RENSSELAER, N.Y. — NYISO’s Market Monitoring Unit is recommending changes to the capacity market and planning processes in import-constrained zones as a result of a New York generating plant’s successful offers into the last two ISO-NE Forward Capacity Auctions.
Pallas LeeVanSchaick of Potomac Economics outlined the recommendations in a presentation on the monitor’s 2015 State of the Market Report to the NYISO Management Committee meeting on Wednesday.
The changes would better account for capacity that is exported to neighboring control areas from import-constrained capacity zones, he said. “This is new this year and we see it as high priority.”
The Roseton 1 generator, a 1,242-MW dual-fuel generator in Newburgh, N.Y., sold 511 MW of capacity in ISO-NE’s FCA 9 for the 2018/19 commitment period and 532 MW in FCA 10 for 2019/2020. The plant will have simultaneous capacity obligations in New York and New England. Roseton 1 is in Zone G in the Lower Hudson Valley, which has been designated as import-constrained.
Potomac said rules were needed to prevent inefficient capacity prices and anticompetitive outcomes.
“If such rules are not devised soon, clearing prices will be set above competitive levels in the Lower Hudson Valley. Therefore, we recommend rules to account for these transactions that would ensure efficient pricing in NYISO’s capacity zones,” according to the report.
The monitor said planning for this now would reduce uncertainty regarding future prices and reliability.
“This would avoid the scenario where prices would be inflated in June 2018 by $40/kW-year” in zones G-J, (Lower Hudson Valley and New York City), LeeVanSchaick said.
Potomac said underlying principles of the adjustments should be that the capacity clearing price is equal to the value of the additional megawatts in the area and that the capacity payment is equal to the reliability value to NYISO.
It proposed:
Accounting for the reliability benefits provided by a Southeast New York resource that exports to another control area when clearing zones G-J;
Compensating exporters based on local/rest-of-state price differentials; and
Adjusting planning assumptions to recognize these benefits.
ISO Seeking Feedback on Potomac
Separately, NYISO will collect comments on Potomac’s performance until July 15 in its annual solicitation of market participant input.
The House of Representatives voted 241-178 to pass an amended version of the Senate’s Energy Policy Modernization Act of 2016, tacking on drought relief aid for California, among other provisions. The passage means the House can now enter a conference with the Senate to reconcile the two versions.
Upton
“This has been a multiyear, multi-Congress effort, and a lot of work has gone into making sure that the bill we put forward to support the future of American energy is truly comprehensive,” Rep. Fred Upton (R-Mich.) said.
The House’s version would make it more difficult for the federal government to use endangered fish species protections to increase the flow of water from California’s dams into the sea. Republicans say this practice wastes precious fresh water for humans in the drought-plagued state, while Democrats say the provision would damage fisheries.
The Obama administration has put forward new rules that would mandate federal contractors disclose their greenhouse gas emissions.
The White House’s Federal Acquisition Regulation Council filed the proposals in the Federal Register requiring contractors to say if they disclose emissions numbers, if they have reduction goals and what effect climate change will have on business operations.
“We’ll be able to better assess supplier greenhouse gas management practices, manage direct and indirect greenhouse gas emission, address climate risk in the federal government’s supply chain and engage with contractors to reduce supply chain emissions,” White House officials said.
Donald Trump, the presumptive Republican presidential nominee, vowed to end President Obama’s Climate Action Plan, of which the Clean Power Plan is the centerpiece, within his first 100 days in office if he’s elected.
“Any regulation that’s outdated, unnecessary, bad for workers or contrary to the national interest will be scrapped and scrapped completely,” he said. “Any future regulation will go through a simple test: Is this regulation good for the American worker? If it doesn’t pass this test, this rule will not be under any circumstances be approved.”
Trump also said he would kill EPA’s Waters of the United States rule, “cancel” the Paris Agreement and ask TransCanada to apply again for the Keystone XL Pipeline.
An Energy Department official said the U.S. should continue funding an international attempt to develop fusion technology, despite the project’s overruns and delays.
Franklin Orr, undersecretary for science and energy, says the U.S. government should increase its support for ITER, a magnetic fusion device being built in France and initiated by President Ronald Reagan in 1985. The department says the U.S. contribution needs to be $230 million in 2018, or $105 million more than it has budgeted.
If successful, ITER would be the first device to maintain fusion for long periods of time and develop more energy than it consumes. Thirty-five nations are now contributing to the project, whose price has escalated dramatically over decades of development.
NRC Sets Sliding Fee Scale For Small Modular Reactors
The Nuclear Regulatory Commission finalized rules that set a sliding fee scale for small modular reactors, aimed at encouraging development of the technology.
The annual fee for light water SMRs will be set according to how much heat they generate, according to the commission. The rules set a minimum fee, a variable fee and a maximum fee.
The commission said applying the same fee to smaller reactors that is applied to large reactors would be unfair, as smaller reactor designs pose a “lower regulatory oversight burden.”
The Nuclear Regulatory Commission has approved the transfer of the license of the shuttered La Crosse Nuclear Plant in Genoa, Wis., to La Crosse Solutions, a subsidiary of radioactive waste disposal specialist Energy Solutions.
Dairyland Power Cooperative retired the plant in 1987 and filed with the commission last year to transfer the decommissioning and fuel storage license to La Crosse Solutions, which will lease the above-ground structures and assume decommissioning responsibility.
Energy Solutions has a similar arrangement with Exelon’s retired Zion nuclear plant in Illinois.
