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 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.)
“What we know for sure is we’ll have a different FERC at the end of 2017 than we did going into the year,” LaFleur told the New England Conference of Public Utilities Commissioners’ (NECPUC) 70th Annual Symposium at the Omni Mount Washington Resort.
The Senate Energy and Natural Resources Committee is scheduled to vote June 6 on approving nominees Robert Powelson and Neil Chatterjee to two Republican vacancies on the commission. The committee questioned the two nominees at a mostly cordial hearing May 25. (See No Fireworks for FERC Nominees at Senate Hearing.)
In addition, LaFleur said, there are “rumblings” that Trump will name a Democrat to replace Commissioner Colette Honorable along with a third Republican nominee.
The five-member commission has been without a quorum since February, when then-Chairman Norman Bay resigned after President Trump stripped him of the chairmanship and promoted LaFleur.
LaFleur said the commission has issued only a fraction of the 100 commission-authorized orders it averages a month. Without a quorum, FERC staffers have been able to issue only delegated orders. Contested dockets and rulemakings have been at a standstill.
“So we are piling up quite a few cases for potential voting when [new] folks come in,” LaFleur said. “On some of these bigger policy issues … it’s not a matter of striking up an order. We’re looking to shape the policy choices in as transparent a way as possible for the incoming commissioners.
“We do have several dozen open rulemakings or generic dockets … multiple rulemakings on price formation in the electric markets, interconnection rules, [the Public Utility Regulatory Policies Act], hydro licensing terms, taxation [and] master limited partnerships in the pipeline area are some of the big ones that come to mind.
“But nothing’s higher on the mind than the issue du jour of harmonizing wholesale market rules and state policy initiatives,” she added, citing an issue that was the subject of a two-day technical conference in May. (See RTO Markets at Crossroads, Hobbled FERC Ponders Options.)
LaFleur said Trump’s decision to pull the U.S. from the Paris Agreement “could only accelerate the extent to which climate policy is increasingly being made in the states.” More than a dozen states — including Connecticut, Massachusetts, Rhode Island and Vermont in New England — have joined the U.S. Climate Alliance, with pledges to meet the Paris commitments on carbon emission reductions. (See related story, Trump Pulling U.S. Out of Paris Climate Accord.)
“There always seems to be one topic that sucks a lot of the air out of the room. I remember back when it was integrated resource planning and whether it worked. When I first came to FERC it was demand response,” she said. “Well now it’s this. … I do think this is one of the bigger things that FERC will be facing when FERC reconstitutes itself.”
Powelson, a member and former chair of the Pennsylvania Public Utility Commission, is the current president of the National Association of Regulatory Utility Commissioners. Chatterjee, of Kentucky, is a senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.).
Assuming the nominees clear the committee vote, how soon they join the commission will be dependent on when their nominations are scheduled for a Senate floor vote.
The commission canceled its open meeting for June 20, as it has all previous meetings since February. The July 20 meeting is still listed on FERC’s calendar.
LaFleur repeated her promise to remain on the commission until the expiration of her term in June 2019.
“I’m very optimistic that we will keep the bipartisan and collegial tradition that has really characterized the commission. I think cultures are slow to change. There’s a lot of swirl in Washington right now, but I believe that FERC is very strong.”
Developers of certain hydroelectric projects can feasibly get federal approval within two years under current regulations, FERC staff said last week.
With the passage of the Hydropower Regulatory Efficiency Act of 2013, Congress directed FERC to study the feasibility of implementing a two-year process for issuing hydropower licenses to non-powered dams and closed-loop pumped storage projects.
After conducting a pilot program, FERC staff determined the time frame is doable, noting that “site selection, a well-defined project proposal, thorough pre-filing consultation and a complete application” are the most important elements.
Staff said that updating and improving the “small/low-impact hydropower” portion of its website would expedite the process.
“Staff also commits to providing more frequent processing updates, when appropriate, to provide additional clarity and certainty during the licensing process,” the report said.
Eligible projects under the program were required to be at a non-powered dam or closed-loop storage project, have a well-developed proposal, result in little environmental impact and be in areas with substantial information on environmental resources and effects.
FERC staff determined in August 2014 that Rye Development’s Kentucky Lock and Dam No. 11 project met the criteria and issued the project a license in May 2016. The 5-MW capacity project will generate about 19,000 MWh annually.
Kentucky Dam and Lock 11 Hydropower Project | Rye Development
Staff also examined processing times for 83 projects that were issued licenses or small hydropower exceptions between 2003 and 2016. Evaluations of 28% of these projects were completed in two years or less, with a median processing time of 1.4 years. Projects that were not licensed in two years tended to be larger, more complex and had more issues to examine.
