SPP’s Market Monitoring Unit (MMU) last week conducted its first quarterly market report webinar, importing a practice MMU Executive Director Keith Collins used while at CAISO.
“It is not only a great forum for us to present on our quarterly report, but it also allows for great interactive discussion between market participants and market monitoring staff,” said Collins, who joined the MMU last year.
Staff reviewed the report’s highlights, focusing, as the report did, on the SPP market’s growing frequency of negative price intervals. The MMU said the market’s practice of self-committing resources in the day-ahead market may be exacerbating the situation.
“We’re not saying negative prices are bad, but they are an indication of what happens on the system as a consequence of thousands of megawatts not participating in the day-ahead market,” Collins told participants. “When they show up in the real-time market, it can create this disconnect.”
Negative Prices | SPP MMU Fall 2017 Quarterly Report
Collins said the MMU will repeat the practice following each quarterly and annual market report. The calls are open to members, market participants and regulatory staff, among other stakeholders.
“Our goal is to improve the markets through education and understanding of market outcomes,” he said.
December MISO-SPP M2M Results in $4.2M in Charges
SPP recorded its third consecutive month of multimillion-dollar market-to-market (M2M) payments from MISO in December, staff told the Seams Steering Committee on Feb. 7. The month’s $4.2 million in charges pushed the amount of M2M payments to SPP past $36.8 million.
M2M Update December 2017 | SPP
Permanent and temporary flowgates were binding for 531 hours in December. SPP’s Riverton-Neosho-Blackberry flowgate on the Kansas-Missouri border was once again responsible for the bulk of the charges.
The two RTOs began the process in March 2015. SPP last month said it has reimbursed MISO more than $2.25 million after resettlements of several M2M flowgates, and that it will continue to perform “limited” resettlements because of a memorandum of understanding between the two. (See “SPP Pays MISO $2.25M After M2M Resettlements,” SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018.)
Staff also briefed the committee on the Feb. 27 MISO-SPP Interregional Planning Stakeholder Advisory Committee meeting. The RTOs’ staff and stakeholders will discuss improvements to the Coordinated System Plan, which has identified four potential seams projects in two previous iterations. None of the four survived regional reviews.
SPP is also trying to meet with Associated Electric Cooperative Inc. before March 9. Staff have drafted a scope that identified needs from its 2018 Integrated Transmission Planning Near-term Assessment that are “electrically significant to the SPP-AECI seam.”
Board Approves Non-Jurisdictional Tariff Change
The Board of Directors approved a Tariff revision that incorporates a refund obligation for SPP’s nonpublic transmission-owning utility members during a special conference call Monday afternoon.
The measure addresses a FERC directive that SPP require non-jurisdictional transmission owners to refund revenues received associated with their service, and that it enforce the membership agreement in court (EL18-19). The RTO has a Feb. 28 filing deadline in the docket. (See FERC Backs off Nonpublic Utility Refunds in MISO, SPP.)
The 20-person Members Committee was divided on its advisory vote to the board, with five members — Empire District Electric, Oklahoma Gas & Electric, Public Service Company of Oklahoma, Southwestern Public Service and Westar Energy — casting opposing votes.
The proposal, which was recommended by the Corporate Governance Committee, includes a provision that should there be a conflict between a FERC refund order and state statute, the refund amount would be deemed uncollectable. Members questioned why non-jurisdictional members should be treated differently than investor-owned utilities and whether their customers might pick up the tab for those entities unable to provide refunds.
“If our customers are overpaid and there’s a refund order, our customers are left with a short amount,” said OG&E’s Greg McAuley.
Kansas City Power & Light’s Denise Buffington, who represents IOUs on the CGC, said she supported the measure because of her understanding that the Nebraska Constitution prevents its entities from delegating authority to someone else.
“I’m OK with this if SPP can show how everyone else will be kept harmless,” she said. “I will be closely scrutinizing the SPP filing. If it doesn’t show harm to other members, we will be filing comments in the docket.”
FERC ruled Friday that the developer of a proposed 1,500-MW Indiana wind farm must go to the end of the interconnection queue to move its point of interconnection (POI) 2.9 miles.
