Great River Energy is urging MISO to account for the effects of inverter-based generation in the RTO’s transmission planning studies.
Inverter-based generation — often new technology resources asynchronously connected to the grid via an electronic interface — can harm reliability in weak power systems, Great River Energy’s Mike Steckelberg said at an Aug. 15 MISO Planning Subcommittee meeting. The Minnesota utility discovered the issue during a recent analysis, he said.
Great River Energy linemen | Great River Energy
Steckelberg cited a June NERC report warning that such resources can affect dispatch and reliability — including voltage control, frequency response and ramping — when too many of them are interconnected into weak power systems.
The company said MISO’s annual Transmission Expansion Plan study process should include screening for transmission with low short-circuit currents, comparing the megavolt-ampere level before a inverter-based resource is connected to the nominal power rating of that resource. If the calculation does not meet a certain threshold, MISO should remedy the transmission by modifying controls, connecting to a stronger source, planning for more transmission or reducing the size of the generation project.
GRE transmission | Great River Energy
“This is a fairly easy screen to be doing ahead of time,” Steckelberg said. While the screen would not have to be a “full-blown study,” it does need to be incorporated into MISO’s generation interconnection studies.
Steckelberg said MISO’s Interconnection Process Task Force and Planning Subcommittee both need to address the issue, and transmission owners and planners should be able to review new interconnection requests for low short-circuit current issues.
Entergy’s Yarrow Etheredge and American Transmission Co.’s Patrick Gerum said their companies shared GRE’s concerns.
Customized Energy Solutions’ Ginger Hodge asked for MISO’s response on the issue.
MISO Director of Planning Jeff Webb said he and his staff would review the request and put together a response at the Planning Subcommittee’s next meeting in October.
Frequent rule changes and an uncertain market structure are causing dissatisfaction among CAISO demand response providers and eroding participation in the programs, those providers say.
Problems with data verification and settlement required the ISO to recalculate its 2016 DR results, and providers say there are other issues with the program, which aggregates utility customers to facilitate their participation in the ISO’s wholesale markets.
“We have not received any energy payment of any dispatch of our resources going back to June 2016,” EnerNOC Director of Regulatory Affairs Mona Tierney-Lloyd told RTO Insider. While Tierney-Lloyd doesn’t think there are large payments still outstanding, “it is obviously sub-optimal,” she said.
EnerNOC control room | EnerNOC
EnerNOC and other companies aggregate retail electric customers and bid the load reductions into the CAISO market to offset the need for generation. Wholesale DR aggregates and compensates electricity users that reduce their consumption to below a pre-established baseline. Separately, utilities also maintain DR programs in which they provide customers a financial incentive to decrease load.
Tierney-Lloyd believes there are several factors causing the decline in DR program participation, including rule changes and modifications to the way DR resources are dispatched. There are also inconsistencies between CAISO and California Public Utilities Commission rules, she said. Agency misalignment is the primary cause of what she said is significant decline in DR program participation.
Participation in PG&E, SCE Demand Response Programs, 2011-2016 | EnerNOC
“It takes work on our side to get those customers familiar with those rule changes,” which also adds costs, she said.
During hot weather, it is more difficult for customers to reduce their usage below baseline, resulting in some taking efforts to reduce demand without getting paid. Others keep a close eye on CAISO operations and don’t understand why they are getting dispatches when no shortages are seen on the system.
CAISO uses DR as a way to make the grid more efficient and reduce greenhouse gases associated with climate change. While the ISO has a number of DR program improvements underway, its past problems slowed payments to market participants. (See CAISO Resettling 2016 Demand Response Results.)
In 2016, the DR system was sometimes unaware that an event had occurred, or the system did not deliver settlement data, CAISO said. The system was not receiving the correct “payload” to identify that a DR event occurred, so the system was unaware of the event and no performance measurement was completed. But even when the event day and historic meter data were available, the DR system in some cases did not send the values to the settlement system, so no settlement occurred. The ISO’s full resettlement should be completed in October.
The CAISO Board of Governors recently approved the second phase of a program meant to make distributed resource integration easier, dubbed the Energy Storage and Distributed Energy Resources (ESDER) Phase 2 proposal. (See New CAISO Rules Spell Increased DER Role.) ESDER includes a set of alternative energy usage baselines to assess the performance of proxy demand resources, one of a series of refinements to the DR program.
NEW YORK — New York must improve its policies and regulations around distributed energy resources in order to ensure that community solar can help meet Gov. Andrew Cuomo’s goal of 325 MW installed solar capacity in the city and nearly 3,000 MW statewide by 2023.
| SEIA
That was the perspective of participants on a community solar development panel at the Infocast New York Energy REVolution Summit held Aug. 1-3 at Times Square.
“The community solar programs in New York were slow to start, much slower than we originally anticipated because the market signals weren’t quite there for a while,” said Cynthia Christensen of Namaste Solar, an employee-owned cooperative with headquarters in Boulder, Colo., and an office in New Paltz, N.Y. “Investors always like certainty. Good, bad or indifferent, give them certainty.”
Panel moderator Valessa Souter-Kline, policy coordinator for the New York Solar Energy Industries Association said, “Community solar is still fairly new. The order authorizing it [Reforming the Energy Vision (14-M-0101)] came out in 2015, and it’s had a slow start because when the CDG [community-distributed generation] order came out, the state also started digging into some other policy issues, including the value of DER. So there has been some policy and regulatory uncertainty.”
The Value Stack
The state’s Public Service Commission in March issued a Value of Distributed Energy Resources (VDER) order (15-E-0751) that began the transition away from net energy metering and toward an approach that aggregates specific value components. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
Drew Warshaw, vice president of community solar for NRG Energy, said that the VDER order differed significantly from its draft form.
“As a result, the slow ramp-up that we’ve had is going to continue unless some of the economics around that problem change. In terms of the governor’s and the administration’s goal of 325 MW of community solar — we don’t see that happening without significant changes around the program economics,” Warshaw said.
