FERC last week ordered settlement judge procedures over Westar Energy’s tariff revisions updating its transmission and distribution loss factors (ER18-1418).
“We find that Westar’s proposed tariff revisions raise issues of material fact that cannot be resolved based on the record before us,” the commission said. “Our preliminary analysis indicates that Westar’s proposed tariff revisions have not been shown to be just and reasonable.”
| Westar
Kansas-based Westar is seeking to raise its loss factors from 3.07% to 3.47%, based on a study it performed using data and load-flow models from 2016 supplied by SPP. The current figure is a result of a 2013 settlement that locked it in for five years, with an updated study to be filed every succeeding five-year period.
Westar noted that the 2016 data reflect system losses lower than those recorded in 2014-2015 and 2017. It contended that customers would benefit from “locking in” lower loss factors for the next five years, given the settlement’s moratorium provision.
Kansas Electric Power Cooperative and the Kansas Power Pool protested, arguing that the increase and the underlying study were highly complex, “with numerous assumptions that must be understood and vetted.” They said the loss factors were inconsistent with known changes on Westar’s transmission system, pointing out the utility had spent more than $900 million in improvements between 2011 and 2016 that should “portend a decrease in transmission losses … not an increase.”
The two parties further alleged Westar’s study “inappropriately” excluded certain elements that would have lowered the estimated losses for 2016. They said that the utility had not demonstrated the reasonableness of including generator step-up losses in its calculation, nor its use of a top-down method for estimating certain losses while using a bottom-up method for others.
Westar responded that its previous study indicated losses of 3.65%, and that the current 3.07% mark was set by the 2013 settlement, noting that its loss factors do not include losses from generator step-up transformers. The utility contended that its treatment of state estimator losses is proper and that its study normalizes for conditions experienced on its transmission system.
The Nemaha-Marshall Electric Cooperative Association also intervened, saying it was concerned that Westar was incorrectly using annual peak load in applying the loss factors for the association’s wholesale distribution service charges, possibly leading to over-recovering facility service charges and associated losses.
In its reply, Westar countered that it uses the peak load for each facility in its losses calculation and the wholesale customer’s coincident peak when determining its share of the facility.
The Public Utility Commission of Texas last week set a hearing for Oct. 16-17 on Rayburn Country Electric Cooperative’s proposed transfer of 96 MW of load and 130 miles of transmission lines from SPP to ERCOT (Docket 48400).
Parties to the contested case agreed to the schedule during a prehearing conference before the commissioners June 28.
PUC of Texas June 28 open meeting | PUCT
Rayburn Country and NextEra Energy’s Lone Star Transmission filed a request in May to move Rayburn’s SPP load and related transmission assets into ERCOT and transfer an 11-mile, 138-kV line and associated facilities to Lone Star.
The contested case stems from an earlier docket (47342), in which Rayburn had proposed to transfer 190 MW of load from SPP into ERCOT. The two companies have proposed to use a transmission plan ERCOT put together as part of the earlier proceeding to integrate Rayburn’s load.
ERCOT originally estimated the integration costs at $38 million, but a “modified alternative option” suggested by Oncor has lowered the cost to $31.7 million.
SPP also conducted a study of Rayburn’s migration in coordination with ERCOT. The RTO’s analysis indicated annual production cost savings of $14 million to $18 million in its footprint through 2025. SPP’s Texas territory would save $15 million to $19 million over the same period. According to the study, SPP’s transmission customers will see a total increase of $4.6 million in their annual transmission revenue requirements.
Both system operators are among the proceeding’s intervenors.
The SPP load accounts for only 12% of Rayburn’s demand, with the remainder in ERCOT. The co-op owns and operates 367 miles of transmission lines in Texas, 207 miles in ERCOT and 160 miles in SPP’s East Texas footprint.
Lone Star is a transmission-only utility in ERCOT that owns and operates about 624 miles of 345-kV transmission facilities in Texas.
Commission Approves Wildorado Wind Ranch Purchase
During the commissioners’ open meeting, the PUC approved GIP III’s acquisition of NRG Energy’s Wildorado Wind Ranch, a 161-MW facility within SPP’s footprint near Amarillo, Texas (Docket 48139).
Wildorado Wind Ranch
The commissioners ruled the transaction would not exceed the Public Utility Regulatory Act’s 20% limitation on combined ownership and control of installed generation capacity within a power region.
PUC of Texas Chair DeAnn Walker | PUCT
PUC Chair DeAnn Walker modified the order to use the facility’s nameplate capacity in calculating the installed generation capacity’s share. The applicants had proposed the capacity be calculated at 5% of nameplate, based on SPP’s planning criteria, but Walker said “no data was provided in the record” to support their calculation.
The use of nameplate capacity increased GIP III and its affiliates’ generation ownership within SPP to 4,814 MW, or 5.48%.
Walker called for a rulemaking to “clarify” how generating capacity is calculated in the future.
“The rules were originally adopted in 2000, and much has been learned since that time,” she said in a memo.
Powelson tweeted “with mixed emotions” the surprise announcement on Thursday, linking to a statement posted on FERC’s website.
“It has been an honor to serve this great country,” he said. “My family and I are deeply appreciative of this opportunity. FERC is a world class organization. Thanks to you, fellow FERCians!”
Powelson said he will leave the commission in mid-August to become president and CEO of the National Association of Water Companies. His departure could impact how the commission acts on several major initiatives, including the resilience docket FERC opened in January.
