey

MISO has sent its 2016 customer satisfaction survey to 1,200 potential respondents, MISO spokesperson Jay Hermacinski told stakeholders, urging their participation. The survey, independently administered by Opinion Dynamics, is open for responses until Aug. 5.

“We take the results seriously. We analyze the data geographically, we share results with the Board of Directors, we post results to our website,” Hermacinski said.

July 5, 2016

Five Years Later, FERC Takes Another Look at Order 1000

By Rory Sweeney

FERC’s technical conference last week on Order 1000’s performance produced a mix of feedback, with some participants suggesting complete overhauls of the landmark rule and others saying it’s too early to tell if any changes would be useful. But nearly every participant urged the commission to improve transparency in transmission planners’ decision-making processes (AD16-18).

ferc order 1000 — FERC Commissioners lead technical conference on Order 1000

Issued in July 2011, Order 1000 sought to increase transmission development by eliminating incumbent utilities’ monopolies and creating incentives for more innovative, cost-effective and efficient projects.

The order — and its 2012 sequels, 1000-A and 1000-B — have caused heated debate as well as confusion about how the order is to be applied.

Transparency and ‘Evaluation Risk’

George Dawe, vice president of Duke-American Transmission Co., said one of his biggest challenges as a competitive developer is what he called “evaluation risk.”

“I have no idea what the RTO is going to do. I have a general framework for how they plan to evaluate my project after I’ve spent ‘X’ amount of dollars, but no real idea because they’re not being real specific. We need that kind of clarity to keep the developers engaged.”

Those on the customer side also called for transparency.

Donald L. Gulley, president of the Southern Illinois Power Cooperative, said his members are not only asking for transparency but also the opportunity to review the results so they can understand what is working and what isn’t. “What it comes down to for us is … what is the consumer ultimately going to pay?” he said.

However, increased transparency poses a litigation risk for RTOs, said Craig Glazer, PJM vice president of federal government policy.

“Order 1000 is driving transparency, so it is driving us to put more and more things in our Tariff. We’ll have to sort of step back when trying to balance between transparency and specificity in the Tariff with not so much specificity that we have taken away the judgment and discretion part of planning,” he said. “When we document every part of the process, that, to me, is creating the ‘gotchas’ that we will have to deal with.”

CAISO Deputy General Counsel Anthony Ivancovich added that “a wrong decision that can be corrected by litigation is much better than a wrong decision that’s embedded in your tariff and can’t be resolved by litigation because it’s the filed rate.”

Cost Containment

Another recurrent topic during the two-day conference was cost caps. Noman Williams, the chief operating officer and senior vice president of engineering and operations for GridLiance, said caps change the standard transmission development process by transferring the risk of overruns from ratepayers to the builder. “It brings value back to the consumer,” he said. “It is incumbent on us, when we say we want those opportunities and we don’t want to have structure, that we also explain how the cost-containment, cost-cap bids can be applied.”

Sharon Segner, vice president of LS Power Development, lauded PJM and CAISO for figuring out “how to make the cost caps enforceable and not just a PowerPoint presentation.” Developers who fail to stay within their caps risk both the project and the approved rate, she said, and “that is a lot.”

Kim Hanemann, senior vice president for delivery projects and construction for Public Service Enterprise Group, said cost-containment provisions “are of limited value.” PSEG “does not view Order 1000 right now as improving the transmission planning process or bringing value to our customers” because it focuses too exclusively on costs, she said.

“Projects with the greatest overall value may be more expensive in the short term, but they might provide other ancillary benefits, such as reducing congestion and replacing aging infrastructure,” she said. “Simply put, the project with the lowest bid-cost is not necessarily the best project or value for our customers.”

In 2014, PJM planners recommended PSEG’s Public Service Electric and Gas to construct a stability fix for the company’s Artificial Island nuclear complex in New Jersey. However, the PJM board reopened the bidding and ultimately awarded much of the project to LS Power, citing the developer’s lower cost and inclusion of a cost cap.

Richard S. Mroz, president of the New Jersey Board of Public Utilities, said cost and cost caps shouldn’t factor into decision-making until the end of the process.

The process must focus on the scope of the project and what needs to get done, he said, before it can determine how much that will cost. “That’s something that can get lost in the process. That sense of cost consciousness is what drives me and what should drive the process for everyone.”

John Lucas, general manager of transmission policy and services for Southern Company Services, who was also representing Southeastern Regional Transmission Planning, asked that the region — which isn’t overseen by a grid manager — be excused from any rules on cost-containment.

“We would note that [cost caps are] voluntarily adopted processes … that were not required in Order 1000,” he said. “Therefore, if the commission feels the need to make adjustments in those regions, we would just ask that you direct changes to the regions where those processes have been adopted.”

Debate over Incentives

There was also debate regarding project incentives, with consumer advocates saying some should be eliminated while industry members asked for more and said they wanted several — including construction work in progress and abandonment incentives — standardized for all projects.

