CARMEL, Ind. — MISO is considering establishing a possible commercial trading hub in Mississippi and will conduct stress tests and sensitivity analyses into the fall to help support its decision.
The RTO will use 12 to 15 months of hourly price and varying load data to create hub parameters and analyze the 618 existing pricing nodes in Mississippi and nearby areas in order to test the viability of the new hub, according to Michael Robinson, principal adviser of market design.
MISO will draft a white paper for stakeholders if the study concludes the Mississippi trading hub is worthwhile, Robinson said. The RTO hopes to finalize the hub in early November and have it go live in early December.
“It looks like there’s enough here to consider,” MISO South Vice President Todd Hillman said of the upcoming study at a June 8 Market Subcommittee meeting.
The RTO has deliberated over the issue since Mississippi became its 10th local resource zone in 2015, Hillman explained. “As the South region has gotten more knowledge, what we found is that when companies look for new locations, part of the reason they might do that is the gas infrastructure, but they also do it to join RTO pricing,” he said.
Hillman also said the state is especially looking for commercial growth. “Mississippi, as you know, is the poorest state in the country, so they’re looking to use their infrastructure.”
MISO has experience in creating and managing new trading hubs. Robinson said the RTO established the FE hub in 2005, redefined the Cinergy hub in 2010 and handled the addition of the Texas, Arkansas and Louisiana hubs during the MISO South integration in 2013.
“We’ve been through this process before, and it’s been a good process,” NRG Energy’s Tia Elliott said. She cautioned that, not being familiar with MISO’s process for creating a new hub, MISO South stakeholders could appreciate periodic updates. Robinson agreed and said he would work with Hillman to keep stakeholders informed about the situation.
CARMEL, Ind. — MISO has issued its annual survey asking stakeholders to rank possible market modifications the RTO should undertake as part of its Market Roadmap process.
The survey contains 34 proposals. Stakeholder results will be measured alongside staff weightings to rank what market projects the RTO will tackle first, Senior Manager of Market Strategy Mia Adams said.
This year, MISO is limiting stakeholders’ scoring to a maximum of four “high” and six “medium” priority designations, with an unlimited number of “low” and “do not pursue” designations.
“We limit this because if everything is a high priority, nothing is a high priority,” Adams said at a special June 8 Market Roadmap workshop. She also said the RTO has finite resources and time to work on simultaneous market changes.
Stakeholders have until July 13 to return their surveys.
This is also the first year that MISO will publicly post a matrix of projects’ scores, representing an attempt to increase transparency around which market changes are pursued. Stakeholders last year voiced disappointment at what they viewed as an opaque approach to project selection. Market projects were ultimately reordered late in the process to account for stakeholder preferences. (See MISO Projects Reordered Following Stakeholder Frustration.)
Executive Director of Market Design Jeff Bladen said projects won’t begin to be ordered until after the Independent Market Monitor releases its annual State of the Market Report. “The actual ranking and prioritization process is months in front of us,” Bladen said.
MISO plans to review the results in August and present a final prioritization in September.
At stakeholders’ request, Bladen said this will be the first year in which the Market Roadmap process will show the Monitor’s recommendations alongside those of the RTO and its participants.
Last month, the Steering Committee created a pair of new project candidates based on Monitor recommendations, improving shortage pricing by revising the operating reserve demand curve to reflect a higher value of lost load and changing the day-ahead margin assurance payment and real-time offer revenue sufficiency guarantee payment rules and performance incentives to reduce gaming. (See MISO Steering Committee OKs IMM Proposals for Market Roadmap.)
Minnesota Public Utilities Commission staffer Hwikwon Ham said it would be helpful for State of the Market Reports to be released earlier in the year to enable stakeholders to read the Monitor’s recommendations before ranking projects.
Monitor David Patton said his office worked to release some project recommendation descriptions earlier this year to meet MISO’s May deadline for submitting Market Roadmap candidates. Patton said in the future his staff will target an earlier publication of the report.
“We’re changing some of our processes on the State of the Market so it better coincides with the Market Roadmap,” Patton said. Adams also said MISO is open to shifting survey deadlines to give stakeholders time to review the reports before completing surveys.
