Page 1576 – RTO Insider

December 16, 2016

FERC Proposes Changes to Interconnection Rules

By Michael Brooks

FERC on Thursday proposed changes to its pro forma large generator interconnection rules intended to increase certainty and transparency for new resources (RM17-8).

The commission issued the Notice of Proposed Rulemaking in response to feedback gathered at a May technical conference and in subsequent comments. (See Generators, Tx Operators Spar over Interconnection Processes Before FERC.) Generation developers have long complained about the long wait time for interconnection approvals. Transmission providers complained about the number of projects that drop out of the interconnection queue — increasing the number of restudies needed — and the high concentration of projects, such as wind farms, in small geographic areas.

ferc interconnection rules — Wind farm near Palm Springs, Calif. | © *RTO Insider*

“Cost and timing uncertainty presents a significant obstacle, as some interconnection customers are less able to absorb unexpected and potentially higher costs or extended timelines resulting from the withdrawal of requests higher in the queue,” the commission said in a news release. “A lengthy interconnection process can be a challenge to generation technologies that are evolving rapidly. The commission believes that interconnection processes should be capable of incorporating rapidly evolving generation technologies into an interconnection request while maintaining system reliability.”

FERC detailed 14 changes to the pro forma Large Interconnection Agreement and Interconnection Procedures that it said should address these and other concerns. Among the most notable are requirements that transmission providers post the methodologies used to form network models in their interconnection studies, as well as congestion and constraint information, on their Open Access Same-Time Information System (OASIS) sites.

They would also be required to allow interconnection customers to:

limit their requested level of service below their generating facility’s capacity;
operate on a limited basis before the full interconnection process is completed; and
use surplus interconnection service at existing points.

RTOs and ISOs would also be required to develop a resolution process for interconnection disputes between developers and transmission owners.

The reforms would apply to projects over 20 MW, but the commission is seeking comment on whether any of them should apply to rules for small generators as well.

Commissioner Colette Honorable cited the need to accommodate new technologies, such as energy storage, as one of the main reasons for the NOPR. Two of FERC’s changes dealt with energy storage resources specifically. One would change the definition of “generating facility” in the pro forma documents to explicitly include storage. The other would require transmission providers to evaluate their methodologies for modeling storage resources in their interconnection studies and report their findings to FERC.

“The commission believes the proposed reforms will benefit interconnection customers through more timely and cost-effective interconnection and will benefit transmission providers by mitigating the potential for serial restudies associated with late-stage interconnection request withdrawals,” it said.

“I think this is a good example of the kind of bread-and-butter work that FERC does that may not always receive much public attention: work that is technical and weedy, but work that nevertheless is very important,” Chairman Norman Bay said at the commission’s open meeting Thursday. “I think today’s NOPR strikes an important balance between the needs of interconnection customers and those of transmission owners.”

Stakeholders have long sought commission action on the interconnection process. The pro forma agreement and procedures were established in 2003 and most recently updated in 2008. May’s tech conference was prompted by a petition from the American Wind Energy Association last year. (See After Years of Questions, Interconnection Customers Await Answers.)

Comments are due no later than 60 days after the NOPR’s publication in the Federal Register.

December 15, 2016

Michigan Upper Peninsula Getting its Own Utility

By Amanda Durish Cook

Michigan’s Upper Peninsula will get its own utility, two new generating plants — and maybe additional transmission — following actions by regulators and MISO officials seeking to address the region’s reliability and cost concerns.

MISO said Wednesday it has committed to a study examining the benefits of transmission connection between Ontario and Michigan’s Upper and Lower Peninsulas. The announcement followed the Michigan Public Service Commission’s Dec. 9 order approving the creation of the Upper Michigan Energy Resources Corp. (UMERC) (Case No. U-18061).

The company will be formed from the electric and gas distribution assets of Wisconsin Electric Power Co. (WEPCo) and Wisconsin Public Service — both subsidiaries of Milwaukee-based WEC Energy Group — and will begin serving about 40,000 Upper Peninsula customers Jan. 1.

The terms of UMERC’s creation were negotiated under a settlement signed by the companies, PSC staff, Attorney General Bill Schuette, Tilden Mining, Cloverland Electric Cooperative and others.

No Cost Sharing

PSC spokeswoman Judy Palnau said the new utility will avoid cost-sharing with Wisconsin, as it will be regulated by Michigan alone.