That brought strong opposition from Peggy Bernardy, staff counsel with the California Department of Water Resources. “The commission should resist the urge to standardize incentives that might be calcified and set in stone for perpetuity,” she said. “That is a risk to us.”

“The commission is perhaps unwittingly complicit in creating an investment environment in which nothing gets done without some form of ‘incentives’ — but which, in reality, are subsidies that only create the illusion of success,” said John Hughes, CEO of the Electricity Consumers Resource Council (ELCON). “Subsidies to promote responses by independent transmission companies to the competitive solicitations mandated under Order No. 1000 do not achieve competitive markets.”

Developers, however, said the potential revenue offered by incentives are key in larger companies getting projects supported by their executives.

Sponsorship or Competitive Model?

Raja Sundararajan, vice president of transmission finance, strategy and siting for American Electric Power, said the order is largely working well, containing both necessary flexibility and transparency. Of the two project-selection methods — sponsorship or competitive bidding — he greatly favored the latter.

CAISO, MISO, SPP and WestConnect have adopted the competitive bidding model, in which transmission planners, with stakeholder input, identify the projects they want and then solicit bids from developers. The winners are eligible for regional cost allocation.

Under the sponsorship model, in contrast, transmission planners and stakeholders identify transmission needs and allow developers to propose potential solutions. PJM, ISO-NE, NYISO, South Carolina Regional Transmission Planning, Florida Reliability Coordinating Council, Southeastern Regional Transmission Planning, Northern Tier Transmission Group and ColumbiaGrid have adopted the sponsorship model.

CAISO’s competitive solicitations have a six-month window that allows time to put together a “real” proposal, Sundararajan said. The sponsorship model is “great for generating ideas” but “doesn’t lend itself” to preparing a comprehensive proposal because it doesn’t allow enough time for the necessary research, he said.

“When the rules are known and the methodology is consistently applied, business works best,” said Michael Sheehan, executive director of NextEra Energy Transmission. California is “getting repeated bidders coming back to competitions in that market because it is clear, transparent, consistently applied and you’re getting feedback.”

ELCON’s Hughes called the project-approval process “nothing more than a food fight” within the RTOs, saying that his membership is seeing transmission costs rise each year without any benefits to show for it.

Southern Co.’s Lucas said there hasn’t been enough information gathered yet to suggest any changes to the order, while Omar Martino, director of transmission for EDF Renewable Energy, said there are many changes that need to be implemented. RTOs are holding onto “historical ways of doing things” that are increasing congestion and hampering grid efficiency, he said.

Planning vs. Regulation

PJM’s Glazer said that by factoring cost into their project approvals, RTOs are effectively setting rates. That movement into a regulatory role “is what makes us nervous,” he said, suggesting the RTO be allowed to take tough decisions to FERC for a second opinion.

PSEG’s Hanemann said grid operators don’t have adequate proficiency in several project development considerations, such as environmental permitting requirements, industry practices, local regulations and equipment procurement.

CAISO’s Ivancovich warned against installing rigid mathematical formulas for decision-making, saying it doesn’t allow for evaluating each proposal on its facts. “You need to establish integrity and credibility that we will be fair in looking at” each proposal, he said.

The entire proceeding was guided by the FERC commissioners’ questions on the positive and negative impacts of the order. Commissioner Cheryl LaFleur said she attempts to follow what she called the “regulatory Hippocratic Oath: Don’t make things worse.”

In a statement before the hearing, LaFleur noted that FERC has dealt with ratemaking and incentive issues resulting from the order on a case-by-case basis and asked for feedback on whether it should issue a policy statement or rulemaking to address the issues generically. “I also hope to address how to harmonize requests for incentives, particularly regarding return on equity, with competitive proposals that include cost caps or other limits on a developer’s ability to recover costs,” she wrote.

July 5, 2016

FERC Accepts ISO-NE Sloped Zonal Demand Curves

By William Opalka

After more than two contentious years of ordering ISO-NE and the New England Power Pool to design sloped zonal demand curves for its constrained zones, FERC last week accepted a compliance filing that does that and also modifies the systemwide demand curve.

The changes will be effective for February’s 11th Forward Capacity Auction for delivery year 2020/21 (ER16-1434).

The RTO and NEPOOL filed Tariff revisions April 15 in response to a commission order Dec. 28, which said the use of vertical demand curves in constrained zones failed to address concerns over price volatility and market power.

The commission had approved the RTO’s systemwide sloped demand curve in May 2014, conditioned on its promise to develop sloped zonal curves in time for FCA 10 in February 2016. The commission granted extensions as the RTO, NEPOOL and stakeholders attempted to reach consensus. But it grew tired of the delays after the RTO said last year that it would be unable to institute sloped zonal curves for the 2016 auction. (See FERC Orders Sloped Zonal Curves for FCA 11.)

The April 15 filing asked the commission to approve both the zonal curves and changes to the systemwide demand curve.

The parties said the new demand curves will significantly improve the performance of the Forward Capacity Market by setting prices that more accurately reflect the locational marginal reliability impact of capacity — how an increment of increased capacity affects the risk of falling short of demand, as measured in hours per year.