To incent community solar, “there are any number of levers on the revenue side that the state can pull,” Warshaw said. “I think the [New York State Energy Research and Development Authority] block program is certainly one — and the market transition credit, which is one of the pieces in the value stack of the VDER order.”
City Goals
Mayor Bill de Blasio in 2015 launched the OneNYC climate change program, which aims to lower the city’s greenhouse gas emissions to 80% below their 2005 levels by 2050, achieve the best air quality of any large U.S. city and send no waste to landfills by 2030.
Benjamin Mandel, renewable energy policy adviser with the mayor’s Office of Sustainability, said the city is working to ensure that as the market moves beyond net metering, it “has the right kind of signals both in terms of where it benefits utilities and also where does policy benefit and where we want to see DER projects going, including community solar.”
In terms of the installed capacity needed to meet its greenhouse gas mitigation goal, the mayor’s office estimated it would need 7 GW of solar citywide, which is “our entire technical potential,” Mandel said. “For reference, we’ve probably got between 110 and 120 MW installed citywide right now … a stretch goal is to reach 1,000 MW of installed solar capacity citywide by 2030.”
The mayor’s office works with Sustainable CUNY and the NYC Economic Development Corporation to expand access to the benefits of solar energy and other forms of renewable energy. Programs include Solarize NYC — for community group purchasing — and a related program called Shared Solar NYC.
Since 2006, the NYC Solar Partnership program has connected government and industry with oversight agencies that permit rooftop solar projects and with the interconnecting utility, Consolidated Edison. This “has greased the skids” and allowed the city to narrow the disparities in solar adoption between the five boroughs and less dense areas like Westchester or Long Island, Mandel said.
And the city has its own large constituents. Bomee Jung, vice president of energy and sustainability for the New York City Housing Authority, said, “If NYCHA doesn’t meet its goals, it’s not likely that the city’s going to get there without us.”
The housing authority serves about 400,000 people in 176,000 apartments and another 200,000 people through its voucher program, the largest numbers of any city in the country.
Near Future
“You’re going to have a fairly limited market here in the near future for a few reasons,” said Tom Hunt, vice president of corporate development for Clean Energy Collective, which licenses community solar software to developers and utilities.
“You have economics under Phase One [of New York’s Clean Energy Standard] that probably don’t work in at least a few different load zones … and in those load zones where the economics do work, you’re going to have some pretty significant interconnection issues, or siting issues for here in the city,” Hunt said.
“The math will work, the economics will work in Con Edison Zone J [NYC], but the challenge there is siting,” Warshaw said. “We have a service area that produces an amount of community solar at scale that’s really going to make an impact. So that’s the challenge that a company like NRG sees, which is very focused on building out community solar, has the money to invest in New York and feels like a lot of positive things are happening in New York in terms of the climate, the horsepower and the brain power in Albany focused and wanting to do this.”
Some solar developers claim that there’s going to be 2 GW of community solar built in the next 12 months in load zones A through C, but Hunt is doubtful.
“I don’t know that there’s 20 MW within all that that have figured out how you deliver a full program in terms of bringing customers in and billing them, invoicing them, let alone getting utilities on your side so you can bill credits,” Hunt said. “While we’re certainly optimistic about the order and what it means, there’s a lot of work left to be done, and which we think needs to be done in order to make this market sustainable.”
VALLEY FORGE, Pa. — Unpredictable rainstorms throughout PJM in the middle of July resulted in overestimated load forecasts last month, the RTO’s Chris Pilong told members during an Aug. 8 Operating Committee meeting.
“Just about every afternoon, we had rainstorms that were possible … and just about every day, those storms did hit,” he said, noting that they reduced temperatures and caused daily forecasts to exceed actual load by as much as 6,000 MW.
One example: While the RTO forecast peak demand of approximately 150,000 MW on July 20, early afternoon storms capped load at about 145,000, Pilong said. That allowed the summer peak so far to remain the previous day, July 19, when demand hit 146,635 MW, he said.
PJM’s peak load forecasting error for the month was 4.58%, 0.79 percentage points above July 2016, PJM’s Joe Ciabattoni said. The overall forecasting error was 3.13%, just above PJM’s 3% target. Ciabattoni attributed the deviation to the “pop-up storms” on the western side of the footprint. The errors were highest in the distribution territories of Dayton Power & Light, Duquesne Light, FirstEnergy’s American Transmission Systems Inc. and Duke Energy Ohio/Kentucky.
The monthly balancing authority area control error limit, which measures how well the RTO maintains constant frequency control, was 99.9%, with total excursions and excursion minutes at their lowest levels in at least the past year.
The Anatomy of a LMP Spike
LMPs jumped to about $900/MWh around 10:30 a.m. on July 27, Pilong said. An outage the previous evening on the Black Oak-Hatfield 500-kV line created increased flow on the Conastone-Peach Bottom 500-kV line. PJM had been controlling flow over the latter segment to roughly 93% of its limit, but flow levels on the line can be volatile, as they are sensitive to load or generation movements. Moves from hydro units and shifting load increased flow over the line by about 5%, Pilong said.
Operators directed PJM’s security-constrained economic dispatch (SCED) engine to reduce flow over the line by 6%, but the demand was too great and sent the engine into a “relaxation mode” in which it doesn’t attempt to control the flow. Pilong said that in those instances, SCED just fails to solve the case and moves on to resolve the rest of the system.
Operators reduced their request to 2%, which SCED could perform but only by raising the LMP to about $900/MWh. The price spike caused generation to respond, which reduced the strain on the line and allowed SCED to realign prices.
GT Power Group’s Dave Pratzon asked if such short-term and unexpected fluctuations were caused by PJM’s move from 15-minute to 10-minute dispatch settlements. He also questioned whether generators will be expected to follow PJM’s dispatch signals during those periods and how signal deviations will be handled.
Pilong said that with the shorter lookaheads, larger transmission changes will create greater price separation. Part of the issue, he said, is the response time of low-cost resources.
“If the low-cost generation isn’t able to move as rapidly as we need it to, we may need to reach out to more costly resources for a short period time,” he said.