The utility will be the owner and operator of two new proposed generating facilities expected in operation by 2019, one year before the Presque Isle plant in Marquette shutters. UMERC will depend on power purchase agreements with WEPCo and WPS until the new generation is operating.

presque isle plant michigan — Presque Isle Power Plant | *WEPCo*

The commission said rates and service for Upper Peninsula customers should not be adversely affected by the changes.

“The transition to UMERC for ratepayers will be as seamless as possible. The commission observes that the personnel currently responsible for management, communications, regulatory compliance and customer relations will not change. Moreover, the PPAs will offer reasonable and affordable rates that may indeed, as the record indicates, be slightly lower than recent rates,” the order said. “The commission is also persuaded that the settlement protects ratepayers from any rate impact associated with the termination of Tilden as a customer, whether voluntary or involuntary. The settlement represents the beginning of the process of ensuring that reliable and affordable power is available over the long term in the UP.”

WEC spokeswoman Amy Jahns said the new utility would not have employees “specifically” assigned to it; instead, WEC’s office in Iron Mountain, Mich., and its WPS office in Menomonee, Mich., “will provide services to support the new utility.”

Jahns said the company is awaiting approvals regarding UMERC from the Wisconsin Public Service Commission and FERC.

Conditions Attached

The PSC’s approval came with several conditions, including that Michigan PSC staff receive UMERC’s yearly capital reports and operations plans and have access to all of WEPCo’s books and records concerning the 431-MW Presque Isle plant when the commission reviews the plant for decommissioning and final cost recovery from ratepayers.

WEPCo and WPS are also barred from changing any of the terms of their PPAs until Jan. 1, 2020. The companies also cannot request FERC to shift “any costs to UMERC customers that are currently shared between Wisconsin and Michigan.”

UMERC plans to build two natural gas-fired plants totaling 170 MW in the Upper Peninsula to provide power in the absence of the Presque Isle plant. WEC will seek permission from the PSC to build the plants next year. (See Upper Peninsula Ratepayers to Seek FERC Probe of Billing Fraud.)

PSC staff and Schuette supported the utility’s creation after the PSC obtained additional information in November on whether the proposal would have an adverse impact on customer rates.

Reliability and costs have long been concerns in the sparsely populated Upper Peninsula. Until recently, the area was home to a trio of system support resource agreements with MISO that kept retiring coal units online. Last month, FERC ruled that MISO and American Transmission Co. could reconfigure the western Upper Peninsula transmission system into two load pockets to end the last of the three SSRs. (See MISO Allowed to End White Pine SSR.)

MISO Agrees to Michigan Reliability Studies

At today’s Planning Advisory Committee meeting, MISO committed to a pair of reliability study requests submitted earlier this year by Michigan officials.

One will examine the benefits of transmission between Ontario and Michigan. The second will evaluate resource adequacy in MISO’s Local Resource Zone 7 in Lower Michigan under a scenario without either the Palisades or Fermi nuclear plants. Earlier this month, Entergy and Consumers Energy announced they intend to mothball the Palisades nuclear plan in southwestern Michigan on Oct. 1, 2018. (See Entergy, Consumers Announce Closure of Palisades Nuke.)

The studies were requested this summer by Michigan Gov. Rick Snyder, who asked the RTO to determine whether transmission linking northern Michigan to Ontario could improve reliability and reduce costs. (See Michigan Asks MISO to Study Tx Links to Ontario.)

“Generally when we get a request from a state, we try to be responsive as we can because we do believe that’s part of our role,” MISO Director of Planning Jeff Webb said.

MISO engineer Adam Solomon said the first phase of the studies are already underway and expected to be completed as part of the 2017 Transmission Expansion Plan’s batch of studies using Electric Generation Expansion Analysis System (EGEAS) modeling. Solomon said while the studies will “kind of overlap MTEP 17, [they are] not necessarily contained within.”

MISO Director of Regional and Economic Studies John Lawhorn said that although the studies will be treated separately, they are related to Michigan’s reliability concerns. “The results of one study will influence the other,” he said.

Lawhorn said the second phase of the studies, a transmission analysis, would begin early next year.

December 15, 2016

EPA: Poor Fracking Practices Have Harmed Drinking Water

By Rich Heidorn Jr.

In a widely anticipated report, EPA said yesterday that fracking has harmed drinking water resources under some circumstances but that data gaps have made it impossible to quantify the scope of the problem.