The new design relies on two steps: an assessment of the reliability improvement from procuring incremental capacity for each possible capacity level in each zone, and establishment of the prices for each demand curve proportional to the improvement.

Generators opposed the introduction of the systemwide change, arguing it was beyond the scope of the proceeding. They also said that frequent changes in the FCM, including the Pay-for-Performance program that begins in 2018, introduced uncertainty.

“We appreciate desire for certainty of market design as expressed by” generators, the commission wrote. “We balance it with our stated concerns regarding the potential exercise of market power and unnecessary price volatility, while also meeting ISO-NE’s own objectives to achieve reliability, sustainability and cost-effectiveness in its capacity procurement.”

FERC also said that even if the proposed Tariff changes were found to be outside the scope of the proceeding and filed separately, they would have been accepted.

July 5, 2016

NH PUC Approves Sale of Merrimack Station

By William Opalka

State regulators on Friday approved Public Service Company of New Hampshire’s divestiture of the Merrimack Station and other generation assets, ending a 20-year odyssey that began with the state’s Electric Utility Restructuring Act of 1996 (DE 11-250, DE 14-238).

The New Hampshire Public Utilities Commission’s order approves a settlement negotiated last year between the utility and regulators in which PSNH, a subsidiary of Eversource Energy, would recover $415.5 million from ratepayers for the cost of a scrubber at the 439-MW coal-fired plant.

Merrimack_Station_(Wikimedia)-content-web, nh puc — Merrimack Station *Source: Wikimedia*

Eversource shareholders would forego $25 million in deferred equity. (See Eversource to Sell New Hampshire Plants.) The order also said the company “prudently incurred” the costs associated with the installation of the scrubber, which was approved by legislators in 2014.

The order also approves the sale of all Eversource generation assets in the state through an auction, which is expected to net $165 million in customer savings from 2017 through 2021.

More than a year ago, a state report said the Merrimack plant sale could net $225 million. In the meantime, however, cheap natural gas has strengthened its position as the dominant fuel source in ISO-NE and power prices have dropped dramatically. (See ISO-NE: Power Prices Fell by One-Third Last Year.)

In addition to Merrimack, and nine hydroelectric plants totaling 69 MW, the sale includes the 400-MW oil-gas Newington Station, built in 1974, and the 63-year-old, 150-MW Schiller Station, which burns coal, oil and biomass.

The plants are the last utility-owned generators in the state. PSNH challenged the 1996 restructuring law, which required retail choice and the divestiture of all utility generation, resulting in years of litigation. In 2003, the state legislature approved a bill delaying PSNH’s sale of its fossil or hydro assets until 2006.

Eversource must transition to competitive procurement for default energy service within six months of the sale of the assets. The agreement also calls for the company to provide tax stabilization to the host communities of the sold plants for three years if the plants sell for less than their assessed values.

The settlement also approves the sale of rate reduction bonds, which will finance the stranded cost balance at a lower interest rate lower than the return on equity that Eversource would receive if its generation remained in rate base. Eversource shareholders will also contribute $5 million to establish a clean energy fund for initiatives throughout the state.

The PUC said the settlement “involved a balanced compromise and resolved technically complex issues arising from the divestiture of Eversource’s generation assets.”

July 5, 2016

State Briefs

Govs. Speak Against Artificial Island Cost Allocation

Maryland Gov. Larry Hogan and Delaware Gov. Jack Markell stepped up their complaints that the cost allocation for New Jersey’s Artificial Island nuclear project disproportionately affects customers in their states.

The two held a news conference at a waterfront restaurant on their states’ border, insisting they’ll do “whatever it takes” to reverse the cost allocation scheme.

FERC has agreed to rehear its decision approving the cost allocation for a stability fix at the complex that houses the Hope Creek and Salem nuclear reactors. (See FERC Taking Second Look at Cost Allocation for 2 PJM Projects.)

More: The News Journal

CALIFORNIA

State Renews Diablo Lease Through 2025

The State Lands Commission has given Pacific Gas and Electric permission to lease the site of the Diablo Canyon nuclear plant through 2025 without an environmental review.

Until the recent announcement of a settlement to retire the plant, environmental organizations and labor leaders had been urging the state to deny the company a lease beyond its previous 2018 expiration. As part of the settlement, the groups said they would back a move by the state to extend the lease. The plant’s operating license with the U.S. Nuclear Regulatory Commission ends August 2025.

The land commission unanimously approved extending the lease after staff assured it that an environmental review was not required for extension. The threat of a review, first raised by state officials last year, was one of the factors that pushed PG&E to seek an agreement.

More: San Francisco Chronicle

DISTRICT OF COLUMBIA

Pepco Seeking 5.25% Residential, Business Hike

Two weeks after the Public Service Commission denied a final challenge to Exelon’s $6.8 billion acquisition of it, Pepco has asked for a 5.25% rate increase for its 282,000 customers in the district. (See District, OPC Ask PSC to Reconsider Exelon-PHI Merger.)