A former Pennsylvania Public Utility Commissioner, Powelson has been an unabashed supporter of natural gas and expressed skepticism over the Department of Energy’s effort to prop up struggling coal and nuclear plants.
“Why should we go out there and pick winners and losers in a market?” he said during a conference in March. “To do what? Hurt the other, more efficient units in the market or send bad market signals?” (See Powelson Tells New England to Learn from Pennsylvania.)
A Republican, Powelson was sworn in on Aug. 10, 2017, to a term that was to run through June 2020. His position on the five-person commission will be filled by another Republican, maintaining the GOP’s 3-2 edge.
“I’ll miss [Powelson]’s trenchant takedowns of the coal and nuclear bailout plans and can only hope he’s replaced by someone with as much vigor, expertise and sophistication,” tweeted University of Richmond law professor Joel B. Eisen.
Until a fifth commissioner is appointed, Democratic Commissioners Cheryl LaFleur and Richard Glick will have increased leverage. The two have dissented repeatedly on gas pipeline certificate orders, calling on the commission to consider the projects’ impacts on greenhouse gas emissions. (See Dem Dissents Show FERC Divide on Carbon.)
“This arrangement appears most likely to complicate — but not necessarily halt — the FERC’s approvals of natural gas pipelines and potentially other issues,” ClearView Energy Partners wrote in a note to clients Thursday night. “If Powelson’s seat remains vacant for an extended period of time, the absence of a third Republican vote could delay potential changes to the commission’s 1999 Certificate Policy Statement, which governs natural gas pipeline approvals pursuant to Section 7 of the Natural Gas Act. It is possible that further action on the commission’s ongoing resiliency docket could be delayed if the commission hits a 2-2 impasse.”
The New England Power Generators Association, which represents competitive generators, called Powelson’s departure “a major loss for FERC and all who participate in the dynamic energy markets. Commissioner Powelson has been a true leader on competitive electricity issues for years.”
But environmentalists and anti-fracking activists expressed no regrets over his departure.
“As a FERC commissioner, Robert Powelson was part of the FERC rubber stamp for pipelines,” said Maya van Rossum, leader of the Delaware Riverkeeper Network. “Powelson was not only a stalwart supporter of pipelines, but he was an outspoken critic of any members of the public who opposed pipelines, likening them to jihadists.”
“Powelson’s abrupt resignation doesn’t change the fact that FERC itself needs a massive change,” Mary Anne Hitt, senior director of the Sierra Club’s Beyond Coal campaign, said in a statement. “The next commissioner must be a strong advocate for considering climate change in FERC’s decision-making process, curtailing the dangerous overbuilding of fracked gas pipelines, and stand firmly against reckless coal and nuclear plant bailouts the Trump administration and grid operators are proposing.”
In his new post, Powelson will be running a trade group representing private water utilities serving almost 73 million people, almost one quarter of the nation. While with the Pennsylvania PUC, he chaired the National Association of Regulatory Utility Commissioners’ Water Committee for three years.
“Rob brings to the association tremendous experience at both the state and federal level,” Aqua America CEO Christopher Franklin, president of the NAWC Board of Directors, said in a statement. “He is taking the helm of the NAWC at an important time in the water industry. His unique skills and relationships will help to highlight the capabilities of NAWC member companies in solving some of the challenges facing many mid- and small-sized municipal water and wastewater utilities. Rob also has firsthand experience in working with utilities and regulators to encourage the investment in infrastructure that is critical in keeping our nation’s viable.”
By Tom Kleckner, Michael Kuser, Amanda Durish Cook, Michael Brooks and Rich Heidorn Jr.
Solar power and storage providers differed sharply with local distribution companies and state officials in comments filed this week in FERC’s rulemaking on distributed energy resources.
More than 50 commenters submitted answers to questions FERC posed, differing on whether aggregation should be limited to single nodes and on the roles of RTOs, state regulators and LDCs (RM18-9, AD18-10).
The commission initiated the rulemaking in February, deciding to separate DER issues from its Order 841 on energy storage. The comments supplement testimony from a technical conference in April. (See RTOs, Regulators Set Course for DER Market Participation.)
Below is a summary of the major issues and the range of recommendations FERC received, based on RTO Insider’s review of 40 comments.
How prescriptive should FERC be in its rulemaking?
Most RTOs and ISOs submitted comments, with PJM, NYISO and CAISO urging FERC to move forward while affording RTOs flexibility. “Distributed energy resources can, and do, participate in wholesale markets, and are contributing to grid reliability and resilience in new and important ways,” CAISO said. “The commission should not foreclose options for these resources.”
MISO said FERC should postpone issuing a final rule on DER market integration, calling it “premature.” The RTO said its footprint does not have a high volume of DER installation and said it’s not predicting significant penetration levels, or a need for DER aggregation, anytime soon.
“Commission directives requiring major additions to MISO’s existing market platform would yield almost no benefits given the lack of capability of MISO’s legacy technology system and low regional DER penetration. Prescriptive action would incur very high costs associated with retrofitting MISO’s soon to be retired platform … likely delaying the transition to a far more capable system,” the RTO said.
ISO-NE also pleaded for flexibility, saying its current market rules and the new approach to integrating storage under Order 841 indicate no need for a DER participation model in New England. “The DER participation model envisioned in the DER [Notice of Proposed Rulemaking] would be costly and disruptive, and would produce no additional value for New England,” the RTO said.
