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.
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.
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.
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.
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.
Sandra Mattavous-Frye
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.
Anya Schoolman
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.”
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.
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.
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 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.”
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.
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’ 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.
“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’ 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.
Public Citizen last week called for a House and Senate investigation into the Commercial Energy Working Group, an industry association the watchdog says appears to be violating federal lobbying rules by not disclosing its membership.
The energy group operates out of the offices of D.C. law firm Sutherland, Asbill & Brennan, which has represented it in filings with FERC, the Commodity Futures Trading Commission, the Securities and Exchange Commission, the Federal Reserve and Congress.
In the second quarter of 2015, the firm reported to Congress $60,000 in lobbying income for the group, but the filing did not list the sources of that income despite a requirement that lobbyists disclose contributions of $5,000 or more, Public Citizen says. Based on records obtained through the Freedom of Information Act, Public Citizen said the group’s members appear to include Vitol, Royal Dutch Shell, NextEra Energy, ConocoPhillips and Hess Corp.
NRC Engineers Urge Fix for Flaw in Most US Reactors
Lochbaum
A group of Nuclear Regulatory Commission engineers is urging the agency to order U.S. nuclear plant operators to fix a problem that lurks in nearly all reactors.
In February, the seven engineers petitioned the agency to order immediate action to address a flaw that puts the reactors at risk of so-called “open phase events” where unbalanced voltage could cause motors to burn out and deactivate emergency cooling systems. Such an event happened at Exelon’s Byron 2 reactor in 2012, shutting down the unit for a week.
Although NRC alerted operators of that event, the agency didn’t require any action. Dave Lochbaum, a nuclear expert and frequent industry critic, said NRC has known about the issue and didn’t push for action. “Why the NRC snatched defeat from the jaws of victory, I don’t know,” he said. By NRC’s own procedure, the agency has until March 21 to respond to the engineers’ request.
The environmental group Delaware Riverkeeper Network is suing FERC, charging that the agency’s oversight process for pipeline projects is “infected with bias” and demanding substantial changes to how the commission works.
The suit alleges that FERC is essentially financed by the industries it oversees through charges and fees. “Because FERC gets its funding from the big companies it is supposed to be monitoring, it has become, perhaps inevitably, a corrupt, rogue agency,” says Maya van Rossum, leader of the Delaware Riverkeeper Network. “That’s why FERC has approved 100% of pipeline projects — literally every single one of them — that it has considered since 1986.”
The suit, filed in U.S. District Court., seeks a declaration that FERC’s approval process is biased and that its funding structure is unconstitutional. The commission said it does not comment on pending lawsuits.
Chief Justice John Roberts on Thursday rejected a request from 20 states to block the enforcement of EPA’s Mecury and Air Toxics Standards.
Michigan and 19 other states asked for a stay or an injunction blocking enforcement of the MATS rule, noting that the court itself last year ruled 5-4 that the rule is illegal.
But EPA said a stay was not necessary as the agency was addressing the parts of the rule the court found invalid. “The requested stay would harm the public interest by undermining reliance interests and the public health and environmental benefits associated with the rule,” the agency said. “The application lacks merit and should be denied.”
Roberts acted unilaterally, without taking the question to the whole court.
The fledgling U.S. energy storage market deployed 112 MW of capacity in the fourth quarter of 2015, more than in 2013 and 2014 combined. According to GTM Research and the Energy Storage Association’s U.S. Energy Storage Monitor 2015 Year in Review, 161 MW were added in 2015, bringing the U.S. total to 221 MW.
The report, broken down into residential, nonresidential and utility segments, notes the last segment continues to be the largest, accounting for about 85% of all new storage. Most of that was deployed in PJM, which saw 160 MW of new storage introduced.
But residential behind-the-meter systems grew at the fastest pace, showing an increase of 405% in 2015.
The Nuclear Regulatory Commission has put Entergy on notice for three apparent violations relating to a leaking storage tank discovered at its Palisades nuclear generating station in Michigan in 2013. The agency sent the company a letter alleging that Palisades deliberately failed to properly document the leak at a safety injection and refueling water storage tank during the event.
Entergy was cited for “willful failure” to document the leak, as well as failure to “perform adequate operability determinations” after the leak and to undertake additional testing of the leak site.
The company said the conditions have been corrected since the incident. “Entergy does not tolerate deliberately failing to follow procedures or falsifying or manipulating data in any way,” the company said.
Feds Move to Drop McClendon Indictment After Fatal Crash
McClendon
Authorities are taking steps to drop the indictment against former Chesapeake Energy CEO Aubrey McClendon, who died hours after the indictment was handed up last week. McClendon was under investigation for alleged bid rigging relating to natural gas leases.
A federal grand jury handed up the indictment Tuesday. McClendon died in Oklahoma City last week when his SUV crashed at high speed into a bridge abutment. That accident remains under investigation.
FERC attended to some housekeeping Friday by putting to rest a rehearing request rendered moot by MISO and SPP’s settlement of their transmission dispute.
SPP-MISO 1,000 MW contractual tie Source: SPP
The commission dismissed MISO’s rehearing request of its December 2014 order approving the RTO’s use of a “hurdle rate” to manage its north-south flows (ER14-2445-002). The commission also dismissed a related compliance filing.