In response to a stakeholder data request, PJM’s Lisa Morelli explained why the real-time SCED engine has not priced for shortages that stakeholders have observed in published data.
The public data come from PJM’s emergency management system (EMS), Morelli said, which has more conservative estimates than SCED. The most significant difference for this was a 2% “back off” in which the EMS system assumes resources will only achieve 98% of their stated capability. This assumption was removed in changes made on July 11, Morelli said, and immediately resulted in a 300-MW increase in the EMS synch reserve.
There are also differences between real-time SCED’s 10-minute lookahead and EMS’ real-time data. Additionally, real-time SCED uses units’ SpinMax (the reserve maximum) to estimate reserves, while the EMS uses the lesser of the SpinMax or the EcoMax (the economic maximum).
Exelon’s Sharon Midgley noted that the data request also asked for all of the unapproved real-time SCED cases, which she said would provide more clarity on whether PJM operators are being presented with real-time SCED cases that include shortages but are declining to select them.
Midgley and Old Dominion Electric Cooperative’s Adrien Ford said they had not been aware of the removal of the 2% back off and asked that PJM be more communicative with such changes in the future.
Morelli said there has been a 12% improvement in the alignment between the two measurements since PJM moved to the 10-minute settlement.
VALLEY FORGE, Pa. — PJM’s Michael Herman told members at last week’s Planning Committee meeting that proposed Manual 14B updates to incorporate modeling changes reflecting the cancellation of the Con Ed-PSEG “wheel” would include reductions in emergency transmission limits.
The capacity emergency transfer limits (CETLs) would be reduced in certain load deliverability areas (LDAs), including by 500 MW in EMAAC, 1,100 MW in MAAC, 1,527 MW in PSEG and 1,309 in PS North.
At PSEG, that would put the CETL at just 574 MW above the capacity emergency transfer objective (CETO), the threshold for necessary transfer capacity to ensure reliability in an emergency. In PS North, the difference between CETL and CETO would be just 335 MW.
The modeling adjustments come in response to Consolidated Edison’s decision to end a decades-long agreement with PJM to route 1,000 MW from upstate New York to New York City through Public Service Electric and Gas’ northern New Jersey territory. The change necessitated reanalysis of regional power flows, which eventually identified that continuing an “operational base flow” of 400 MW would be the most reliable solution. (See Analysis Recommends Continuing Reduced Con Ed-PSEG ‘Wheel’ for Grid Stability.)
In the updated CETL calculations, PJM removed any non-firm energy transfers. However, it kept them in its updated capacity import limit calculations. Stakeholders questioned why non-firm was removed from the CETL.
“If it’s a non-firm product, we just can’t depend on it during these critical times,” PJM’s Mark Sims said. “There could be a time when our system is stressed, the neighboring system is stressed, and then to depend on non-firm energy to support your system … just doesn’t make sense.”
The revisions were approved by acclamation with one objection and 14 abstentions.
PJM has scheduled a webcast on Aug. 30 from 1-3 p.m. to address questions about the CETL procedural changes.
Resilience Planning to Recognize Outage Propagation Potential
Sometimes, resilience means knowing when to give up.
In analyzing its planning criteria, PJM will be considering what is likely to happen downstream when a piece of equipment fails. Sometimes, this will mean the equipment simply collapses at that point. But it could also open a pathway for cascading failures further throughout the system and a larger collapse. (See “Resilience to Become Planning Driver,” PJM PC/TEAC Briefs: July 13, 2017.)
“If you had an existing station where you improved the strength of it such that during an event, where normally it would be lost very quickly and cleanly, it’s now hanging on,” Sims said.
As a result, the grid operator could face a scenario “where the system collapsed instead of being bounded because you actually have a stronger part of the system which allows the event to propagate further and in the end the result is worse,” he said.
To prepare for such a contingency, PJM is developing appropriate metrics and criteria for factoring resilience into planning.
“These are not events that happen often. I can’t pull data on voltage collapses,” Sims said. “We have to do our best to make some valid assumptions.”
Stakeholders have previously asked how PJM plans to address the subjectivity of the topic.
“To PJM, megawatts would just be load, but to others, megawatts are customers,” said John Farber with the Delaware Public Service Commission. He asked if PJM plans on considering the amount of load that would be impacted by a piece of equipment failing.
“I don’t know if you’re suggesting that some load is perhaps more critical than others, [but] I think many people would generally agree with that,” PJM’s Paul McGlynn said.
“I salute your eagerness to swim with the alligators,” Farber replied.
Market Efficiency Analysis Ongoing
Staff have completed analysis of market efficiency projects in the Reliability Pricing Model and are nearly finished examining interregional projects, Sims told members at last week’s Transmission Expansion Advisory Committee.
The RTO is currently reviewing projects from PPL’s zone.
The analysis identified six projects to be recommended for approval by the Board of Managers, including four in Commonwealth Edison’s LDA and one in Duke Energy Ohio/Kentucky. Two of the ComEd projects were proposed by American Electric Power.
Six other proposals — two from AEP and Exelon, one from Transource Energy and three from Northeast Transmission Development — were not recommended. PJM is expecting to seek approval on recommended projects at the board’s October meeting.
Reliability Analysis for 2022 Finds 190 Violations
PJM’s reliability analysis of the Regional Transmission Expansion Plan for 2022 conditions found violations at 190 flowgates.
The majority (115) were generation delivery issues, with most of those (50) being on 138-kV lines on the western side of the RTO’s footprint. Overall, the 138-kV system had the most issues, with 77 violations identified.
The runner-up was the 345-kV system, with 46 violations identified. That system also had 35 of the 37 overall total high-voltage violations. All 35 were in the MAAC region.
Of the total 190 flowgates identified with violations, 41 will be included in the 2017 RTEP proposal window: 33 in the West region, five in the South region and three in MAAC. Generation delivery issues account for 35 of the available projects and six are N-1 thermal violations.
The remaining 149 flowgates were excluded because they were either “immediate need” projects or under 200 kV, which are expected to be addressed by the incumbent transmission owner.