SACRAMENTO, Calif. — California lawmakers on Wednesday expressed concerns that expanding CAISO into a regional grid operator would result in higher electric bills, job losses and the export of energy development to other states.
Members of the Assembly Committee on Utilities and Energy did not appear to reach conclusions during a June 7 hearing, but they did ask detailed questions of representatives of CAISO, public interest groups and power companies.
Committee Chairman Assemblymember Chris Holden (D-41st District)
Chairman Chris Holden, a Democrat, called the hearing to gather information about whether the expansion is necessary and provides the least-cost alternative to meeting the state’s aggressive renewable mandates.
The 2015 Clean Energy and Pollution Reduction Act, which established the state’s 50% by 2030 renewable portfolio standard, also directed the state’s energy agencies to explore transforming CAISO into a regional entity to help meet the RPS target. More recently, the State Senate passed a bill setting a 100% renewable goal by 2045. (See California Senate Passes Bill Mandating 100% RPS.)
There is consensus between the legislature, CAISO and other stakeholders that expansion would have benefits, including enabling California to export its periodic oversupply of renewable generation and reducing the costs of curtailing output. CAISO cites its finding that regionalization would save electricity customers up to $1.5 billion annually by 2030. (See Study Touts Benefit of CAISO Expansion.)
But public interest groups have urged the state to go slow on the initiative, and skeptics challenged some of the study’s findings. (See CAISO Expansion in Question as EIM Grows.) Lawmakers wanted to know what the trade-off is for California consumers.
At the hearing, Republican Assemblyman Brian Dahle said he did not think the legislature had adequately studied the consequences of the “arbitrary” goal in the state’s RPS. He mentioned the costs associated with renewable curtailment and high electricity bills.
“I want to figure that out, and I don’t want to continue to have more solar if I don’t need it in the middle of the day” in some parts of the state, Dahle said. He also expressed concern about the loss of California jobs from regionalization.
This year, CAISO has curtailed about 2.6% of potential solar generation and 1.3% of renewables. But that amount could grow 10-fold and become a very costly problem, CAISO Vice President of Market and Infrastructure Development Keith Casey said. The state is well on its way to meeting a 33% RPS by 2020.
“The solution is to take a holistic approach to meeting the RPS mandate,” Casey told Dahle. That means factoring in the cost of curtailment and the differing costs of renewable resources that are used to meet the RPS.
There are abundant wind and geothermal resources in neighboring states that can be developed cheaply and support out-of-state jobs, but importing low-cost power also has an indirect stimulus on jobs in California, Casey said.
“The bottom line is there is no silver bullet here,” Casey said, asserting that California is leading the world in integrating renewables. Officials in Asia, Africa and South America visit the ISO almost weekly to study the state’s effort.
California State Capitol Building in Sacramento
“Some of this isn’t new at all,” said Jan Smutny-Jones, CEO of the Independent Energy Producers Association, which represents owners and operators of renewable, natural gas, energy storage and demand response resources. California has been involved in a Western energy market in some form for 60 years, but it could be made to work better, he said. Regionalization could reduce costs and create market opportunities.
“Our interest, quite candidly is that we want to grow that market, and we don’t think we can grow that market here in California, assuming you can get stuff sited,” Smutny-Jones said.
CAISO said its goals are to preserve state authority, transparently track greenhouse gas emissions and retain the ability of state representatives to direct policy. But Gov. Jerry Brown has heeded the concerns expressed by some, directing state agencies to take more time to develop a proposal. (See Governor Delays CAISO Regionalization Effort.)
After a pause last summer, the momentum toward regionalization of CAISO may be resuming, but the June 7 hearing indicates there will be careful scrutiny as to whether the negatives outweigh the positives for the state’s consumers and businesses.
CARMEL, Ind. — Behind-the-meter generation would need to demonstrate its deliverability before offering into MISO’s capacity auction, under a new proposal being floated by the RTO.
The proposal would allow “excess” behind-the-meter (BTM) generation without existing transmission service to submit to an optional engineering study identifying a deliverable megawatt volume of capacity eligible to be bid into a single planning resource auction. Any BTM generation that exceeds a utility’s planning reserve margin requirement is considered excess BTM, a term the RTO is considering adding to its Tariff.