The agency said it identified cases of impacts on drinking water at each stage in the fracking water cycle: acquiring water for use in fracking; mixing the water with chemical additives; injecting the water and chemicals into the production well to create and increase fractures; collecting wastewater after injection; and disposing or reusing wastewater.

General timeline and summary of activities at a hydraulically fractured oil or gas production well | *EPA*

“Impacts cited in the report generally occurred near hydraulically fractured oil and gas production wells and ranged in severity, from temporary changes in water quality to contamination that made private drinking water wells unusable,” EPA said.

The report identifies conditions under which impacts can be more frequent or severe, including:

Water withdrawals in times or areas of low water availability, particularly areas with limited or declining groundwater;
Spills of fracking fluids or wastewater involving large volumes or high concentrations of chemicals reaching groundwater;
Injections into wells whose steel casing or cement lacked “mechanical integrity,” allowing gases or liquids to escape;
Injections directly into groundwater resources;
Discharge of inadequately treated wastewater to surface water resources; and
Disposal or storage of wastewater in unlined pits.

“This assessment is the most complete compilation to date of national scientific data on the relationship of drinking water resources and hydraulic fracturing,” Dr. Thomas A. Burke, deputy assistant administrator of EPA’s Office of Research and Development, said in a statement.

Generalized depiction of factors that influence whether spilled hydraulic fracturing fluids or additives reach drinking water resources, including spill characteristics, environmental fate and transport, and spill response activities | *EPA*

EPA said, however, the report “was not designed to be a list of documented impacts.”

“Data gaps and uncertainties limited EPA’s ability to fully assess the potential impacts on drinking water resources both locally and nationally. Generally, comprehensive information on the location of activities in the hydraulic fracturing water cycle is lacking, either because it is not collected, not publicly available, or prohibitively difficult to aggregate,” the agency said. “In places where we know activities in the hydraulic fracturing water cycle have occurred, data that could be used to characterize hydraulic fracturing-related chemicals in the environment before, during and after hydraulic fracturing were scarce. Because of these data gaps and uncertainties, as well as others described in the assessment, it was not possible to fully characterize the severity of impacts, nor was it possible to calculate or estimate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle.”

Done at the request of Congress, the report was based on a review of more than 1,200 cited scientific sources, new research conducted as part of the study and an independent peer review by EPA’s Science Advisory Board. The board had been sharply critical of a 2015 draft that said the agency “did not find evidence that [fracking activities] have led to widespread, systemic impacts on drinking water resources” in the U.S.

December 15, 2016

CPUC Orders Renegotiation of San Onofre Settlement

By Robert Mullin

The California Public Utilities Commission on Tuesday ordered Southern California Edison and San Diego Gas & Electric to meet with groups opposed to the commission’s 2014 settlement that saddled ratepayers with 70% of the costs related to the premature closure of the San Onofre Nuclear Generating Station.

cpuc san onofre nuclear generating station — Edison retired San Onofre nuclear generating station in 2013 after defective steam generators caused a radiation leak the previous year. | *Pharoah Construction*

Commissioner Catherine Sandoval reopened the record on the proceeding in light of revelations that former CPUC President Michael Peevey engaged in persistent unreported ex parte communications with SCE during negotiations leading up to the $4.7 billion deal.

“The CPUC’s rules require a level playing field by mandating ex parte disclosures for rate-setting proceedings, such as this one,” Sandoval said in a statement. “The CPUC must ensure the integrity of its processes and that its decisions serve the public interest.”

The CPUC urged the utilities to “carefully consider” changes to the agreement proposed by California’s Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) — both of which withdrew their support for the original deal when Peevey’s activities became public after state investigators seized notes from his home showing that he discussed terms of the settlement with an SCE executive at a Warsaw, Poland, hotel. Peevey had previously served as president of the utility.

SCE expressed disappointment with the Dec. 13 ruling but said it will comply with the directive to meet with the other settling parties by Jan. 31. The utility said it continues to believe that the original settlement represents an “appropriate allocation” of costs.

“SCE has provided or will provide refunds and rate reductions of almost $1.6 billion under the settlement, and this amount may be increased by recoveries from Mitsubishi Heavy Industries, the supplier of the defective steam generators,” the company said in a statement.

Among the modifications sought by TURN are the removal of some or all of the $2.17 billion in plant investment currently included in the rate base and a refund to ratepayers of costs related to the failed replacement steam generators that forced San Onofre’s permanent closure.

