Page 1464 – RTO Insider

March 14, 2016

SPP, MISO Declare Year 1 of M2M a Success

By Tom Kleckner

LITTLE ROCK, Ark. — SPP and MISO staff told stakeholders last week that the market-to-market process across their seam worked well in its first year and that a memorandum of understanding between the two RTOs will solve most remaining problems.

In a meeting at SPP’s headquarters Tuesday, staff said that the process has worked as intended since it began in March 2015. M2M is designed to improve price convergence on flowgates along the RTOs’ 1,200-mile seam. They compensate each other for re-dispatching generation to reduce congestion in a way that reduces overall costs.

“For the most part, it has generally worked very well and as designed,” SPP’s Gerardo Ugalde said. “We had a few issues … and a few procedures were eliminated.”

Through Feb. 15, the RTOs have had 1,075 M2M events (343 requiring settlements), which resulted in $9.5 million changing hands, according to a review of the first year. Two-thirds of the M2M payments came from three SPP flowgates in Nebraska. The RTOs’ analysis showed the shadow prices are generally within $30 of each other.

“[Those] 1,200 miles are, by far, the largest seam of any RTO we’re aware of,” said SPP’s David Kelley, director of interregional relations. “It has become a lot more complex with the integration of the Integrated System.”

Ugalde said shadow prices and price convergence remain the biggest issues along the seam. “The majority of the time, we’re able to [keep prices] under $500” per megawatt-hour, he said. “For the most part, we tend to price converge.”

MISO and SPP told stakeholders they are continuing their development of an MOU to “ensure cost-effective solutions for both markets.” The MOU, they said, will address ineffective real-time coordination on some flowgates, correct calculation errors in settlements and improve some settlement rules.

Seven Principles

Staff has developed a list of seven principles for the MOU. Among them: excluding reciprocal coordinated flowgates from the M2M process based on a threshold test for generators that affect it; recalculating firm-flow entitlements (FFE) due to changes in facility ratings; and capping FFEs to the system operating limits (SOL) for M2M flowgates.

Another principle would give the non-monitoring RTO the ability to switch from controlling market flows to total flow control. MISO’s Ron Arness said he hoped controlling all transmission on a flowgate rather than just market flows will help moderate some of the price and power swings he has seen on the SPP side. He said new processes on the PJM seam have addressed similar situations.

“What we’ve seen with the SPP flowgates is the [swings] are more severe [than PJM’s],” Arness said. “We need to tweak that process.”

Kelley said SPP’s stakeholders are “not comfortable” with exchanging ownership of flowgates. “It’s really who has the more efficient, effective generation to control the constraint,” he said. “There’s no way you can control the SOL when MISO has 900 MW of generation flowing.”

In response to a question by American Electric Power’s Kip Fox, Ugalde said the MOU will solve “60 to 70%” of the M2M problems.

Ugalde said some of the MOU’s provisions will require JOA changes be filed at FERC, while others will necessitate software changes. The RTOs will continue to evaluate the day-ahead exchange of FFEs and settlements.

MISO’s Beibei Li shared an analysis she and others at the RTO have conducted with PJM on interface pricing. Li said the results indicate a common interface method has “merit” in resolving pricing issues.

Adam McKinnie, chief utility economist for the Missouri Public Service Commission, questioned the analysis. “A lot of time and treasure has been spent between MISO and PJM discussing these various options, but you’ve never been able to say how much this will save,” he said.

Li hedged her response by noting congestion varies from year to year. “Compared to the ideal — where we want to be and where we were — we have identified $2 million in improvement opportunities,” she said.

“I wonder whether you’ve already spent the savings on analysis,” McKinnie responded.

‘Freeze Date’

Work is also continuing through the Congestion Management Process Council, which includes SPP, MISO and PJM, to update the 2004 “freeze date” used in determining CMP allocations and FFEs, based on pre-market firm flows. Arness said the council’s members have agreed there is a need to work on freeze-date alternatives, with the goal of making a Tariff filing by year’s end.

miso, spp, m2m — Ron Arness *© RTO Insider*

“We would like to have an indication we can move forward by the end of the year,” Arness said. “We’ve heard this will be tough, but we’re still working on it.”

Arness said the CMPC has approved guiding principles for firm-flow allocation calculations and a procedure to calculate market-flow impacts associated with external pseudo-tied resources.

However, the council has not been able to move forward with using long-term auction revenue rights to develop M2M FFEs. The RTOs have compared each other’s ARR nomination process and discovered similarities and differences.

March 14, 2016

MISO, SPP Considering Second Joint Tx Study

By Tom Kleckner

LITTLE ROCK, Ark. — SPP and MISO’s Interregional Planning Stakeholder Advisory Committee met last week to discuss how to improve a process that failed to recommend any interregional projects during its first go-round in 2015.

As required by the RTOs’ joint operating agreement, the IPSAC’s March 9 annual issues review meeting was intended to determine whether a joint study should be performed this year and, if so, what should be in the study’s scope.