But there’s a catch: the excess BTM generation volunteering for the study “must commit” to entering the same number of megawatts into the interconnection queue study process to offer capacity in any subsequent auction.
Going forward, excess BTM generation from new projects would have to enter the interconnection queue and commit to a deliverability study to obtain external network resource interconnection service like other MISO generators, MISO Manager of Resource Adequacy John Harmon said during a June 7 MISO Resource Adequacy Subcommittee (RASC) meeting.
Harmon said the optional study and subsequent queue commitment is intended to treat BTM generation more like traditional capacity resources that must demonstrate access to the transmission system before supplying capacity.
“We don’t want this optional study going into perpetuity. We want there to be a transition at some point. What we want is a commitment to go through those other study processes,” Harmon said. He asked for stakeholders to comment on the proposal by June 21.
MISO said it will continue to allow BTM generation to satisfy load-serving entities’ planning reserve margin requirements without a deliverability demonstration. Under MISO rules, demand response resources have first crack at reducing planning reserve margins, followed by BTM generation.
BTM generators identifying as load-modifying resources were able to demonstrate deliverability for excess capacity in the 2017/18 PRA by meeting with staff for a case-by-case review, a process MISO said it will not repeat in next year’s capacity auction. (See MISO to Take Case-by-Case Approach on BTM Generators.)
Stakeholders have in recent months urged MISO to consider alternatives for BTM generation to demonstrate deliverability other than acquiring full interconnection service or firm transmission service.
More BTM Generation Talk Upcoming
Harmon said the issue of BTM generation entering the capacity auction will be subject to further assignment decisions by the Steering Committee after a common issues meeting tentatively scheduled for July 24. The meeting was called after storage resource owners Consumers Energy, DTE Energy, Ameren, Xcel Energy and Indianapolis Power and Light submitted a joint request for MISO to create a model for the participation of storage in the market and to track its growth using the RTO’s Market Roadmap list of market revisions. (See MISO’s Next Step on Storage: ‘Common Issues’; Task Team?)
RASC Chair Chris Plante said the Steering Committee might task the RASC with defining the criteria for “lowercase” behind-the-meter generation, which represents resources not registered with or dispatchable by the RTO and not subject to market mitigation. “Uppercase” BTM refers to resources that can be dispatched. (See MISO Behind-the-Meter Generation Definitions Create Confusion.)
MISO hopes to adopt business practice manual language that clarifies the market treatment of BTM generation by this fall.
MISO to Study Extended Outage Effect on Loss of Load
Meanwhile, the RTO will continue to investigate whether extended outages should be factored into future loss-of-load-expectation studies. After an analysis of extended outages, the RTO has concluded that planned outages during peak times are “not trivial” to MISO’s planning reserve margin, said Ryan Westphal, of MISO’s Resource Adequacy Coordination department.
The issue will be further discussed in MISO’s Loss-of-Load-Expectation Working Group. MISO is also weighing whether to prohibit units on extended outages from offering into the PRA. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
Stakeholders on Wednesday pressed CAISO for details on a proposal to broaden and make permanent certain operational measures developed in response to Aliso Canyon gas restrictions.
CAISO is proposing to make the gas-electric coordination measures applicable to the ISO’s entire footprint — including the Western Energy Imbalance Market — and not just the Southern California area affected by the closure of the Aliso Canyon gas storage facility. (See CAISO Mulls Making Aliso Canyon Measures Permanent.)
Key among those measures is a provision allowing the ISO to limit output from gas-fired generators within a specific “gas operating zone.” The limit would allow the ISO to enforce a maximum gas burn during shortages.
Carrie Bentley, a consultant representing the Western Power Trading Forum, asked about the rationale for broadening application of that provision to areas outside those normally dependent on gas from Aliso Canyon.
“To me that seems like it would still be a Southern California issue, but given [that] you’re proposing this for the entire footprint, I wondered what operational risks you saw for the ISO, including the EIM,” Bentley said.
Mark Rothleder, CAISO vice president of market quality and renewable integration, acknowledged that the risks stemming from Aliso Canyon were still specific to Southern California.
