Page 1194 – RTO Insider

January 23, 2018

SPP Stakeholders Still Struggling on BTM Reporting

By Tom Kleckner

OKLAHOMA CITY — SPP’s Markets and Operations Policy Committee last week continued to hash through the difficulties of reporting behind-the-meter (BTM) load, a holdover issue from its previous two meetings.

In July, the committee directed a stakeholder group to address “inconsistency and uncertainty” over which BTM generation qualifies as network load. In October, the committee rejected the Regional Tariff Working Group’s proposal of a 1-MW threshold for reporting BTM network load, and the Board of Directors declined to reverse the decision on an appeal by Southwestern Public Service. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)

spp btm behind-the-meter load — | *Sunrun*

SPP staff shared with the MOPC and the Strategic Planning Committee initial results of a survey of network integration transmission service (NITS) customers. The survey focused on NITS load reporting, with an emphasis on grandfathered agreements (GFAs), BTM generation and “special circumstances.”

“It was unclear to us in whether all the behind-the-meter gen was identified, and then netted with the load,” said SPP COO Carl Monroe. “There was some controversy as to whether you can net the load with behind-the-meter generation.”

Monroe said staff are reviewing the survey responses and asking follow-up questions, such as:

What load and BTM generation is netted versus added?
Why are some grandfathered megawatts not being included in resident load? (Resident load is a term SPP uses to ensure all load is paying Tariff rates.)
What are the details of the “special circumstances”?

Monroe said the aim is to foster continued discussion and education, and to determine the consistency of members’ NITS reporting practices. He hopes to produce a final report in April.

“One of the real concerns is that stakeholders with network load may not really understand what needs to be reported. Your survey results may indicate a lack of knowledge,” said Golden Spread Electric Cooperative’s Mike Wise. “That is what I was hopeful of finding. You are really highlighting some of the folks in our footprint don’t understand the rules and don’t understand FERC’s requirements.”

“We just asked what people were doing. We didn’t proclaim what needed to be done,” Monroe responded.

At the same time, SPP’s legal staff met with FERC to gain a better understanding of what is and what isn’t net metering.

“As we thought, since SPP has a pro forma Tariff, all load, if reported, can’t be netted,” said General Counsel Paul Suskie. “If somebody thinks they have a good case because of behind-the-meter load, it can be filed at FERC. To our knowledge, no SPP member has ever done that.”

Suskie said his department is working to further clarify for members what the BTM rules are today, and “what it would be tomorrow if we make a filing at FERC.”

“Once we get the results finalized and understood, we can see which ones don’t line up with what we believe FERC has said through its pronouncements,” Monroe said.

MOPC Chair Paul Malone, of Nebraska Public Power District, pushed unsuccessfully for a face-to-face educational meeting to help bring some consistency to network load reporting and “make sure we have a legal understanding of what FERC requires.”

“That’s critical, because that’s what billing is based on,” he said. “I think some of it is just different interpretations,” he said. “Looking at the [survey] items, it’s no wonder. ‘GFAs’? Lots of issues there. ‘Special circumstances’? I think we’re getting murkier, rather than clearer.”

Kansas City Power & Light’s Denise Buffington pressed both the MOPC and the SPC as to whether the 1-MW exemption would go before the Board of Directors next week. Monroe reminded members the board took no action on SPS’ appeal; Suskie said SPS could still place the issue on the agenda.

“I thought we made a commitment that it should be on the agenda in January,” said Board Chair Jim Eckelberger.

An agenda and meeting materials for the board’s Jan. 30 meeting had yet to be posted as of Monday.

Suskie said staff will present the board with draft reporting rules based on its “pretty extensive” discussion with FERC and the survey results “later this month.”

Separately, MOPC approved a revision request (RR 251) from the Supply Adequacy Working Group that addresses three issues FERC used in once again rejecting SPP’s resource adequacy package last year. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)

The commission said:

SPP’s proposal failed to include requirements that all power purchase agreements are backed by verifiable capacity to meet the RTO’s resource adequacy requirement (RAR), and that provisions to allow SPP to verify the agreements are backed by capacity;
the proposed treatment of firm power purchases and sales in determining net peak demand is unduly discriminatory; and
SPP has not supported as just and reasonable its proposal to publicly post a list of load-responsible entities that had not met their RAR.

The motion was opposed by the Kansas Municipal Energy Agency, while 10 other members abstained.