The commission’s Feb. 9 order rejected Harvest Wind’s request for a waiver allowing it to change the POI without triggering the “material modification” language under PJM’s Tariff. FERC sided with PJM in requiring a new queue application and facilities study (ER18-615).
Colorado-based Renewable Energy Systems Americas acquired the Harvest Wind project after the previous developer agreed in late 2016 to move to a second POI after AEP Indiana Michigan Transmission said the original was not a suitable spot for the wind farm’s 765-kV switchyard.
RES Americas said it learned in fall 2017 that the new location, POI 2, had some of the same problems as the original location, including wetlands and endangered species concerns. In addition, noise from the switchyard’s transformers would be too loud because of nearby houses, the company said in its Jan. 5 waiver request.
The developer said its proposed interconnection, POI 3, is “electrically identical” to the current location because it is just 2.9 miles away on the same 765-kV transmission line.
PJM opposed the request, arguing that the waiver would delay other projects in the queue because of the size of the wind project and the need for transmission restudies.
The commission agreed with PJM, finding that “Harvest Wind has not sufficiently demonstrated that it acted in good faith. Harvest Wind states that it became aware in September 2016 that both POI 1 and POI 2 presented some complicating factors due to site topology, but at that time it did not believe these factors were insurmountable. … Moreover, Harvest Wind fails to explain why it did not discover these additional complications for almost a year after initially being put on notice that complications existed at POI 1 and POI 2, demonstrating a lack of due diligence on Harvest Wind’s part.
“Harvest Wind has not sufficiently demonstrated that granting the waiver request will not have undesirable consequences or harm third parties,” the commission continued. “We agree with PJM that changing the point of interconnection at this late stage would introduce uncertainty that could well impact other lower-queued interconnection customers and that such restudy of the point of interconnection would require reassessment of protection, requiring the expenditure of time and resources, thus burdening and harming other parties.”
RES Americas said in its waiver request that it might be forced to abandon the project if the waiver were not approved.
An RES Americas spokesman said the company was “planning to proceed with the project” but did not say why a delay might force it to abandon it.
FERC approved PJM Tariff and Operating Agreement revisions incorporating two pro forma pseudo-tie agreements and a pro forma reimbursement agreement effective Nov. 9, 2017.
The commission’s Feb. 5 order rejected protests by MISO’s Independent Market Monitor, NYISO, American Municipal Power, Illinois Municipal Electric Agency and North Carolina Electric Membership Corp. (ER17-2291). (See Critics Protest PJM Dynamic Transfers Plan.)
| MISO, PJM
In its protest, NYISO said PJM’s rules will likely cause “adverse reliability impacts” and “exacerbate interregional seams.” But PJM pointed out that there are no resources currently pseudo-tied into PJM from NYISO.
The MISO Monitor David Patton contended FERC should not consider PJM’s proposal separately from other pending pseudo-tie proceedings. The plan creates “substantial economic and reliability harm to the customers in [the MISO and PJM] area,” he said.
The commission was unpersuaded, saying: “The terms of the proposed revisions and pseudo-tie agreements are not unjust and unreasonable merely because the commission has not yet acted in the other proceedings.” FERC also rejected the Monitor’s request for a technical conference.
“We agree with PJM that the pseudo-tie agreements and corresponding Tariff and Operating Agreement revisions promote uniformity among the pseudo-tie and dynamic schedule requirements and increase the transparency and efficiency of the implementation process,” the commission said.
California regulators on Thursday approved an order putting new requirements on community choice aggregators (CCAs), saying the decision did not come easily.
At the same time, CCAs and their supporters are arguing for more transparency and control over resource adequacy (RA) procurement.
“I just have overwhelming anxiety about the purpose of resource adequacy,” California Public Utilities Commission President Michael Picker said, addressing a crowded hearing room at commission headquarters in San Francisco after a public comment period. “It seems as if people have forgotten the energy crisis of 2001 and 2002.”
The State Legislature authorized the creation of CCAs in 2002 in response to the energy crisis, allowing local governments to directly contract for energy services to serve their residents. CCAs did not begin appearing until 2010 but have since grown rapidly.
Until now, CCAs have avoided the requirement to carry RA reserves, even as they’ve taken on a greater share of California load. Instead, customers of investor-owned utilities have been left with stranded costs because of the timing of load forecast submissions and RA allocations, in some cases procuring RA for customers about to be served by CCAs. Cost-shifting can run into the tens of millions of dollars annually, the CPUC said.