Pepco said it needs the $85.5 million increase to help pay for the $658 million it has spent on reliability improvements over the past three years. The increase would cost district customers about $50 a year when it takes effect next summer.

More: The Washington Post

INDIANA

IPL Files for Rate Hike For Coal Plant Clean Up

Indianapolis Power & Light has filed for a rate hike to pay for the installation of $100 million in emissions-control technology at its coal-fired Petersburg Generating Station.

The utility filed petitions with the Utility Regulatory Commission to increase customer bills by 20 cents a month in 2017. The amount would rise until 2021, when customers would pay $1.40/month more for the pollution-control measures at Petersburg, which are aimed at reducing sulfur dioxide emissions and coal ash.

IPL has financed $450 million in pollution controls at Petersburg in recent years, but some environmentalists say continued investment is wasted as environmental regulations become more stringent. “IPL continues to throw good money after bad,” said Jennifer Washburn, an attorney at utility watchdog Citizens Action Coalition of Indiana.

More: Indianapolis Business Journal

MASSACHUSETTS

Edgartown Tidal Project Drifts Closer to Reality

A plan to install a pilot tidal energy project in the Cape Cod Canal is gaining momentum with a collection of grants, including funding from the state Seaport Economic Council.

The Marine Renewable Energy Collaborative is gathering the funds, permits and technology to install a tidal generator capable of producing up to 5 MW from the swift currents in the canal. The collaborative has identified a site, in the Muskegat Channel off Wasque Point, which has already received a preliminary permit from FERC.

The project has garnered more than $2 million in state and federal funds, and now needs about $300,000 to complete the final permits and conduct an underwater archeological study of the site. It would be the first of its kind in the U.S.

More: Vineyard Gazette

MICHIGAN

MSU 13-MW Solar Project To Go Forward with Tax Deal

A $24 million, 13-MW solar project at Michigan State University will go forward after the East Lansing City Council approved an 80% tax abatement for 10 years, 15 years fewer than the developer was seeking.

Inovateus, the developer, said the 10-year abatement will save it $2.6 million.

Some council members saw the tax subsidy as a win-win for the city by providing some tax revenue in the long run and increasing the renewable energy needed to help the city and the university meet their sustainability goals. Opponents decried the loss of tax revenue.

More: Midwest Energy News

Report Offers Ways State Can Develop Clean Energy

The state’s Agency for Energy has released a new report, “Clean Energy Roadmap,” recommending approaches the state can use to foster private competition in its clean energy industry.

The $702,500 report, funded primarily by the U.S. Energy Department, advises the state to strengthen research and development by partnering with universities, hosting regular technology contests and finding more sales and export opportunities for clean energy manufacturers in the state. It also encourages the state to use its business networking program to link technology developers with builders and architects.

The report also recommends the state “umbrella” all utility energy efficiency programs into a single program so customers have similar incentives.

More: Crain’s Detroit Business

MISSOURI

Clean Line Submits New Application for Grain Belt

Clean Line Energy Partners has submitted a new application for the Grain Belt Express transmission project to the Public Service Commission. The move came after recent high-profile endorsements from the public and private sector.

The PSC scuttled the project’s initial application last year amid concerns from farmers and other landowners in the transmission line’s path. Gov. Jay Nixon last week endorsed the project, and it has also won support from a number of state municipalities and businesses. The state’s approval is the last needed for the project to go forward.

More: St. Louis Post-Dispatch

MONTANA

PSC Suspends QF Rate For New Solar Projects

The Public Service Commission narrowly approved suspending the $66/MWh qualifying facility rate for new small-scale solar facilities, instead requiring NorthWestern Energy to negotiate prices for solar projects ranging from 100 kW to 3 MW.

The state has recently seen a flood of solar energy developers looking to take advantage of the Public Utility Regulatory Policies Act’s QF provision, which requires utilities to obtain some of their power from smaller sources. The commission said the suspension was necessary to ensure that customers pay a reasonable price for solar power.

Commission Vice Chair Travis Kavulla dissented, saying the PSC should have devised a new rate and questioning the legality of the commission’s action. Commissioner Kirk Bushman also dissented, but he said that the suspension should apply to all QFs, not just solar facilities.

More: Sidney Herald

NEW MEXICO

Regulators Question PNM’s Nuclear Energy Purchase

The Public Regulation Commission resumed a hearing last week on Public Service Company of New Mexico’s proposed rate increase of as much as 15.8%, which would add between $5 to $13 to customer utility bills.

PNM says it needs the money to offset the purchase of electricity from a nuclear power plant and its investments in alternative energy. Regulators and lawyers questioned whether PNM had taken into account the decline in the market for nuclear energy and the electricity needs of the state, as well as what is fair to customers.

The company purchased 64.1 MW from two units at the Palo Verde Nuclear Generating Station for a cost of $163.3 million in early January. The purchase was meant to replace the power lost in the shutdown of two coal-burning units at the San Juan Generating Station.