Distributed Energy Resources | Clean Coalition
The Advanced Energy Management Alliance called on FERC to create a “participation model” with a checklist for RTOs to demonstrate compliance with minimum requirements, like the one it included in Order 841 on energy storage. (See FERC Rules to Boost Storage Role in Markets.) It said the model should cover issues including market access, measurement and verification, and coordination with LDCs.
The Edison Electric Institute said FERC should “carefully consider the far-reaching impacts” of allowing DER aggregations to participate in the wholesale markets and defer to the grid operators and states on details.
“The proposal has significant implications for the reliability of the distribution system and additional time is needed to install infrastructure and to develop coordination agreements to ensure that the reliability of the distribution system and the [bulk power system] is maintained,” EEI said.
Public interest groups, including the Environmental Defense Fund, Sustainable FERC Project and Union of Concerned Scientists, said it would be premature for FERC to mandate best practices for transmission-distribution coordination. But it said the commission should finalize the DER aggregator participation model it proposed in November 2016. (See FERC Rule Would Boost Energy Storage, DER.)
“Relying on ISO/RTO stakeholder processes alone to eliminate barriers to market participation by non-incumbent storage and DER participation without commission involvement (as EEI suggested) would not likely yield results consistent with efficient functioning of the market or a fair outcome for these resources,” the groups said. “As noted by many commenters, the ISO/RTO stakeholder processes generally favor incumbent stakeholder members and underrepresent emerging technologies and the public interest.
“There is no need to further delay finalizing the proposed rule. Understanding that there might be legitimate reasons for RERRAs [relevant electric retail regulatory authorities] to delay implementation of the rule in their own regions, that may be done by granting a longer implementation timeline for that RERRA or a limited waiver,” the groups said.
The American Public Power Association said FERC must distinguish between “undue barriers to DER participation in wholesale markets and factors that, although they might have the effect of limiting DER participation in those markets, are grounded in legitimate operational, reliability and regulatory considerations.”
The Electric Power Supply Association said “any initiatives or rules to facilitate participation of [DER] must first and foremost be designed to serve reliability and efficiency objectives, not simply to facilitate DERs business model objectives.”
Should FERC permit aggregation of DER beyond a single node?
AEMA and the Solar Energy Industries Association said the commission should allow multi-nodal aggregation. “Aggregation at a node is not aggregation,” said AEMA, calling for aggregation across an area as “geographically broad as technically feasible.”
SEIA said it supports the commission’s proposed 100-kW minimum size requirement. “Even with [a] 100-kW minimum size requirement, however, there is no guarantee that each of the many thousands of nodes across the RTO/ISOs would be of a sufficient size to sustain aggregations and to foster market competition among multiple aggregators. Aggregators should have the ability to compete across a load zone, and allowing multi-node aggregation should reduce the price of delivered power by reducing congestion and alleviating system constraints.”
Limiting aggregations to a single node would hurt the economics of DERs and their value to system operators, “restricting their ability to deploy these resources economically and in response to reliability needs,” said Advanced Energy Economy, which represents more than 100 companies and organizations in energy efficiency, demand response, natural gas, renewables and storage.
PJM said multi-nodal aggregation would be challenging but that its experience modeling DR across multiple nodes shows it can be done. “PJM does not anticipate any significant modifications to modeling and dispatch software, communications platforms or automation tools to implement multi-node DER aggregations,” the RTO told the commission.
But opponents, including Calpine and EPSA, cited the technical conference comments of PJM Independent Market Monitor Joe Bowring and NYISO Manager of Market Design Michael DeSocio, who expressed concern at the technical conference over aggregation over multiple nodes.
“DER aggregation across multiple nodes is inconsistent with the design of the organized wholesale markets, will distort market outcomes and reduce efficiency, and should therefore not be mandated,” Calpine said.
“If the precedent is established now that DER, alone among generation resources, does not need to be nodal, it will be difficult or impossible to reverse that precedent as DER grows based on that approach,” the Monitor said in its filing. “The fact that aggregation may provide some short-term business benefits to the providers of DER is not relevant to defining the correct market design to facilitate the long-term, effective participation by DER.”
The Monitor said DERs can be priced and dispatched at individual nodes and still be aggregated across multiple nodes for settlement purposes.
How much control should local distribution utilities have over DER?
EEI said electric distribution companies “must have transparency and ultimate control over the resources connected to the distribution system” and that regulators must address cost allocation issues associated with distribution system investments needed to facilitate DERs.
“Generally, DER aggregations will increase, not decrease, volatility on the distribution system given its radial design, and because there may be significant changes in power flows that will have to be mitigated to ensure that load can be served under all circumstances,” EEI said.
The Transmission Access Policy Study Group, which represents transmission-dependent utilities, said “DER aggregations can adversely affect distribution systems.” FERC should “defer decisions to those with the best understanding of the relevant distribution systems, including an ‘opt-in/opt-out’ mechanism modeled on Order No. 719-A or, at minimum, an express opt-in requirement for small distribution utilities.”
The National Rural Electric Cooperative Association said FERC’s proposal to allow third-party DER aggregators to participate directly in RTO markets will present bigger challenges for its members than the deployment of DERs on cooperatives’ systems, requiring them to invest in new equipment and software.
“Third-party DER aggregators participating in the RTO/ISO markets will have incentives to operate the DER in response to wholesale market signals, which can pose operational, reliability and safety issues for local distribution cooperatives,” NRECA said.
NRECA also said third-party aggregators may engage in “cherry picking,” potentially preventing cooperatives from using their own or their members’ DER, which “may be a significant part of many cooperatives’ integrated resource portfolios. If those DER resources are available to third-party aggregators, this could severely undermine the cooperative’s ability to manage cost and risks for its consumer-members.”