TURN has also proposed that SCE eliminate $25 million in utility funding for greenhouse gas research at the University California-Los Angeles, a key outcome of the secret talks with Peevey.

Contending that “information has value, as does unequal access to decision-makers,” ORA has proposed that SCE refund ratepayers $383 million for the “quantifiable loss” of ORA’s litigation position — the difference between the settlement amount and what ORA says ratepayers would have negotiated if the agency had equal access to information. The agency is also recommending the utilities issue an additional $408 million in refunds.

The CPUC has set an April 28, 2017, deadline for the settling parties to reach an agreement to modify the original settlement. If no agreement is reached, individual parties will be asked to file a summary of their positions in order to inform further action by the commission.

San Onofre was shut down in January 2012 after detection of a radiation leak from one of the plant’s generating units. Operators soon discovered that the steam generators in both units on the site suffered from excess tube wear, despite having been replaced in 2009 and 2011 at a cost of $671 million. SCE decided to retire the plant in 2013.

December 14, 2016February 5, 2025

Seattle City Light Signs EIM Membership Agreement

By Robert Mullin

Seattle City Light has signed an agreement with CAISO to begin participating in the Western Energy Imbalance Market (EIM) in April 2019.

“Seattle City Light has preliminarily evaluated the Energy Imbalance Market from an environmental, commercial and reliability perspective, and I believe City Light’s participation can deliver benefits to our customers in all three areas,” City Light General Manager Larry Weis said in a statement.

Weis said City Light’s participation in the EIM would represent the best use of the utility’s resources and expertise to support “a clean energy economy” throughout the West.

| Seattle City Light

“This is the first in a number of steps to better integrate large-scale renewable resources in the West, and a new tool in our ‘tool belt’ to address climate change and set the foundation for a cleaner energy future,” Weis said.

With a generating portfolio heavy in hydroelectric resources, City Light stands to benefit from the EIM as an exporter of the flexible ramping capability needed to smooth out intermittent renewables.

City Light’s participation will ultimately be contingent on satisfying concerns of Seattle City Council members who have asked for a more thorough accounting of the costs and benefits of market membership. (See Council OKs Seattle City Light Bid to Explore Joining the EIM.)

In order to support a decision to join the market, Seattle lawmakers have asked City Light to flesh out the findings of an EIM benefits study performed by consulting firm E3 that showed the utility could earn an additional $4 million to $23 million in yearly revenues from the market. Council members Lorena González and Mike O’Brien expressed concerns about the estimated $8.8 million in upfront costs for joining the market and the uncertainty around revenue projections.

“We will continuously evaluate the financial impact of participation in the Energy Imbalance Market,” City Light spokesman Scott Thomsen told RTO Insider. “If at any time we find that participation would not be in the best interests of Seattle City Light’s customer-owners, we can walk away from the agreement with CAISO at no cost.”

The utility is required to report its updated determinations to the council’s Energy and Environment Committee by April 10, 2017.

City Light would become the seventh balancing authority area to join the market after the entry of Portland General Electric in October 2017 and Idaho Power in April 2018.

It would also likely be the first publicly owned utility to participate in the EIM, although its entry could coincide with that of the Sacramento Municipal Utility District. SMUD announced its intent to join the market September and is expected to sign an implementation agreement early next year, according to Jim Shetler, general manager of the Balancing Authority of Northern California, of which the utility is the largest member. (See SMUD to Join EIM in Spring 2019 at the Earliest.)

December 13, 2016

PJM Names New Chief Communications Officer

PJM announced today it has appointed Susan Buehler as chief communications officer to oversee media relations, employee communications and the RTO’s website. She replaces Ian McLeod, who retired last month.

chief communications officer pjm — Buehler | *PJM*

Buehler is a former executive vice president for Bellevue Communications, a Philadelphia public relations firm, where she developed media, public relations and government relations strategies for clients including Citizens Bank, Campbell Soup and McDonald’s.

Before that, she was an Emmy award-winning television news reporter and editor at Fox News and worked in communications for Exelon’s PECO Energy. She holds a bachelor’s degree in broadcast journalism from Syracuse University.

“Susan’s career in strategic communications and broadcast journalism brings a new perspective to reaching our stakeholders,” said Nora Swimm, senior vice president of corporate client services. “Her experience helping large firms achieve their communications goals coupled with her keen awareness of what resonates with audiences will enhance PJM’s approach to communicating.”

– Rich Heidorn Jr.