“I think the extension — and the things that are being proposed as permanent — is really in light of potentially other types of gas-related constraints arising in other parts of the footprint that we want to be prepared for in case they do arise, not just strictly [constraints] associated with Aliso,” Rothleder said.
Bentley pressed Rothleder for more information about the risks elsewhere in the ISO system.
“I don’t want to give too much detail, but there’s broader rule changes that affect other storage facilities and how much can be withdrawn and injected to other facilities over time, and those will affect not just Aliso or Southern Cal Gas storage facilities,” Rothleder said.
The California Air Resources Board earlier this year passed tougher standards for monitoring and testing for methane leaks from all the state’s underground storage fields, as well as requiring equipment changes that could slow the flow to and from the facilities.
Site of Aliso Canyon leak in December 2016 | SoCalGas
Rothleder also pointed out the that ISO has “become aware of” gas constraints outside California.
“They are probably more localized, but they could affect multiple generators in localized areas of the EIM footprint,” he said. “And we’re at least aware of some of those that could arise [for which] we would need to enforce gas-burn constraints eventually and appropriately allocate gas to multiple physical generators.”
Rothleder said the ISO would be committed to providing “transparency and advance notice” to market participants when it must enforce a constraint and that the measure would be “prudently applied.” The Aliso Canyon gas-burn constraint has been invoked only once, over four days in January when SoCalGas had to withdraw gas from the facility to meet heating needs.
“It was more for the gas-side need than the electrical-side need,” Rothleder said of the event.
Cathleen Colbert, senior market design and regulatory policy developer at the ISO, who gave a presentation on the proposal, said EIM balancing authority areas would gain use of the gas constraint as part of their market role. “This is similar to existing authority for the EIM entities to use [to] dispatch at their discretion,” Colbert said.
Lindsey Schlekeway of NV Energy expressed confusion over how and when EIM members would use the gas constraint.
“I wasn’t sure … if we were supposed to contact the ISO and how this would really work,” Schlekeway said.
“These are some details that we will have to develop as part of the process, but I think it’s important to keep in mind that, whether or not this constraint is enforced, the decision will be made by the balancing authority area and the procedures would be established by the entity itself,” replied Anna McKenna, ISO assistant general counsel.
Ryan Kurlinski of the ISO’s Department of Market Monitoring said that extending to EIM entities the ability to enforce gas constraints would constitute “a major market design change.”
“What we’re looking for is that hopefully the ISO can provide more clarity on what are the conditions under which an EIM entity can define a gas nomogram,” Kurlinski said, referring to the diagram representing the interrelationship of fuel consumption among gas-fired generators on the system under various operating conditions.
Bentley questioned why CAISO was referring to the initiative as “Aliso Canyon Gas-Electric Coordination Phase 3” when the extended measures will in fact have broad application across the ISO. “I think the name is very misleading and I think potentially you won’t get full stakeholder review if you aren’t really clear what you’re doing here,” Bentley said.
“We actually weighed both sides of that,” replied Brad Cooper, the ISO’s manager of market design and regulatory policy. Cooper said the ISO had considered a different name but was concerned that stakeholders might lose sight of the fact that it was proposing to extend and make permanent the Aliso Canyon measures.
“So I take your point, but I think that either way, we had the potential to be misleading, and we thought it would just be clearer calling it Aliso Canyon Phase 3,” Cooper said.
“But I’m not misunderstanding this, right?” Bentley asked. “I mean, the operational risks have really very little to do with Aliso Canyon and you’re saying there’s all these other circumstances that are leading to this need.”
Colbert said the closure of Aliso Canyon had provided insights that can be applied throughout the ISO.
“We’re learning as we go, we’re learning by doing,” Colbert said. “And so other concerns have come up through our continued exercising of this gas-electric coordination. So while we’ve learned about additional constraints, and we’d like to broaden and expand the scope of this project, the genesis of it is from Aliso Canyon.”
Most of the $280 million bill for PJM’s Artificial Island project would shift from Delaware to New Jersey and Pennsylvania under two alternative analyses the grid operator developed in response to complaints about how costs for the project would be allocated.