Environmental Groups Call for End to FERC Pipeline Review
New Jersey opponents to the $1.2 billion PennEast natural gas pipeline project urged FERC to halt its review, contending the developers have failed to provide required information on the project.
The organizers of the 118-mile project, which would deliver 1 Bcf/d from the Marcellus Shale region in northeastern Pennsylvania primarily to New Jersey utilities, say they have provided all necessary information. “As PennEast moves through the FERC process, PennEast will continue to provide application information to FERC,” a company spokeswoman said.
The project has aroused organized opposition, especially in New Jersey, where opponents say 70% of the property owners along the proposed path refused to allow PennEast to survey their land, and municipalities have passed resolutions opposing it.
FERC last week fined Coaltrain Energy and its owners $37.5 million for fraudulent up-to-congestion trades in PJM.
It also demanded the company disgorge $4.1 million in unjust profits. (See Traders Deny FERC Charges; Seek Independent Review.)
Coaltrain attorney Ken Irvin, of Sidley Austin, said the order “reflects the flawed process FERC uses and reiterates the need for our judicial system to impose the rigors due process provides. With ample transparency and cooperation on our part, we have shown compliance with the market rules and regulations. Our confidence remains that we have proven our case before FERC and will prove it in court too.”
After allegations of management interference led PJM to replace its internal market monitoring unit with an independent monitor in 2008, FERC had an opportunity to prohibit other RTOs from using the internal structure. Because it chose not to do so, the temptation for RTO officials to muzzle their MMUs still exists.
First in a Series
By Rich Heidorn Jr.
The independence concerns raised by former SPP market monitors John Hyatt and Catherine Mooney resulted in part from FERC’s compromises in Order 719, its 2008 rule spelling out market monitoring units’ duties and their relationships with their RTOs (RM07-19, AD07-7). (See related story, SPP Squelching MMU Independence, Former Monitors Say.)
FERC said the rules, which updated a 2005 policy statement, were needed to “improve the performance and transparency of organized RTO and ISO markets.” They prohibited RTO management from supervising their MMUs, and required, in most instances, that MMUs report directly to their RTOs’ board of directors.
But the commission rejected protections urged by some stakeholders — allowing RTOs to choose their structures and declining to provide job security protections for MMU employees.
RTO Choice on Structure
The commission allowed each RTO to decide through its stakeholder process whether it will have an external or internal MMU, or a hybrid structure using both. FERC also declined to remove MMUs from any oversight by the RTOs.
The commission ruled that the RTO boards would supervise market monitoring functions and that RTO management representatives on the board “be excluded from this oversight function.” However, it permitted MMUs to report to management “for administrative purposes, such as pension management, payroll and the like.”
“Removing the MMU from reporting to management will give it the separation needed to foster independence,” the commission said, promising to revisit the decision “if occasion demands.” However, it declined to conduct periodic reviews, as requested by the Federal Trade Commission.
Both internal and external monitors can face conflicts of interest, the commission noted. As the market operator, the RTO is one of the players a monitor is expected to critique. So are market participants, who are essentially the RTO’s constituents, with the ability to leave or switch RTOs.
Inherent Tension
Order 719 acknowledged this, citing the “inherent tension between [market] mitigation and the RTO or ISO goal of promoting new markets.”
An external monitor that is too critical could find itself unemployed when it comes time to renew its contract. In 2013, some PJM board members considered seeking a new monitor before state regulators pressured them to renew the RTO’s contract with Monitoring Analytics.
An internal MMU, on the other hand, can face peer pressure and management interference.
The commission also rejected a proposal by the American Public Power Association, Exelon and the Pennsylvania Public Utility Commission that it use the settlement that created PJM’s independent monitoring structure as a “best practice.”
“The provisions of that agreement were specific to one RTO and represented a negotiated balancing of interests,” the commission said. “It would be inappropriate to impose the specifics of that settlement on all other RTOs and ISOs.”
Core Duties
The Transmission Access Policy Study Group, an association of transmission-dependent electric utilities in 35 states, recommended that the “core” MMU duties — reviewing market performance, identifying ineffective market rules and making confidential referrals to the commission — be assigned exclusively to the external monitor in hybrid structures.
FERC disagreed.
“This solution might impose upon the RTO or ISO an MMU structure that it does not want,” the commission said, insisting its requirement that the monitors performing the core functions report to the board was sufficient. “This solution allows the RTO or ISO to structure its MMU function in the way it deems most suitable, while also ensuring that the market monitor that performs the core MMU functions enjoys the independence from management that reporting to the board accomplishes.”
It also rejected the Public Utility Commission of Ohio’s proposal that monitors report to a federal-state board independent of both the management and boards of RTOs. “Not only does an arrangement of this type raise jurisdictional concerns, it is difficult to see how such a potentially cumbersome structure could oversee MMUs in a timely and responsive manner. … Should the reforms we adopt in this final rule fail to achieve the needed independence we envision for MMUs, we will not hesitate to rectify the situation.”
Employee Protections
Some commenters proposed that major changes in MMU status, such as termination of employment, be subject to FERC review, a requirement included in the contracts that PJM, MISO, ISO-NE and SPP (which then had a hybrid structure) signed with outside monitors. The commission, however, said it did not want to impose “a ‘one size fits all’ requirement on the remaining RTOs or ISOs absent their consent.”
“Should the situation arise in which an RTO or ISO terminates its MMU in such a way as to violate its tariff requirements concerning MMU independence, the commission will address such a violation on a case-by-case basis,” it said.