“These factors were an integral part of the commission’s decision to permit RERRAs to decide whether to allow aggregators to bypass utility demand response programs and bid retail demand response directly into the wholesale markets in Order No. 719,” NRECA said.
Several commenters said they opposed giving LDCs veto power.
AEE said it supports reasonable mechanisms to ensure LDCs, aggregators and RTOs have sufficient operational coordination and situational awareness. “However, distribution utilities should not be given discretion to reject DER registrations in an aggregation for reasons beyond operational coordination and reliability,” the group said. “Allowing distribution utilities a broad veto, even in instances when a DER has an interconnection agreement in place, will restrict DER participation in wholesale markets, erode competition and potentially result in undue discrimination. The interconnection process determines what a DER needs to do to operate in a safe and reliable manner.”
EPSA said FERC should ensure LDCs don’t use their knowledge of their systems and needs for a competitive advantage in developing DERs. “If utilities are allowed to exploit their asymmetric access to information to the detriment of their competitors, even for the short term to speed the deployment of DERs, it will serve to chill merchant investment in this space, which may ultimately slow DERs deployment.”
SEIA also raised market power concerns. “Facing true competition from DERs, certain distribution utilities may have incentives to engage in conduct … to protect their current market positions,” it said.
Should state and local regulators have opt-out rights over DER?
AEMA and the Energy Storage Association said states should not be able to prevent consumers from participating in wholesale markets.
Instead, AEMA said FERC should clarify that states have the right to implement retail tariffs that prohibit participants from direct participation in wholesale markets. “In that instance, customers would choose whether they preferred to participate in a retail tariff or … via an aggregator in the wholesale market. The retail tariff could facilitate wholesale services and enable states to preserve their jurisdiction over retail customers, programs, and activities without impinging on customers’ ability to access wholesale markets,” AEMA said, citing Indiana and Michigan Power’s DR service rider.
But NRECA said FERC should defer to RERRAs’ timetables for implementation because the industry “is not uniformly ready for third-party DER aggregations.”
The National Association of Regulatory Utility Commissioners said it opposed a limited opt-out provision that would allow states to require DERs to choose participation in either the wholesale markets or retail programs, but not both.
“The limited opt-out provision provides no additional benefits or options to state commissions,” NARUC said. “States already have the authority to prevent an asset from participating in a retail compensation program [under the Federal Power Act]. … No FERC FPA-based regulation can require states to allow aggregated DER assets to participate in both RTO/ISO markets and retail compensation programs.”
Xcel Energy asked FERC to suspend the rulemaking pending further technology improvements, saying technology does not exist “to effectively and fairly integrate DERs” into wholesale markets. “In the meantime, states and other stakeholders can serve as the laboratory for policy initiatives in this arena as they move forward with incremental and evolutionary programs involving DER integration.”
How should concern over double payments be addressed?
AEE said “there is little to no risk that customers will ‘pay twice’ for the same service.”
The commission’s proposed blanket prohibition on wholesale market participation by aggregated DERs that participate in retail programs would “arbitrarily exclude many, if not most, existing DERs from the wholesale market, and limit the benefits that the wholesale grid can capture from these resources,” AEE said.
“Dual participation does not equal double compensation,” ESA said.
“Rather than limiting an entire function of DER assets by forcing the asset to participate exclusively in one market, ESA suggests that states examine specific services on a case-by-case basis, with sufficient evidence to demonstrate a justification for the exclusion, to limit a specific combination of two services by the same DER asset.”
ESA cited resources participating in both NYISO and Consolidated Edison’s DR program. “These assets are providing value for both the retail and wholesale markets and should be compensated accordingly — they provide demand savings for consumers and export power onto the grid for system support.”
Calpine said the commission must prevent DERs that receive out-of-market compensation from skewing RTO markets and price formation. “In particular, DERs that are compensated for participating in retail programs will not have to submit offers in the RTO/ISO markets that reflect their actual costs, and would therefore have a competitive advantage over resources that do rely on RTO/ISO market revenues,” it said. “Put simply, DERs should have to choose whether they want to participate in the retail market or an RTO/ISO market, and stick with that decision for a defined period (e.g., for five years, similar to the fixed resource requirement process in PJM).”
Vehicle and battery manufacturer Tesla said RTOs should require proof before allowing restrictions. “RTOs/ISOs should be required to articulate a specific scenario in which a resource would receive more than one revenue stream for only one distinct value.”
SEIA said the most effective solution “is to ensure that wholesale and retail services are clearly defined. Whether two markets compensate the ‘same service’ or ‘distinct values’ is a question that should be addressed on a fact-specific basis.”
RENSSELAER, N.Y. — NYISO stakeholders on Tuesday again backed joint proposals by North America Transmission (NAT) and the New York Power Authority (NYPA) to build two 345-kV transmission projects that could cost $900 million to $1.1 billion.
The Management Committee voted to recommend that the Board of Directors approve the ISO’s draft AC Transmission Public Policy Transmission Planning Report, as recommended by the Business Issues Committee the previous week. The board will consider the matter at its July 17 meeting. (See NYISO BIC Backs AC Tx Projects; Losing Bidders Protest.)
Dawei Fan, manager for public policy and interregional planning, said ISO staff analyzed seven proposals to address persistent transmission congestion at the Central East (Segment A) electrical interface, and six proposals for the Upstate New York/Southeast New York (or Segment B) interface.