A majority of commenters agreed the pilot was a success and that it is feasible to implement a formal two-year licensing program, staff said. Changes to the Federal Power Act are not required, but factors outside of FERC’s control, such as the actions of other agencies, could affect permitting timelines, according to the report.
The Senate Energy and Natural Resources Committee voted 20-3 Tuesday to advance Neil Chatterjee and Robert Powelson, President Trump’s nominees for FERC.
Senate Energy and Natural Resources Committee
Sens. Ron Wyden (D-Ore.), Bernie Sanders (I-Vt.) and Mazie Hirono (D-Hawaii) voted no.
Murkowski
“Both FERC nominees failed to commit to avoiding political interference from the White House or maximizing public engagement in proposed energy projects,” Wyden said. “Given FERC’s important role in energy infrastructure in Oregon and communities across the country, I am also concerned that nominating commissioners from only one political party is a signal from the White House that it has no intention of ensuring FERC continues as the bipartisan and independent agency it has long been. I will continue to insist FERC considers local voices in its decisions and that the administration moves beyond politics to keep FERC bipartisan and independent.”
Otherwise, the nominees received bipartisan support.
Cantwell
“I am assured both have understood the important role that FERC plays in ensuring fair markets and guarding against market manipulation,” said Sen. Maria Cantwell (D-Wash.), the committee’s ranking member.
This prompted Ted Glick, of environmental group Beyond Extreme Energy, to interrupt the meeting with shouts of protest against FERC. The hearing was interrupted two more times.
The committee also advanced Trump’s nominees for deputy secretary of energy and deputy secretary of the interior, Dan Brouillette and David Bernhardt respectively, mostly on party line votes. The committee voted 17-6 for Brouillette and 14-9 for Bernhardt.
RENSSELAER, N.Y. — NYISO and adjacent grids will likely be able to serve load throughout summer based on historical performance of generation and transmission infrastructure, the ISO reported last week.
However, an unlikely scenario of extreme heat could pose challenges for system capacity reserves, if not the system itself, according to the ISO’s Summer 2017 Capacity Assessment.
Under a baseline scenario in which this summer’s load peaks at 33,178 MW, NYISO expects to have a capacity margin of 386 MW, down 746 MW from the 2016 baseline forecast. The positive margin represents the amount of surplus generation available after factoring in peak load plus a required 2,620 MW of operating reserves.
Under extreme weather conditions — the 90th percentile forecast — the ISO predicts a capacity shortfall of 1,924 MW, compared with a 1,191-MW shortfall in last summer’s forecast.
“That’s taking the 90th percentile peak forecast, which is a very large peak, adding 2,620 of reserve requirement, saying that’s the requirement on a day-ahead basis, and then comparing it to that available capacity,” Wes Yeomans, NYISO vice president of operations, said during a May 31 meeting of the Management Committee.
Despite the expected deficiency under those conditions, the ISO expects it could avoid involuntary load curtailments by relying on up to 3,083 MW of demand resources available under emergency procedures.
NYISO activated demand response during its all-time summer peak of 33,956 MW in July 2013, which would have hit 34,900 MW without DR, Yeomans said.
| NYISO
Yeomans explained that the 90th percentile projection slightly exceeds NYISO’s all-time high. For an extreme heatwave, the capacity requirement would reach 38,000 MW.
“If we compare that against the capacity resources assuming 4,800 MW of derates — and we may or may not have that amount in a very hot heatwave — on paper we would be short on capacity by about 1,900 MW … but we have at least 3,000 MW of emergency operating procedures we would activate to make up that difference,” he said. (See New York Geared for 2017 Summer Load.)
MC Approves Funding 2nd PAR at Ramapo
The Management Committee approved a Tariff modification to fund Consolidated Edison’s replacement and operation of the Ramapo 3500 phase angle regulator, destroyed in a fire last June, as well as the operating expenses for the existing PAR at the substation close to the New Jersey border. The estimated $5.5 million in annual costs will be allocated statewide across all New York load-serving entities, but they would be reimbursed with any monies eventually paid by PJM, PJM transmission owners or refunded by Con Ed.
Mark Younger of Hudson Energy Economics asked for a definite commitment from either Con Ed or NYISO on the timeline for installation.
Jane Quinn of Con Ed said that upon an affirmative vote, the company will begin moving the PAR into place, which should take three to four weeks. Installation should take an additional eight to 10 weeks.