Order 719 in Summary
Below is a summary of Order 719’s requirements. Except in direct quotations, this article will use “RTOs” or “grid operators” to refer to RTOs and ISOs.
Functions
The commission limited MMU functions to three: evaluating the effectiveness of market rules, tariff provisions and market design elements (and proposing changes where needed); reporting on market performance; and referring suspected wrongdoing to the commission.
It also broadened the monitors’ reporting duties — requiring them to refer to the commission any misconduct by the grid operators as well as by market participants — and expanded their referral obligations to include market design flaws in addition to tariff and rule violations.
RTO Review of MMU Reports
FERC said RTOs may require their MMUs to submit reports in draft form for RTO review and comment but could not alter the reports “or dictate the MMU’s conclusions.”
“RTOs or ISOs need not require submission of draft reports, but if they do, input from knowledgeable employees may serve to strengthen the end product or catch errors of fact or reasoning,” the commission said. “In any event, the MMU is free to disregard any suggestions with which it disagrees.”
APPA opposed giving RTOs advance review of MMU reports, saying FERC should impose the same prohibition against such review as was included in the PJM-MMU settlement. The settlement resulted from Monitor Joe Bowring’s complaint at a FERC technical conference in 2007 that PJM ordered him — then a PJM employee — to modify the State of the Market Report and delayed the release of another MMU report because management disagreed with his conclusions.
Market Mitigation Role
The market mitigation role of external MMUs was limited to retrospective mitigation and the calculation of inputs required for the RTOs to conduct prospective mitigation. The separation was made because of concerns that an MMU would have a conflict of interest in proposing prospective market mitigation and then opining on how the resulting market rules worked. It also separated the duties of internal and external MMUs for RTOs with hybrid structures.
In its Notice of Proposed Rulemaking, FERC proposed that MMUs be removed from tariff administration, including market mitigation, “to free MMUs from a role that might make them subordinate to the RTO or ISO.” The proposal “engendered heated disagreement” by commenters, the commission said.
SPP, the Electric Power Supply Association, some industrial customers and several utilities supported the commission’s proposal. But more commenters opposed it, including Potomac Economics, other industrial customers and utilities, the Organization of MISO States, the National Association of Regulatory Commissioners and regulators from California, Maine, New York and Ohio.
The opponents said RTO officials who have designed and implemented the markets — and whose compensation may be based on market growth — may have a greater conflict of interest than the MMU. As FERC described the argument, RTOs would be disincented from imposing enforcement measures “on what in effect are their customers, or in refraining from mitigating a member that threatens to leave the RTO or ISO.”
FERC said it took seriously comments that “the MMU serves as a useful buffer between the RTO or ISO and the market participants, performing what is often viewed as a hostile act.”
Ultimately, the commission chose a compromise that it said “strikes the appropriate balance between allowing modified participation by the MMUs in mitigation, while protecting against the conflict of interest and subordination inherent in their unfettered participation.”
The commission said RTOs may allow their MMUs to conduct retrospective mitigation because it is only prospective mitigation — that which can affect market outcomes on a forward-going basis, such as altering the prices of offers — that creates a potential conflict of interest for an MMU.
The commission also said the MMU may provide inputs required by the RTO to conduct prospective mitigation, including determining reference levels, identifying system constraints and calculating costs.
Information Sharing
The order required MMUs to report on market performance at least quarterly to commission staff, state commissions and RTO management and boards. MMUs must conduct regular conference calls for FERC, state commissions and RTO staff, as well as market participants.
It cut the lag time for the release of offer and bid data to three months from six but allowed RTOs to propose a shorter period — or, if the RTO demonstrates a collusion concern, it may propose a longer lag. The identity of market participants remained masked, although RTOs were permitted to propose a time period for eventual unmasking.
Requests for Information
State commissions were permitted to make “tailored” requests for information from the MMUs, limited to information regarding general market trends and the performance of the wholesale market. “If this limitation were not imposed, the MMU could rapidly become an unpaid consultant for the states, and would be unable to perform its core functions,” the commission said.
Barry Trayers of CitiGroup Energy won endorsement from the Markets and Reliability Committee for his proposal to add an acceptable reason for early capacity replacement to Manual 18: PJM Capacity Market.
After Trayers agreed to remove the words “wind” and “solar,” the motion passed with three objections and six abstentions.
The change adds the following as an acceptable reason for early replacement: “If the replacement resource’s capacity is not affected by its outage rate, such as cleared incremental auction buy bids, the replacement transaction can be completed at any time.”
“The reason is the deal’s already done,” Trayers said. “There’s a sale and a purchase, and you’d like to merge those in your portfolio and know where you stand.”
End of Life Senior Task Force has New Name, Charter
Members approved a charter for the Transmission Replacement Process Senior Task Force, previously referred to as the End of Life Senior Task Force.
The group will be tasked with developing ways to provide more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan. (See PJM TOs Oppose Proposal to Develop End-of-Life Criteria.)
New Issue for Energy Market Uplift Senior Task Force
The committee approved revisions to the Energy Market Uplift Senior Task Force charter to incorporate a problem statement and issue charge regarding the review of virtual transaction rules.
The group will study biddable nodes and the application of uplift and determine whether recommendations from PJM’s
October 2015 white paper on virtual transactions should be implemented. (See PJM Suggests Changes to Virtual Transactions.)