VALLEY FORGE, Pa. — Going into last week’s Market Implementation Committee meeting, it appeared that PJM and its Independent Market Monitor would not find common ground regarding several changes to Manual 11 in preparation for implementing intraday offers on Nov. 1. (See “Revision on Intraday Offers Postpones Vote,” PJM MIC Briefs: July 12, 2017.)
“I don’t believe we are going to come to agreement on [the differences], so even if we delay the vote until next month, there is still going to be a difference of opinion,” said PJM’s Lisa Morelli.
But stakeholders pressed the sides to coalesce around a proposal, which resulted in PJM and Monitor staff — along with Calpine’s David “Scarp” Scarpignato — huddling during a break to hash out their dispute. The outcome is expected to be available for the Markets and Reliability Committee meeting on Aug. 24.
The issues were twofold: first, whether or not generators’ ability to “opt in” to utilizing intraday offers must be enunciated in their fuel-cost policies; and second, how to apply offer caps when a unit decides to change its offer after it has already received a commitment and failed the three-pivotal-supplier test.
Later in the meeting, IMM staff member Joel Romero Luna detailed differences with PJM on the triggers for updating price- and cost-based offers. The Monitor argued that they need to be updated simultaneously, even if the generator only wishes to update one, and the fuel-cost policy must specify the events that will trigger an update. If both offers did not have to change at the same time, it would permit the exercise of market power, the Monitor said.
“The point of intraday offers is to ensure that the current market value of gas is reflected in power prices. If the cost of gas goes down during a day and the generation owner does not have to reduce the offer, then the result is the exercise of market power,” Monitor Joe Bowring said. “If the generation owner opts for flexibility, which we think is a good idea, flexibility must reflect both increases in gas costs and decreases in gas costs.”
The Monitor also argued that all market-power mitigation analysis and approval should keep up with offer updates, but PJM said those revisions would require additional Tariff changes that might not receive FERC approval by the necessary Nov. 1 implementation date. PJM’s revisions, staff argued, could be implemented immediately. The Monitor’s changes would also require additional software changes, Morelli said.
PJM hoped to have its revisions approved and then work with the Monitor on its revision requests, but stakeholders asked that the two staffs resolve their differences before taking a vote.
“You can get it together now, or let’s go straight for guns and lawyers,” said Ruth Ann Price of the Delaware Division of the Public Advocate office. She expressed worry that no process had been defined or agreed upon to address the Monitor’s concerns if the PJM revisions were endorsed, and about the costly and time-consuming process involved in filing an action at FERC that could impede the smooth implementation of intraday offers.
Scarp said it was important that any additional changes be discussed through the stakeholder process and not be a “grand bargain” between PJM and the Monitor. Morelli said any changes would be presented as an expedited problem statement and issue charge.
The Monitor’s position received some pushback from generation owners.
“I think that if [an offer is] not mitigated, I shouldn’t have to have people sitting around, making work for them, just to appease [the Monitor] just because we made a market decision,” American Electric Power’s Brock Ondayko said.
UGI’s Gil Crystle questioned why price- and cost-based offers should be linked in the fuel-cost policy for simultaneous updating, as price-based offers can be adjusted for little more reason than just trying to get dispatched. “My price-based offer, I can change that all day long for no apparent reason, right?” he asked. “There can be a scenario where I don’t even care. … I’ll take whatever the market bears.”
Following the conclave, the sides agreed to defer the MIC vote until September’s meeting but work together to have the single proposal prepared for the August MRC meeting. The MRC vote will be held at the September meeting. The proposal will include all revisions that both sides agree can be implemented by the Nov. 1 deadline. They will also present Tariff and manual changes that both sides agree on, but that PJM believes will require FERC approval for implementation. The Monitor will present a problem statement and issue charge in September or October for the “opt in/opt out” changes on which PJM does not agree.
In a related disagreement, PJM and the Monitor also outlined their differing Manual 11 revisions for energy market offer verification. PJM’s revisions would limit offers to a hard cap of $2,000/MWh for dispatch and setting LMPs. Only cost-based offers would be allowed to exceed $1,000, and all but those that set LMPs would require verification. The Monitor acknowledged verification is essential and raised a list of issues with PJM’s proposal focused on the inadequacies of PJM’s approach to verification.
PJM is also removing references to offer capping and market-power mitigation from Manual 28, as they are now in Manual 11.
Fuel-Cost Policy Update
As part of the preparation for implementing intraday offers on Nov. 1, PJM and IMM staff have been working with generators to get fuel-cost policies reapproved. Policies were submitted in May to conform with recently implemented analysis changes. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)
Romero Luna said 56% of units passed Monitor evaluation for Nov. 1. Among the failed submissions, some only required minor changes such as formatting, while others required major changes to conform with the new rules regarding intraday offer updates. The policies requiring major changes are “all gas units, basically,” Romero Luna said.
PJM’s Jeff Schmitt also outlined changes that the RTO is requesting for fuel-cost policy submissions, such as indicating if the variable operations and maintenance, emissions or 10% adders are used in cost-based offers.
“You’ve got to think through how you’re going to create a $1,000 offer and above,” he said.
Stakeholders endorsed by acclamation two problem statements and issue charges proposed by the Monitor. (See “IMM Presents Problem Statements on Transmission,” PJM MIC Briefs: July 12, 2017.)
The first set addresses what the Monitor believes is the need for clear rules governing the use of transmission penalty factors in setting prices in the PJM energy market when there is locational scarcity.
The second addresses market path/interface pricing point alignment, calling out situations that can arise when market participants submit transactions that are not consistent with actual physical power flow. Market manipulation results when scheduling is inconsistent with actual power flows, Bowring said. “There’s not an explicit rule” covering the issue, he said. “There needs to be a clear rule for the benefit of those entering transactions, for other market participants and to ensure that market power is not exercised.”
A “Top 10” project list emerged after stakeholders ranked 34 market modification proposals in the RTO’s annual Market Roadmap process, MISO Senior Manager of Market Strategy Mia Adams said during an Aug. 10 Market Subcommittee meeting.