“We anticipate having the PAR, absent contingencies, in place on or around September 15,” Quinn said. (See “Con Edison Gets Approval to Install 2nd PAR at Ramapo,” NYISO Business Issues Committee Briefs.)
Market Participants to Review Monitor’s Performance
Shaun Johnson, NYISO director of market mitigation, asked market participants to join in an annual review of the Market Monitoring Unit’s performance.
NYISO last year signed a three-year contract with Potomac Economics to perform monitoring functions through March 31, 2019. The MMU’s duties include ensuring that the markets administered by NYISO function efficiently and appropriately, as well as identifying market violations, market design flaws and market power abuses. The Monitor also produces annual and quarterly State of the Market reports assessing the performance of the New York electrical markets.
The budget for the MMU for 2017 is $3.5 million, up $400,000 over last year. Most of the additional costs cover additional work related to cybersecurity and new requirements mandated by reliability-must-run and FERCOrder 1000 filings.
One participant said that Potomac sometimes shows up at FERC and protests what NYISO is doing.
“Something just seems at odds there, that we’re paying a company $3.5 million a year and we’re fighting with them at FERC,” he said.
Such action is part of the duties of an MMU, according to NYISO, and one thing FERC cited in a recent review of the SPP Monitor was the lack of reporting on disagreements with the grid operator.
Tariff Changes on Tx Cost Recovery
The Management Committee approved proposed Tariff revisions to add a mechanism to recover and remit costs associated with regulated transmission projects eligible under the ISO’s Congestion Assessment and Resource Integration Study or the public policy transmission planning process. Following board approval in July, the revisions to the cost recovery mechanism for regulated transmission projects under Rate Schedule 10 — and related amendments to the Tariff’s Attachment Y — would be filed with FERC under Section 205 of the Federal Power Act.
The Rate Schedule 10 revisions establish a new regulated transmission facilities charge (RTFC) to LSEs, with payments allocated to developers of such projects.
John P. Buechler, NYISO regulatory policy adviser, said the revisions do not in any way “affect or change the cost allocation provisions, which, relevant to our transmission planning process, are in Attachment Y, Section 31.5.”
Eligible projects include:
Regulated backstop transmission solutions proposed by a responsible transmission owner;
An alternative solution NYISO selects as a more efficient or cost-effective solution to a reliability need;
A regulated transmission gap solution proposed by a responsible TO;
An alternative regulated transmission gap solution determined by an appropriate state regulatory agency;
An approved regulated economic transmission project;
A public policy transmission project selected by NYISO;
Costs incurred by a developer in preparing a proposed transmission solution in response to a request by the Public Service Commission or Long Island Power Authority; and
The portion of an interregional transmission project selected by NYISO in the Comprehensive System Planning Process that is allocated to the NYISO region.
NYISO will calculate and bill an RTFC separately for each eligible project.
NYISO to Enhance Buyer-side Mitigation
The committee approved proposed Market Services Tariff changes to improve inflation forecasting and how mothballed units are treated in the capacity and energy forecast used to make buyer-side mitigation determinations.
The committee recommended that the Board of Directors authorize revisions to buyer-side mitigation rules in the Market Services Tariff, which would then be filed with FERC under Section 205 of the Federal Power Act.
In FERC docket ER13-1380, filed in 2013 to create NYISO’s G-J locality, the commission determined that such an enhancement was outside the scope of the docket but encouraged the ISO to work with stakeholders on the issue.
NYISO analyst Lorenzo Seirup presented the rationale for mitigation enhancements and said that, since the topic first arose in 2013, “we discussed this ad nauseam and also had a vote that failed and then a vote that passed — that’s the 30-second highlights.”
The proposal would include in the forecasts existing units as well as additional units, “which is the more complicated” category, Seirup said. Units that would be excluded are those transferring their capacity resource interconnection service (CRIS) or that have expired CRIS.
Additional units include mothballed facilities, units under forced outages, retired units and those in similar condition with unforced capacity deliverability rights. These additional units either must have CRIS or show positive indicators of repair or have a new present value greater than $0 in the “inclusion test” performed for resources that have the ability to re-enter the market under more favorable conditions.
The Tariff changes on inflation would call for use of the most recently published 10-year inflation projections from the Survey of Professional Forecasters, or if no longer available, a similar source to identify net cost of new entry projected for the mitigation study period, and the price on the installed capacity demand curve projected for such a period.
NextEra’s “fatal flaw” was its refusal to accept “appropriate ring-fencing conditions, and any benefits offered could not overcome that failure,” Marquez said.