Steve Herling, PJM’s vice president of planning, presented the grid operator’s analyses on Friday but was careful to explain that the alternative cost allocations were meant to “facilitate discussion” and that PJM was not advocating for any specific method. The right to petition FERC for any changes under Section 205 of the Federal Power Act remains with the transmission owners, he said, but “we will support any discussion FERC would facilitate on this issue.”
The cost allocations under question will cover the majority of the cost of the project. PJM spokeswoman Paula DuPont said as much as 6.8% of the total will be socialized across the PJM footprint based on the project’s reliability value.
The current allocation method would saddle Delmarva Power & Light ratepayers with about 93% of the remaining bill. The first alternative, which Herling called a “direct extension” of the current solution-based distribution factor method, would reduce DPL’s responsibility to about 7% while raising the bill for Public Service Electric and Gas to more than 42%. New Jersey’s other utilities — Jersey Central Power & Light and Atlantic City Electric — would pick up 13% and 7.3%, respectively. PECO Energy would shoulder about 20% of the costs.
The second alternative, termed a “stability deviation method,” would allocate 19% to PSEG, 15% to PECO, 12.5% to PPL, 12.4% to JCPL, 10.4% to DPL, 7.2% to Atlantic City and about 5% to Met-Ed. Herling said the method was like dropping a rock in a pond and measuring impacts based on the ripples.
| RTO Insider analysis based on PJM data
“Mathematically, you’re going to feel this disturbance all the way out to the Rocky Mountains,” he said, so PJM “arbitrarily” decided to ignore any load-bus deviations of less than 25%.
“Obviously, with the cutoff being arbitrary, it would give people some concerns,” he said. Additionally, the method would be “a lot more work for PJM,” he said, but he assured stakeholders that “it’s not something that we would shy away from.”
The failure of any of the methods will be its subjectivity, he said, and there are “any number of ways to tweak” the numbers.
“Let’s face it: advantages and disadvantages are in the eye of the beholder,” he said.
Documents and information about PJM’s conclusions were purposefully withheld until minutes before the Friday morning announcement, Herling said, because PJM wanted to be first to provide the information to its membership rather than have them learn of it through media reports.
The Delaware Public Service Commission was cheered by the new analyses, which it said “more appropriately reflect the benefits of a stability-based transmission solution.”
“Each of the alternate methods illustrate that Delaware customers benefit substantially less from the AI project than the previous solution-based DFAX cost allocation,” the PSC said in a statement.
“This is only a beginning step in a lengthy process to secure an appropriate cost allocation with results that are commensurate with the benefits to Delaware,” PSC Executive Director Robert Howatt said.
Texas regulators on Wednesday rejected NextEra Energy’s last-gasp attempt to acquire Oncor, rebuffing a request to rehear a previous decision denying the proposed $18.7 billion deal.
The Public Utility Commission of Texas reiterated the finding of its initial April order, saying Florida-based NextEra “failed to meet its burden of proof” to show its acquisition of Texas utility Oncor was “in the public interest.”
Commissioners Ken Anderson and Brandy Marty Marquez spent about a minute during their open meeting agreeing with each other’s memos offering edits to a draft order.
NextEra’s “fatal flaw” was its refusal to accept “appropriate ring-fencing conditions, and any benefits offered could not overcome that failure,” Marquez said.
Throughout the docket’s (46238) proceedings, the commissioners stressed the importance of ring-fencing measures to protect Oncor’s credit rating and local ownership — which had similarly protected the utility during the bankruptcy of parent company Energy Future Holdings.
Anderson was unmoved by NextEra’s arguments in its bid for a rehearing. NextEra had argued that the PUC went beyond the scope of its powers in rejecting the acquisition. (See NextEra’s Rejected Oncor Bid Gets Second Look.)
“It is inappropriate for NextEra Energy to attempt to amend its application to request different relief in a motion for rehearing,” Anderson wrote in his memo. “NextEra Energy has failed to meet its burden of proof to show [the transaction] is in the public interest, and so that request is denied.”
NextEra proposed last summer to purchase Oncor in three transactions:
The approximately 80% interest indirectly held by EFH;
The 19.75% interest indirectly held by Texas Transmission Holdings Corp.; and
The 0.22% interest held by Oncor Management Investment.