December 13, 2016

SPP Board of Directors Briefs

LITTLE ROCK, Ark. — SPP’s Board of Directors last week approved a 13.2% increase in the RTO’s administrative fee and a 6.6% boost in its budget for 2017. The approval came Dec. 6 after a unanimous vote by the Members Committee.

The vote means the fee will rise from 37 cents/MWh to 41.9 cents/MWh in 2017, based on a net revenue requirement (NRR) of $160.5 million, a $9.9 million increase over 2016.

The RTO projects annual fee increases for the next five years, reaching 49.9 cents/MWh in 2021.

SPP is projecting an under-recovery of $5.9 million from the 2016 NRR. Other factors contributing to the NRR’s increase are a $3.5 million increase in maintenance expenditures and a $2.7 million increase in personnel costs.

SPP Director Harry Skilton, chair of the Finance Committee, said a decline in load growth led to the administrative fee’s increase. SPP had budgeted 407.2 million MWh in billable energy but revised that down to 393.9 million MWh. It is budgeting 383 million MWh through 2021.

“That reduction in load has set us up for an under-recovery that carries on to the next year,” Skilton said.

SPP budgeted a net loss of $35 million this year but has upped that to a $41.6 million loss given the under-recovery.

The board approved a budget with $194.1 million in income and $196.4 million in expenses for 2017. The 2016 spending plan had $176.2 million in income and $217.8 million in expenses.

The budget sets SPP’s headcount at 610 employees, an increase of one from 2016.

Besides a few questions on SPP’s practice for depreciating expenses, members quickly accepted Skilton’s report and recommendations.

Director Harry Skilton, with CEO Nick Brown and Chairman Jim Eckelberger, delivers the annual budget report | © *RTO Insider*

Stakeholder Surveys Stay Close to Form

Michael Desselle, SPP vice president and chief compliance and administrative officer, told the board and members that the RTO sent out nearly double the usual amount of stakeholder satisfaction surveys, but that the final results were not significantly different than previous years.

Desselle said the annual survey’s average satisfaction scores dropped for every service except one, by a difference of 0.12 points (out of 5) or less. Training was the lone exception, rising by 0.03.

Stakeholders identified the Z2 revenue crediting process as a repeat theme in their comments. One stakeholder said “the ‘Z2 Monster’ has been an unqualified disaster … I tip my hat to SPP management’s ability to skirt their contribution to the situation,” while another dinged SPP staff for “allowing too many years to transpire before implementing Z2.”

“Last year, [the concern] was the transparency of the Z2 process,” Desselle said. “This year, it was the expediency of the Z2 process.”

As in past years, Desselle said staff will prioritize the comments and address them. He said staff has closed 71 of last year’s 76 comments.

Among the positive comments were many praising the staff’s professionalism, responsiveness and communication efforts. Criticisms included the lack of detailed settlement reports in the Integrated Marketplace portal and what one called the “patronizing attitude” of staff and board members. One critic called for an external market monitor, saying there are “way too many conflicts of interest with an internal” monitor. (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)

December Board/Members Committee meeting | © *RTO Insider*

SPP distributed 4,597 survey invitations to organizational group members, market participants and other individuals who had interacted with the RTO during the previous 12 months, either through meetings, training, customer relations or other exchanges. Staff received 716 responses, for a response rate of 16%, up one percentage point from last year (410 responses) and four points from 2014 (181 responses).

Desselle also said auditing firm KPMG issued an unqualified opinion with no exceptions following its Statement on Standards for Attestation Engagements (SSAE) No. 16 audit. He said auditors found “no disagreements with management” and that “no illegal acts came to their attention.”

Stakeholders Again Give Organizational Groups High Marks

SPP’s annual survey of its organizational groups matched that from 2016, with stakeholders rating groups’ overall effectiveness at 4.2, out of a possible 5.

The scores reflected the average response to “Please rate the overall effectiveness of this group.” The individual group scores ran from 3.5 for the Event Analysis Working Group to 4.8 for the Human Resources and Oversight committees and the System Protection and Control Working Group.

SPP CEO Nick Brown said he was pleased with the survey’s 71% response rate, and he assured the board and members that SPP “is not just gathering this data and doing nothing with it.”

Ciesiel Pleased with RE Survey Results

Regional Entity General Manager Ron Ciesiel said he was happy with the RE’s stakeholder satisfaction survey, which produced scores of 3.9 to 4.4 on a 5-point scale for customer service and responsiveness, and 3.2 to 3.6 for how well the program meets expectations.