Stricter Standards OK’d for Project Queue Submittal
Members approved the Earlier Queue Submittal Task Force’s recommended Tariff revisions, which would require earlier submittal of documentation in order for projects to secure a place in the interconnection queue.
The revisions will be presented for endorsement to the Members Committee at its June 30 meeting. (See “New Project Submittal Process to Require Earlier Filing of Documents,” PJM Planning Committee and TEAC Briefs.)
Tweaks to DER Problem Statement OK’d
Members approved clarifications to the previously approved distributed energy resources problem statement. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM Markets and Reliability Briefs.)
The changes recast the entry of distributed resources into the PJM market as having “unique challenges” instead of being “cost-prohibitive and time-consuming.”
Members Hear First Reads on PLS, Tx Equipment Upgrades
Members heard the first read of a proposal to update the parameter limited schedule exception process to permit more flexibility.
Paul McGlynn, senior director of planning, presented a first read of a proposal to except transmission substation equipment upgrades from the competitive window. (See “Typical TO Upgrades Would be Excluded from Competitive Window Under Proposal,” PJM Planning Committee and TEAC Briefs.)
Real-Time Values Added to Manual 11
The committee approved changes to Manual 11: Energy and Ancillary Services Market Operations that incorporate real-time values.
The changes allow a market seller to communicate a unit’s actual operating parameters to PJM before and after the day-ahead market closes when the unit cannot operate for certain reasons.
The language stipulates that real-time values may be used to modify the turn-down ratio, minimum run time, minimum down time, maximum run time, start-up time and notification time, and they can be made whole due to an actual constraint.
Committee Unanimously Endorses Manual Changes
The following manual changes were approved Thursday:
Manual 11: Energy and Ancillary Services Market Operations. Resources that cannot reliably provide day-ahead scheduling reserve obligations in real time will be excluded from DASR eligibility. They include nuclear units, dynamic transfers, run-of-river and self-scheduled pumped hydro units, wind units, solar units and non-energy resources. (See “Day-Ahead Scheduling Reserve Eligibility to be Studied,” PJM Market Implementation Committee Briefs.)
MISO last week presented a plan to address FERC’s order in an ongoing dispute over its seam with PJM, even as the RTOs and other parties sought rehearing on the ruling.
The RTOs have until June 20 to submit a compliance filing in response to an April 21 order in which the commission partially denied and granted a 2013 complaint by Northern Indiana Public Service Co. regarding the two RTOs’ interregional planning (EL 13-88). (See FERC Orders Changes to MISO-PJM Interregional Planning.)
At a Joint and Common Market meeting last week, MISO said the RTOs will work together to create “step-by-step deadlines” for a coordinated system plan in their joint operating agreement (JOA) by the filing deadline. By mid-August, the RTOs will align their respective annual transmission project packages — MISO’s Transmission Expansion Plan and PJM’s Regional Transmission Expansion Plan.
As ordered by FERC, MISO will also:
Lower its interregional project voltage threshold to 100 kV;
Eliminate the $5 million cost threshold for interregional projects;
Remove its interregional cost-benefit analysis; and
Work with PJM to incorporate interconnection coordination procedures from their respective business practice manuals into the JOA.
“With the order, FERC required a lot of MISO,” Planning Advisory Committee Chair Bob McKee said during last week’s Steering Committee meeting.
PJM’s Chuck Liebold said the RTOs continue to work together on a targeted market efficiency project study that would identify quick, low-cost upgrades to alleviate congestion, while simultaneously adding JOA language that incorporates the study process.
The RTOs and SPP are also seeking alternatives to the April 1, 2004, “freeze date” for determining firm rights on flowgates based on flows before they instituted their current markets. The RTOs plan to develop a solution and file Tariff revisions by the fourth quarter, with implementation expected by next June.
MISO is also seeking stakeholder input on how to implement a new joint model that uses the same assumptions and criteria in the regional processes for both RTOs.
“The rest of the order didn’t order stakeholder involvement, but we certainly want some input,” said Eric Thoms, MISO’s manager of planning coordination.
Rehearing Requests
Last week, NIPSCO, MISO, PJM and others filed requests for rehearing of FERC’s order.
NIPSCO asked the commission to reverse its decision disallowing use of market-to-market payments as an alternative justification for interregional projects. It also wants FERC to impose a timeline on market efficiency project analyses.
“NIPSCO appreciates the commission’s attention to seams issues to date, but respectfully requests that the commission ‘hold the RTOs’ feet to the fire’ regarding the significant compliance efforts that remain,” the company wrote in its request.
The Organization of MISO States argued that the new 100-kV threshold for interregional economic transmission projects is unjust and unreasonable. The group contends there is no “substantial” evidence that projects above 100 kV but below 345 kV can provide benefits broad enough to justify a 20% load ratio cost allocation across MISO’s footprint.
“Any such change would require an appropriate process that includes substantial stakeholder input and engineering studies to support any changes,” OMS said.
MISO Transmission Owners asked FERC to revisit its decision to lower the voltage threshold and eliminate the $5 million cost threshold for interregional economic transmission projects. The TOs say that in ordering the changes, the commission “inappropriately relies on the results of MISO and PJM’s quick hit analysis, which utilizes different planning criteria and inputs than MISO and PJM utilize for identifying and evaluating interregional market efficiency projects.”
MISO asked FERC to reconsider a decision to eliminate the interregional benefits-to-costs analysis — also known as the joint metric — claiming the commission provided no explanation for the move. The RTO also contends that the joint metric “is not a hurdle and is needed to harmonize regional benefits calculations and prevent gaming.”