Brett Hooton (SPP-MISO interregional planning) — Brett Hooton *© RTO Insider*

Though stakeholders expressed an appetite for another study, they will first provide written feedback to the IPSAC. The committee will then provide a study recommendation to the RTOs’ Joint Planning Committee, which will vote to determine whether a coordinated system plan (CSP) study should begin this year and which transmission issues should be studied.

The JPC — comprising David Kelley, SPP’s director of interregional relations, and MISO’s Eric Thoms, manager of planning coordination and strategy — will be given 45 days to vote after receiving the recommendation.

“When we designed the process, we didn’t want a joint-study process that drags on and on,” said Brett Hooton, SPP’s senior interregional coordinator, in explaining the 45-day timeframe.

‘Triple Hurdle’

Stakeholders will provide comments on the CSP process’ suggested improvements and issues, which included overburdened flowgates, market-to-market congestion, carbon-constrained futures, the MISO North-South flows and what American Electric Power’s Kip Fox “affectionately” refers to as the “triple hurdle” approval process for interregional projects.

Kip Fox (SPP-MISO-interregional planning) — Kip Fox *© RTO Insider*

“To get through the regional process, a project has to get through three models, three different sets of criteria,” said Fox, AEP’s director of transmission strategy and grid development. “That makes it very difficult to build across the seam.”

The JOA currently requires interregional projects to be agreed upon by both RTOs, improve congestion by at least 5% on either side of the seam and be approved through the respective regional reviews. SPP approval requires a 1.0 benefit-to-cost ratio, while MISO approval requires a 1.25 B/C ratio and limits projects to 345 kV or above.

The first joint study evaluated 67 potential transmission projects and identified three congestion-relieving upgrades, but it was unable to move forward with any of the three. (See SPP, MISO Conclude Joint Study Empty-Handed.)

Several stakeholders said they favored a more targeted study to analyze specific topics instead of another comprehensive process. “We don’t want to see another comprehensive study. Great information, but not very helpful,” said George Dawe, vice president for Duke American Transmission Co.

Arash Ghodsian (MISO-SPP-interregional planning) — Arash Ghodsian *© RTO Insider*

“We identified three projects and none of them had steel put in the ground,” Fox said. He offered two options to eliminate the triple hurdle: 1) a new interregional project category to allow easier approval and cost allocation, including voltages as low as 100 kV; and 2) adding new benefit metrics following both interregional and regional studies.

“The [adjusted production cost] doesn’t capture all the value of transmission along the seam,” Fox said. His suggested new metrics would include avoided costs, net load payments, and reduced emission rates and operating reserves.

Fox also urged the two RTOs be more flexible with their interregional projects and negotiate solutions beneficial to both sides.

‘Common Sense’

“Let’s use a little common sense,” Fox said. “We want to pay our fair share; you pay your fair share.”

“I think that works when both parties are interested in projects,” responded Jake Langthorn, Oklahoma Gas & Electric’s RTO policy director. “I’m confident SPP wants to do some projects. I don’t have same confidence MISO wants to do any projects.”

Adam McKinnie © RTO Insider (miso-spp-interregional planning) — Adam McKinnie *© RTO Insider*

MISO bore the brunt of stakeholders’ dissatisfaction with the CSP process. Adam McKinnie, chief utility economist for the Missouri Public Service Commission, said he is “not always impressed” with MISO’s regional studies. Marguerite Wagner, ITC Holdings’ director of SPP RTO policy, said MISO’s 345-kV threshold makes it difficult to fund interregional projects. She noted congested flowgates are constrained by lower-voltage projects.

Davey Lopez, MISO advisor of planning coordination and strategy, discussed a “quick hits” analysis recently conducted with PJM, suggesting a similar process with SPP. However, DATC’s Dawe was skeptical.

“To me, quick hits equals sub-optimal projects,” he said. “I remember quick hits. We got there because we couldn’t do anything through the [PJM] IPSAC.”

A stoic Thoms took much of the criticism in stride. He said MISO “left no stone unturned” in the last joint study, but the cost benefits of the proposed projects “haven’t been there yet.” He said addressing the 345-kV threshold issue is one of MISO’s top priorities.

“I agree finding interregional projects has been elusive,” he said. “MISO sees value in doing coordinated studies and joint evaluation with SPP. We will take all the information here, meet internally, and make that determination as to whether to do another coordinated joint study and what that scope will look like.”

CPP Impacts

DATC’s Bob Burner focused his company’s suggestions on the Clean Power Plan’s impacts and the MISO North/Central-South constraint. Burner said an interregional analysis is needed to better understand the new PROMOD models MISO introduced last year in its Transmission Expansion Planning package.

Wagner likened the SPP-MISO north-south constraint to renting a car, and said transmission expansion could replace MISO’s settlement payments for flows across the seam. “You have these payments, but nothing long-term … no increased flexibility, no increased robustness of the system,” she said. “It’s current money, and you’re going to be paying that into perpetuity instead of for something that might be longer-lasting.”