MISO, its Market Monitor and several regulatory agencies and utilities had sought rehearing, arguing that FERC’s order would cause the $9.57/MWh hurdle rate to climb by 4.5 times, rendering MISO’s North-South interface transfers of more than 1,000 MW uneconomical.
“Because the hurdle rate is no longer effective, and in the [December 2014] order, the commission exercised its discretion to not order refunds … there is no need to address the” matters raised by MISO and others, the commission said.
Under the settlement, MISO will pay SPP $1.33 million monthly until February 2017 to cover flows over 1,000 MW passing through MISO’s North-South interface. MISO is temporarily collecting the funds from members through a miscellaneous charge based on market load ratio share while the RTO and stakeholders continue settlement discussions to decide on a long-term cost allocation (ER14-1736).
FERC last week approved a request by CAISO to eliminate from its Tariff a long-suspended provision establishing convergence bidding at scheduling points on the interties into California.
The commission’s order eliminated the prospect that CAISO would reinstate a market mechanism it revoked within months of implementing it in 2011 (ER15-1451-001). At the time, the ISO’s Market Monitor determined that bidding strategies at the interties underpinned a complex scheme to manipulate prices and inflate payouts in other areas of the California market.
CAISO has in recent years explored reviving the mechanism in light of structural changes in Western markets, but it ultimately sought a full repeal based on concerns that illiquidity in 15-minute trading left intertie points vulnerable to gaming.
FERC’s ruling did not affect convergence bidding at points inside the ISO balancing area. At the request of municipal utilities in Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, FERC also directed CAISO to delete from its Tariff an additional reference to virtual bidding in order to avoid ambiguity.
Convergence — or virtual — bidding allows market participants to hedge their physical positions and limit exposure to day-ahead and real-time price differentials. A convergence bid is a purely financial bid implying no obligation to take or deliver electricity. Instead, a market participant buys or sells “virtual” energy in the day-ahead market, a position required to be automatically liquidated in the opposite direction in real time.
Depending on the relative movements in the two markets, the participant either pockets or pays the difference between the two prices. Bidders are not required to control physical resources or serve loads in the ISO, allowing speculators to take positions in the market.
RTOs have adopted convergence bidding under the theory that the practice narrows the gap between day-ahead and real-time prices as traders arbitrage spreads between the two markets. The benefit is a more predictable spot market, protecting utilities from price swings stemming from load fluctuations and unplanned generating outages.
Troubled from the Start
In California, convergence bidding was fraught with problems since CAISO introduced the practice two years after restoring its day-ahead market. A week after implementing the market in February 2011, CAISO suspended bidding at nodes on nine interties linked to the Mountain States region because of a software glitch that risked overscheduling those points in the physical day-ahead market.
That incident was followed months later by the more serious discovery that some CAISO market participants were using virtual supply bids on the interties to offset virtual demand bids at nodes located just inside the state, a gaming strategy that produced no benefit for the physical market and cost the ISO more than $50 million.
(Virtual trades at CAISO’s New Melones intertie are at the center of market manipulation allegations filed by FERC in December. The defendant last week asked FERC to compel CAISO to disclose information about market design flaws (IN16-2). See earlier story, FERC Seeks $2.5M Fine in CAISO Market Manipulation.)
The strategy was facilitated by predictable differences in prices stemming from what the ISO referred to as a “bifurcated” settlement process, with the interties settled at the hour-ahead price and internal points in real time. Shortly after identifying the issue, CAISO suspended bidding at the interties indefinitely — or at least until it could resolve the bifurcation issue.
Liquidity Concerns
That goal would ultimately elude CAISO. While FERC Order 764 — which mandated 15-minute scheduling between neighboring balancing areas — should have helped, the ISO became concerned about declining short-term trading volumes at the interties, which could reintroduce opportunities for strategic bidding. A 2015 report from the ISO’s Market Monitor indicated that “most of the dozens of CAISO interties have no market participants providing economic bids in the 15-minute market and only a few interties have multiple market participants providing such bids.”
CAISO hoped Bonneville Power Administration’s implementation of 15-minute scheduling — synching it with CAISO’s schedule — would boost exports from the Pacific Northwest. But the change had little impact on trading activity.
“The CAISO does not yet understand the causes of this low market liquidity,” the grid operator wrote in an April 2015 filing asking FERC to extend the suspension of convergence bidding on the interties. “Based on informal feedback from market participants, the CAISO believes that some of the possible causes may be neighboring balancing areas not supporting 15-minute schedule changes, difficulty in procuring transmission in 15-minute blocks, an absence of bilateral trading at a 15-minute granularity and reticence of resource owners to adjust their output within the hour.”
According to a report by CAISO’s Department of Market Monitoring (DMM), low 15-minute liquidity could translate into a situation in which convergence bids would first settle at a day-ahead market price that includes intertie congestion, then be liquidated at a 15-minute market price not subject to congestion because of light physical volumes. That would give bidders incentive to profit from the structural differences between congestion prices in the day-ahead market and the 15-minute market.
“Regardless of the causes,” CAISO wrote in its April 2015 filing, “based on DMM’s recent analysis, the CAISO has determined that the existence of such low market liquidity, as evidenced by the lack of economic bids submitted in the 15-minute market, makes it problematic to reinstate intertie virtual bidding.”
Public Citizen last week called for a House and Senate investigation into the Commercial Energy Working Group, an industry association the watchdog says appears to be violating federal lobbying rules by not disclosing its membership.
