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.
CARMEL, Ind. — After two years, MISO and SPP have negotiated a memorandum of understanding to address overlapping congestion charges, implement a small interregional project type and swap flowgate control to account for power flows.
RTO officials say the MOU, which borrows elements from MISO’s coordination efforts with PJM, provides market-to-market specifics where the joint operating agreement is vague. The document won’t result in major changes in coordination, officials said.
The MOU addresses exchanging control of market flows, correcting errors in firm-flow entitlements, studying the impacts to entitlements when facility ratings are changed, capping entitlements at the security operating limit and making market-to-market hold-harmless reimbursements. (See “MISO, SPP Agree to M2M Improvements,” SPP-MISO Briefs.)
SPP Director of Interregional Relations David Kelley said the RTOs have been working to improve M2M coordination since early 2015. “These are some very complex topics that often involve months or years of negotiations,” he said.
Staff say the memo is meant to target problems the RTOs have experienced since the start of the M2M process, including ineffective real-time congestion management on flowgates and errors in settlement calculations. Kelley said the memo documents the RTOs’ “common agreement” on how to handle M2M issues. “There were honestly some different interpretations of the JOA,” Kelley said at a May 31 meeting between the two RTOs at MISO’s headquarters, the first JOA meeting in a year. MISO’s Jeremiah Doner said that given the complex interregional goals the RTOs have laid out, another JOA meeting would be scheduled soon.
Kelley said the memo’s objectives aren’t written out verbatim in the JOA, but the “intent” of the memo is in the JOA.
Ron Arness, of MISO’s seams management division, said a few of the items outlined in the MOU, such as swapping control of flowgates, will require JOA changes. Arness said the agreement still needs approval from representatives of both RTOs’ legal departments and executive leadership.
Kelley said the document won’t necessarily be filed or become public. He said the RTOs want to execute the MOU in the next few weeks and file with FERC a revised JOA to allow limited resettlements during the summer.
Swapping Flowgate Control
“The longest pole in the tent is the market flow control change. We have software being delivered for that,” added MISO Director of Forward Operations Planning Kevin Vannoy.
The memorandum allows MISO and SPP to use an alternative flowgate control at certain times when power swings are significant, so predominant market flow dictates relief control on a flowgate, and not solely which RTO has monitoring control, Kelley said.
There have been situations in the past where MISO has had 95% of the flow on a flowgate but SPP still controls it, and it’s difficult to manage, Kelley said. He added that the RTOs will only swap control of flowgates when both agree that it’s the best course of action, either resulting in better price convergence or better congestion constraints. All instances where the RTOs trade monitoring roles will be reviewed after-the-fact.
At MISO’s last Board of Directors meeting in March, MISO Market Monitor David Patton appealed for MISO, PJM and SPP to become more active in transferring monitoring of constraints. (See Tornadoes, Wind Generation Drive MISO Tx Congestion.)
Resettlements
MISO and SPP will also form a technical committee by early October to address M2M issues and resettlements, but the RTOs said they will not retroactively provide resettlements more than six months prior to the MOU except for three 2015 cases, in which SPP will refund MISO more than $600,000.
Kelley said the RTOs will not pursue any other resettlements. “While we would love to chase down every penny, we don’t think that’s effective. We don’t think that’s a good use of your dollars,” Kelley said.
Going forward, when market participants dispute settlement amounts in the M2M process, Kelley said they will have to fill out a standardized form for RTO staff to review.
Stakeholders asked if the MOU’s resettlement provisions will extend to overcharges on pseudo-tied resources from double-counting congestion. Vannoy said those charges are not in the scope of the memo, and the issue will probably be handled with FERC-ordered refunds.
Adam McKinnie, chief utility economist for the Missouri Public Service Commission, asked whether the MOU is permanent or will be continually revised depending on future resettlements.
“Is this going to be some interminable, shifting document that we’re never quite sure of?” he asked.
Kelley said SPP’s resettlements are discussed at monthly Seams Steering Committee meetings.
“You’re not my problem as much as the other RTO in this room,” McKinnie said.
“Shots fired,” Kelley jokingly replied.
Arness said MISO presents resettlement payments exceeding $250,000 at the Seams Management Working Group, but McKinnie countered that not all seams issues are routed through the group.
“I know where to go when there’s a seams issue at SPP. … It’s frequently difficult to follow seams issues at MISO,” he said.
Flowgate Management Criteria
MISO and SPP staff also revealed new flowgate management criteria in the memo and said M2M flowgates will be removed when a non-monitoring RTO does not have at least a 5% forward or dispatchable 5% reverse impacts. Flowgates can be reinstated once they pass the 5% threshold.
Vannoy said he imagined that the RTOs would address which flowgates are used in their weekly M2M staff meetings. A more formal review to remove flowgates will take place at monthly meetings between SPP and MISO staff.