L to R Eric Thoms (MISO), Adam Bell (SPP), Jeremiah Doner (MISO) at IPSAC on 3-9-16 — Eric Thomas, Adam Bell, Jeremiah Doner *© RTO Insider*

SPP’s Adam Bell, representing its interregional relations department, reviewed with stakeholders initial feedback gathered by the IPSAC in December following the first study’s conclusion. He said staff reviewed the suggestions it has already received, separating them into process-improvement options, scope-related suggestions and issues to be addressed later.

“We knew this being the first time through the process, we would have significant room for improvement, and that turned out to be true,” Bell said.

Potential improvements include aligning the system plan’s timing with SPP’s Integrated Transmission Process and the MTEP process; aligning the CSP’s models with the RTOs’ regional models; using broader metrics; creating task teams to create more transparency for stakeholders into the process; and providing more information on why projects did not pass screens or were not recommended as interregional projects.

Bell also suggested creating a separate interregional evaluation process to replace SPP’s and MISO’s separate regional review processes and requiring the respective boards of directors to vote up or down on any project recommended by the JPC.

Kelley noted interregional projects have to come through the Order 1000 process. “In lieu of separate regional reviews, we would rely on the results of the interregional evaluations,” he said. “We will still go through three [sets of] approvals but rely on only one review.”

Added Complexity

With the addition of the Integrated System, staff pointed out, the MISO-SPP seam is now approximately 1,200 miles long, and includes more than 60 interconnections, adding to the complexity of determining interregional projects. The concentration of wind energy in the upper Midwest has only exacerbated the situation.

Dan Lenihan, manager of transmission and distribution planning for the Omaha Public Power District, said Nebraska has historically seen heavy north-to-south flows in the summer and a reversal during the winter. “With the large addition of variable energy,” he said, “we’ve seen those north-and-south flows flip on almost a daily basis, depending on how the wind blows.”

“I’m always surprised how this much wind can be added without the transmission to support it,” said Paul Malone, transmission compliance and planning manager with the Nebraska Public Power District. “We’re looking for mitigation on this, or MISO can build some more outlet transmission.”

Xcel Energy asked the RTOs to examine the “very complex” seam along North Dakota. “We would like to determine if any efficiencies in interregional coordination can be found to increase system reliability and provide more cost-effective operational solutions,” said Drew Siebenaler, a transmission and regional planning engineer with Xcel.

Several other stakeholders suggested future studies take into account the growing development of wind energy and other renewables, which are crowding out coal generation.

Steve Gaw (MISO - SPP Interregional Planning) — Steve Gaw, David Kelley *© RTO Insider*

“Most people acknowledge we’re seeing a shift to lower-carbon generation. I think we missed that in the last study with the [business-as-usual] case,” said the Wind Coalition’s Steve Gaw. “I think it makes sense to make that commitment in the studies going forward. I think it very important, especially considering the seams have increased in distance and we’re involved in a lot more states now.”

Kelley, while welcoming the feedback and asking for more from the stakeholders, pointed out such a study would be the time-consuming, 18-month analysis to which some were objecting.

“If we were to look at a carbon-constrained future, that would be a comprehensive, broad study,” Kelley said. “We could do the exact study we just did, except the [business-as-usual case] would be a carbon-constrained future instead.”

— Amanda Durish Cook contributed to this article.

March 14, 2016

PJM Market Implementation Committee Briefs

VALLEY FORGE, Pa. — Two proposals that would have delayed the disclosure of financial transmission rights ownership following an auction were defeated by the Market Implementation Committee on Wednesday.

Bruce Bleiweis of DC Energy offered a package that would have allowed PJM to post aggregate data after an auction, mask ownership data for three to six months and disclose ownership after one year. It garnered only 10% of a sector-weighted vote.

A PJM proposal would have aligned the release of data with how the RTO treats other information, disclosing full ownership after four months. It received only 21% in a sector-weighted vote. (See “Proposals Would Delay Posting of FTR Ownership,” PJM Market Implementation Committee Briefs.)

Bleiweis said his proposal was intended to provide FTR owners the same confidentiality as other market participants.

The rejections were not a surprise. Several members and Market Monitor Joe Bowring had expressed opposition when Bleiweis won MIC approval of a problem statement to explore the issue in September.

Day-ahead Submission Deadline Moved up

Members endorsed updates to PJM’s regional transmission and energy scheduling practices intended to improve the alignment of the gas and electric markets.

A five-minute “shotgun” start window was created for hourly spot-in reservations (spot market imports), and the day-ahead bid submission deadline was moved from noon to 10:30 a.m.

Operating Parameter Definitions Approved

The committee approved short-term operating parameter definitions and voted to amend a problem statement to set June 1, 2017, as the deadline for permanent clarifications of the terms.

The amendment was proposed by Bob O’Connell of Main Line Electricity Market Consultants and included some clarifications to the terms cold/warm/hot start-up time, minimum run time and cold/warm/hot soak time.

PJM’s definitions were approved by 82% of the members in a sector-weighted vote. O’Connell’s definitions were approved by 60% of the vote. Both proposals will advance to the Markets and Reliability Committee, although O’Connell’s definitions will not be considered if PJM’s definitions are approved.