The PUC last year rejected Dallas-based Hunt Consolidated’s attempt to acquire Oncor, which owns and operates power lines serving 3.4 million customers. The utility’s future is central to EFH’s bid to exit Chapter 11 bankruptcy, which has dragged on for more than three years.
Both NextEra and Oncor declined to comment. At stake is a $275 million termination fee.
NextEra’s stock gained 65 cents to close the day’s trading at $142.58/share.
CARMEL, Ind. — In a shift opposed by some stakeholders, MISO has adopted the Independent Market Monitor’s recommendation to base pricing of external capacity resources on bordering balancing authorities.
MISO is now proposing a single clearing price for resources based on balancing authority in upcoming Planning Resource Auctions. For external resource zones adjacent to MISO Midwest and MISO South, the RTO plans to use historic shift factors based on energy flows to produce a blended price, Laura Rauch, manager of resource adequacy coordination, said during a June 7 Resource Adequacy Subcommittee meeting.
MISO’s original proposal for implementing external resource zones would have set prices based on geographic groupings of external generation regardless of balancing authority. (See “IMM Offers Own PRA External Zone Design,” MISO Resource Adequacy Subcommittee Briefs.)
Reliability Concern
Rauch said MISO wants to prevent reliability problems over the RTO’s growing reliance on external resources. The RTO says external resources, which averaged about 5,000 MW for planning years 2015/16 through 2017/18, could increase by more than 2,600 MW “in upcoming years.”
“It’s not too large of a concern right now because they are spread out throughout the footprint, but in the coming years, they are expected to [increase],” Rauch said.
Last month, Michael Chiasson of IMM Potomac Economics said MISO’s original proposal would mean that two external resources located in different balancing authorities could be lumped into the same external zone. He argued that preserving balancing authority borders would make for more efficient pricing.
| MISO
A MISO analysis showed that the Monitor’s proposal would have resulted in prices ranging from $6.63/MW-day in MISO Midwest’s Zones 1-3 and 5-7 for the 2015/16 PRA (versus an actual $3.48/MW-day) and $3/MW-day in MISO South’s Zones 8 and 9 (versus $3.29 actual). The Monitor proposals would not change the $150/MW-day clearing price in Illinois’ Zone 4.
Stakeholder Opposition
Not all stakeholders are sold on the Monitor’s pricing plan.
WPPI Energy’s Steve Leovy and MidAmerican Energy’s Greg Schaefer said the proposal would treat far-flung resources the same as resources close to MISO. “It strikes us as counter-intuitive, at least initially. It seems odd to us that you call this a locational proposal but you really don’t care about the location of resources,” Schaefer said.
Rauch said the concern is “not so much where an external resource is located in a neighboring balancing authority than how a resource impacts the MISO footprint.”
NRG Energy’s Tia Elliott said her company also opposes the creation of external zones and instead wants the RTO to require firm transmission to both its border and to the sink.
Rauch said resources that MISO designates as “electrically equivalent” will continue to count toward local credit as internal resources do. Some stakeholders have balked at that approach, saying it amounts to special treatment of external zones.
Last month, Consumers Energy’s Jeff Beattie said external resources should come in second to MISO resources, as the latter are factored into the Transmission Expansion Plan. MISO also ensures deliverability, while deliverability from external zones, even with firm service, is not certain, Beattie said. “Resources in the MISO footprint do receive preferential treatment, as they should,” he said.
Dynegy’s Mark Volpe said his company supports creating external zones. “We’ve always thought that an external resource counting toward the [local clearing requirement] is inconsistent when MISO does not have dispatch control over the external resource,” Volpe said.
Motion to Halt Proposal
Customized Energy Solutions’ David Sapper, representing the Load-Serving Entities sector, said MISO should simply prohibit external resources from counting toward local clearing requirements. The RTO would conduct a pre-auction check of external capacity that intends to offer to see if any are pivotal suppliers; if there are pivotal suppliers, it would have to institute new mitigation measures, Sapper said.
“We understand that reliability issues have been raised; whether that amounts to a concern or not remains to be seen,” he said.