Picker struck an assertive tone on the RA issue, saying that grid reliability is at stake as procurement of electricity disaggregates through CCAs, which he’s unsure could meet critical grid needs.
“It really makes me nervous and it makes me wonder if people are really prepared to embrace this opportunity to serve as [load-serving entities],” Picker said, adding that the CPUC made reasonable efforts to accommodate the concerns of CCA supporters.
The CPUC made changes to its initial RA proposal in response to written comments, including extending the deadline for CCAs to submit their RA implementation plans until March 1 in order to allow several of them to begin serving their new customers in 2019. The CPUC also created two waiver options, one in which CCAs and IOUs can agree on the CCA’s RA requirements and cost responsibility, and another stipulating that if agreement was not reached, the CCA agrees to be bound by a future CPUC determination in the RA proceeding regarding its RA cost responsibility.
Many of the more than 40 registered speakers attending the CPUC hearing were there to speak against the CCA ruling. West Hollywood City Councilmember Lindsey Horvath told the CPUC that CCA customer energy costs must be determined in a fair and open process.
“How can we properly determine our fair share without access to contracts we’re being asked to account for?” Horvath asked. “We are glad to see the direction the commission is moving with in the current form of its resolution, but we’re not there yet.”
The CPUC introduced the proposal in December with a comment period near the holidays, leaving CCA representatives saying the expedited order did not give them time to provide input. (See California Proposes Resource Adequacy Obligations for CCAs.) Other proponents said it would delay CCA creation and slow achievement of climate goals. CCAs have grown rapidly and are popular as a way for localities to take control of energy consumption, with many marketed as green energy options.
But Picker said that if the decision delays the implementation of CCAs, “we are just going to have to live with that.” The consequences of having grid failure “can wipe the slate clean,” he said, again invoking the reliability crisis of the early 2000s.
Commissioners appeared sympathetic to CCA supporters, but Martha Guzman Aceves said that issues with the RA program have led to more procurement of natural gas generation.
“This is a problem to reaching our climate goals,” she said. “This is actually an environmental justice issue for me.” She added that, “Sometimes we don’t use the best process, I totally acknowledge that. But we need to deal with this problem now.”
“There has got to be good dialogue, there has to be trust,” Commissioner Carla Peterman said. “The last thing I want is to exacerbate tension between the CCAs, the utilities and the commission.”
In its order, the CPUC said: “Numerous commenters assert that the resolution violates their due process rights. We disagree. The changes in the CCA timeline made by this resolution are an exercise of authority the commission has had since 2002.”
Decision Adopts IRP Process
Another decision approved by the CPUC on Thursday sets RA requirements for all California LSEs. It institutes a two-year integrated resource planning process including electrical cooperatives, IOUs, CCAs and electric service providers.
The decision also recommends the state’s Air Resources Board adopt a greenhouse gas emissions target for the electric sector of 42 million metric tons by 2030, a 50% reduction from 2015 levels.
CPUC Delays Gas Moratorium Vote
In other items on the CPUC decision list, the commission tabled a proposal to require Southern California Gas to enact a moratorium on new commercial and industrial natural gas connections in Los Angeles County because of supply issues.
The CPUC said that while conservation measures by customers in response to the Aliso Canyon storage facility have helped, “significant new reliability challenges on the SoCalGas system exist due to a series of major unplanned outages and maintenance issues. The Los Angeles region faces greater uncertainty than a year ago with respect to the ability of SoCalGas to meet customer demand this winter.”
FORT LAUDERDALE, Fla. — The chairman of NERC’s Board of Trustees said last week the organization hopes to have a new CEO in place by the summer.
Roy Thilly told the Member Representatives Committee (MRC) during its Feb. 7 quarterly meeting that the selection process is “well underway,” with a goal for this spring.
“This is an important decision the full board needs to be involved in,” he said.
Russell Reynolds Associates has been conducting the executive search. Thilly said the board will select a group of about eight potential candidates, with a small group of trustees whittling that list down to two or three final candidates. The board will interview each of the finalists.