Advised by consultant Substation Engineering Co. (SECO), ISO staff recommended Project T027, a double-circuit 345-kV line from Edic to New Scotland for Segment A, and a standard 345-kV line from Knickerbocker to Pleasant Valley for Segment B Project T029.
Market Monitor Evaluation
Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, said it found the recommended projects will be economic if the Clean Energy Standard is satisfied with high levels of intermittent renewable generation upstate.
However, benefits will be reduced if state policies shift more investment to offshore wind and energy storage in downstate areas, LeeVanSchaick said. Ultimately, the benefits of the recommended transmission projects are heavily dependent on the placement of new renewable generation and the locations of retiring generation.
| Potomac Economics
While finding the ISO’s methodologies reasonable, the MMU suggested several enhancements for NYISO to consider in future public policy transmission evaluations, including incorporating additional priced and unpriced benefits of new transmission projects into a single cost/benefit metric; estimating operations and maintenance costs of new and decommissioned facilities; estimating the cost savings from avoided refurbishment of older facilities; and developing Tariff provisions to allow developers to take on the risk of cost overruns.
The MMU also recommended that the ISO model entry and exit decisions for generators consistent with expected competitive market outcomes, and consider transmission outages and other unforeseen factors in estimating production cost savings. Finally, LeeVanSchaick suggested enhancements to natural gas and emission allowance price forecasts.
Zach Smith, ISO vice president for system and resource planning, said they liked the MMU’s recommendations, not only in context of the public policy transmission needs process, but for the Congestion Assessment and Resource Integration Studies process as well.
Brian Duncan of NextEra Energy Transmission NY (NEETNY) repeated his presentation from the previous week’s BIC, arguing that the ISO was picking winners for a $1 billion project “despite a virtual tie on project benefits” among competing projects, which included NEETNY’s T022 in Segment B.
The MC also voted to recommend that the board approve Tariff revisions to provide extensions of historic fixed-price transmission congestion contracts, as was recommended by the BIC.
The SPP Regional Entity (RE) will cease all compliance monitoring and enforcement activities at the close of business Friday, ending 11 years in an official reliability oversight role that drew concern from FERC and NERC.
RE President Ron Ciesiel said the entity will shut down its database at 5 p.m. CT. He said data and files have been transferred to the registered entities’ new REs and will be available to those entities at their new locations Monday morning.
“Overall, I couldn’t be happier with the transition,” Ciesiel said during the RE Board of Trustees’ final conference call Thursday. “I hope people on the other end are as pleased as I am with how this has moved on.”
SPP announced last July that it was dissolving the RE, citing a mismatch between its and SPP’s footprints. However, NERC and FERC have also expressed reservations about the RTO’s involvement in RE activities. (See SPP to Dissolve Regional Entity.)
The RE was responsible for auditing and enforcing reliability rules in three balancing authorities (SPP, Southwestern Power Administration and parts of MISO). Most of its 122 registered entities have been reassigned to the Midwest Reliability Organization, with the remainder joining the SERC Reliability Corp.
NERC’s board of trustees and FERC both approved the SPP RE’s dissolution earlier this year. (See FERC Approves Dissolution of SPP RE.) FERC issued an order that terminates an amended and revised delegation agreement between NERC and SPP, effective Aug. 31, and revises the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints.
NERC will assume the compliance monitoring and enforcement of the RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.
Ciesiel and a transition staff of three other employees will remain at SPP’s headquarters in Little Rock, Ark., until Aug. 31 to close out any remaining issues.
The Illinois Commerce Commission has agreed to open the remaining meetings for its NextGrid study process to the public just days after two groups accused its chairman of keeping the public in the dark on the study and violating the state’s open meetings laws.
Sheahan | Illinois Commerce Commission
Consumer advocate Illinois PIRG Education Fund and Chicago-based energy storage and wind energy company GlidePath Development filed suit in Cook County Circuit Court on Monday against the ICC and Chairman Brien Sheahan, alleging that the commission is largely conducting its NextGrid study without public involvement (2018-CH-07943).
The two organizations allege that since launching the NextGrid study, the ICC and Sheahan have committed dozens of breaches of the state’s Open Meetings Act, including failing to post meeting notices and agendas in advance; repeatedly denying the public the opportunity to attend meetings; “actively” excluding certain individuals from attending meetings; failing to keep reliable meeting records; excluding input from working group members in meeting records; and issuing draft reports containing content that had not been discussed in meetings.
The ICC confirmed on Friday that it will open all remaining NextGrid working group meetings to the public, hours after meeting with the plaintiffs in court and working out an agreement order.
A handwritten agreement between the parties says that if the ICC wants to continue its status quo of closed meetings, it must postpone all NextGrid meetings, but if meetings proceed, they should be in full compliance with the Open Meetings Act. The ICC also agreed to provide plaintiffs with advance notice of all meetings and specific steps it will take to comply with the Open Meetings Act. The agreement also notes the ICC must still answer the plaintiffs’ complaint by July 20.
ICC Senior Public Information Officer Victoria Crawford said the ICC was “pleased that progress on this important study to explore the electric grid of the future will continue.”
“The ICC and the NextGrid facilitators and leaders remain committed, as always, to an open and transparent process,” Crawford said.