January 23, 2018November 29, 2023

SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018

OKLAHOMA CITY — SPP’s Markets and Operations Policy Committee unanimously approved a Market Working Group (MWG) revision request (RR 245) that adds a major maintenance cost in mitigated start-up and no-load offers, resolving pushback from the RTO’s Market Monitoring Unit.

The MWG said the change allows market participants to include major maintenance costs associated with the number of starts or run hours in their mitigated start-up and no-load offers, resulting in the recovery of true variable costs.

The revision received a thumbs-up from MMU Executive Director Keith Collins, who said he was aware the Monitor had opposed previous versions of the change.

“The Market Monitor believes that changes made to 245 … are substantial differences that allow the Market Monitor to find this approach acceptable,” he said. “One, we’re not moving down the variable maintenance approach we tried last time, and two, we are talking specifically about major maintenance for start-up and no-load. This approach is consistent with how other RTOs address major maintenance.”

The MOPC’s endorsement allowed the MWG to recommend closing several action items and withdrawing two other revision requests it had been working on: RR 231, which addressed fuel-cost changes, and RR 214, which removed locally committed resources from the economic mitigation tests. The latter revision request, which also created a 10% cap for resources committed for local reliability, had been remanded back to the working group by the committee for additional review.

The MMU opposed RR 214, saying it discovered resources were “self-mitigating” to pass the conduct threshold test and avoid possible mitigation.

RR 245 “takes a little of what PJM is doing and what MISO is doing, and puts them together,” Collins said. “We like driving in the middle of the road.”

MWG Vice Chair Jim Flucke, of Kansas City Power & Light, said, “Given everything else we passed, 214 as written is no longer the right approach to the remaining issues we have.”

Golden Spread Electric Cooperative’s Mike Wise thanked the MWG for its work, saying, “This is taking SPP substantially forward.”

The MOPC approved the recommendation to withdraw the revision requests with three abstentions.

Members unanimously endorsed two other revision requests brought forward by the MWG:

- - MWG-RR247: Clarifies language to reflect how the market-clearing engine treats contingency reserves in the real-time balancing market when a contingency reserve event is deployed.
  - MWG-RR257: Responds to a FERC compliance requirement (EL16-110) requiring SPP to limit the eligibility for auction revenue rights and long-term congestion rights of network customers with service subject to redispatch. The changes will ensure network service subject to redispatch is treated comparably with point-to-point service subject to redispatch. (See FERC Again Rejects SPP Rules on ARRs, LTCRs.)

SPP Pays MISO $2.25M After M2M Resettlements

SPP has reimbursed MISO more than $2.25 million after resettlements of several market-to-market (M2M) flowgates and will continue to perform “limited” resettlements because of a memorandum of understanding between the two RTOs.

The resettlements stem from binding events on three flowgates along the SPP-MISO seam. SPP has accumulated $32.73 million in M2M payments through November since the two RTOs began the process in March 2015.

“Large dollars are transferring between SPP and MISO on a daily basis,” said David Kelley, SPP’s director of interregional relations. The resettled payments “shouldn’t have been paid to us to begin with, but we didn’t have a lot of criteria around it. We needed to ensure [M2M coordination] is grounded in some of [the MOU’s] principles.”

The RTOs executed the MOU last summer to improve M2M coordination after what Kelley called a “significant” amount of time and negotiation. They then revised the MOU to address power swings and capping its firm-flow entitlement provisions. FERC accepted the revisions in December (ER18-150).

Kelley reminded members that the commission directed the RTOs to begin M2M coordination with the implementation of SPP’s Integrated Marketplace in 2014. FERC cited the success of a similar process between MISO and PJM.

“We knew we had some room for improvement almost immediately because of the way the system operated,” Kelley said. “From the moment we threw the switch, we saw significant oscillations and power swings on some flowgates. We knew this wasn’t how it was supposed to work.”

“It’s all because Iowa wind is impacting our system,” SPP COO Carl Malone said, issuing a refrain familiar to many of his colleagues.

“I think we’ve ended up in a good place where the process should work much better,” Kelley said.

SPP and MISO will both file waivers with FERC to complete the resettlements.

Kelley also said SPP will “take a run at another filing” with FERC over two potential seams projects with Associated Electric Cooperative Inc. The commission last year rejected both projects, saying SPP had not shown its proposed cost allocations on a load-ratio share basis were “roughly commensurate” with the projects’ benefits. (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)

SPP staff have met with FERC staff to gain further insight as to why their filings were rejected. “It’s not a for-sure slam dunk [for SPP],” said General Counsel Paul Suskie, “but it’s worth another try.”