“Essentially, we want to be enthusiastic about the final candidate and have no hesitation that we have the right person for this job,” Thilly said. “If we don’t, then it’s important that we step back and take the time to do so.”
NERC has been without a CEO since Gerry Cauley resigned in November following his arrest for domestic abuse. General Counsel Charlie Berardesco stepped into the CEO role on an interim basis. (See Cauley Resigns; NERC Launches Search for Replacement.)
Thilly complimented NERC’s management team and staff for “really stepping up,” along with the Regional Entity CEOs.
“We feel like we’re in a good place right now,” he said. “The feedback I’ve gotten is that Charlie has stepped into the job in a seamless way and pulled the organization together.”
NERC also needs to hire a new chief security officer to replace Marcus Sachs, who resigned shortly after Cauley. (See NERC Parts Ways with Chief Security Officer.) Thilly said candidates have been “assembled,” but the agency won’t move forward until the new CEO is in place.
“It’s essential the new CEO participate in that hiring process and be very comfortable with the selection,” he said.
FERC’s McIntyre Says Resiliency Still of Interest in DC
FERC Chairman Kevin McIntyre told NERC trustees and stakeholders that the federal government still remains focused on grid resiliency, despite the commission’s rejection of the Department of Energy’s Notice of Proposed Rulemaking meant to address the issue. FERC launched a new resiliency initiative Jan. 8 after declining to take up the department’s proposal.
“Interest in that subject is not waning on [Capitol Hill], and it is not waning in the administration,” McIntyre said. “When real-world engagements occur with resiliency, like it’s old-fashioned cousin, reliability, we should use that as a teachable moment, and take lessons forward into the game plan and be better prepared for future events.”
McIntyre said the commission looks forward to working with NERC, and that it must remain “vigilant” in ensuring the grid’s resiliency, “a phrase you’ve no doubt heard.”
McIntyre and Berardesco were among several industry witnesses who recently testified before the Senate Energy and Natural Resources Committee about the January “cold-weather bomb.” (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“Hanging in the air was the broader overall topic of grid resiliency,” McIntyre said. “I was very glad to be in a position to report that, based on various analyses, the bulk power system operated very reliably. My general impression was that my report, and those of the other witnesses, was well-received and appreciated in how well the grid performed.”
Resiliency is a priority at FERC, McIntyre said, and he expressed his gratitude to NERC for its work on the issue. He referenced the MRC’s Reliability Issues Steering Committee, which, at the trustees’ request, is developing a framework for resiliency.
The committee told stakeholders that most resilience definitions have two common elements: that it is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. It said the National Infrastructure Advisory Council’s framework for establishing critical infrastructure goals is a “credible source for further understanding and defining resilience.”
Bruce Walker, assistant secretary of the Energy Department’s Office of Electricity Delivery and Energy Reliability, said the department’s goal is to develop partnerships within the industry and provide resources to move issues forward.
“We have the opportunity to see the results of real work being done by FERC and NERC, and to shape policy through our coordination with both of these agencies,” said Walker, whose nomination was approved in October. “The [DOE] has stepped back to take a look at what our mission really is. It is … our mission-critical focus across the energy sector.”
Walker, formerly a deputy executive for Putnam County, N.Y., ran a boutique consulting firm focused on risk management at investor-owned utilities and served in leadership positions at National Grid and Consolidated Edison. He said his first goal is to develop a North American energy model “that integrates all different forms of energy so that we can run, like we do on our transmission system, a load flow.”
He said the bulk power system’s interdependencies will identify “those assets than can be enhanced, replaced or installed” to improve the system’s “affordability” as “we start moving forward” with the administration’s proposed $1.5 trillion infrastructure bill.
Other goals will focus on cyber and physical security, rapidly moving forward storage technologies, making use of sensing technologies and developing hardening strategies that add “some resiliency in a viable way.”
Jim Robb, CEO for the Western Electricity Coordinating Council, said recent developments within the Western Interconnection have put “substantial financial pressure” on Peak Reliability, the region’s delegated reliability coordinator (RC).
Within the past few months, Peak has announced it would team up with PJM Connext to attract participants to a new Western energy market. (See Peak, PJM Pitch ‘Marketplace for the West’.)