PJM asked the commission to clarify whether it meant for the RTOs to eliminate the current 1.25-to-1 benefit-to-cost ratio on interregional projects. Determining a cost split using separate regional metrics “will result in significantly different benefit values for the same project,” the RTO said.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week continued the debate over who should be responsible for Texas’ largely unused smart meter monitoring website.
The website, which allows authorized parties to access individual consumers’ electricity-usage data, has been operated from its inception by Smart Meter Texas (SMT), an entity created by a coalition of transmission and distribution utilities. For the past two years, the state Public Utility Commission has been considering whether to transfer oversight of the website to ERCOT. The coalition, along with several other industry and advocacy groups, has supported the move. The ISO, with support from the state Office of Public Utility Counsel, has resisted the responsibility, citing technical and financial hurdles.
At the TAC meeting last week, the main concern was the potential impact on ERCOT’s budget and administrative fees.
TAC Chairman Randa Stephenson, of the Lower Colorado River Authority, asked for a synopsis from an ERCOT workshop earlier in the week that had focused on the potential transition. Mark Ruane, ERCOT’s director of settlements, retail and credit, explained that the PUC has been looking at data-flow projections if the ISO were to take over the website. Attendees at an April PUC meeting agreed to a “high-level” concept, he said, in which ERCOT would provide settlement data to the web portal rather than take control of the portal itself.
Cost Information Sought
The goal of last week’s workshop was to decide the scope of the project. Attendees left saying they needed more information on the likely costs versus the potential benefits. The PUC plans to take up this issue again at its June 9 meeting.
CenterPoint Energy’s Kathy Scott, chair of the Retail Marketing Subcommittee, said that the subcommittee has asked competitive retailers to detail what functionality they’d want to see from both ERCOT and SMT if the ISO takes over operation of the web portal. CenterPoint is one of the utilities that runs SMT. She said committee members and the competitive retailers will meet after the June PUC meeting to determine how to move forward.
Stephenson asked that updates to the process be included in future RMS reports.
Eric Goff, of Citigroup Energy, noted that SMT is funded through rate surcharges and asked whether there are legal mechanisms to direct some of that funding to ERCOT for taking on the responsibility.
Scott said it’s likely within the PUC’s purview to decide on the allocation.
Website Usage Low
Perhaps a larger question is what should be done with the website. Scott highlighted statistics showing that the site has about 68,000 registered users. That equals a little less than 1% of the more than 7 million customers who have smart meters installed and could be using the site.
Additionally, according to a 2014 report by the South-central Partnership for Energy Efficiency as a Resource (SPEER), it’s just 8,000 more users than the site had two years ago.
Connecting to the website is supposed to enhance the usefulness of energy-saving “home area network” (HAN) devices, but the statistics showed that consumers who purchase them aren’t continuing to use them. While the 2014 SPEER report noted 12,000 HAN devices being used throughout ERCOT’s territory, Scott reported last week that only about 9,700 were still in use as of March.
Concerns have also been raised about SMT’s privacy and data protection. At May’s RMS meeting, representatives of consumers and several investor-owned utilities abstained from voting on two measures that would allow using SMT to submit information from small generation sources, such as rooftop solar arrays. The IOUs questioned whether providing generation data violated customers’ privacy.
Quicker Processing
The TAC also voted to endorse retail market guide revision request (RMGRR) 136, which is meant to help the market process documents quicker by clarifying the procedures for removing holds on switching customers’ retail providers. Holds can occur when a customer has an outstanding balance or the provider believes the meter has been tampered with.
The TAC also endorsed RMGRR 137, which would create a timeline for correcting inaccurate customer billing information.
Additionally, the final review has been performed for system change request 786, which sets “retail testing environment” business requirements. ERCOT has assigned it project number 192-01.
Finally, Scott noted that a draft nodal protocol revision request (NPRR) is being developed that may replace RMGRR 132 or require it to be rewritten. With the help of Oncor’s Taylor Woodruff, Tom Burke of Amarillo-based Golden Spread Electric Cooperative will guide the new NPRR through the stakeholder process.
The average real-time price of wholesale power in New England fell by more than a third last year, according to the 2015 Annual Markets Report by the Internal Market Monitor of ISO-NE.
Prices dropped more than $22/MWh to $41, as the average price of natural gas fell 41% to $4.73/MMBtu in 2015, from $7.99/MMBtu in 2014.
The report by the Monitor said the wholesale power markets operated competitively last year. The prices of both natural gas and wholesale power were the lowest since 2012, with natural gas generating 49% of the electricity produced in the region.
“Natural gas prices fell last year with increased domestic production, above-average storage levels nationally and mild weather that moderated demand for natural gas for heating and power generation for most of the year,” said Jeffrey McDonald, ISO-NE’s vice president of market monitoring. “Because of the moderate demand, there was sufficient space in the region’s natural gas pipeline infrastructure to deliver low-priced natural gas to the region’s generators. The New England markets were competitive in 2015, as demonstrated by the close linkage between natural gas and wholesale power prices.”
The Monitor also reported that total costs — including energy, capacity, ancillary services and transmission — fell about 25%, from about $12.4 billion in 2014 to about $9.3 billion in 2015.
At 126,833 GWh, total electricity usage in New England was 0.3% lower in 2015 than in 2014.