Clarifications Sought for Bilateral Transactions

Members approved a problem statement and issue charge to clarify rules on how auction-specific bilateral transactions credit bonus payments and indemnification. (See “PJM Proposes Clarifications to Capacity Bilateral Transactions,” PJM Market Implementation Committee Briefs.)

In such transactions, a seller transfers capacity to a buyer, but the obligation for performance remains with the seller.

The problem statement seeks to clarify how nonperformance charges and bonus payments apply to such transactions, and how they would be treated in litigation such as bankruptcies.

– Suzanne Herel

March 14, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — PJM members last week approved manual and Tariff changes dictating the ramp rates Capacity Performance resources will have to meet to avoid penalties during performance assessment hours.

PJM said it found that many generators are able to increase their output faster than reflected in the ramp rates plant operators entered in Markets Gateway. The new rules will measure generators against the unit’s actual ramp performance between Jan. 1 and March 31, 2016 (or June 1 to Aug. 31, 2015, for units not dispatched in the first three months of this year).

Units would be excused from penalties if they are following PJM dispatch or had approved outages.

The approach is a short-term solution that PJM hopes to have in place before the delivery year starts June 1.

The Markets and Reliability and Members committees will be asked to endorse the changes on March 31, following a special OC session highlighting ramp rate examples on March 22.

PPL SPS to be Removed

A special protection scheme to prevent generator instability if the Susquehanna-Wescosville 500-kV line ever fell onto the Susquehanna-Harwood 230-kV lines is no longer needed with the addition of the Lackawanna-Hopatcong 500-kV line, according to PPL. The SPS — which would have resulted in tripping Susquehanna Unit 1 — will be removed during an outage of the nuclear unit and should be complete by April.

Dominion Zone SPS Retired

A special protection scheme installed in 2007 in the Dominion zone was retired last month. The SPS addressed potential thermal overloads on the Carolina-Kerr Dam 115-kV line. The scheme is no longer needed with the completion of Regional Transmission Expansion Plan project b1793 to rebuild Kerr Dam-Carolina line 22 and project b1793.1 to remove the Carolina 22 SPS.

– Suzanne Herel

March 14, 2016

PJM Transmission Expansion Advisory Committee Briefs

VALLEY FORGE, Pa. — PJM and Dominion Resources are conducting an end-of-life review to prioritize upgrades on the utility’s system, a project that could result in the creation of proposal windows.

Of the 106 facilities being studied, about half are at the 230-kV level, with most of the rest split between 115-kV and 500-kV lines. In total, the review is considering 2,350 miles of transmission.

PJM already has verified the need for upgrades to two 500-kV facilities: the 82-mile Mt. Storm-Valley line and the 23-mile Valley-Dooms span. The RTO said the loss of either facility could cause thermal and voltage problems.

Although some transmission owners have criteria for end-of-life facilities, others do not, treating them as supplemental projects.

The Markets and Reliability Committee agreed last month to form a task force to develop RTO-wide criteria for end-of-life transmission facilities. Proponents said uniform guidelines would help planners prioritize equipment replacement. Just two of 12 Transmission Owners voted in favor of the proposal. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)

According to industry guidelines, wood structures can last 35 to 55 years, conductors and connectors 40 to 60 years and porcelain insulators 50 years.

Planners Select Dominion-Transource Project to Address APSouth Congestion

PJM planners have selected a $292 million project by Dominion High Voltage Holdings and Transource Energy to reduce congestion in the APSouth interface.

Pending reliability and sensitivity analyses, PJM planners intend to recommend the market efficiency project to the Board of Managers in April.

It would tap the Conemaugh-Hunterstown 500-kV line and build a new 230-kV double circuit line between Rice and Ringgold. The plan also calls for building a new 230-kV double circuit line between Furnace Run and Conastone and rebuilding the Conastone-Northwest 230-kV line.

Planners added $10 million to the proposed $282 million cost, saying additional upgrades were required at the Ringgold transformers. The projected in-service date is 2020.

The project was selected from among a dozen projects culled from responses to a proposal window last year.

Planners said that the benefits of most competing projects were hurt by the need for optimal capacitors, and that several projects that passed the 1.25:1 benefit-cost test have minimal impacts on APSouth or increase congestion elsewhere in the RTO.

PJM said the Dominion/Transource proposal (project 9A) “consistently ranked highest in most categories,” with a 2.66 B/C ratio and $31 million savings in annual production costs.

In a WebEx session Thursday, planners expect to release the results of the reliability analysis on the project as well as the sensitivity analysis on several combination projects. They also will identify designated entities.

— Suzanne Herel

March 14, 2016

Commenters: DFAX Cost Allocation Inappropriate

By Suzanne Herel

PJM’s solution-based distribution factor cost allocation method is inappropriate in certain situations and an alternative scheme should be developed, the majority of commenters told FERC as the comment period on the issue closed last week (EL15-95).

FERC called for an inquiry in November in response to complaints over the cost allocation for two transmission projects: a stability fix for New Jersey’s Artificial Island nuclear complex and the Bergen-Linden Corridor upgrade.