Stakeholder scoring results still have to be tallied alongside staff weightings to arrange what market projects the RTO will eventually undertake first.
“This is not a prioritization yet. We’ll come back again this fall with an updated work plan,” Adams said. “However, it does look like [staff and stakeholders] are in pretty good alignment this year, more so than last year.”
This year, MISO limited stakeholders’ scoring to a maximum of four “high” and six “medium” priority designations, with an unlimited number of “low” and “do not pursue” designations. This year’s market project candidates included proposals outlined in the Independent Market Monitor’s annual State of the Market report. (See MISO, Stakeholders Embark on Market Roadmap Rankings.)
Rising to the top of stakeholder priorities: energy storage. Sixty-one market participants with voting rights determined that the most pressing issue for the market is defining a new resource type to accommodate the unique qualities of energy storage. During a special storage workshop last month, stakeholders asked MISO for a storage market definition. (See MISO Rules Must Bend for Storage, Stakeholders Say.)
Three other issues earned high priority from stakeholders:
Creating an automatic generation control software enhancement that deploys fast-ramping resources more quickly. MISO currently estimates that software can be operational in late 2019;
Better modeling of MISO’s approximate 40 combined cycle generators worth 29 GW, which was first requested by market participants in 2011 and is currently in a benefit analysis and design option phase. The new modeling could save an annual $14 million to $34 million in production costs, according to MISO’s Yonghong Chen, but won’t be ready until 2020.
Market improvements recommended by Monitor David Patton took four of the six medium-priority designations in final stakeholder scoring:
Setting up short-term capacity pricing and reliability standards so energy can be provided within 30 minutes when needed to manage capacity needs;
Factoring seasonal needs and risks into the capacity auction;
Refining modeling and rules so demand response and storage resources “operating across multiple buses” can aggregate to meet a minimum megawatt participation limit;
Expanding conditions and temperature-adjusted transmission ratings into MISO’s Energy Management System;
Creating a virtual spread product; and
Incentivizing frequency response service.
MISO will release its final Market Roadmap by December.
Five-Minute Settlements Delayed?
Several stakeholders have asked MISO to consider pushing back the March 1, 2018, target for implementing the five-minute settlements calculation. (See “Five-Minute Settlements BPM due in Summer,” MISO Market Subcommittee Briefs.)
Northern Indiana Public Service Co.’s Bill SeDoris said his company is still awaiting Business Practices Manual language while it works to implement five-minute settlements, and could miss the deadline while still making software and mechanical adjustments. DTE Energy’s Nick Griffin agreed.
“We are hearing from folks the same concern,” said MISO Executive Director of Market Design Jeff Bladen. “We are still subject to a FERC order. … We can ask for an extension, but we have a FERC order that we have to comply with. That said, we can only do what everyone is feasibly capable of.”
Bladen said MISO has already requested a later implementation date than other RTOs, but it will further discuss the possibility of an extension during the September Market Subcommittee meeting. He said MISO still has a team working to create five-minute settlements rules, but the work, originally due in early summer, has been delayed. It is also working on identifying units that habitually deviate from setpoint instructions, he said.
MISO has used geometric analysis to identify 159 electrical pricing node candidates to comprise Mississippi’s own commercial trading hub, said Michael Robinson, principal adviser of market design.
The nodes are located in both the MISO South and Southern Mississippi Electric Power Association territories, Robinson said. All other MISO trading hubs contain at least 100 electric pricing nodes, and the RTO’s analysis considered 622 possible nodes.
The proposed hub, the first MISO hub in the state, will be rigorously stress-tested over the next two months before final recommendation is made at the October MSC meeting, Robinson said. The RTO hopes the new hub will go live before the end of the year. (See MISO Examines Potential Mississippi Trading Hub.)
Market Reopen Incident
Stakeholders also asked why MISO had to briefly reopen its day-ahead market after market close on July 26.
MISO Executive Director of Strategy Shawn McFarlane called the reopening a “market participant issue.”
“To not correct this issue would have caused all other sorts of issues in the market,” McFarlane said, adding that the error fell into the “broad category” of data-entry errors. He declined to provide any other details.
Tariff changes made last year enable MISO to extend or reopen the day-ahead market to address technical problems. (See “Day-Ahead Market Extension to be Written into Tariff,” MISO Market Subcommittee Briefs.) Stakeholders asked MISO officials for a future presentation describing under what scenarios MISO may reopen the market. Bladen said MISO could put together a presentation for the September MSC meeting.
AUSTIN, Texas — Industry experts and ERCOT stakeholders and staff jammed the Texas Public Utility Commission’s hearing room Friday for the first of several discussions on scarcity pricing and other price-formation issues in the grid operator’s energy-only market.
The PUC workshop was called to discuss a report commissioned by independent power producers NRG Energy and Calpine, which asserted that subsidized renewable resources, socialized transmission planning and the lack of local scarcity pricing have “exposed areas where there is a need for adjustments” to the ISO’s pricing rules. (See PUCT Workshop to Address ERCOT Market Improvements.)
Some participants were not convinced of the need for the session.
Amanda Frazier spoke for Luminant, the state’s largest generator, when she wondered aloud what ERCOT market problem needed to be solved. “We don’t believe the question was answered,” said Frazier, vice president of regulatory policy for Luminant parent Vistra Energy.
The report, “Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT,” recommends several market improvements, including adjusting the operating reserve demand curve (ORDC) and adding local scarcity pricing, to address intermittent renewables and improve incentives for generators.
“Fundamentally, we don’t see the system as broken,” said Harvard University’s William Hogan, who cowrote the report with FTI Consulting’s Susan Pope. “We tried to look at those issues … scarcity pricing and related subjects, that might be considered further. They’ve been discussed in the past and postponed, but now might be a good time to look at them.”
| Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT; William W. Hogan, Harvard University and Susan L. Pope, FTI Consulting
Commissioner Ken Anderson agreed with the report’s conclusion that the ERCOT system isn’t broken.
“It’s been six years since we went to the nodal system,” Anderson said. “I think it’s a good time to see whether we need any material improvements to the system, and what the costs and benefits to the system are.”