Delaware Gov. Jack Markell, the state’s congressional delegation and LS Power are among those asking FERC to revisit its April 22 ruling approving solution-based distribution factor (DFAX) cost allocation for the Artificial Island and Bergen-Linden Corridor projects.
Salem Nuclear Generating Station Source: Wikimedia
A request for rehearing was filed by the public service commissions of Delaware and Maryland, whose electricity customers will pay for the bulk of the work to upgrade the New Jersey complex that houses the Salem and Hope Creek nuclear reactors. That’s because the Delmarva peninsula is the sink point for the new transmission line that will link Artificial Island with the Red Lion-Cartanza and Red Lion-Cedar Creek 230-kV lines in Delaware, and thus the target of the DFAX methodology.
In its 3-1 ruling, with Commissioner Cheryl LaFleur dissenting, FERC said it “found that where a cost allocation method is accurate in a very high percentage of circumstances to which it applies, then it is a strong indicator that the cost allocation method is just and reasonable” (EL15-95, ER15-2563). (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)
No Free Pass
The complainants said that’s not good enough.
“The Federal Power Act does not provide the commission with a free pass on its obligation to ensure just and reasonable rates for the ratepayers in Delaware and Maryland simply because the commission previously approved a cost allocation methodology that works for other projects and other ratepayers,” said LS Power, one of the developers of the Artificial Island stability fix.
“The presence of the facility ensures reliable delivery of power and alleviates future reliability concerns and violations that could have otherwise caused operational issues equally, or in fact more so, to a large segment of the grid beyond Delaware and Maryland, and those beneficiaries are not identified by solution-based DFAX and therefore are not paying their appropriate share for the reliability benefits received,” LS Power said.
Since FERC’s order, the estimated cost of the Artificial Island project has ballooned, with Public Service Electric and Gas nearly doubling the cost of its work from $137 million to $272 million. (See Cost Estimate of PSE&G Portion of Artificial Island Fix Doubles to $272M.) LS Power has stood by its cost cap of $146 million.
In looking for ways to reduce the cost, PJM planners are considering a new configuration that would terminate the transmission line at Hope Creek instead of the Salem substation. That could alter its scope and require the RTO to solicit new bids under FERC Order 1000. (See Artificial Island Cost Increase Could Lead to Rebid.)
Cancellation Sought
In addition to the requests for rehearing, the Delaware Division of the Public Advocate wrote to the PJM Board of Managers asking it to cancel the project.
“The DPA exhorts the PJM board to re-evaluate its approval of the project in light of the staggering increase in the cost of the PSE&G portion of the project,” wrote Public Advocate David Bonar. He said the updated cost estimates more than double the Delmarva zone’s share with an increase of $107.4 million.
Commercial electricity consumers could see their bills increase by $50,000 per month, he said, while residents would see about a $13 hike.
“The DPA is not asking PJM to do something it has never done before,” he said. “After reconsideration, PJM canceled the Mid-Atlantic Power Pathway and the Pennsylvania-Allegheny Transmission Highway projects.”
The PSCs’ filing was submitted also on behalf of the Delaware Division of Public Advocate, the Maryland Office of People’s Counsel, Old Dominion Electric Cooperative and the Delaware Municipal Electric Corp.
The parties challenged FERC’s factual findings and legal conclusions and said the DFAX cost allocation would violate precedent and produce unjust and unreasonable rates.
In a letter supporting the filing, Markell said, “The commission’s order will have a significant direct negative impact on customers in the Delmarva zone and on the economy of the region. Several manufacturing facilities have already expressed concerns about the impact the added costs will have on their operations.”
U.S. Sens. Tom Carper and Chris Coons and Rep. John Carney also wrote to FERC in support of a rehearing.
“The current cost allocation results in over 90% of project costs being borne by Delmarva zone customers in exchange for just a small portion of the project benefits,” they said. “This cost distribution is not sustainable for Delaware users and could seriously impact the state’s ability to recruit and retain industry.”
The issue of cost allocation for the Artificial Island stability fix and Bergen-Linden Corridor transmission project was the topic of a January FERC technical conference, called after the commission determined the DFAX method may be unjust and unreasonable in some cases. (See DFAX: ‘Poison Pill’ or ‘Best Method’ of Cost Allocation?)
As with the Artificial Island project, the factors surrounding the project have changed since FERC’s ruling.
Consolidated Edison, to which PJM assigned $629 million of the costs of PSEG’s $1.2 billion upgrade, recently decided to stop using the “wheel” by which PSEG takes 1,000 MW from Con Ed at the New York border and delivers it through New Jersey to Con Ed load in New York City. (See Con Ed-PSEG ‘Wheel’ Ending Next Spring.)
“The order states that the purpose of the Bergen-Linden Corridor project is to facilitate the Con Edison wheeling arrangement,” Hudson Transmission Partners wrote. “The Con Edison wheeling arrangement has been terminated. Moreover, Linden VFT, HTP and others brought this likelihood to the commission’s attention on the record in this proceeding, but the commission entirely ignored these facts.
“It is now a reality. Therefore, the very basis upon which the Bergen-Linden Corridor project was founded … and presumably the basis for allocating most of the project’s costs to Con Edison (as, presumably, the beneficiary), has fundamentally changed. Initial analyses by PJM, which were also presented to the commission, indicate that most of the costs previously allocated to Con Edison will now be shifted to HTP.”
The NYPA wrote that it expects its cost allocation associated with the BLC project to increase from about $100 million to more than $600 million.