More: Santa Fe New Mexican

NEW YORK

Groups Send Cuomo Letter Opposing Nuclear Bailout

More than 100 environmental organizations urged Gov. Andrew Cuomo to reject a proposed plan to provide economic support to struggling New York nuclear generating stations, calling nuclear “dirty and dangerous.” They urged Cuomo to support renewable energy projects instead.

Sen. Joseph Griffo, chairman of the Senate and Telecommunications Committee, last month urged the state Public Service Commission to implement a nuclear subsidy in the pending Clean Energy Standard. Entergy has already announced plans to shutter its James A. Fitzpatrick plant, and Exelon has threatened the same for its Nine Mile Point Unit 1 while also saying Unit 2 and R.E. Ginna are also economically threatened.

More: Alliance for a Green Economy

NORTH CAROLINA

Coal Ash Bill Passes House, Heads to McCrory’s Desk

State legislators crafted a compromise that allows Duke Energy to close seven coal ash pits without excavation and does not reinstate an independent coal ash commission that Gov. Pat McCrory disbanded.

Legislators said the new bill, which is ready for McCrory to sign, will allow the company to spend less on cleaning up seven of its pits while ensuring that residents living near the coal ash pits will have clean drinking water, a large concern for many of the lawmakers.

More: The Associated Press

PENNSYLVANIA

IDT Customers Get Rebates From Polar Vortex Settlement

IDT Energy customers will receive $2.4 million in rebates under a settlement approved last week by the Public Utility Commission regarding electricity overcharges during the 2014 polar vortex.

IDT already has provided more than $4.1 million in rebates, refunds and rate adjustments voluntarily, the company said. Under the terms of the settlement, consumers who were on a variable-rate plan from January to March 2014 will be contacted by the settlement administrator if they qualify.

The refunds are part of a $6.75 million settlement IDT agreed to after Attorney General Kathleen G. Kane and Acting Consumer Advocate Tanya J. McCloskey leveled charges of deceptive marketing practices against the company. IDT will also pay a $25,000 civil penalty.

More: IDT Energy; The Philadelphia Inquirer

TEXAS

Legislators Seeks Limit on Turbines near Military Bases

Two state legislators are drafting proposals that would exclude wind energy projects in a 25-mile radius of military installations from getting state tax abatements, though the measures will not be considered until the Legislature reconvenes in January.

Two potential wind farm developments could threaten flight training missions and radar operations at nearby Sheppard Air Force Base, according to base officials and wind energy opponents. The worst-case scenario, they say, is that Sheppard’s missions are moved elsewhere and Wichita Falls loses an estimated $750 million in annual economic impact.

Representatives of Horn Wind, the developer of the projects, and Alterra Power, the Canada-based owner, have repeatedly said they want to minimize any potential impact the facilities have on the air bases. They also have contracted with an aeronautics consulting firm to determine whether projects in Bluegrove and Byers would interfere with base operations.

More: Times Record News

PUC Seeks Comments On Ratemaking Rules

The Public Utility Commission is seeking comments on its recently released report on alternative ratemaking mechanisms.

The report, which surveys and analyzes 11 ratemaking rules and methods, was commissioned by the PUC in response to state legislation passed last year. The methods that may be of most interest to the state are ones focused on streamlining the regulatory process, according to the report.

The PUC is requesting comment on whether the report is “sufficiently comprehensive” and any other recommendations it should make to the legislature.

More: Public Utility Commission of Texas

VIRGINIA

Gov. Creates Climate Change Task Force

Gov. Terry McAuliffe signed an executive order creating a work group to address climate change, drawing complaints from both Republicans, who said the governor is overstepping his bounds, and environmentalists, who criticized the move as “vague and uncertain.”

The governor charged the group with recommending how the state can combat climate change. The move is seen as an attempt to get around language in the Republican-controlled legislature that blocks any actions by the state to comply with the Clean Power Plan.

Environmentalists pointed to the Democratic governor’s support of two planned natural gas pipelines that would cross the state, which they say show he is not serious about fighting climate change. Republican House Speaker William J. Howell criticized McAuliffe’s use of an executive order, saying it was “another deliberate attempt to circumvent the legislature and the will of Virginia voters.”

More: The Washington Post

July 5, 2016April 9, 2024

FERC Conference Debates PURPA Costs, Purchase Obligations

By Robert Mullin

Nearly four decades after its passage, the Public Utility Regulatory Policies Act still generates controversy.

PURPA’s supporters and critics sounded off at a June 29 FERC technical conference exploring the ongoing challenges of implementing the law, which Congress enacted in 1978 to diversify the country’s energy supply, increase efficiency and develop a market for independent power producers. The session focused on PURPA’s mandatory purchase obligation and the determination of avoided costs for those purchases (AD16-16).

“In my view, PURPA has held up reasonably well,” Ken Rose, an economist representing the Independent Power Producers Coalition of Michigan (IPPC), told the conference. “It’s hard to believe [that] 40 years on, we’re still working on implementation.”