“Obviously, significant changes are going on that create a lot of uncertainty about how the ultimate reliability landscape will play out,” Robb said. He thanked FERC staff for working with WECC staff “as we move to a multiple RC model.”
NERC, WECC, British Columbia Agree to MOU
The board unanimously approved a memorandum of understanding between the British Columbia Utilities Commission (BCUC), WECC and NERC.
Modeled on recent MOUs with other Canadian jurisdictions, the agreement recognizes the parties’ roles under existing laws and authorities, maintains the status quo on funding arrangements, and provides for sharing of confidential and compliance-related information. WECC will periodically provide information on the Canadian province’s noncompliance for NERC’s review.
WECC General Counsel Steve Goodwill said a fully executed MOU should be in place in March, pending board approval from NERC and WECC.
NERC began formal correspondence with British Columbian authorities in 2006, while WECC has provided compliance monitoring for BCUC since 2009 through an administration agreement.
Goodwill said WECC is also negotiating similar terms with Mexico that recognize the changes in that country’s regulatory structure.
“Like the MOU with British Columbia, it will openly recognize for the first time the ability to share critical information on compliance enforcement in Mexico with NERC,” Goodwill said. “This is an all-around good story. The ability to share data among ourselves is critical.”
The MRC approved two new members and re-elected two incumbents to the board. Suzanne Keenan was elected to a two-year term expiring in 2020 and Rob Manning to a three-year term expiring in 2021, while George Hawkins and Jan Schori were re-elected to three-year terms also expiring in 2021.
Keenan served as CIO and senior vice president of process improvement for Wawa from 2008 to 2017. Her industry experience includes field services, re-engineering and performance, regulatory performance, and emergency preparedness experience with PECO Energy.
Hawkins, CEO of the D.C. Water and Sewer Authority, was first elected to the board in 2015. He serves on the Standards Oversight & Technology and Corporate Governance & Human Resources committees.
Manning was involved in transmission and distribution infrastructure research for the Electric Power Research Institute but will give up those duties with his election. He also spent six years with the Tennessee Valley Authority.
Schori, former CEO of the Sacramento Municipal Utility District for more than 14 years, was elected to the board in February 2009. She chairs the Finance and Audit Committee and serves on the Compliance and Enterprise-wide Risk committees.
The D.C. Circuit Court of Appeals last week dismissed the Kansas Corporation Commission’s appeal of a 2015 FERC ruling over formula rates, saying it lacked standing in the case (No. 16-1093, 16-1164).
The KCC argued before the court in November that FERC acted unlawfully by approving formula rates for future public utilities to use in operating electric transmission facilities. The Kansas commission asserted that FERC couldn’t determine that the formula rates for “not-yet-existing entities to implement at some point in the future” are just and reasonable.
D.C. Circuit Courthouse | U.S. Court of Appeals
Writing for the three-judge panel on Feb. 6, Judge Karen Henderson said the KCC had not suffered harm sufficient to establish standing. “A harm that will not occur unless a series of contingencies occurs at some unknown future time is not concrete, particularized, actual and imminent,” she said.
The Kansas commission was appealing a 2015 FERC decision, in which the agency granted Transource Energy’s request for formula rates for future affiliates by replicating approved rates for Transource Kansas. Transource formed the wholly owned subsidiary to compete for Kansas-based transmission projects in SPP and said it expected to create additional subsidiaries in the future.
FERC rejected the KCC’s rehearing request in 2016, ruling that preapproving a formula rate for Transource Kansas, which did not operate any active transmission facilities, was “no different” from preapproving a formula rate for future Transource affiliates.
The KCC’s appeal to the D.C. Circuit also included a similar FERC proceeding involving MPT Heartland Development, which formed Kanstar to compete for Kansas-specific projects. The federal agency in 2015 approved Kanstar’s request for a formula rate for its own use and that of future affiliates and later denied the KCC’s rehearing request.
The court consolidated the two appeals.
In November, the KCC lost another appeal in the D.C. Circuit when it attempted to challenge a 2014 FERC order approving SPP’s merger with the Integrated System. (See Court Rejects Challenge to SPP-Integrated System Merger.)
CARMEL, Ind. — MISO is proposing to set limits on the amount of time its members have to initiate alternative dispute resolution measures, but stakeholders are saying the RTO might not be leaving them enough room to research and raise settlement issues.