“The BLC project costs that will be allocated to NYPA following termination of the Con Edison wheel are so grossly disproportionate to the total value of NYPA’s firm export rights on the HTP line that NYPA will be forced to pursue all of its options, which may include termination of the [firm transmission withdrawal rights] it has contractually acquired from HTP, if it cannot mitigate its exposure to [Regional Transmission Expansion Plan] costs in some other way,” it said.
“Given the significant cost of the BLC project, the economic stakes are high,” the NYPA said. “Further ramifications should be expected if rehearing is not granted.”
AUSTIN, Texas — ERCOT’s Technical Advisory Committee endorsed the Wholesale Market Subcommittee’s recommendation to increase the fuel adder factor for coal- and lignite-fired resources to $1.10/MMBtu from $0.50/MMBtu. The committee added a sunset date of June 1, 2018, and directed the subcommittee to continue developing a permanent solution to address changing coal prices.
“Given the ongoing pressures in the coal markets, we’d like to see additional work on getting an indexed price for coal, like we have for gas,” Austin Energy’s Barksdale English said. “We’d like to get something a little more dynamic that reflects ongoing changes in the market.”
Citigroup Energy’s Eric Goff said any “hard-coded dollar amount[s]” included in ERCOT’s protocols should be handled “with great caution.”
“If we hard-code that amount, we should make sure it expires,” Goff said. “We’re talking about costs, but not costs we get from market prices. It’s important generators can recover their costs.”
The recommendation was one of two verifiable cost manual revision requests (VCMRRs) brought to the TAC by the WMS. VCMRR 009 was also endorsed, with one abstention; it clarifies the calculation of the minimum requirements fee assessed to qualified scheduling entities based on the total amount of fuel purchased and transported.
TAC Sends 12 Revision Requests on to Board
The TAC unanimously endorsed a nodal protocol revision request providing improved transparency to market participants when transmission outages that could create congestion are submitted with less than 90 days’ notice. The committee, however, asked that more information on the matter be brought back to the committee.
NPRR 758 would identify outages that have historically resulted in high congestion costs, as adjusted through stakeholder review to account for upgrades and other changes. Determining who develops the outage list and who reviews it will be part of the “homework” that TAC Chair Randa Stephenson, of the Lower Colorado River Authority (LCRA), asked to be brought back to the committee.
“I’m expecting the primary focus of this to be transparency … not to make it more difficult for me to get the transmission I need,” American Electric Power’s Richard Ross said during the discussion.
“The idea is you may not have as much visibility of the problems you create in the market,” said Morgan Stanley’s Clayton Greer. “LCRA may have a 169-kV switch causing millions in congestion, but the wires side has no concept. You’re taking outages, but Oncor may be taking outages at the same time. That could cause major market disruptions.”
The NPRR was developed following a year of work by a task force focused on outage-coordination improvements. It has an estimated cost impact to ERCOT of between $300,000 to $400,000, but the spending won’t happen until 2017, when improvements to the Outage Scheduler system are expected to be completed.
The TAC also briefly discussed NPRR 766 before giving it a unanimous endorsement. The revision request aligns ERCOT’s systemwide discount factor with a proposed operational adjustment to the reserve discount factor (RDF) in the market’s physical responsive capability (PRC) calculation, ensuring consistency with a proposed timeline for changes to the RDF. (See “Reserve Discount Factor Proposal,” ERCOT Technical Advisory Committee Briefs.)
The committee changed the effective date from July 1 to Oct. 1, giving staff additional time to analyze the results of this summer’s RDFs. The PRC used a 2% discount factor last year; ERCOT has proposed a 1% factor.
The committee unanimously endorsed seven other NPRRs, a pair of revision requests to the Commercial Operations Market Guide and a revision to the Nodal Operating Guide, and a system change request:
Nodal Protocol Revision Requests
NPRR 709: modifies the alternative-dispute resolution procedure and clarifies parts of the settlement and billing dispute process.
NPRR 754: revises the posting frequency of the load-forecast distribution factors report. Posting is required only when the factors are changed.
NPRR 761: clarifies that a resource will not be eligible for make-whole payment start-up cost compensation in the day-ahead market when the market considers the resource as not having a start-up cost.
NPRR 762: removes references to the provision of responsive reserves across DC ties.
NPRR 763: corrects the formula for calculating qualified scheduling entities’ load-allocated monthly block load transfer amount to reflect a charge, rather than a payment.
NPRR 764: changes calculations for charges to entities short their capacity obligations in the reliability unit commitment. Calculations for wind and solar resources will be based on their production potential.
NPRR 765: eliminates publisher names for various fuel prices and provides additional clarifying language regarding the use of a substitute source for daily fuel prices.
COPMGRR 041: updates to reflect current ERCOT and market participant practices for market notices.
COPMGRR 042: updates to reflect the Market Data Working Group’s creation and the Profiling Working Group’s responsibilities.
Nodal Operating Guide Revision Request
NOGRR 050: removes ERCOT’s requirement to produce outage-scheduling reports until systems can be changed to include only transmission service providers’ outages.
System Change Request
SCR 790: adds an additional level of geographical granularity — the Panhandle/North area — to existing reports for wind energy production and forecasts.
The TAC once again tabled, this time for two months, whether to consider an appeal of NOGRR 149. The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission-operator services from a third-party provider if their annual peak is less than 25 MW.
The Reliability and Operations Subcommittee rejected the NOGRR in March.