Of 10 filings, only two, from Public Service Electric and Gas and the PJM Transmission Owners, defended the status quo, echoing their testimony at a Jan. 12 technical conference on the issue. (See DFAX: ‘Poison Pill’ or ‘Best Method’ of Cost Allocation?)

FERC posed two questions: Is there a definable category of projects for which the DFAX cost allocation method might not be appropriate, and could a fair approach be developed for those occasions?

“Cost causation is the gold standard for allocation of new transmission projects,” wrote Hudson Transmission Partners and Neptune Regional Transmission System.

“When an analytical methodology hits the boundaries of its usefulness (and every model has such bounds), it starts to kick out unreasonable results,” they said. “The solution-based DFAX cost allocations for the New Jersey projects and for Artificial Island are jarring in their unreasonableness.”

PSE&G disagreed, saying the evidence “does not provide any basis for identifying one or more categories of [Regional Transmission Expansion Plan] projects for which the current solution-based DFAX cost allocation methodology does not provide a just and reasonable methodology for allocating costs commensurate with benefits. To the contrary, the cost allocation for each of the projects at issue in the underlying dockets is supported by the existing record.”

The transmission owners’ group concurred.

“Solution-based DFAX provides a just and reasonable measure of benefits from relative use over time for the vast majority of reliability projects in PJM,” the TOs wrote.

The remaining commenters said that DFAX should not be used to assign cost for projects not driven by flow-based issues, such as the stability fix at Artificial Island.

“The commission should direct PJM to modify the DFAX methodology to include load zone counterflow impacts in determining load zone impacts on that studied facility, to consider whether a project’s need is driven by flow-based issues, and to eliminate discriminatory post-analysis exceptions including the de minimis threshold,” wrote ITC Mid-Atlantic.

Wrote Consolidated Edison: “The record here, as developed at the technical conference, establishes that there is no rational relationship between energy flows and the intended benefits of non-overload projects.”

The Delaware Public Service Commission, together with the Maryland Public Service Commission, Delaware Division of Public Advocate and the Maryland Office of People’s Counsel, asked FERC to determine that stability-driven projects constitute a definable category for which the DFAX method should not be used.

Similarly, Old Dominion Electric Cooperative asked FERC to direct PJM to use an alternative cost allocation method for projects designed to address generator stability problems.

Weighing in with similar concerns were Linden VFT, the New York Power Authority and the Easton Utilities Commission.

March 11, 2016

Exelon-Pepco Doubtful as DC Officials Reject Alternatives

By Suzanne Herel

The D.C. Office of the People’s Counsel and Mayor Muriel Bowser’s administration came out Friday against Exelon’s revised merger proposal in filings that appear to quash the energy giant’s chances of acquiring Pepco Holdings Inc.

Neither the alternative offered by Public Service Commissioner Joanne Doddy Fort nor the options filed March 7 by Exelon guarantee “the type of rate protection I have been seeking in this case for almost two years,” said People’s Counsel Sandra Mattavous-Frye.

“Most critical to me were the benefits for residential ratepayers, particularly low-income residents who struggle to pay their electric bills,” she said. “OPC worked hard to achieve the guarantee of no rate increases for residential ratepayers through March 2019. We urge the PSC to resolve this issue expeditiously to bring closure for D.C. residents.”

In the March 7 joint filing, Exelon and PHI offered three options: Accept the agreement brokered by Mayor Muriel Bowser’s administration, which the commission rejected 2-1 Feb. 26; adopt the revision of that agreement that Fort and Commissioner Willie Phillips proposed; or agree to a new alternative that would provide $20 million in rate relief taken from funds earmarked for smart grid and environmental programs. It asked the PSC to rule by April 7. (See Exelon, Pepco Urge Compromise Deal to Win DC PSC OK for Merger.)

In a short filing on behalf of the D.C. government, Attorney General Karl Racine said the only acceptable option would be to accept the settlement that the PSC already rejected.

“The district continues to support the [settlement] as proposed on Oct. 6, 2015, and believes that approval of the merger on those terms provides direct and tangible benefits to ratepayers, promotes sustainability and otherwise remains in the public interest,” he wrote.

In a joint statement, Exelon and Pepco said, “Practically every party that filed comments today continues to believe the merger is in the public interest and supports its approval. The comments show differing opinions on how a portion of the more than $78 million in funds that Exelon has committed to the district should be used if the merger is approved. We hope the Public Service Commission will find a solution that secures all of the benefits for the district and Pepco’s customers and urge it to consider the alternatives we have outlined to approve the merger.”

Four other settling parties in the case also filed comments. The National Consumer Law Center, National Housing Trust and National Housing Trust-Enterprise Preservation Corp. rejected the revised settlement proffered by the commission but urged consideration of Exelon’s third alternative.

“Should option three be rejected, the merger is likely to collapse,” they said. “From the perspective of NCLC/NHT, this is contrary to the public interest, and particularly contrary to the interests of low-income households in the district.”

The Apartment and Office Building Association of Metropolitan Washington filed its support of Fort’s revised version of the settlement “as reasonable and in the public interest.”

