Page 1363 – 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, 2016

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 energy imbalance market — | *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

MISO Board of Directors Briefs

MISO’s Board of Directors last week unanimously passed a $239.1 million operating budget and a $29.9 million capital spending plan for 2017. (See “MISO Predicts Budget Increase in 2017, Introduces 5-Year Business Plan,” MISO Advisory Committee Briefs.)

The RTO had proposed a $238.6 million budget before the board’s Human Resource Committee approved a 3.5% increase in the salary budget, as recommended by human resource consulting firm Mercer.

miso board of directors — Human Resource Committee of the Board of Directors | © *RTO Insider*

The firm’s review of MISO’s compensation recommended a 3% increase in merit-based compensation and a 0.5% increase for employees’ promotional increases.

“We looked at things like GDP and inflation rates; we looked at anecdotal things,” Director Paul Bonavia said at the committee’s Dec. 6 meeting.

MISO CEO John Bear said he consulted with the CEOs of 11 member companies on the proposed increase.

“The range we have in mind is in line with their thinking,” Bear said. He said a key concern among the CEOs was the aging workforce and attracting younger staff.

MISO expects to exceed its $225 million 2016 operating budget by $600,000, resulting in a maximum 0.3% possible overrun.

The RTO has spent $187.9 million of the $188.6 million allowed to date, leaving less than 0.3% of the budget untouched, acting Vice President of Finance Tony Guisinger said at MISO’s Dec. 8 board meeting.

MISO anticipates between $30.5 million and $31.5 million in capital spending for the year, potentially exceeding its $31 million budget.

Guisinger also said MISO hopes to procure financing in 2018 for technology needs and said talks will begin in early 2017 on the amount it will request.

MISO to Welcome 3 New Board Members, Thanks Departing Directors

Board Chair Judy Walsh and Directors Michael Evans and Paul Feldman will exit MISO at year-end, replaced by former ERCOT CEO H.B. “Trip” Doggett, former Calvert Investments CEO Barbara Krumsiek and Todd Raba, who is leaving Twenty First Century Utilities and has served as CEO of both GridPoint and Berkshire Hathaway’s Johns Manville.

During the meeting, Senior Vice President of Compliance Services Steve Kozey confirmed election results and said all three candidates received sufficient votes in the electronic voting process. “No lapse in security; no Russian hackers,” he joked.

Former MISO Director Eugene Zeltmann called in to congratulate the trio of departing board members.

“You certainly presided over an incredible transformation of an extraordinary organization,” said Zeltmann, who left the board a year ago.

“We couldn’t have done this without you,” Walsh replied to Zeltmann.

Organization of MISO States President Sally Talberg called the three directors a “bedrock” for MISO.

“In my first meeting, we had two directors that had been thrown out, we had hostile stakeholders and cost overruns. At that time, it was a dicey deal indeed to see if MISO would succeed in becoming an organization,” Walsh said. She felt the board was being left in “very good hands,” she said.

The board also adopted two motions pertaining to itself — the elimination of post-service restrictions and a pay raise.

MISO will make a FERC filing by the end of the year to eliminate the post-service restriction and trim the pre-service restriction, leaving it with only a one-year pre-service restriction. Directors cannot have served as “a director, officer or employee of a member, user or an affiliate of a member or user engaged in the electric utility industry or participating in wholesale electricity markets” during that period.

“MISO was the only RTO in the nation with a post-service restriction,” Director Tom Rainwater said. Rainwater said MISO was having trouble attracting new board members with its two-year pre- and post-service prohibitions from utility and wholesale energy market participants. (See Board OKs Pay Hike, Change to Independence Rules.)

Rainwater said the board and MISO discovered that the Transmission Owner’s Agreement subjects “key” MISO employees to a 12-month “cooling off” period after leaving the RTO, during which they cannot have “any involvement … on behalf of any parties other than MISO with regard to any matters in which they were substantially involved when serving for, or employed by, MISO.” Bear has agreed to compile a list of employees that would be subject to a restriction for board approval.

The board also adopted a $4,000 annual pay increase for directors. Rainwater said the changes will up the yearly retainer from $55,000 to $89,000 but eliminate meeting fees for the first six scheduled board meetings and two annual strategic retreat meetings. (See Board OKs Pay Hike, Change to Independence Rules.) A typical MISO director who attends those eight meetings and serves on three committees is expected to earn about $116,000 annually.

MISO Still Undergoing FERC Audit

A little over a year later, MISO is still undergoing a FERC compliance audit, Chief Compliance Officer Joseph Gardner told the board. Gardner said it is not unusual for RTO audits to last 18 to 24 months. He said FERC staff has been on-site at MISO headquarters for two visits during the audit.

“No big concerns that I’m aware of have come up,” Gardner added.

— Amanda Durish Cook

December 13, 2016

PJM Board OKs $260M in Tx Projects

The PJM Board of Managers last week approved almost $260 million in transmission reliability projects.

The projects in the 2016 Regional Transmission Expansion Plan include:

New baseline reliability upgrades ($158.1 million);
Changes to previously approved upgrades (net increase of $47.3 million); and
Facilities, network upgrades and withdrawal of canceled facilities related to the interconnection queue (net increase $54 million).

With the board’s action, PJM has approved more than $29 billion in transmission additions and upgrades since the first RTEP in 2000.

PJM transmission projects — Dooms – Valley 500 kV Line Project | *PJM*

The board also approved an installed reserve margin of 16.6% for 2017/18. The IRM approval includes associated parameters for each of the next four delivery years.