Overlapping Congestion
The RTOs are currently monitoring interface pricing and are asking for stakeholder advice on how to reduce their overlapping congestion charges after a joint analysis.
The RTOs analyzed price incentives using current interface definitions, comparing them to “ideal” incentives with no congestion overlap. An analysis of binding constraints in 2015 and 2016 showed congestion pricing was 1.85 times the ideal, said Dustin Grethen of MISO’s market evaluation design group. Vannoy said the RTOs are over-incentivizing impacts of transactions, paying 85% more than necessary when congestion pricing is used.
The RTOs are considering resolving the modeling problem using either a MISO Monitor-endorsed solution in which the monitoring RTO prices the entire path from the non-monitoring RTO area with zero payments made by the non-monitoring RTO, or use a common bus interface definition in which each RTO sets its interface price “relative to a common set of interface points,” the solution MISO and PJM elected to use. (See PJM, MISO Go Quiet on Pseudo-Ties; Reach Interface Pricing Accord.)
SPP’s Tanzila Ahmed said the RTOs don’t have to use the common interface definition just because it worked for PJM and MISO. “We’ll possibly see if there are other solutions. These two solutions might not work perfectly with SPP and MISO.”
MISO and SPP currently charge or credit congestion for the entire path of pseudo-ties, even when the path crosses into another balancing authority.
The RTOs are also considering varying levels of rebates depending on whether they adopt a common bus definition and the eventual scheduling of pseudo-ties in the day-ahead market to address the double-charging problem, Vannoy said. They’re also still analyzing pseudo-tie data and the RTOs’ separate modeling methods and have not yet arrived at any solution, he said.
Replacing Freeze Date, Implementing TMEPs
As with PJM, MISO is aiming to replace the freeze date by which firm-flow entitlements are calculated with SPP with four tranches based on generator in-service date, and implement a targeted market efficiency project (TMEP) type for cost-effective and congestion-relieving seams projects that might otherwise be overlooked because of their low cost and small size. (See “Four Categories for Freeze Date,” MISO, PJM to Try Again on FERC Pseudo-Tie Filings; MISO-PJM TMEP Projects Drop to Five.)
MISO and PJM filed to implement TMEPs in their JOA on Dec. 30 (ER17-721); the two have identified $17.25 million worth of upgrades in five TMEP candidate projects. By September, both RTOs hope to finish evaluation of TMEP candidates and ask for board approvals by the end of the year.
MISO and SPP could begin drafting JOA and Tariff language to create the project type while looking for small project candidates that could relieve historical congestion on the seam, said Davey Lopez, MISO adviser of planning coordination and strategy. He said the RTOs could determine regional and interregional cost allocation throughout 2018 and have board-approved projects ready for construction by early 2019.
Entergy’s Yarrow Etheredge said she was apprehensive that the RTOs will begin selecting projects before the JOA language is finalized. She wondered if MISO and SPP had considered that their TMEP would have different criteria than a MISO-PJM TMEP. “The needs on the PJM-MISO seam are so different than the needs on the SPP seam, so an entirely different process could be warranted,” she said.
Lopez said the RTOs built enough time into the project creation and selection timeline for multiple rounds of stakeholder reviews. Kelley also said there is room for “commonalities” between the two types of TMEPs, and SPP stakeholders have signaled that there is appetite for a similar TMEP project type creation.
McKinnie asked if MISO and SPP assume that no TMEPs would be opened to competitive bidding because of the short timeline. MISO engineer Adam Solomon said MISO expects that “99%” of TMEP project candidates — including all five current MISO-PJM TMEP candidates — will be upgrades to existing facilities and therefore not open to competitive bidding.
CARMEL, Ind. — Barring a FERC denial, MISO says it will begin sharing gas usage profiles of gas-fired generators with three natural gas pipeline owners before winter as part of a pilot program aimed at improving reliability.
Mark Thomas, MISO manager of gas-electric coordination, said the RTO will offer day-ahead hourly usage profiles to Northern Natural Gas, ANR Pipeline and DTE Energy in an effort to ensure adequate fuel supplies for gas-fired generators.
MISO filed with FERC last month for approval to share hourly burn estimates with select gas operators (ER17-1556).
The RTO doesn’t have a fixed target date to begin sharing the profiles, but staff would like to begin before winter hits and gas usage spikes, Thomas said during the June 1 Reliability Subcommittee meeting. MISO will await FERC approval before sharing any data.
Thomas stressed that MISO will only communicate aggregated data, but he also said sharing nonpublic operational information is “consistent with FERC Order 787.” He added that the RTO will “execute nondisclosure agreements and notify gas pipelines and utilities of existing FERC rules which enforce protection of nonpublic information.”
In April, some stakeholders voiced reservations about the pilot, saying the sharing of estimated day-ahead data could harm reliability if gas operators begin to make burn rate decisions relying solely on partial data. (See MISO Stakeholders Question Electric-Gas Info Sharing.)