FERC Commissioner Tony Clark said the law provided a “foot in the door” for the renewable resources now roiling the power industry and its markets.

He also pointed out the commission’s motivation for revisiting the law, saying, “We’re hearing anecdotally about some of the concerns, especially from the West.”

‘Gaming’ the System

Paul Kjellander, president of the Idaho Public Utilities Commission, said his state’s biggest concern is developers disaggregating large wind projects into smaller units in order to obtain the most favorable avoided cost rates for qualifying facilities.

Kjellander referred to the practice as “gaming” the system.

PURPA requires utilities to pay QFs the cost a utility would incur for supplying the power itself or by obtaining supplies from another source. The law leaves it to each state’s utility commission to formulate those rates, depending on project size.

At one time, Idaho’s rules allowed for projects of 10 MW or below to qualify for the state’s most favorable avoided cost — or standard — rate. As in all other states, projects were subject to FERC’s “1-mile rule,” which requires developers to maintain a 1-mile buffer between projects in order to qualify them as separate QFs. The commission implemented the provision to prevent disaggregation.

In 2010, the Idaho PUC received applications for 500 MW of PURPA projects. The minimum system load for the state’s largest utility, Idaho Power, is about 1,100 MW.

Each project submitted that year came under the 10-MW threshold, and most met the 1-mile standard. Kjellander pointed to an instance in which a developer divided the 151-MW Cedar Creek Wind Farm into five projects, each spaced 1 mile apart.

The Idaho PUC reduced the eligibility cap for the QF standard rate to 100 kW later that year in response to requests from the state’s three investor-owned utilities. The regulator last year reduced contract terms from 20 to two years.

Still, Kjellander said his agency observed what it considered another type of gaming when a PURPA developer moved a proposed project across the state line to Idaho Power’s territory in neighboring Oregon, where avoided cost rates were higher. The Oregon Public Utility Commission approved the project, which had also been broken into five units. Despite the project’s location, Idaho customers will foot nearly all the costs for that project, he said.

“We’re looking at an ugly border war with the state of Oregon,” Kjellander said.

‘Manageable Issue’

“This is a manageable issue — it’s not something that can’t be resolved,” countered Robert Kahn, executive director of the Northwest and Intermountain Power Producers Coalition. “To say [PURPA] is easily gamed is to understate the capacity of [state] commissions.”

Kahn called PURPA a “keystone” in facilitating competition. He said that in Oregon — which he said was “a model for PURPA” — small power producers have built just 5% of the resources used to serve the state’s electricity customers.

Without PURPA’s mandatory purchase obligation, he said, small producers in the Northwest are unable to interconnect with the regional market.

“We advocate for organized markets,” Kahn said. “We are not there yet.”

“The argument that the [Western Energy Imbalance Market] negates PURPA is nonsense,” he added.

Organized Markets not Enough

Varnum attorney Laura Chapelle, who represented Michigan’s IPPC, said that even a fully organized market is insufficient to support the financial viability of most QFs in the state, most of which is located within MISO. She contended that the RTO fails to provide a long-term market for smaller generating resources, given that most states in the footprint retain regulated markets.

“Utilities [receive a state-regulated] rate of return to pay for their resources but want to require that QFs use MISO to get compensated,” Chapelle said.

The power purchase agreement is “the single most important component for a project not owned by a utility,” said Todd Glass, an energy attorney with Wilson Sonsini Goodrich & Rosati, who represented the Solar Energy Industries Association at the conference.

Wind projects are becoming more challenging to finance and develop, according to Glass. He also contended that “the utilities are becoming harder to deal with” with respect to negotiating contracts, and that interconnection processes are “very difficult and discriminatory.”

“You should do no harm to the mandatory purchase obligation,” Glass advised FERC commissioners.

Jeff Burleson, vice president of system planning for Southern Co., countered that “QF contracts that are based on long-term avoided costs pose a risk to our customers.”

Burleson said resources acquired through requests for proposals can be dispatched — or not — depending on power prices. “We fix the capacity price, so we can dispatch around it,” he said.

QF resources, on the other hand, cannot be curtailed, even when their costs exceed market prices, Burleson said.

Michael Wise, senior vice president with Golden Spread Electric Cooperative, noted that his members operate in both SPP and ERCOT and said those markets are “best positioned” to set avoided cost rates for their utility market participants. He suggested that FERC narrow the purchase obligation to cover projects of just 1 MW or less in order to prevent “unfair advantages.”

At the very least, Wise said, the commission should reduce the terms of PURPA contracts.

“QFs of all sizes have what we believe are unfettered access to these markets,” Wise said.

John Hughes, CEO of the Electricity Consumers Resource Council, said forcing QFs to become experts in RTO market design violates the spirit of PURPA. He also contended that the industry is trending toward the elimination of long-term contracts.

“We already have that in the organized markets and now we’re attempting that in the unorganized,” Hughes said. “This is a very serious situation that we’re going to have to look at.”

July 5, 2016

NY Power Trends Report Cites Tx Needs, Seeks Support for Markets

By William Opalka

Dynamic. Changing. Challenging.