Unlike RTOs in the East, ERCOT does not run a capacity market, which pays generators to keep their plants ready to run. The Texas grid relies on price spikes during scarcity events — currently capped at $9,000/MWh — to incent the construction of new plants and maintenance of aging facilities.
However, ERCOT’s nearly 20 GW of wind generation and an expected wave of solar generation threaten to push the grid’s coal- and nuclear-fired generation out of the market. Investment firm Tudor, Pickering, Holt & Co. has said all but two of Texas’ 15 coal plants are losing money.
Still, scarcity pricing is “working just as designed,” Hogan told the commissioners as he and Pope reviewed their report with the PUC.
“You’ve been fortunate in that you have a lot of capacity and short-term load growth,” Hogan said. “Scarcity pricing has been pretty small, which should happen. It’s working … but the other side of story is it’s not been severely tested.”
“If someone asked me today what’s the biggest problem with our market, it would be that we have too much power,” Commissioner Brandy Marty Marquez said. “We do have so much surplus.”
David Patton, president of Potomac Economics, ERCOT’s Independent Market Monitor, cautioned against relying on the generation surplus. The ISO has said it has 81.6 GW of capacity available this summer, more than enough to meet a projected demand peak of 72.9 GW.
“It can be easy to have a false sense of security and think you have this big surplus. Then, all of a sudden, a couple of units retire and there’s no surplus any more, in the span of a year,” Patton said. “It’s pretty clear to me there are resources in Texas under extreme economic pressure. If operators decide it’s not worth it to continue losing money, you’ll see the surplus disappear.”
Patton reminded the commission of the Monitor’s recent State of the Market report, which listed co-optimizing energy and ancillary services among seven proposed market improvements. The report suggests using a local reserve product, such as the 30-minute reserves used by other RTOs, and considering including marginal losses in LMPs. (See ERCOT Monitor: Optimizing Energy, A/S Top Priority.)
“Implement software to better commit peaking resources more economically,” Patton said. “Whatever you do to try and solve the RUC [reliability unit commitment] problem with regard to pricing, it’s probably much less if you economically commit those units and assist participants with committing those units in a short time frame.”
Patton has a supporter in Golden Spread Electric Cooperative’s Mike Wise. The co-op’s s senior vice president of regulatory and market strategy, who has railed against the use of RUCs in both ERCOT and SPP, said it has supported a local reserve product since 2013.
“Additionally, Golden Spread has had positive experiences with real-time co-optimization in [SPP] and is optimistic ERCOT can realize significant benefits from implementation of that feature as well,” Wise said. “An effective marginal-loss methodology helps achieve the best price signals in an organized wholesale electric market.”
Vistra’s Frazier disagreed.
“We’re concerned with Dr. Patton’s suggestions that we should make major changes to the wholesale market just because economists generally think they are good ideas, without assessing the costs and benefits of those changes,” Frazier said. “This is particularly the case since all three experts admitted that they had not performed any studies to evaluate the impacts of implementing marginal losses in ERCOT,” she said, referring to Patton and the study’s authors.
Assessing the costs and benefits of implementing real-time co-optimization and scarcity pricing has been left to the ISO. Staff has already estimated it will take at least $40 million and up to five years to deploy co-optimization, citing the project’s complexity and scope: It would affect 13 ERCOT systems. Staff have yet to define requirements or develop a design, and face months of testing and market trials.
“It’s a large-scale, high-impact project. It impacts multiple core systems of ERCOT,” said Chad Seely, ERCOT’s general counsel and corporate secretary. “A large assumption here is if the commission decides to move forward with real-time co-optimization, we would still work on other projects while also working on real-time co-optimization.”
“I had hoped this was a simpler process, given that other RTOs have done it,” Anderson said.
Seely told the commissioners ERCOT would likely have to rely on outside consulting to quantify the benefits of the proposed market improvements.
“I’m not sure how I think about that,” Anderson said. “I’m a little hesitant to launch off on a project of this magnitude and complexity, particularly based on ERCOT’s view that this is a four- or five-year project and a $40 million cost.”
“On the other hand, if you have too many more $50 million [reliability-must-run contracts], that load could have already bought [the project],” Marquez pointed out, referring to a costly RMR contract in Houston that recently ended. (See ERCOT Ending Greens Bayou RMR May 29.)
Implementing scarcity pricing would be a project similar in cost and scope as the co-optimization initiative, staff said. Kenan Ögelman, ERCOT’s vice president of commercial operations, said staff have discussed marginal losses and locational reserves with NYISO and ISO-NE. ERCOT has promised further information on co-optimization and scarcity pricing before the PUC’s Oct. 12 open meeting.
Anderson also asked Patton to file with the PUC a document that would put “meat on the bones” of his proposal to address RMR issues with a local reserve product.
The workshop was the first of at least two, although the next session has yet to be scheduled. Several stakeholders took advantage of the opportunity to question Hogan, Pope and Patton. Stakeholders also have been promised a chance to present their cases for and against the market recommendations.
The two commissioners — a third is not expected to be appointed until Texas’ current special legislative session ends — will take up the issue again at their next open meeting Thursday. PUC staff said they would resubmit their May 31 request for comment, which includes a list of questions for stakeholders, as a starting point in the docket (No. 47199).
“I want to chew on this cost and benefit analysis,” Anderson said. “I’m inclined to believe there are proposals, or changes or modifications, that make a lot of sense. The question is, what foundation do we need to build or support a decision like that?”
The RTO Insider Top 30 collectively had a good second quarter, but nearly half the companies turned in worse bottom-line performances than a year ago.
| Company Filings
The Top 30’s total income rose 18.1% to $5.9 billion on an 8.2% increase in revenue to $75.4 billion. In all, 26 companies were profitable in the quarter, but only 16 saw their income rise from a year earlier. Eleven posted income declines, one — Great Plains Energy — swung to a loss, and two saw their losses increase.
Sempra Energy posted the largest percentage increase in net income, earning $248 million in the quarter, up from only $27 million the year prior.