Work Group Produces MISO Resilient Operations Plan
MISO is putting emphasis on resilient operations in the response to stepped-up NERC Critical Infrastructure Protection standards.
Kim Sperry, liaison to the Resilient Operations Work Group (ROWG), presented the RSC with a work plan outlining short-term reliability goals . In one to two years, MISO wants to establish better threat procedures for areas under greater risk for outages and work with local balancing authorities to specify alternatives for balancing during extended outages. She said that the ROWG will submit the balancing authority resiliency topics to the Steering Committee for issues assignment.
By 2019, the RTO also hopes to automate the entry of large volumes of data and identify alternative methods of communications when traditional means are not functional, Sperry said.
MISO’s outage restoration plans will focus on “black sky” outage situations — larger regional outages that last considerably longer than average operational or weather outages, she said.
The work plan also states that in two to five years, MISO will expand training on high-impact, low-probability events. Ongoing resiliency efforts expected to last beyond five years include cybersecurity improvements and gas-electric coordination, Sperry said.
MISO has performed a review of its reliability modeling in order to study the decline in its frequency response capability. One result: The RTO has learned there’s room to improve its dynamics modeling, according to Resource Adequacy Manager Durgesh Manjure.
Preliminary results show that seven of MISO’s 35 local balancing authorities contain generators that do not appear in the dynamics model, accounting for about 1% of generation, Manjure said. In addition, 31 local balancing authorities contain generators that do have governors appearing in the model, totaling 25%. Dynamics modeling, along with power flow modeling, is a key component of the RTO’s transmission planning.
Manjure said MISO will reach out to individual generators to confirm the absence of equipment or determine if the RTO is overlooking the equipment in its modeling inventory.
“This is a very preliminary review,” Manjure said. “We’re trying to get to a point where our models are useful.”
MISO earlier this year committed to studying its deteriorating frequency response and will later this year review performance based on collected data and compare results to actual events. (See MISO Begins Study on Declining Frequency Response.)
MISO’s Steve Swan shared the frequency response statistics supplied to NERC. Frequency response averaged -563.30 MW/0.1 Hz in 2014, -477.39 MW/0.1 Hz in 2015 and -336.30 MW/0.1 Hz in 2016. MISO’s current frequency response obligation under NERC’s frequency response reliability standard (BAL-003-1) is -211 MW/0.1 Hz.
“We’re getting to a point where this is real and our margin isn’t as big as it was a few years ago,” RSC Chair Tony Jankowski said. “I think we need to keep this a focus. It’s getting risky.”
Manjure also said MISO cannot use frequency measurements from supervisory control and data acquisition (SCADA) software for study data as originally hoped because the measurements aren’t produced quickly enough, despite the ability for SCADA to produce one measurement every four seconds. He said the RTO is investigating other means of data collection.
MISO Says Solar Eclipse No Big Deal; Energy Storage Meeting Planned
This summer’s total solar eclipse will not threaten MISO’s operations, but it can provide lessons for the future, according to RTO staff.
“It does cross through MISO’s footprint, but it’s not expected to be a significant reliability event,” RSC liaison Mike McMullen said.
Solar installations from Oregon to North Carolina will be in the path of the Aug. 21 eclipse, and portions of Illinois within MISO will be affected, McMullen said, adding that the RTO will monitor distributed energy resources during the event. He said this eclipse can serve as a learning experience in preparation for the next total solar eclipse on April 8, 2024, when he expects there to be greater solar penetration in the footprint.
“Certainly, we’ll see changes to the system between now and then,” he said.
McMullen also noted that MISO has set a tentative date of July 24 to hold a common issue meeting on energy storage.
At the April Steering Committee meeting, Consumers Energy, DTE Energy, Ameren, Xcel Energy and Indianapolis Power and Light, which all own storage resources, submitted a joint request that MISO create a model for storage’s participation in the market and track its growth using the RTO’s Market Roadmap list of market revisions. Staff also said a task team dedicated to energy storage could follow the common issues meeting. (See MISO’s Next Step on Storage: ‘Common Issues’; Task Team?)
MISO Ends Manitoba Hydro Reserve Support
MISO successfully carried Manitoba Hydro’s usual contingency reserves throughout May during the utility’s spring maintenance outages, Swan reported.
Swan said three separate contingency events occurred during the month while MISO cleared the utility’s 150-MW share of contingency reserves. The RTO stopped carrying Manitoba’s reserves May 29, when the Canadian utility’s dams returned from the outages that reduced its transfer capability. (See MISO to Make Up Manitoba Hydro Reserves During Spring Outages.)
NextEra’s “fatal flaw” was its refusal to accept “appropriate ring-fencing conditions, and any benefits offered could not overcome that failure,” Marquez said.