Regional Entity Trustees Chair Dave Christiano and GM Ron Ciesiel share stakeholder feedback with the board. | © *RTO Insider*

Ciesiel noted RE staff is seen as responsive, knowledgeable, professional and personable and that members see the RE’s workshops on reliability issues as “valuable.”

“Here’s the good news: We’re not having the events we need to do analysis on. We’re not really getting events,” he said. “I’ll take this every day, because it’s good news across the board, not only here, but in North America.”

Ciesiel said the RE is considering a spring workshop and including sessions on new standards. It will also use the RE’s newsletter to focus on the top 10 violated standards.

Paul Malone, Todd Fridley Approved as MOPC Chairs

The board and members unanimously approved the Nebraska Public Power District’s Paul Malone as the incoming chair of the Markets and Operations Policy Committee. Malone, NPPD’s transmission compliance and planning manager, replaces SouthCentral MCN’s Noman Williams, whose term expired.

Todd Fridley, vice president at Transource Energy, was approved as the committee’s vice chair.

The board and members also approved revisions to the Corporate Governance Committee’s charter to formalize bylaw revisions that added committee seats for federal power marketing agencies and independent transmission companies. Bob Harris (Western Area Power Administration-Upper Great Plains) and Brett Leopold (ITC Great Plains) currently fill those respective seats.

Also approved was a charter change for the Seams Steering Committee. It changes the committee’s scope of review and guidance activities from “existing seams agreements” to “new or existing seams agreements.”

– Tom Kleckner

December 13, 2016

RGGI Carbon Auction Prices Drop 22%

By William Opalka

Carbon dioxide allowance prices dropped 22% at the 34th Regional Greenhouse Gas Initiative auction on Wednesday, renewing calls from environmentalists to tighten emission limits in the nine-state compact.

Nearly 14.8 million allowances were sold at a clearing price of $3.55, down from the $4.54 they netted in September in the last quarterly auction. (See Md. Balks at Proposed Emission Cuts as RGGI States Ponder Future.)

Carbon prices have flattened out as the program’s success in limiting emissions has led to an oversupply of emission credits, advocates say. Prices are 53% lower than they were a year ago. Last week’s clearing price is the lowest since December 2013, when 38.3 million allowances cleared at $3.

rggi auction prices — Brayton Point Power Station | *Wikipedia*

RGGI is now undergoing its quadrennial Program Review, which will map out 2020 and beyond.

“We now have eight years of experience demonstrating that the electric sector can achieve ambitious emissions reductions at low costs; it’s time for that experience to be reflected in ambitious reforms,” Peter Shattuck, director of the Acadia Center’s Clean Energy Initiative, said in a statement. “The states must use the Program Review to establish more stringent cap levels through 2030 and to implement program design elements that account for the continuing decline in emissions.”

Currently, RGGI states have agreed to reduce the cap on emissions by 2.5% annually, with many stakeholders advocating those reductions should be accelerated to 5% annually.

“The elements that made RGGI such a successful program at its inception are just as relevant today,” Katie Dykes, chair of the Connecticut Public Utilities Regulatory Authority and chair of the RGGI Board of Directors, said in a statement. “The use of a market-based system to cap emissions allows for the most cost-effective reductions. And the auctioning of allowances and the reinvestment of auction proceeds provides benefits for consumers while locking in emissions reductions. The program’s flexibility allows it to adapt to changing circumstances and support the goals of nine states across a diverse region.”

The sale netted about $52.5 million for the nine member states’ clean energy and energy efficiency programs. RGGI auctions have raised about $2.6 billion since their inception in 2008.

December 13, 2016

MISO Takes Stakeholders’ Temperature on Redesign

By Amanda Durish Cook

CARMEL, Ind. — A year into MISO’s stakeholder redesign, member leadership says the stakeholder process is more efficient but that discussions at meetings could use more depth.

The redesign “check-in” was the Hot Topic discussion at the Advisory Committee’s Dec. 7 meeting. Executive Director of External Affairs Kari Bennett said the redesign has cut stakeholder meetings by 22% and that staff posted 81% of meeting materials a week prior to meetings in 2016, compared to 71% in 2015. She also said MISO is working to attract more speakers from outside the RTO for presentations at informational forums. (See MISO Redesign Nears Completion.)

MISO’s sectors praised the consolidation of stakeholder groups, a cleaner process for those wishing to raise issues and the reduction in meetings and repetitive presentations.