“The Illinois Commerce Commission agreed today to a court order requiring the NextGrid process to abide by the Open Meetings Act while the lawsuit proceeds. Despite an ICC spokesperson’s claims that the lawsuit was ‘frivolous,’ attorneys for the commission agreed to plaintiff demands to open the process and fully comply with the Open Meetings Act,” Illinois PIRG and GlidePath said in a joint statement on Friday.
‘Behind Closed Doors’
In their Monday complaint, Illinois PIRG and GlidePath asked the court to altogether restart the NextGrid study process in compliance with the Open Meetings Act, claiming that the study “contains recommendations that could impact competition while increasing utility control of electric generation.”
“NextGrid, as an arm of the ICC, is a public body and subject to the terms of the Open Meetings Act. NextGrid also qualifies as an advisory body of the state or a commission of the state and is subject to the terms and requirements of the Open Meetings Act,” the lawsuit contends.
The 18-month NextGrid study seeks to help Illinois prepare for the long-term needs of its utilities, grid and markets in light of new technology and an evolving resource mix. The study involves seven working groups created by the ICC, each tasked with writing one chapter of the report. The University of Illinois’ Electrical and Computing Engineering Department will edit and assemble chapters to form a final report that will likely contain recommendations for improving the state’s energy industry.
The working groups focus on separate issues, such as ratemaking, new technology, markets, metering, reliability and resilience, customer participation and environmental policy. The ICC selected working group chairs and group members. The groups have been holding closed meetings since early December.
The lawsuit claims that the ICC has so far held about 22 private meetings concerning NextGrid. In one instance in late January, a lawyer seeking to dial into a working group meeting was disconnected three times, even over the objection of a working group member, the plaintiffs contend.
The suit also alleges that the work of Next Grid lead facilitators Peter Sauer and George Gross, both professors at the University of Illinois Urbana-Champaign, is being paid for by Commonwealth Edison and Ameren. The resolution creating NextGrid acknowledges that “Illinois electric utilities will provide funding to support the work of the facilitator.”
Illinois PIRG and GlidePath also note ComEd and Ameren maintain representatives on every working group, the membership of which has not been made public.
GlidePath’s Elwood Battery Storage facility in West Chicago, Ill. | GlidePath
In a letter describing NextGrid, Sheahan said that because the effort was established by a commission resolution and is not a docketed proceeding, it will not produce a commission order at its completion.
“The purpose of the final report is to provide a comprehensive view of our current grid, and to provide a menu to policymakers, regulators, consumer advocates [and] the public about the tools, technologies and policies that could lead to the grid of the future,” Sheahan wrote.
“The report will not in every instance determine a ‘best path forward.’ We want the report to be an honest assessment of where there is agreement on policies and where there is dissention.” He added that the final report will document areas of consensus and discord alike.
Sheahan also said the decision to cap the number of members in the working groups was made to “control the number of participants and encourage frank, open dialogue and a participatory environment.”
Illinois PIRG and GlidePath disagree with Sheahan’s characterization.
“The electric grid of the future should empower consumers to have maximum competition and choice, but that won’t happen in a closed process dominated by the utility of the past,” Illinois PIRG Education Fund Director Abe Scarr said in a press release. “NextGrid must be developed with maximum transparency and in full compliance with the Open Meetings Act.”
“We can’t create good policy behind closed doors. Experience shows that excluding consumer watchdogs and market participants will hurt ratepayers,” GlidePath CEO Dan Foley said.
The two organizations say the nonpublic NextGrid process has already resulted in a draft report from the technology working group that includes a section on smart cities that had not been discussed in the meetings. They also argue the study could form the basis for major Illinois energy legislation that will affect ratepayers.
“It is important to note that the ICC has gone out of its way to ensure an open and transparent process. NextGrid is a collaborative study that relies on the input of technical experts, stakeholders and the general public,” Crawford said in an email to RTO Insider. “A diverse group of more than 230 individuals representing various sectors of the energy industry, consumer advocates, environmental groups, academia, business and community leaders are active participants in the NextGrid study.”
The commission also said it “actively” seeks involvement through mass emails, press releases and NextGrid public comment sessions after preliminary drafts of findings or report chapters are written.
The ICC keeps records of NextGrid working groups’ agendas, meeting summaries and presentations online. It also maintains separate email addresses for each working group to receive comments on the publicly available information.
“Interested parties are and have been encouraged to submit written input,” the ICC said.
SPP staff told stakeholders last week that the RTO will not conduct a joint transmission planning study with Associated Electric Cooperative Inc. this year, saying they were unable to find any “reasonable projects on either side of line.”
“The next shot will be in 2020,” said SPP’s Clint Savoy during a June 21 conference call of the SPP-AECI Interregional Planning Stakeholder Advisory Committee. “We will have plenty of time to get our hands around what we want to look at in the next study.”
A needs assessment along the seams identified more than 200 violations, but most were eliminated through model corrections or system adjustments, or because they were invalid contingencies. Most AECI violations were voltage issues, SPP said.
The RTO is proposing that one identified project, a 161-kV transmission line, be included in its 2018 near-term assessment.
A final report will be published at the end of July.
SPP and AECI have been performing joint studies every other year since 2010, as outlined in their joint operating agreement. Their only success was in 2016, when their study identified two projects near Springfield, Mo.: a new 345/161-kV transformer at AECI’s Morgan Substation and uprate to an existing 161-kV Morgan-to-Brookline transmission line, and installation of a new 345-kV 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation.
SPP would have been responsible for $17.1 million of the projects’ estimated $18.75 million cost, but FERC last year rejected the proposed cost allocation for both projects. The Brookline reactor project is now being addressed through the RTO’s regional planning process as part of the 2018 near-term assessment, and the Morgan transformer project is being prepared for another filing at FERC.