Sapper submitted an LSE motion that called for MISO to file a capacity transfer rights proposal that would treat long-term supply arrangements involving external resources the same as internal planning resources. The RTO would delay creating any external resource zones until FERC’s final action on the filing. The motion went to an email vote that will be tallied late next week.
“As stakeholders have already noted in RASC discussions, it is impossible for LSEs to fully assess the risks of MISO’s proposal for changing the treatment of [external resources] without having certainty about the rules for the distribution of excess PRA revenue,” the motion said. It said a capacity transfer rights filing is the “proper starting point for any discussions about changing the treatment” of external resources.
“Let’s take up the hedge proposal first and wait for a FERC decision,” Sapper urged stakeholders.
RASC liaison Shawn McFarlane said waiting for final action by FERC could prevent the RTO from heading off reliability problems with the increasing amount of external capacity. Dynegy’s Volpe said it could be as late as 2025 before petitions for rehearing are resolved.
“I look forward to the day where these external resources that pose a threat to reliability one day join the MISO footprint,” Sapper said. “I think footprint growth or changes have really called into question some of these concerns.”
Beattie said Consumers has always disagreed with external resources counting toward local clearing requirements. “Local is the key word here,” he said, prompting laughs among the stakeholders. “There is more fuel diversity taking place and there are a number of plant retirements occurring. … If MISO doesn’t have control of these external resources through pseudo-tying or something else, then this new rule is worthless,” Beattie said of MISO’s revised proposal.
MISO plans to alter auction hedging under the external zones, using historical considerations to distribute excess auction revenue to shield some prioritized generators against price separation.
The first in line for excess revenues would be 500 MW of external and internal generation that opted out of the energy market when it was formed. Second would be 4,600 MW of market arrangements made before the capacity market was created, assuming their grandmothered agreements are still valid. Almost 2,800 MW of generation that signed contracts with load before MISO changed zonal boundaries in 2011 would be third in line for revenue distribution for a temporary, seven-year period.
MISO plans to file its proposal with FERC in early fall in order to introduce external zones in the 2018/19 PRA. The RTO will accept feedback on its proposal until June 21 and present any revised proposals at upcoming RASC meetings.
CAISO has proposed to make permanent its practice of curtailing gas burn at some power plants and using certain market tools to reduce the reliability risk posed by ongoing pipeline limitations stemming from the closure of the Aliso Canyon gas storage field.
Aliso Canyon Relief Well 2 | SoCalGas
Set to expire at the end of November, the ISO’s temporary mitigation measures have been “particularly effective,” it said in its “Phase 3” straw proposal seeking to extend the life of those provisions. Staff will discuss the proposal during a June 7 stakeholder call.
“CAISO proposes to make market constraint limiting the maximum gas burn of a group of generators a permanent operational tool that can be used throughout the CAISO and Energy Imbalance Market balancing areas,” the ISO said in the proposal.
The ISO said the measures are necessary because the withdrawal limitations at Aliso Canyon are set to be in effect for most of this year because of a large-scale leak that was discovered at the Southern California facility in October 2015 and plugged in February 2016.
Southern California Gas — operator of both the storage facility and regional pipeline network — recently warned state officials that the withdrawal restrictions might lead to gas supply shortages in summer and winter peak seasons. (See California Grid Emergency Comes Days After Reliability Warning.)
The commission’s approval allowed CAISO to enforce a market constraint that limits the minimum and maximum amount of gas that can be burned by generators in the affected area during periods of low gas supply. Generators have demonstrated they can regulate their minimum burns by lowering the price of their bids into the real-time electricity market.
Under the new proposal, the ISO would also have permanent authority to override its “dynamic competitive path” assessment when it determines that a transmission path is no longer competitive in the face of a gas constraint, and to suspend virtual bidding to prevent market manipulation.
CAISO also proposed to make permanent provisions that provide scheduling coordinators with two-day-ahead advisory schedules and allow gas-fired generating units to incorporate more timely fuel prices into their market offers.
Up for temporary extension are provisions that give generators the ability to reflect gas cost expectations into day-ahead bids by using an approximation of next-day gas prices, which are published after the ISO’s morning day-ahead market runs. ISO rules typically require generators to incorporate the previous day’s next-day gas prices into energy bids.