Transmission Reports Endorsed
ERCOT staff shared two reviews of planning projects designed to address reliability and import issues in the high-growth Rio Grande Valley region along the Texas-Mexico border. The TAC endorsed both reviews, though each received a pair of abstentions.
Jeff Billo, ERCOT’s senior manager of transmission planning, said staff’s voltage and transient stability review of the Valley Import Regional Planning Group project narrowed 10 solutions down to a preferred option: a $91 million project to add two static VAR compensators capable of handling an additional 2,800 MW of summer peak load.
The project review was driven by competing project proposals from AEP and Sharyland Utilities-CPS Energy, designed to meet a 2011 report that identified upgrades needed in the region by 2020. Direct Energy’s 2014 announcement that it would disconnect from ERCOT and begin dispatching its 524-MW Frontera combined cycle plant to the Mexican market only increased the urgency.
ERCOT’s review assumed six LNG plants proposed for the Port of Brownsville would add 2,400 MW of load but that a 780-MW generation project would also be built.
“We recognize that if the additional generation doesn’t show up, we may be back asking for additional upgrades,” Billo said.
Staff also reviewed AEP’s proposed project to address reliability needs in the North McAllen-Edinburg area. ERCOT’s planning group is recommending an option that will add two new 345-kV lines, a 345-kV double-circuit line, two 345/138-kV transformers and various other improvements at an estimated cost of $51.5 million.
ERCOT’s analysis did not account for the roughly 50 MW of distributed generation in the valley because “DGs are not dispatchable by ERCOT,” Billo said. “They’re not price-sensitive to the LMPs.”
MISO’s Steering Committee concluded last week that the Resource Adequacy Subcommittee acted properly when it retired the Competitive Retail Solution Task Team on May 5 without a vote or motion.
MISO already displays a real-time wind generation in a graph on their website. A pending data request asks the RTO to break down wind output data by North, South and Central regions. MISO says that my not be possible.
But in its meeting Wednesday, the committee discussed whether the RTO’s stakeholder governance guide should be updated to outline a process for retiring a task team. To retire the CRSTT — which was established last October to develop capacity auction improvements — the RASC relied on written comments and discussion with stakeholders.
RASC Chair Gary Mathis said the issue was presented to the Steering Committee after questions were raised about the procedure the RASC used.
“I don’t think we need to formalize this process,” Steering Committee Chair Tia Elliott said.
But Bill SeDoris, director of MISO integration for Northern Indiana Public Service Co., said it may be helpful for committee charters to state that task teams can be closed out “entirely at the discretion of committee leadership.”
Indianapolis Power & Light’s Lin Franks also recommended that the Steering Committee produce a non-enforceable guideline document on the creation and dissolution of task teams.
In lieu of task teams, Kent Feliks of American Electric Power suggested MISO could hold special meetings on topics, as PJM does.
Elliott said further discussion on the issue will be taken up at the July Steering Committee meeting.
IMM Makes Recommendation in Data Request
Two pending data requests must be adjusted before being implemented by MISO, RTO staff and the Independent Market Monitor said.
The Monitor cautioned against fully granting a stakeholder request to post commercial limits for binding constraints in the real-time and day-ahead markets. It recommended rejecting the release of day-ahead values “but is still considering the possibility of real-time values on a week delay,” according to MISO. The RTO’s Tom Welch said staff plan to postpone a decision until July, when the Monitor’s final recommendation becomes available.
Foreknowledge of the constraints creates concerns about market manipulation, Welch explained.
The RTO is also putting the brakes on an early May request to break down wind output data by North, South and Central regions in both real-time and day-ahead forecasts. (See “MISO Grants 2 Data Requests, Denies Another,” MISO Steering Committee Briefs.)
Welch said the request is still under review, noting that when the first wind units open in MISO South, wind output reports would inadvertently “expose their unit-specific information.” To protect nonpublic information, MISO said the data posting might not be prudent until at least three wind units are installed in the region.
“We can break down the northern regions,” Welch said.
Financial Transmission Rights Working Group Retired
MISO’s Financial Transmission Rights Working Group was retired as a result of a Steering Committee decision. Duties associated with financial transmission rights and auction revenue rights have been transferred to the Market Subcommittee.
The move was approved by consent with little discussion.
Pallas LeeVanSchaick of Potomac Economics outlined the recommendations in a presentation on the monitor’s 2015 State of the Market Report to the NYISO Management Committee meeting on Wednesday.
An Energy Department official said the U.S. should continue funding an international attempt to develop fusion technology, despite the project’s overruns and delays.
The Nuclear Regulatory Commission finalized rules that set a sliding fee scale for small modular reactors, aimed at encouraging development of the technology.
The Nuclear Regulatory Commission has approved the transfer of the license of the shuttered La Crosse Nuclear Plant in Genoa, Wis., to La Crosse Solutions, a subsidiary of radioactive waste disposal specialist Energy Solutions.
New Jersey opponents to the $1.2 billion PennEast natural gas pipeline project urged FERC to halt its review, contending the developers have failed to provide required information on the project.
FERC said the rules, which updated a 2005 policy statement, were needed to “improve the performance and transparency of organized RTO and ISO markets.” They prohibited RTO management from supervising their MMUs, and required, in most instances, that MMUs report directly to their RTOs’ board of directors.
The RTOs have until June 20 to submit a compliance filing in response to an April 21 
Prices dropped more than $22/MWh to $41, as the average price of natural gas fell 41% to $4.73/MMBtu in 2015, from $7.99/MMBtu in 2014.