Those words, which NYISO CEO Brad Jones uses frequently, are themes echoed throughout the 2016 NYISO Power Trends report.

New York’s Reforming the Energy Vision, the Clean Energy Standard (CES), distributed generation and customer engagement also feature prominently in the report, which was released today.

“The power market is changing as much or more than I’ve seen it in the last 20 years,” Jones told RTO Insider in an interview. “It’s a fantastic place for the NYISO to be in, in the middle of all this dramatic change.

“We wring our hands around here all the time, but I feel very good that we have the capabilities here to meet these challenges,” Jones continued.

Nuclear Power

Part of the hand-wringing concerns the possible loss of much of the nuclear fleet, which is unable to earn sufficient revenues in an energy market dominated by cheap natural gas. New York’s average wholesale electric energy price last year was $44.09/MWh, the lowest in the 15-year history of the state’s competitive markets.

Without a financial lifeline, three nuclear plants in western New York are under threat of closure in early 2017. State regulators are considering a zero-emission credit to subsidize the upstate plants.

“The real key is that we do not properly value the carbon in our markets,” Jones said. (See Lack of Carbon Pricing Distorting RTO Markets, CEOs, Ex-Regulator Say.)

Clean Energy Standard Requires Transmission

The CES requires the state to procure 50% of its energy from renewable resources by 2030. That would require 75,000 GWh of renewable power annually, according to an estimate by the state Public Service Commission. By themselves, that goal would require either 25 GW of solar, 15 GW of wind or 4 GW of hydro, most of that in northern or western New York, far from the load centers in and around New York City.

The city, Long Island and the Lower Hudson Valley use 58% of the state’s electricity. But while more than 80% of the new generation since 2000 has been downstate, the region still produces only 40% of the state’s total, the report notes.

“What this speaks to is the need for more transmission,” Jones said. “Transmission is the key for us to be able to move green power from remote areas to the high-demand areas of the state.”

Flat Load Growth

The increasing shift to renewables will come during a period of flat load growth. “Year-over-year growth in the overall usage of electric energy from New York’s bulk electric system is expected to flatten or decline slightly over the next decade,” the report says.

Other trends highlighted in the report include:

Shifting patterns of electricity demand because of energy efficiency and distributed energy resources: “Distribution-level solar photovoltaics, in 2016, have an estimated summer capability of more than 250 MW. That total is expected to triple by 2026.”
Aging infrastructure requiring replacement and upgrades: “More than 80% of New York’s high-voltage transmission lines went into service before 1980. Of the state’s approximately 11,000 circuit-miles of transmission lines, nearly 4,700 circuit-miles will require replacement within the next 30 years, according to New York’s transmission-owning utilities and power authorities.”
Increasing choices for customers as a result of public policies aimed at reducing emissions and expanding renewable power.

The report concludes with a plea to continue the state’s commitment to competitive markets — a commitment some observers say could be undermined by generation subsidies and long-term contracting for clean power.

The report notes that five of the seven reliability assessments the ISO has conducted since 2005 identified emerging reliability needs. “In each case, markets responded with resources to address those needs, avoiding the need to call upon regulatory solutions,” the report notes.

July 1, 2016

MISO, Monitor Release Negotiated Auction Redesign

By Amanda Durish Cook

CARMEL, Ind. — MISO and its Independent Market Monitor have developed a compromise auction design calling for a prompt, single Planning Resource Auction with separate prices for competitive retail areas.

But that isn’t stopping the RTO from also keeping its original forward auction proposal on the table, a proposal Monitor David Patton says is not viable.

“We don’t believe there is one definitive solution forward, but we do believe we have two very good options in front of us,” MISO executive director of market services Jeff Bladen said during a two-day Resource Adequacy Subcommittee meeting Wednesday and Thursday. “We’re deep into the weeds of evaluating both for price stability.”

Bladen said MISO has hired The Brattle Group to conduct an analysis on both proposals and will select a plan based on the results.

The hybrid competitive retail solution marries elements from earlier proposals by the Monitor and MISO. With it, the RTO could abandon its proposed three-year forward auction for deregulated sections of the footprint in favor of the IMM’s multi-stage prompt auction in which only merchant supply could receive competitive retail pricing set by a systemwide sloped demand curve.

Assets controlled by a load-serving entity whose demand is outside a competitive retail zone would be precluded from clearing at the competitive retail price. MISO’s forward proposal would allow non-merchant generators to offer into the separate, retail choice auction.

Two-Stage Auction

The hybrid proposal would deliver the auction in two stages: Immediately after the competitive retail stage of the auction is cleared, the PRA, with traditionally rate-regulated supply and demand, would take place. The PRA would be referred to as the “legacy” stage of the auction and would continue using the current vertical demand curve.

Fixed resource adequacy plans remain the same under the two proposals; LSEs would have to create plans on a forward basis to opt out of serving retail-choice load.