Comments on the straw proposal are due June 14, with CAISO’s Board of Governors set to vote on a final proposal in July. The EIM Governing Body will also review the measures under its advisory role.
Some stakeholders have told CAISO that they do not wish for the measures to be substitutes for permanent market reforms. The ISO said it has used the gas burn constraints sparingly and has described them as “a valuable operational tool.”
ERCOT’s wholesale market performed “competitively” in 2016, the ISO’s Independent Market Monitor, Potomac Economics, said in its annual State of the Market report filed last week with the Public Utility Commission of Texas.
However, the Monitor recommended seven potential improvements to system operations and price formation in the energy and ancillary services markets. While some of the suggestions have been seen before, this year’s report included three new recommendations, all focused on improving price formation.
The first calls for ERCOT to ensure that the price of a reliability-must-run unit’s energy “reflects the shortage conditions that exist.” The report notes that RMR units are currently required to submit energy offer curves with prices equal to the systemwide offer cap, but those units may also be needed to resolve local transmission constraints in the future. The Monitor said the RMR unit’s energy offer price will likely be mitigated when the constraint is noncompetitive, resulting in its dispatch before other competitively offered units.
“In the absence of any other market changes designed to reflect the reliability needs that caused the RMR,” the Monitor said, “we believe that pricing the energy from the RMR unit such that its costs to resolve the relevant constraint are higher than the costs of other available market-based resources will establish more efficient economic signals in the ERCOT market.”
The ISO’s stakeholders have already taken steps to address RMR contracts, driven by a 2016 agreement with NRG Texas Power’s Greens Bayou Unit 5 in Houston. The contract was terminated last month. (See ERCOT Ending Greens Bayou RMR May 29.)
ERCOT’s Board of Directors has approved three protocol revision changes, including a requirement that RMR units only be procured when they have a material impact on expected transmission overloads. Other changes clarify ERCOT’s commitment process for RMR units, update the contracting and reimbursement process for RMR units and create a mechanism to claw back capital contributions from an RMR unit if it returns to the market.
The Monitor also suggests that the ISO evaluate the need for a local reserve product, such as the localized 30-minute reserve product used by other RTOs. The Monitor contends that defining such an ancillary service product would allow the real-time energy and reserve markets to price local reserve shortages and provide the revenues necessary to satisfy local capacity needs, “eliminat[ing] the need to sign out-of-market RMR contracts.”
The third recommendation asks for ERCOT to consider including marginal losses in LMPs and using a revenue-allocation methodology to address collecting more payments for losses than their aggregate cost. “Recognizing marginal losses will allow the real-time market to produce more from a higher-cost generator located electrically closer to the load, thus resulting in fewer losses,” the Monitor said.
While the Monitor lauded ERCOT’s competitive performance, it also noted an increase in negative pricing over the last five years, driven by additional wind generation and transmission infrastructure. It said ERCOT saw 131 hours of prices at or less than zero in 2016, compared with 55 in 2015 and 44 in 2014.
The Monitor also said the market’s total congestion costs were $497 million in 2016, up 40% from 2015, primarily because of transmission outages.
The report also highlighted ERCOT’s record-low average real-time energy prices — since the nodal market’s implementation in 2010 — of $24.62/MWh, an 8% drop from 2015. It said real-time prices never exceeded their PUC-mandated limit of $3,000/MWh, and breached $1,000/MWh for only 3.9 hours.
| ERCOT 2016 State of the Market Report
ERCOT Approves Retiring 61 MW of Capacity
ERCOT has approved South Texas Electric Cooperative’s request to retire its three gas-fired units in Pearsall, southwest of San Antonio. The units, with a combined capacity of 61 MW, will be decommissioned in August.
The co-op filed a notification of suspension of operations with the ISO in April. The Texas grid operator responded by saying the units “are not required to support ERCOT transmission system reliability” and said their operations may be suspended, effective Aug. 1.
NextEra’s “fatal flaw” was its refusal to accept “appropriate ring-fencing conditions, and any benefits offered could not overcome that failure,” Marquez said.