The RTO is recommending market participants have a 30-day time limit to request either an informal or formal alternative dispute resolution, John Weissenborn, director of market services, told a Feb. 8 Market Subcommittee meeting. Settlement disputes and corrections would be wrapped up within one year from the operating day in question under the proposal, he said.
The process is used in place of a lawsuit or FERC complaint when parties seek to negotiate contractual disputes over settlements. The RTO’s current Tariff doesn’t contain provisions that “categorically bar settlement disputes raised after a long time,” according to MISO.
MISO plans to revise Attachment HH of its Tariff — which governs such disputes — to provide market participants with 30 calendar days from the RTO’s denial of a settlement dispute to ask for an informal alternative dispute resolution, then another 30 days after that to request a formal dispute resolution if the informal request is denied by MISO.
Weissenborn said the deadlines will apply to both transmission and market settlements. The deadlines will promote “market certainty, prevent stale claims and facilitate accuracy in corrections of settlement statements,” he said.
MISO is aiming to file the plan with FERC by May, with the deadlines imposed by July.
Weissenborn said other RTOs have time limits ranging from five months to three years. Both SPP and PJM impose a two-year cutoff, while CAISO follows a three-year limit. NYISO employs the shortest cutoff at five months.
“There is precedent for this type of thing,” Weissenborn said. “It will encourage market participants to file their claim in a timely manner.”
Northern Indiana Public Service Co.’s Bill SeDoris and Dynegy’s Mark Volpe both asked how MISO’s one-year limit will line up with other RTOs’ disparate time limits should disputes involve inter-RTO matters, such as pseudo-ties and coordinated transaction scheduling, and which timeline MISO market participants should follow.
Weissenborn said MISO looked into such transactions and concluded that alternative dispute resolution would be separate for each RTO’s settlement.
Other stakeholders cautioned that the 30-day limit to research and initiate a dispute resolution may be too tight, asking instead for 60 or 90 days to initiate a dispute.
Weissenborn asked for more stakeholder comments over the next two weeks and said the comments could influence the final draft of MISO’s plan.
Lubbock’s City Council and Electric Utility Board last week both approved a settlement agreement with all parties involved in Lubbock Power & Light’s effort to move 470 MW of its load from SPP to ERCOT.
The agreement, with intervenors from both systems, was approved unanimously in separate votes. Following the board’s vote, LP&L on Thursday filed the stipulation and proposed order with the Public Utility Commission of Texas for its consideration. The PUC is scheduled to take up the issue during its Feb. 15 open meeting (Docket No. 47576).
LP&L power plant | LP&L
Under the agreement’s terms, LP&L will make a $24 million hold-harmless payment to Southwestern Public Service, which serves the utility’s load through a pair of long-term contracts, upon the transition’s effective date (targeted for June 1, 2021). The utility will also make five annual payments of $22 million, credited to ERCOT’s transmission customers in compensation for integration costs, and has committed to opting into the Texas ISO’s competitive market.
Preferred Option 4OW for Integrating LP&L | ERCOT
LP&L said it expects to achieve annual savings exceeding the two payments.
“The agreement … sets Lubbock on the best possible path forward that saves their ratepayers money and opens the door to retail electric competition in Lubbock,” the utility said in a statement.
The only issue left to decide is what entity will build the transmission facilities linking LP&L with ERCOT. The parties signing on the settlement agreement, which include PUC staff, SPS and several consumer groups, have recommended moving forward with a project already identified by ERCOT. A pair of independent transmission companies, Cross Texas Transmission and Wind Energy Transmission Texas, are urging the PUC to open the construction to competitive bidding.
ERCOT in 2016 said its preferred solution was “Option 4ow,” a $364 million project that would result in 141 miles of new 345-kV lines. Staff last week said a competitive bidding process would “consume time and commission resources” not needed if the PUC simply followed ERCOT protocols, which provide “a suitable guide in this unique situation.” (LP&L is not yet registered in the ISO and therefore not covered by its protocols.)
| ERCOT
Cross Texas said it envisions a competitive bidding process, conducted by the PUC, that could be accomplished in about 90 days.