“I think the hybrid prompt proposal would work,” Monitor David Patton said after multiple stakeholders asked for his opinion. “I’m confident the forward proposal would produce more volatility than the hybrid proposal.”

Patton said the hybrid proposal’s sloped demand curve could be adjusted by MISO to correct instances of over- or under-procurement.

Dynegy’s Mark Volpe asked for Patton’s view on both proposals.

Patton said the forward proposal MISO is continuing to consider is not structured to produce an efficient price and does not represent a compromise. “It may not surprise you that I don’t think the forward proposal is not a viable proposal,” he said . …We’re going to be providing some information regarding the price that you get under both proposals at the next meeting,” he said.

Bladen countered that the hybrid approach could produce volatility. He also said MISO’s Tariff would have to undergo extensive revision to implement the hybrid proposal.

“While it has theoretical elegance, the practical application is questionable,” Bladen said. “FERC is the ultimate judge.”

Stakeholders asked if either proposal had been reviewed by FERC staff.

Bladen said although commission staff has been following MISO’s deliberations “FERC would never give advance notice on what they would approve.”

Bladen also said he didn’t have an estimate on when draft Tariff language would be in front of stakeholders, but he did say it would be “very difficult to achieve” implementation in time for the 2017/18 planning year.

“I wish I could give an exact date when we’re going to walk into the room and announce the selected proposal,” he said.

Forward Proposal Still Unfinished

MISO has yet to offer a demand curve shape for its forward proposal for deregulated areas. Bladen said the final shape is “pending further Brattle Group analysis” but the resulting shape would most likely resemble shapes used by other RTOs. MISO has asked Brattle to look at broader, New York-style demand curves that have more megawatt breadth as well as the narrower PJM-style demand curve, he said.

The RTO’s forward proposal also has yet to identify the “hurdles” rate-regulated supply could face when electing to participate in deregulated areas. Bladen said MISO is working with Brattle on restrictions.

“MISO does not want to be a party to any LSE selling itself short,” Bladen explained.

Stakeholders: Give Us the Evidence

Stakeholders sought more evidence that either proposal would work, with several asking MISO to run simulations using the 2016/17 planning year offers.

Indianapolis Power and Light’s Ted Leffler asked if simulations have been run at all.

“We’re working on it. The short answer is it’s complicated,” Bladen said. He said both MISO and the IMM would come back with simulations and concrete examples, but their results could differ.

Bladen also said there has been “a high lack of understanding [among stakeholders] on how these proposals would work.”

Susan Satter, public utilities counsel for the Illinois attorney general’s office, asked at what point regulated suppliers would supply load in Zone 4 using a hybrid model. Bladen responded that regulated suppliers would influence the competitive retail price by contributing to the systemwide demand curve. He added the systemwide demand curve is needed so deregulated areas contribute to footprint-wide resource adequacy.

“In a sense, [rate-regulated load-serving entities] are providing a moderating service on the competitive retail price,” Bladen said. “While they’re not being explicitly committed to serving load, they’re implicitly moderating the price … versus if there was only merchant generator participation.”

Stakeholders asked if MISO’s forward proposal would guarantee lower prices.

“I’m hesitant to say anything in life is a guarantee,” Bladen responded. But he added that the forward proposal’s price mechanism should produce lower prices. “We think the proposal has legs.”

Patton continues to maintain that MISO’s forward proposal would fail to produce efficient price signals. (See MISO Considering Changes to Proposed Auction Design.)

Initial stakeholder feedback on the hybrid and forward proposals is due July 7.

An additional special meeting of the RASC will take place July 14, at which stakeholders are again expected to discuss the hybrid proposal. Bladen promised Brattle representatives would be on hand to explain their analysis of both proposals and answer questions.

“One of these proposals will fall by the wayside, unless they’re miraculously merged, which I don’t think will happen,” said RASC Chair Gary Mathis.

MISO Contemplates Outages in Seasonal Capacity Accreditation

MISO ‎Manager of Resource Adequacy Coordination Laura Rauch also continued discussion at the RASC on how outages might be handled under seasonal capacity accreditation. (See MISO Moves Forward on Auction Design; Seasonal Filing Delayed Again.)

Stakeholders have said some planned outages during peak hours are appropriate under certain circumstances: when a unit is undergoing a one-time upgrade, when a unit hasn’t cleared the capacity auction or when weather is mild.

miso auction redesign — Rauch © *RTO Insider*

Currently, MISO’s planning reserve margin does not make room for any planned or maintenance outages during peak times. Rauch said the RTO is weighing increasing the reserve margin or reducing individual units’ capacity accreditations to reflect the risk of outages during peak hours.

“We’re still trying to get the point where we identify and clear what’s needed under a two-season construct,” said Rauch.

MISO’s locational filing, which would create external resource zones, is still being examined.

“One of the things stakeholders requested is more transparency and more clarity on how local resource zones would be run in the auction,” Rauch said. “Our homework is to come back with some better examples.”

Further discussion on MISO’s seasonal and external zone constructs is expected at the August RASC meeting. Rauch said an updated design document on the constructs will be released in September.