The Independent Power Producers, Coordinating Members, End Use Customers and Transmission Dependent Utilities sectors said the redesign had made meetings more effective.

Indiana Utility Regulatory Commissioner Angela Weber said she appreciated the issues tracking process, through which stakeholders who introduce topics can trace MISO’s response. Under the new process, the Steering Committee confers with MISO staff and may assign the issue to a senior committee.

Northern Indiana Public Service Co.’s Paul Kelly said the creation of the Resource Adequacy Subcommittee helped to combine several related issues but that the standard six-month life of a task team isn’t always long enough to fully address an issue.

Dynegy’s Mark Volpe commended MISO’s new video conferencing capabilities that help connect stakeholders.

“It’s not mentioned much, but over this past year, MISO did a technology refresh. … It allows stakeholders in Little Rock and Eagan [Minnesota] to go to the nearest MISO facility and attend meetings. It helped a number of members with limited resources. … MISO needs some kudos on that investment,” Volpe said.

Feedback Process Lacking

Multiple sectors said that MISO’s feedback process has fallen short and asked for more formalization and transparency around the comments it receives. MISO staff usually ask for stakeholder feedback via email within about two weeks of a presentation on a proposal. The RTO summarizes the responses and sometimes shares them — identified by sector only — at follow-up presentations. Some stakeholders have commented on the challenge of keeping up with a heavy volume of feedback requests and MISO’s inconsistent record of publishing comments.

MISO Advisory Committee | © *RTO Insider*

NIPSCO’s Kelly said stakeholders sometimes do not understand where MISO stands on issues and that some members are confused about what feedback requests are open because the requests are only documented on the final slide of presentations.

Weber said it’s difficult to locate meeting materials and issues on MISO’s website. She suggested the RTO create a feedback calendar.

Bennett said MISO may be stuck in a “‘do loop’ of chasing the calendar,” referring to a section of computer code in which an instruction is executed repeatedly. But she said MISO has committed to revamping its website in 2017. She said MISO staff could create a feedback request tracking page on its website.

“Even though we’ve created some efficiencies, there’s still a lot of work going on, and it’s hard for any one stakeholder to keep up,” Bennett said.

“It struck me that stakeholders said the website is hard to navigate and it’s hard to find information. In a world where you can Google and find information across the globe,” an easily accessible website should be a goal, Director Baljit Dail said.

The Organization of MISO States said the process has “led to incremental increases in efficiency, but the impact on effectiveness is less certain.” Alcoa Power Generating’s DeWayne Todd agreed and said that although MISO has gained efficiencies, the meetings may not have gained effectiveness, as little deep discussion takes place.

Mitch Myhre of Alliant Energy asked for MISO to facilitate more stakeholder policy discussions with the Board of Directors. For example, he said, the board and stakeholders could discuss the RTO’s multiyear effort to revise its cost allocation.

“We’re wondering if the meetings are as effective as they should be. We’re wondering if MISO is open enough. Sometimes you get better discussion in the hallway. [MISO staff] are more relaxed. Maybe because you’re in front of people, it’s harder to be completely open,” Weber said. She suggested setting aside meeting time for brainstorming sessions.

“We are in a bit of a rut in terms of how we process subject matter,” Volpe said. MISO is in a pattern of presenting on a given topic, requesting feedback and coming back with refinements in a months-long cycle, he said. “There really isn’t an open dialogue among subject matter experts and stakeholders. We’re in this rut of consistent feedback cycles, but we really don’t have that policy debate. I feel bad for the chair of these committees; they have to watch the clock and make sure someone goes through 30 slides in 20 minutes. That’s not possible.”

Chris Plante of Wisconsin Public Service said stakeholders could come to meetings armed with presentations of their own to prompt deeper conversations. He also said MISO should make member responses public by default.

Director Michael Evans said he’s seen nearly 12 years of stakeholder process, from “the food fight era” to the “pitchforks era.”

“I think we’re at a spot where the dialogue is healthy. Now it’s time to improve the content,” he said.

Director Tom Rainwater said the redesign is a “tremendous” effort. “I think what you’re emphasizing today is continuous improvement,” he said. Rainwater suggested MISO identify what improvements it could accomplish in 90, 180 and 365 days.

“This is your process. It’s not our process,” Director Judy Walsh told stakeholders. “I would encourage MISO to understand how it can better facilitate improvements into the process.”