On an adjusted basis, Sempra’s earnings increased to $276 million from $200 million the year before. Excluded from the calculations for the last quarter were a $47 million impairment of Sempra Mexico’s Termoeléctrica de Mexicali assets and $28 million in recoveries related to a permanent release of pipeline capacity. Also excluded were $123 million in losses from the release of pipeline capacity at Sempra LNG & Midstream and about $60 million in deductions related to a 2016 rate case at its California utilities.
| Company Filings
Pacific Gas and Electric posted the second largest percentage increase in net income, nearly doubling profits to $406 million. In its earnings press release, the company attributed the gain to two rate cases.
NextEra Energy had the third largest percentage increase at 47%, as its net income rose to $793 million. CEO Jim Robo attributed the gain primarily to new investments at the company’s Florida Power & Light and NextEra Energy Resources subsidiaries.
Company
Market Cap ($ billions)
Revenue Q2 2017 ($ billions)
% change vs. 2016
Net income Q2 2017 ($ millions)
% change vs. 2016
Alliant Energy Corp
$9.6
$0.77
13.23%
$94.30
12.40%
Ameren Corp
$14.1
$1.54
7.78%
$193.00
31.29%
American Electric Power Co Inc
$34.7
$3.58
-8.13%
$375.00
-25.31%
Avangrid
$14.4
$1.33
-7.51%
$120.00
17.65%
Berkshire Hathaway Energy Co
NA
$4.55
10.51%
$574.00
7.09%
Calpine Corp
$5.0
$2.08
79.04%
$(216.00)
NA
Centerpoint Energy Inc
$12.4
$2.14
36.15%
$135.00
NA
CMS Energy Corp
$13.3
$1.45
5.69%
$92.00
-25.81%
Consolidated Edison Inc
$25.3
$2.63
-5.76%
$175.00
-24.57%
Dominion Resources Inc
$49.7
$2.81
8.28%
$390.00
-13.72%
DTE Energy Co
$19.4
$2.86
26.22%
$177.00
16.45%
Duke Energy Corp
$60.0
$5.56
6.56%
$686.00
34.77%
Edison International
$25.9
$2.97
6.77%
$278.00
-0.71%
Entergy Corp
$13.7
$2.62
6.33%
$409.92
-27.74%
Eversource Energy
$19.6
$1.76
-0.25%
$230.75
13.31%
Exelon Corp
$36.0
$7.62
10.32%
$80.00
-70.04%
FirstEnergy Corp
$14.3
$3.31
-2.71%
$174.00
NA
Great Plains Energy Inc
$6.7
$0.68
1.76%
$(22.10)
NA
NextEra Energy Inc
$69.1
$4.40
13.77%
$793.00
46.85%
NiSource Inc
$8.6
$0.99
10.37%
$(44.40)
NA
NRG Energy Inc.
$7.8
$2.70
20.15%
$(626.00)
NA
OGE Energy Corp.
$7.1
$0.59
6.35%
$104.80
46.57%
PG&E Corp.
$35.4
$4.25
1.94%
$406.00
97.09%
Pinnacle West Capital Corp
$9.9
$0.94
3.19%
$167.44
38.03%
PPL Corp
$26.4
$1.73
-3.36%
$292.00
-39.54%
Public Service Enterprise Group Inc
$23.0
$2.13
11.97%
$109.00
-41.71%
Sempra Energy
$29.0
$2.53
17.49%
$248.00
818.52%
Wec Energy Group
$20.1
$1.63
1.84%
$199.10
9.76%
Westar Energy Inc
$7.2
$0.61
-1.95%
$72.07
-0.38%
Xcel Energy Inc
$24.5
$2.66
8.78%
$227.26
15.48%
Totals
$75.4
8.24%
$5,894
18.56%
NOTE: No % change is listed for net income if either the current quarter or previous year was a loss.
All wasn’t tangerines and cream for NextEra during the quarter, however, as the company had its attempt to acquire Oncor rebuffed a third and final time by Texas regulators. (See NextEra Seeks $275M Fee for Failed Oncor Bid.)
FirstEnergy posted the largest earnings gain in dollars during the quarter, rebounding from a loss of $1.1 billion in the second quarter of 2016 to post a net income of $174 million. Despite the improvement, CEO Chuck Jones declared during the company’s earnings call that he thinks the “country is heading for a disaster” because of its heavy reliance on natural gas for power generation. (See FirstEnergy CEO Says Country Heading for Natural Gas ‘Disaster.’) FirstEnergy’s large loss last year was because of the closure of five uneconomic coal plants; it says it is getting out of the competitive generation business.
NRG Energy lost the most money ($626 million) in the quarter and saw its loss increase the most ($433 million). It actually earned $93 million from continuing operations, however, and in its earnings conference call, CEO Mauricio Gutierrez expressed optimism about the lawsuits against the zero-emission credit programs in New York and Illinois in which the company is a plaintiff, even though both were dismissed last month. Appeals are pending. (See NRG CEO Hopeful About ZEC Suits, Company Future.)
Calpine posted the second largest loss, $216 million, after losing $29 million in the second quarter of last year. The Houston-based merchant generator had an adjusted profit of $419 million in the quarter, and Bloomberg reported that it was in talks to be acquired. (See Q2 2017 Earnings Briefs.)
Exelon, which stands to benefit from the ZEC programs if they are upheld, posted the largest decrease in net income, dropping 70% to $80 million, because of a $250 million loss from its generation division. (See Exelon Confident on ZECs; Will Seek PJM Changes.)
Rising natural gas prices will likely mean an end to ERCOT’s all-time low energy prices, according to the Independent Market Monitor’s midyear review of the Texas grid operator’s market.
IMM Director Beth Garza told the ERCOT Board of Directors last week that real-time prices are up almost 40% over the first half of 2016, averaging $28.50/MWh, compared to $20.41/MWh during the same time last year.
The load-weighted average for all of 2016 was $24.62/MWh — the lowest ever since the nodal market’s implementation in late 2010. (See “IMM Year in Review: Low Prices, Windy, Lots of RUC,” ERCOT Board of Directors Briefs.)