AECI, based in Springfield, is owned by and provides wholesale power to six regional generation and transmission cooperatives.
President Trump’s nominee to head the Department of Energy’s Energy Efficiency and Renewable Energy (EERE) program sidestepped controversy in his confirmation hearing Tuesday but was unable to answer several senators’ questions about key legislation and programs.
Assistant Secretary nominee Daniel Simmons, who has been running EERE on an acting basis for the last year, told the Senate Energy and Natural Resources Committee that his work at DOE is much different than his previous roles at the Institute for Energy Research (IER) and American Energy Alliance — groups backed by the conservative Koch brothers that have supported fossil fuel use and called for Congress to “eliminate” EERE. Simmons also previously worked at the American Legislative Exchange Council, which also backed fossil fuels.
Simmons | Senate Energy and Natural Resources Committee
In his opening statement, Simmons said his parents’ decision to build “a passive solar double envelope home” sparked his lifelong interest in energy efficiency and renewables. “Since [joining DOE], I have approached this job with an open mind and an eagerness to learn and have focused on following congressional direction while advancing the administration’s priorities,” he said.
Later, Simmons discussed meeting with solar and wind industry representatives in his new role, acknowledging that “we’ve had policy differences in the past.”
Ranking member Sen. Maria Cantwell (D-Wash.) asked Simmons whether he would aid her in convincing the House of Representatives to back Senate legislation increasing energy efficiency standards for buildings and appliances. (See House, Senate Conferees Begin Work to Narrow Differences on Energy Bill.)
“I’m not familiar enough with that disagreement to really comment on it; I’m sorry,” Simmons responded.
“O-kayyy … ” Cantwell said incredulously. “This will be a key part of your job, so maybe before we vote on you, you could take a look at that.”
Cantwell also complained that DOE had repeatedly missed deadlines for completing EE regulations. “We had seen a slow walking by some on this, and I’m telling you it’s wrongheaded,” she continued. “ … Our nation is going to be in the manufacturing base very, very competitive on an international basis if we can drive down electricity costs. So, that should be our mantra, and I hope that you will lead that charge.”
“I will … I will not slow walk any of those regulations,” Simmons promised.
Nominees, left to right: Teri L. Donaldson, nominee for inspector general; Karen S. Evans, assistant secretary overseeing DOE’s new Office of Cybersecurity, Energy Security and Emergency Response; Christopher Fall, director of the Office of Science; and Daniel Simmons, assistant secretary of the Energy Efficiency and Renewable Energy (EERE) program. | Senate Energy and Natural Resources Committee
In response to a question from Sen. Tina Smith (D-Minn.), Simmons also distanced himself from his comments during a 2013 podcast in which he argued that “wind and solar is more expensive and will increase the price of electricity.”
He noted that solar PV costs have dropped sharply in the last five years. “That’s one of the things that [has] changed since I made that statement,” he said.
But Simmons stumbled again under questioning from Sen. Rob Portman (R-Ohio), who with Sen. Jeanne Shaheen (D-N.H.) has led the — mostly unsuccessful — effort to win Congressional approval for tougher EE standards.
Portman asked Simmons his opinion of DOE’s “Tenant Star” program, the result of narrower EE legislation approved in 2015.
“The Tenant Star program, I’m not familiar enough with that to comment on it. But I will look into it,” Simmons said.
The senator asked whether there were more DOE should be doing on EE without Portman and Shaheen’s larger EE bill. “I’m not familiar enough with the legislation to add on to it,” Simmons responded.
Simmons was the only one of four DOE nominees testifying Tuesday to receive pointed questions from the senators. Also testifying were Teri L. Donaldson, nominee to be DOE’s inspector general; Christopher Fall, named as director of the Office of Science; and Karen S. Evans, who would become assistant secretary overseeing DOE’s new Office of Cybersecurity, Energy Security and Emergency Response.
MISO’s markets performed competitively last year, but the RTO should implement several new recommendations to improve market functions, the Independent Market Monitor’s 2017 State of the Market report concluded.
MISO IMM David Patton said energy prices averaged $29.46/MWh in 2017, an 11% increase over 2016 but in line with rising prices for natural gas and other fuels.
“The markets continued to perform competitively, although we have areas of concentration with local market power,” Patton said during a June 26 conference call held by the Markets Committee of the MISO Board of Directors.
But market performance could be made more efficient, Patton said, offering seven new market recommendations in combination with past State of the Market suggestions.
Fast-Track Ideas
Patton said two of his new recommendations could be fast-tracked and not require a slot on MISO’s Market Roadmap process, which is traditionally reserved for more complex improvements.
The first: to improve market power mitigation rules. Patton said his proposed changes are “modest in scope and impact” but would help in the effectiveness of market power mitigation provisions.
“Every year, MISO makes a cleanup filing of [mitigation rules], and we collaborate with them on it,” Patton explained. This year he has recommended that MISO adjust its impact test and sanctions rules to include the impact of negative prices; make the price impact threshold for ancillary services better reflect prevailing clearing prices; and create a better generation shift factor cutoff on mitigation for broad constrained areas, a type of congested transmission area. Including negative prices in mitigation measures will allow the Monitor to “effectively mitigate conduct whose effect is to lower prices at locations and aggravate transmission constraints,” Patton said.