LP&L formally announced in September its intention to move after one of its SPS contracts expires in 2021. A second SPS deal that expires in 2044 serves the remaining 130 MW of its load.
This year’s effort will be scaled back because of the ongoing, $130 million project to replace MISO’s market platform, Lakisha Johnson, market strategy adviser, said during a Feb. 8 Market Subcommittee meeting. (See 8 Projects Set for 2018 MISO Market Roadmap.)
Stakeholders have until May 1 to submit new ideas for market improvements, and the RTO has scheduled a June 7 workshop to discuss submissions. Stakeholders will then have until July 12 to rank the new ideas, which will influence MISO staff decisions on what improvements to pursue. Through December, MISO and stakeholders will work to integrate the selected ideas into the RTO’s existing list of Market Roadmap projects.
Minnesota Public Utilities Commission staff member Hwikwon Ham asked MISO if this year’s submission window will line up with the Independent Market Monitor’s annual State of the Market report, which provides market design recommendations.
The Monitor is planning to release the report earlier this year in an attempt to better align the two sets of recommendations, IMM staffer Michael Wander said.
SACRAMENTO, Calif. — Nearly 600 people crowded into the California Energy Commission’s EPIC Symposium on Wednesday, doubling attendance from last year.
It was a testament to the widespread interest in securing the hundreds of millions of dollars in grant funding California makes available to research and deploy innovative energy technologies.
Funded through a charge on utility electric bills, the CEC’s Electric Program Investment Charge program was designed to provide $162 million annually from 2013 to 2020 to bring innovative technologies to market. The California Public Utilities Commission created the initiative in December 2011 to promote clean energy technologies, reliability, lower costs and safety. About $130 million of the annual funds are administered by the CEC.
State Sen. Nancy Skinner (D) told a packed room that the EPIC program is a way to explore and develop energy storage technologies that can reduce the curtailment of renewables and foster other efficiency improvements.
“We want to wrestle every bit of output from each unit of electricity or energy we produce,” Skinner said, discussing how her 2010 legislation, AB2514, fostered storage deployment by requiring the CPUC to consider mandating storage procurements for investor-owned utilities. “IOUs bought more storage and the price of storage came down. We want it to come down further.”
“EPIC has contributed to the development of numerous green technologies and facilitated the creation of thousands of jobs,” State Assemblymember Autumn Burke (D) said.
The CEC marked its third iteration of the EPIC program when it submitted its 2018-2020 Triennial Investment Plan last spring. The document lays out in detail the commission’s strategy over the three-year period for allocating the funds provided through EPIC, promising more coordination with local governments and enabling market growth of distributed energy resources.
“When we look at EPIC 3, we are really kind of thinking of that next generation of grid technology,” said Daniel Ohlendorf, Pacific Gas and Electric’s senior manager of electric emerging technologies.
“Electric vehicles and storage continue to be very important to us,” he said, as well as new maintenance approaches using new technologies such as augmented reality (computer-generated imagery) and drones.
Utilities at the symposium also discussed the growing pains associated with implementing storage technology. PG&E’s Morgan Metcalf described the challenges of behind-the-meter implementation.
“Figuring out how to use all these resources is an important next step,” Metcalf said. “It’s not just policy that is driving this, it is our customers as well.” She added that PG&E customers are increasingly exploring solar, electric vehicles and energy efficiency.
Southern California Edison, Lawrence Berkeley National Laboratory, the University of California Berkeley and a diverse group of companies and energy organizations also held panel discussions at the symposium, with a strong focus on engineering issues, new technologies and applications such as food production.
Feb. 20 Deadline
The EPIC program is actively soliciting applications for a $15 million “Bringing Rapid Deployment to Green Energy” grant, which includes $10 million in applied research and development and $5 million for technology demonstration and deployment. Open until Feb. 20, the CEC developed the solicitation to provide follow-on funding for “the most promising energy technologies” that have previously received an award from an eligible state or federal agency for research, technology demonstration and deployment.
“The purpose of this solicitation is to fund applied research and technology demonstration and deployment energy efficiency projects that will allow researchers to continue their technology development without losing momentum or pausing to fundraise from private sources,” the CEC said. The grant is focused on advancing technology to commercialization, and is not open to public and private universities, national laboratories, utilities, private nonprofit research organizations and technology end users.