“The proposed [revised settlement] clarifies the responsibilities of Exelon and Pepco in a post-merger environment, permits all ratepayers to participate in the benefits of the merger, ensures that funds that are intended to benefit ratepayers and improve Pepco’s electric system in the District of Columbia are not diverted to other purposes, and retains the commission’s statutory authority to enforce the terms and conditions of the [agreement],” it said.

The D.C. Water and Sewer Authority was the only settling party that did not file comments with the PSC, but it publicly has come out against the commission’s revised deal. The comment period is open through Thursday.

Critics of the merger were pleased.

“Today’s filings are great news for D.C. residents and ratepayers,” said Anya Schoolman on behalf of the PowerDC coalition. “There is no viable path forward for Exelon’s attempt to take over Pepco. We agree with the Office of the People’s Counsel’s filing. D.C. is ready to move on.”

The merger began looking doubtful March 1, as Mattavous-Frye, Bowser and Racine said publicly they couldn’t support the commission’s alternative. (See Exelon-Pepco Deal in Doubt as Mayor, Consumer Advocate Balk at New Terms.)

All took issue with the PSC’s requirement that $25.6 million earmarked for residential rate relief be held in escrow until the next Pepco rate case and then be considered for disbursement, including to nonresidential customers.

The PSC said it would approve the merger under its revised settlement with no further commission action if all settling parties agreed to it within 14 days. (See DC PSC: Will OK Exelon-Pepco Deal for Additional Concessions.)

Exelon has spent an estimated $259 million over the past two years trying to capture Pepco’s $7 billion rate base.

CEO Chris Crane said in a Feb. 3 earnings call that the company was prepared to immediately begin buying back the 57.5 million shares it issued for the $6.8 billion deal if the merger fell through.

Friday’s news further weakened Pepco’s stock, which closed Monday at $22.22, down 8% from Friday’s open and down 16% from the open on Feb. 26, before the PSC rejected the mayor’s settlement. Exelon’s share closed Monday at $34.63, down almost 1% from the Friday open but up almost 9% since Feb. 26.

March 8, 2016

FERC Rejects PJM’s Method for Capacity Offer Caps

By Suzanne Herel

FERC ordered PJM last week to change its method of calculating capacity market offer caps, saying it was inconsistent with its practice in the energy market.

“We find that PJM’s Tariff is unjust and unreasonable because it allows the cost-based energy offer cap to be used as the sole measure of short-run marginal cost in calculating capacity market offer caps,” it said (EL14-94).

Harrison Power Station (first-energy) — Harrison Power Station *Source: FirstEnergy*

“In the energy market, when a generation resource fails the three pivotal supplier test and submits a non-zero market-based offer less than its cost-based offer cap, PJM uses the lower, market-based offer, not the cost-based offer, as the basis for determining the resource’s commitment and dispatch,” FERC said. “When a resource is not subject to market power mitigation, PJM uses its offer as the basis for the resource’s commitment and dispatch. In both cases, PJM’s energy market relies on the offer, not the cap, as reflecting the resource’s short-run marginal cost.”

The ruling stemmed from a 2014 petition by FirstEnergy, which said PJM’s Independent Market Monitor was violating the Tariff by calculating marginal cost using the lower of the market-based offer and the cost-based offer.

But the commission ruled that the Monitor’s interpretation was appropriate and that the Tariff, which dictated use of cost-based offers only, was improper.

Joining FirstEnergy in support of the petition were PJM, Duke Energy, the PJM Power Providers Group and the Electric Power Supply Association. Opposing the petition were the Organization of PJM States, the Public Utilities Commission of Ohio, PJM Consumer Representatives, the Office of the Ohio Consumers’ Counsel and the Monitor.

FirstEnergy contended that cost-based offers are an accurate, transparent method for estimating marginal cost, and that market-based offers reflect factors other than marginal cost.

But the Monitor said using only cost-based offers could lead to the exercise of market power. For example, units that can use multiple fuels could base their higher, cost-based offers on their secondary fuel and their lower market-based offers on the primary fuel, the Monitor said.

The commission ordered PJM to submit a compliance filing specifying a new procedure using a resource’s non-zero market-based offer as proxy for marginal costs in most cases.

The cost-based offer would be used when the resource is mitigated and its market-based offer is above the cost-based offer cap, “as the market-based offer in this circumstance may reflect the exercise of market power,” FERC said.

The cost-based offer also would be used when the market-based offer is less than its fuel and environmental costs, “since the generator is losing money for each megawatt produced, a reasonable projection of its energy and ancillary services revenue should reflect such a reduction.”

March 8, 2016

MISO Market Subcommittee Briefs

A year after rolling out its extended LMP methodology, MISO plans to move into a second phase as it considers expanding online fast-start pricing to more peaking resources and investigating offline fast-start pricing.

MISO said it is considering using a 30-minute window instead of 10 minutes to summon fast-start resources. The change, according to MISO, could increase from 90 units contributing about 4,000 MW to 214 units contributing about 9,000 MW during summer peak capacity.