Patton’s second fast-track suggestion would remove transmission charges from coordinated transaction scheduling (CTS) transfers with PJM. MISO and PJM launched CTS last October to allow market participants to schedule economic transmission transactions based on forecasted energy prices in the two RTOs. While CTS should have lowered the cost of serving load in both regions, it has not been used since mid-February because MISO has been applying transmission charges to the transactions both when they are offered and scheduled, Patton said.
“We had advised that the RTOs not apply transmission charges or allocate costs to these transactions because they do not cause any of these costs,” said Patton, who estimates the charges average $6.24/MWh on MISO imports and $2.57/MWh on exports. He urged MISO to “unilaterally eliminate” all charges from CTS transactions.
“Although MISO should encourage PJM to do the same, there is no reason to wait for PJM to agree to eliminate its charges,” Patton said. “We could change these relatively quickly … This is a very discreet change,” he told MISO board members.
Quick Fix to Make-Whole Payments
Patton said another “relatively simple” market change could help MISO distribute make-whole payments more accurately: improve commitment classifications and create a process to correct classification errors.
Patton said his team has observed MISO operators misclassifying “a fair number” of resource commitments needed to manage transmission constraints as capacity commitments. The RTO assigns a classification code to any resource it commits to either satisfy capacity needs or manage transmission constraints, which determines whether the resource is eligible for make-whole payments through its revenue sufficiency guarantee (RSG), how the RSG payment will be allocated and whether the payment will be subject to mitigation. Patton said the misclassification of code assignments can have “significant” implications on revenue sufficiency guarantee allocations and market mitigation.
“ … It is imperative that MISO have a robust process for reviewing and correcting commitment classifications as needed,” Patton said. He added that he also understood some commitments can address multiple issues and constraints and called on MISO to create clearer procedures for determining a classification based on “cost-causation” principles.
Operator Accountability
Another recommendation would place more accountability on MISO operators in the control room by improving operator logging tools to better describe operator decisions and actions. Patton said MISO operators often inconsistently log or describe manual adjustments, making them difficult to evaluate later.
Operators can make several system adjustments, including changes in generating units’ operating status, real-time adjustments to forecasted load, manual redispatch of resources for system needs, alterations of real-time limits for transmission constraints, real-time adjustments to the transmission constraint demand curve and requests for market-to-market constraint tests and activations.
“Because these actions can have significant cost and market performance implications, we recommend that MISO upgrade its systems and procedures to allow these and other operator actions to be logged in a more complete and detailed manner,” Paton said, adding that MISO could include new logging tools in its effort to replace its market platform.
Day-Ahead Market Change
Patton also proposed MISO’s platform replacement effort could provide MISO the chance to evaluate the feasibility of solving the day-ahead market with 15-minute — rather than hourly — scheduling intervals. Patton said when MISO first created its markets, the day-ahead software wasn’t sophisticated enough to be more time-specific.
“By producing hourly schedules based on 60-minutes of ramp capability and hourly load forecasts, the day-ahead schedules cannot track the expected changes in real-time system needs, particularly during ramping periods. It also regularly results in generator schedule changes from hour to hour that are not feasible, which results in substantial make-whole payments,” he said.
But advances in technology might permit 15-minute day-ahead market schedules, which could improve market response times and reduce uplift costs.
Auction Improvements
Patton’s two final recommendations involve MISO’s annual Planning Resource Auction (PRA).
The first suggestion would require that installed capacity of planning resources be deliverable over the transmission network. While the Tariff already requires all resources to be deliverable to load to qualify as capacity resources, Patton says that, in one instance, MISO’s deliverability requirements are too relaxed because resources with Energy Resource Interconnection Service (ERIS) must only secure firm transmission for its unforced capacity values, which tend to be about 5% to 10% less than their full installed capacity levels.
But Patton said resources with ERIS should be required to procure firm transmission service to the full level of their installed capacity.
“The requirements imposed by MISO on ERIS resources is not consistent with the intent of the Tariff. We recommend that MISO determine deliverability for all resources based on the entire [installed capacity] of applicable planning resources,” Patton said.
Such a move will improve the accuracy of MISO’s loss-of-load studies since they are conducted with the assumption that resources will perform up to their installed capacity when available, he noted.
The Monitor also recommended MISO establish unique capacity credits in the PRA for emergency-only resources that better reflect their availability. While those resources can be compensated through the PRA, they are only required to deploy during emergencies when called on by MISO. If they “are not available to mitigate capacity shortages that usually occur early in the emergency events, then they are not providing the reliability value assumed in the planning studies and for which they are compensated,” Patton said.
An increased volume of emergency-only resources cleared in this year’s PRA. (See MISO Clearsat $10/MW-day in 2018/19 Capacity Auction.) Patton pointed out that some of the resources have lead times up to 12 hours that “render them essentially unavailable in an emergency.” He said emergency-only and load-modifying resources should only receive full PRA capacity credit if “they are expected to be reasonably available in an emergency” and can respond to a benchmark not yet established by MISO.
Patton pointed out that other generation is subject to capacity-selling requirements, including qualifications based on past forced outage performance, day-ahead must-offer rules and reduced capacity credits for intermittent resources. He recommended MISO quantify emergency-only capacity credits based on factors such as expected availability, historical performance and curtailment ability.
Executive Director of Market Development Jeff Bladen said MISO will provide a formal response to this year’s report within 120 days, per its Tariff.
Bladen reminded the board that MISO’s ability to take on new market improvements will continue to be “constrained” by MISO’s technology capabilities as the RTO replaces its outdated market system platform. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)