“Anytime we bring a big group together, you can feel stuck and like you’re talking over one another,” Bennett said, before quoting the Beatles: “We can work it out.”

AC Priorities Take Cue from Subcommittee Purposes

During the meeting, the AC also adopted a set of priorities set forward by the Transmission Dependent Utilities sector that borrow from MISO subcommittee mission statements. (See “AC to Approve One of Two Sets of 2017 Priorities,” MISO Advisory Committee Briefs.)

Sectors voted 13-9 for the TDU’s offering over a slight revision of 2016 priorities proposed by AC leadership. The new priorities seek to implement best planning practices; preserve and enhance reliability; improve market efficiency; ensure resource adequacy; and ensure equitable cost allocation.

December 13, 2016

Mass. Considering Storage Mandate

By William Opalka

BOSTON — Massachusetts officials will announce by the end of the month whether to join California in mandating the procurement of energy storage.

For the more than 300 people who attended or live-streamed Raab Associates’ 152nd New England Electricity Restructuring Roundtable last week, however, the only question is how much storage the state is likely to order. The session provided a briefing on both the policies driving the adoption of storage and the companies that are deploying the technologies.

Judith Judson, commissioner of the Massachusetts Department of Energy Resources, said the “State of Charge” study produced a surprising result: Up to 1,766 MW of advanced storage could save ratepayers $2.3 billion. Comments on whether Massachusetts should set targets are due Friday.

“We have reduced average consumption in Massachusetts, but our peak demand continues to grow,” she said. “Our top 1% of the hours accounts for 8% of our electric spend. Our top 10% of hours account for 40% of our electric spend. … So [storage] could be a tremendous savings for ratepayers.”

massachusetts energy storage mandate — | *RTO Insider*

California Leads the Way

California has led the nation in mandating storage, with 1.3 GW to be deployed by 2024. Since 2013, 630 MW in projects have been approved, California Public Utilities Commissioner Carla Peterman said.

“The commission has to determine that these projects are viable and cost-effective. Typically, that requirement has not been placed on emerging technologies. For example, there is not a similar requirement on our solar incentives,” said Peterman, who participated via video.

Jesse Jenkins, of the Massachusetts Institute of Technology Energy Initiative’s Utility of the Future study, said the two-year effort that will be released this week includes an examination of the impact of distributed storage resources.

Locational Value

Jenkins said storage and demand response resources in some locations can have a value three to 10 times greater than a typical distribution node. “They can deliver [cost benefits] to the power system, but only if the incentives are appropriately granular,” Jenkins said.

Roger Lin, senior director of product marketing for NEC Energy Solutions, described the company’s 2-MW, 3.9-MWh battery storage system in Sterling, Mass., which it says will be the first utility-scale project in the state and the largest battery-based system in New England.

The project will provide the town’s municipal utility with a backup during weather-related power outages and a way to save money by shaving its peak usage. He said storage could have saved the town several hundred thousand dollars over a couple hours when the town’s 3-MW solar array became shrouded by clouds at 2 p.m. on a September day and LMPs jumped from less than $100/MWh to more than $500.

“That cloud cover came at the worst possible time, at the system peak, as the pro rata share of transmission charges and forward capacity market charges” is determined, he said.

Demand Reduction

Vic Shao, CEO of Green Charge Networks, said his company focuses on the software and controls that predict when peaks will come.

“In California, we really focus on demand reduction. California is particularly expensive, with demand charges going up by about 10% a year,” he said.

“When it comes to storage, controls are everything,” said Josh Castonguay, chief innovation executive at Green Mountain Power in Vermont, which has added storage to a 2.5-MW solar array on a capped landfill. “Because at the end on the day, that’s what’s going to unlock all the value streams for you.”

Matthew Morrissey, vice president of Deepwater Wind’s operations in Massachusetts, said the company, which built the first offshore wind plant in the U.S. in Rhode Island, is developing storage capabilities so it can bid into capacity auctions and state solicitations. He said the company recently won a solicitation to provide the Long Island Power Authority offshore wind combined with storage — beating out more traditional gas-fired alternatives on price.

“Even with offshore wind, where we have wonderful peak incidences where demand matches our power curve perfectly, we recognize we must have an offset of storage,” he said.

Fouad Dagher, director of new energy solutions at National Grid, also emphasized the need to install storage where it provides the most benefit. “How do we dispatch it? When do we dispatch it? And that’s very important for capturing the value,” he said. “Where is the best location to place something?”