“Our intention is certainly not to raise prices, but to reflect the true price,” said Jeff Bladen, executive director of market services, told the Market Subcommittee last week. He said if unnecessary costs were hiding in the revenue sufficiency guarantee, including more resources would bring more transparency to ELMP.

“Phase II is meant to capture broader benefits,” MISO Market Design Engineer Congcong Wang said. “By expanding from 10 minutes to 30 minutes with fast-start resources, we would have the capacity almost doubled in terms of megawatts and units.”

Wang said studies on moving the fast-start window would be completed by August. MISO is targeting a FERC filing and new software testing for the first quarter of 2017.

Some stakeholders said it wasn’t reasonable to think fast-start resources would be able to commit to a five-minute interval and were afraid it would depress revenue sufficiency guarantee amounts. Others expressed concern that MISO would remain silent until August.

“This is not a proposal; it’s an investigation at this point. The purpose today is to let you know … we’re scoping out the project. We’re taking a lot of notes on what we’re hearing,” said Dhiman Chatterjee, MISO’s senior manager of market evaluation and design.

Chatterjee said MISO would provide stakeholders updates throughout the study process. He asked stakeholders to submit written questions and comments by March 15.

During the first six months of ELMP operations since last March, MISO said only about 40 units were enabled to set prices. MISO’s Independent Market Monitor said the number represented only about 1% of online peaking resources that were eligible to set prices.

MISO defines fast-start resources, which participate in price-setting, as those that can start within 10 minutes of notification and have a minimum run time of an hour or less.

So far, MISO said ELMP has resulted in “modest” benefits. Using ELMP has decreased uplift charges by 1%, a projected annual savings of more than $165,000. The RTO also said that the deviation between day-ahead and real-time prices was reduced by 2.25%.

More Info Sought from Load-Modifying Resources

Hoping to boost pricing accuracy during shortages, MISO will begin requiring market participants to identify the reductions each of their load-modifying resources will provide in an LMR event. The RTO is adding an additional form to its communications system to capture the data.

The other stages of MISO’s LMR reporting will be unaffected. Market participants will still use the system to report their daily LMR availability, with the RTO responding with scheduling instructions.

No date has been set for the change, but MISO hopes to have the additional reporting page active prior to the summer.

Jeff Knight of Entergy asked if participants could make changes on the form to select a different LMR to curtail without incurring additional charges. MISO Business Analyst Danielle Logsdon said market participants could make changes up to the hour before deployment.

“Just as baseball professionals are immersed in spring training for the upcoming season, this is preparation for emergency pricing implementation this summer, if it’s needed,” said Michael Robinson, MISO’s principal adviser of market design. “This is an effort to better set prices when we’re in these shortage conditions.”

Logsdon said MISO’s 2016 summer readiness training will be held April 14-May 19.

MISO Backs Make-Whole Fuel Payments

MISO has proposed reimbursing system support resources for unburned fuel when real-time schedules diverge from day-ahead schedules.

The RTO is also proposing that generation owners identify their fixed costs in filings with FERC. Currently, SSR units have to file directly with FERC only when MISO, the Monitor and the generation owner cannot negotiate a compensation agreement. MISO said having generation owners deal directly with FERC could reduce delays in implementing SSR agreements.

MISO said it “does not have independent information to evaluate SSR costs and relies on the generator owner for information on fixed cost compensation for the filing.”

Robinson said MISO would accept written comments until March 15. He said it is eyeing filing rule changes by the end of March.

Most Second-Tier Commercial Pricing Nodes Being Eliminated

MISO will terminate 28 second-tier commercial pricing nodes effective June 1. The changes will take effect with the 2016/17 financial transmission rights auction and the annual allocation process for auction revenue rights.

The RTO said it is jettisoning most of its second-tier interface commercial pricing nodes to “reduce administrative burden and be consistent with external balancing authority boundaries.”

“We reviewed these commercial pricing nodes and determined there is no business need for them,” said Zhaoxia Xie, MISO’s manager of modeling and market engineering.

MISO is evaluating the usefulness of six additional second-tier pricing nodes.

First-tier pricing nodes are associated with balancing authorities that are directly interconnected with MISO while second-tier nodes are not.

Illinois and Michigan Hub Definitions Changing

MISO is changing its Illinois and Michigan hub definitions as a result of the March 2016 model update, but the new descriptions are not expected to affect pricing substantially.

The Illinois and Michigan hubs will continue to have 151 and 265 elemental pricing nodes (EPNode), respectively. For both hubs, one EPNode was removed and replaced as a result of a substation closure.

For Illinois, the updated definition will reduce LMPs by less than a penny, according to MISO’s analysis, with average real-time prices expected to decrease from $25.13/MWh to about $25.12/MWh. In Michigan, the switch is projected to also amount to a penny reduction in day-ahead LMPs, from $25.91/MWh to $25.90/MWh.

Prices for MISO’s seven hubs are computed as the weighted average of the LMPs of the EPNodes comprising them.