The IRM study results were approved by the Markets and Reliability Committee in October. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)

– Rory D. Sweeney

December 13, 2016

FERC Rejects Challenges on Local Tx Cost Allocations

By Rich Heidorn Jr.

FERC last week upheld its February 2016 ruling that projects solely addressing a transmission owner’s local planning criteria are not eligible for regional cost allocation, rejecting rehearing requests from Dominion Resources and others.

“Cost allocation is not an exact science, and there may be ‘multiple just and reasonable rates’ on the same set of facts. Here, whether the allocation proposed by the PJM transmission owners is the best allocation method is not the issue; the issue is whether it is a just and reasonable method, and we find that it [is] just and reasonable based on the supporting data,” the commission said (ER15-1387-002).

The commission directed PJM to make a compliance filing ensuring that the costs incurred after the May 25, 2015, effective date of its February order for projects included in the Regional Transmission Expansion Plan solely to address Form 715 local planning criteria be allocated to the zones of the individual TOs. PJM must also rebill for any costs for such projects allocated incorrectly for the period.

FERC also denied rehearing in two cases applying the 2016 ruling and making Dominion solely responsible for the cost of its 500-kV Cunningham-Elmont (RTEP project b2582) (ER15-1344) and Cunningham-Dooms rebuilds (b2665) (ER16-736, EL16-96-001).

regional cost allocation ferc transmission — Elmont-Cunningham 500kV Rebuild | *PJM*

Dominion argued that the projects have regional benefits, unlike most Form 715 projects, which deliver only local benefits. Old Dominion Electric Cooperative, LSP Transmission Holdings and ITC Mid-Atlantic Development also had sought rehearing. (See Dominion: Tx Project Should be Regionally Allocated.)

Commissioner Cheryl LaFleur repeated her earlier partial dissents in the three dockets, saying that “high-voltage transmission lines in PJM have inherent regional benefits that warrant some measure of regional cost allocation, and those benefits exist regardless of the underlying need that drove the project.”

The commission also denied Public Service Electric and Gas’ request to reconsider an order assigning its zone all of the costs of its Sewaren upgrade to replace aging infrastructure and provide storm hardening (ER14-1485). PSE&G said the Sewaren projects (b2276, b2276.1 and b2276.2) addressed both aging infrastructure and short-circuit issues. It will convert the two 138-kV circuits from Sewaren–Metuchen to 230 kV and make related changes.

December 13, 2016

SPP Briefs

SPP says it has successfully implemented system changes required by FERC Order 809, which ordered RTOs to improve the alignment of their market schedules with those of interstate gas pipelines (RM14-2). SPP’s changes took effect Sept. 30.

“After roughly two months of operational experience, it appears it’s successful so far,” SPP legal counsel Joe Ghormley told a meeting of the Gas Electric Coordination Task Force last week, where he shared the draft of an informational report to be filed with FERC.

The report says “the changes have improved coordination between the SPP markets and natural gas nomination cycles while taking into account stakeholders’ price formation concerns as well as the relative immaturity of SPP’s market and the resulting need for an incremental approach to market system changes.”

SPP described “a year of transition” involving the revised market schedule and the development of system changes for the RTO’s enhanced combined cycle system initiative, the subject of proposed Tariff changes filed with FERC in November (ER17-358). The report also details “extensive efforts” to reach out to and train members and stakeholders. SPP said it is only aware of one resource that has reported potential problems with gas availability, which occurred after a pipeline was taken out of service last December for repairs. When the line was returned to service, it operated below capacity because of reductions mandated by the Pipeline and Hazardous Materials Safety Administration.

“SPP continues to work … to identify cost-effective ways to further compress its market system solve times without jeopardizing the [Integrated Marketplace’s] fundamental functions … or its upcoming enhancements to commitment and dispatch of gas generators utilizing the most efficient configuration of components.”

The report will be filed with FERC on Thursday. The commission required SPP to file an annual report on its compliance with Order 809 for the next three years.

SPP, AECI Narrow Target Areas to Southern Missouri

SPP and Associated Electric Cooperative Inc. have whittled a list of five target areas under consideration for joint transmission projects down to one.

SPP and AECI staff told the Interregional Planning Stakeholder Advisory Committee on Friday that they are still narrowing down different transmission solutions to address high voltages and overloads in the Brookline area of southern Missouri. Planners intend to issue a draft report for the IPSAC’s review early next year.

The two entities currently use an operating guide to manage their seam, but the cost is becoming too big to ignore. Staff said it is considering the use of transmission reactors around Brookline instead of using the operating guide to control voltages. Any final solutions will be coordinated with SPP’s 2017 Integrated Transmission Planning’s 10-year assessment.

SPP and AECI determined three other target areas can be managed without joint projects. The fifth target area, in Northeast Oklahoma, was removed from consideration because a change in transmission ownership shifted facilities to AECI’s management.

Based in Springfield, Mo., AECI is owned by six regional generation and transmission cooperatives.

M2M Payments Flow Back to SPP

Market-to-market payments between SPP and MISO reverted to previous form in October, with MISO paying SPP almost $2.2 million for 871 binding hours on 34 flowgates along the seam.

MISO paid more than $2.2 million for 27 temporary flowgates, while SPP sent about $29,000 to MISO for seven permanent flowgates.

SPP had paid its counterpart for binding flowgates the previous three months, but MISO has sent about $10 million to SPP since the two RTOs began the process last year.

— Tom Kleckner