Garza said the rise in prices is linked to a corresponding increase in gas prices, which have gone from less than $1.70/MMBtu in early 2016 — “The lowest gas prices I’ve certainly seen in my career,” Garza said — to pennies shy of $3/MMBtu this month. Gas prices averaged $2.45/MMBtu in ERCOT last year.
The Energy Information Administration has attributed the rising prices to an increase in exports to Canada and Mexico. The Mexican energy market in recent years has been replacing coal- and oil-fueled generation with natural gas.
The increasing cost of gas has also resulted in a decrease of its use for generation. Gas accounted for 35% of ERCOT’s fuel generation during the first half of the year, down from 44% for all 2016. Coal and wind sources have picked up the slack, increasing to 32% and 21%, respectively, through June, up from 29% and 15% last year.
| Potomac Economics
Garza also noted that price spreads between ERCOT’s cheapest (West) and most expensive (Houston) zones have been increasing as well, from a $4 spread in the first half of last year ($18 to $22/MWh) to $11 through June 2017 ($23 to $34/MWh), because of increased congestion. ERCOT’s top 10 constraints have accumulated approximately $375 million in congestion costs, more than halfway to last year’s total of about $500 million.
“So, [there is] more frequent, more costly congestion going along with those higher prices,” Garza said in summation.
Much of that congestion occurs in the Houston zone. A constraint on a path that imports energy from the north has incurred more than $90 million in costs through the first six months, almost double its $49 million in congestion costs for all of 2016.
The Houston Import Project, a $590 million project scheduled to be completed by summer 2018, is expected to resolve much of the congestion. In the meantime, however, lines being taken out of service to enable construction of new facilities has exacerbated the problem, Garza said.
“I think that’s what we’re seeing this year,” she said.
ERCOT BOD Chair Craven Crowell (left) and CEO Bill Magness
ERCOT CEO Bill Magness said higher-than-expected congestion in the day-ahead market also resulted in a surplus in the congestion revenue rights (CRR) balancing account. The unexpected balance resulted in a $24.2 million credit to load in June.
Gas Production Affects Texas Grid
Staples
Todd Staples, president of the Texas Oil & Gas Association, said fracking and improved technologies that have reduced the cost of natural gas have also made the U.S. the largest producer of natural gas in the world.
Natural gas production has grown almost 30% since 2010, Staples said, with Texas leading all states by accounting for more than 27% of U.S. marketed natural gas production in 2015. The Lone Star State also has 90 Tcf of proven natural gas reserves, 26% of the nation’s total.
“Low-cost natural gas is the reason you’re seeing billions of dollars of capital investment in Texas for today and the long haul,” Staples said. “This capacity is the reason you see the strength of continued planned investment and development in Texas. This infrastructure, what we have in place today and what is planned for the future, is the reason we think we’ll have this continued growth.”
Much of the production takes place in the Permian Basin of West Texas. Staples said he expects “the Permian will be active no matter the highs and lows of the investment market.”
ERCOT’s Warren Lasher presenting to the August ERCOT BOD meeting
Warren Lasher, ERCOT’s senior director of system planning, said natural gas production, consumption and exports are causing localized growth in electric demand. He pointed to the natural gas extraction in the Permian Basin but also noted industrial demand near Houston and the several LNG facilities being built on the Gulf of Mexico.
“We’re working with providers in the area to ensure we’re meeting their demand,” Lasher said.
He said ERCOT is beginning a study to ensure the existing pipeline capacity can meet demand, given recent changes to both the natural gas system and the ISO’s grid. A 2012 assessment of the Texas region’s natural gas infrastructure found the existing pipeline capacity was sufficient to meet demand, even with the expected growth of natural gas generation capacity.
Recent staff planning studies have not identified any single points of disruption on the natural gas system that would have a significant impact on ERCOT generation capacity, Lasher said.
“It’s not an issue now,” he said, “because there’s so much pipeline capacity in Texas.”
ERCOT on Track to Finish 2017 $5M Under Budget
Magness said the ISO is projecting a $4.5 million favorable variance in net revenues at year’s end, based on current balances and the load forecast for the remainder of 2017. A $3.1 million savings in interest expenses for project funding is $3.1 million under budget because of minimal use of revolving lines of credit.
July’s record-breaking demand helped ERCOT erase $1.3 million of a $2.1 million unfavorable variance in system administration fees. The Texas grid has yet to break 70 GW this summer, “but there’s a lot of August yet,” Magness said.
While Texas has sufficient capacity to meet demand, more is on the way. Magness said ERCOT had received 306 active generation interconnection requests totaling 67.6 GW — including 30.2 GW of wind generation — at the end of June. The ISO had 19.3 GW of wind capacity in commercial operation as of July 1.
Magness also said the Aug. 21 solar eclipse will have a “likely minimal” impact on the ERCOT region, with much of it in North Texas. Ancillary services and the solar forecast will address the expected effects, he said.
However, the April 8, 2024, eclipse’s line will pass over the middle of Texas. “So that’s something to look forward to,” Magness said.
Board OKS 2 Revision Requests, SCR
The board’s unanimously approved consent agenda included two nodal protocol revision requests (NPRRs) and a system change request (SCR):
NPRR822: Designates the procedure for identifying resource nodes as an “other binding document” instead of a “business practice manual.” It also adjusts the process for handling a retired resource’s nodes by allowing ERCOT to convert CRRs at that node to a different, nearby settlement point.
NPRR833: Adjusts NPRR827’s language to account for the base-case model when ERCOT implements the long-term, automated change affecting point-to-point (PTP) obligation bid clearing. The NPRR updates the day-ahead market optimization engine to address situations where a contingency disconnects a resource node. The engine will pick up the PTP megawatts and distribute them to other nodes, instead of ignoring them in contingency analyses if that PTP sources or sinks at the disconnected point.
SCR792: Allows ERCOT to send consecutive clock-minute average exceedances of balancing authority area control error limits to appropriate entities, and creates a situational awareness display in the information system’s public area showing the exceedances.