Staff Considers Reusing Market Roadmap Information

MISO is considering reusing certain data in its Market Roadmap process to improve efficiency. The question of “prioritizing only new projects without reassessing existing projects” marked the beginning of the annual process at the MSC.

“What we’re looking for today is based on feedback we got at the tail-end of last year’s process. There were questions about the necessity of doing a full refresh of the Market Roadmap every year, where every item on the roadmap is looked at as it if were new or if we should only look at a subset of items,” Bladen said. For instance, Bladen said MISO’s roadmap could focus heavily on forward-looking projects beyond 2017 while using existing information for other projects.

MISO’s Mia Adams said the RTO was looking for feedback on the proposal by the end of the month.

— Amanda Durish Cook

March 8, 2016

MISO: Energy Storage Could Work into Existing Market Structure Next Year

By Amanda Durish Cook

MISO could have a limited set of market rules for energy storage as early as 2017, RTO officials told the Market Subcommittee last week.

AES energy storage array — AES’ 20-MW energy storage array in Indianapolis, expected to go into operation in June, will be the first utility-level battery energy storage facility in MISO. *Source: AES Energy Storage*

MISO External Affairs Policy Advisor Jennifer Richardson said storage provisions could be a “combination of using established definitions” and creating new market rules.

In the near term, MISO said it will work with stakeholders on minor revisions to the Tariff and business practice manuals that would open the market to short-term and medium-term storage. By summer, MISO hopes to have a clear idea if storage should be treated as a generation resource or a transmission asset and whether it can participate in MISO’s capacity or ancillary service markets. For that, MISO needs to consider how behind-the-meter storage can function as load-modifying resources or demand response.

AES Project Nears Completion

The storage conversation comes as AES’ Indianapolis Power & Light edges closer to finishing the 20-MW Advancion Energy Storage Array in Indianapolis. The project, slated to be put into operation sometime in June, will be the first utility-level battery energy storage facility in the footprint.

Stakeholders have submitted a first round of comments on the issue in response to MISO’s call for input in January. (See MISO Preparing a Place for Energy Storage in Tariff.)

“A lot of stakeholder comments focused on developing new software,” said Yonghong Chen, MISO’s principal advisor of market development and analysis, during a presentation to the subcommittee. “In the next few months, probably from April to July, we’re going to work with stakeholders to determine what we can do [with existing software]. By next year, we hope to have implementation rules on how storage can participate with our current market software and market rules. … We have some existing language in the Tariff and BPMs that could apply, but some language needs clarification to apply to storage.”

From mid-2017 onward, MISO plans to tackle how storage will fit into five-minute settlement schedules, voltage and local reliability commitments, minimum megawatt participation limits and automatic generation control enhancement, software that deploys fast ramping resources more quickly.

“We want to remain as technology-neutral as possible, but FERC may have to step in at some point,” Richardson said.

AES energy storage — AES’ 20-MW storage facility will have the flexibility of a 40-MW resources. *Source: AES Energy Storage*

Long-Term Plans

MISO said its longer-term storage considerations would run into 2019 and include make-whole payments, cost allocation and impacts to the annual Transmission Expansion Plan.

“We need more time to figure out how to make these work well together,” Chen said.

Jeff Bladen, MISO’s executive director of market design, said storage should work “holistically” with MISO’s market.

“This is very much a topic on stakeholders’ minds, as they’re thinking of developing projects and bringing them to market,” he said. “We have to be careful not to put energy storage into its own silo. It needs to fit into the larger Market Roadmap.”

Stakeholder Comments

Ameren told MISO that it believes energy storage could be categorized as “generation, transmission or other, depending upon its characteristics.” The company proposed that MISO classify storage as a use-limited resource, then perform an “initial asset evaluation” to determine if it should be treated as a generator or transmission asset. Use-limited resources are those “unable to operate continuously on a daily basis, but … able to operate for a minimum set of consecutive operating hours.”

Madison Gas and Electric said storage could fit into a generation or transmission definition. The company went a step further, suggesting that MISO remove prescriptive resource definitions from the Tariff altogether. “To be agnostic or ‘neutral’ when it comes to technology, then we need to be neutral as to what type of resource provides services. The Tariff lists the products and services permitted by each resource type. To become neutral, we should remove prescriptive/descriptive limitations and allow resources to provide any product or service for which it can satisfactorily deliver. We can test and measure performance of resources, eliminating the need to limit products/services by resource type,” Madison’s Megan Wisersky wrote MISO.

ITC Holdings advocated leaving storage unclassified, saying it was “premature” to categorize the technology when it hadn’t yet been integrated into the grid.

Amber Motley, manager of market operations for Xcel Energy, said market participants should be given the option of choosing to categorize storage as either generation or transmission, a position supported by MidAmerican Energy.

Chen said work on energy storage rules would play out in MISO’s Planning Subcommittee and Resource Adequacy Subcommittee, as well as other committees, if needed.

“We’re very mindful that stakeholders don’t want to chase these issues in a hundred different committees. Believe me, we don’t want that either. We’ll try our best to iron out those hard questions internally before we bring them to stakeholders,” Richardson said.

Chen asked for another round of stakeholder input before March 18.