In the meantime, Kelley has kept open the lines of communication with AECI.

“We’ve reiterated our support and commitment, and they’ve reiterated their support and commitment as well,” Kelley said.

MOPC Agrees to Pull Basin Electric Project’s NTC-C

The committee unanimously agreed with staff’s recommendation to withdraw a notification to construct with conditions (NTC-C) for a Basin Electric Power Cooperative transmission project in North Dakota.

Staff said their updated load projections indicated there was no longer a need for the 33-mile, 345-kV Kummer Ridge–Roundup line. Staff studied winter and summer peak scenarios in 2022 and 2027 before making their decision.

The project began as a 115-kV line in SPP’s 2016 near-term assessment, but its NTC-C was modified by the Board of Directors in July 2016 to reflect the change in voltage to 345 kV. It has an estimated cost of $52.3 million.

The MOPC and board both approved Basin Electric’s request for an expedited re-evaluation in April 2017. (See “MOPC Endorses Re-evaluation of Basin Electric Project,” SPP Markets and Operations Policy Committee Briefs.)

Staff also alerted MOPC about a change in a New Mexico project that came out of its 2014 High-Priority Impact Load Study. Tapping an existing 115-kV line to build a new 115-kV substation at Ponderosa Tap had been approved at a cost of $4.9 million. However, staff said the project costs were incorrectly designated as “direct assigned” and should be “base plan” funded instead. The cost was reduced slightly.

Stakeholders separately unanimously endorsed the 2018 Transmission Expansion Plan, sending it to the board for its approval. Members completed 36 projects costing $246 million in 2017, while SPP issued 71 NTCs for an additional $263.2 million in spending.

North Dakota Sponsored Upgrade Study Approved

The MOPC endorsed SPP’s sponsored upgrade study performed for Central Power Electric Cooperatives, a member company in North Dakota that purchases power from Basin Electric to serve its own six-member cooperative.

CPEC proposed changing a 115-kV breaker status from “normally open” to “normally closed” and completing a 115-kV loop between two Western Area Power Administration substations to correct a potential thermal violation in the 2026 summer models. Staff said CPEC would have to bear the costs of the upgrade and any mitigations.

SPP issued a report to CPEC, Basin Electric and WAPA in November.

NERC Stakeholder Teams to Review, Reduce Standards

‎Charles Yeung, SPP’s executive director of interregional affairs, told members they face a Feb. 2 deadline for submitting input to NERC on its standards streamlining effort.

The agency has formed three teams to review long-term planning, operations planning and real-time operations standards. The teams will provide recommendations on reducing the number of NERC standards — not including critical infrastructure protection standards — by the third quarter of this year.

The teams, which still have open seats, have scheduled one-hour webinars Jan. 24-25 for orientation and to discuss scope, timelines and other matters.

Consent Agenda Clears 10 Revision Requests

The MOPC approved a measure that documents market import service (MIS) as a transmission product in the Tariff; it has been offered in SPP’s Integrated Marketplace since 2014. RR 250 places all information related to reserving and scheduling MIS in one location as a new business practice.

Malone pulled the revision from the consent agenda, pointing to language that said MIS had not been implemented through Tariff language.

“The Tariff language being added is brand new,” he said. “I read that it didn’t exist until today. It looks like new service to me.”

Malone was joined in opposing RR 250 by the Municipal Energy Agency of Nebraska. ITC Holdings abstained from the vote.

The MOPC unanimously approved nine other revision requests on its consent agenda:

- - CPWG-RR249: Corrects, updates and clarifies unclear or outdated letter of credit language to make it more acceptable to financial institutions.
  - MWG-RR 18 2: Removes the term “control area,” which is no longer used by SPP, from the market protocols and the Tariff.
  - M WG-RR2 00: Removes bilateral settlement schedules (BSS) at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. The revision allows only BSS at a withdrawal point to be included in the OCL distribution calculation. It caps the BSS at the maximum amount of the real-time withdrawal minus any amount of grandfathered agreements and federal service exemptions.
  - MWG-RR2 4 6: Clarifies language explaining SPP’s congestion management efforts when declaring transmission loading relief (TLR) and removes a reference to an old system name. SPP does not have an active TLR for every congestion management event, but the protocol language will be updated to read “as soon as practicable,” and adds provisions for market-to-market coordinated curtailments in lieu of TLR market flow curtailment targets when appropriate.
  - MWG-RR253: Changes how dispatchable variable energy resources (DVERs) provide regulation down service. SPP said the change will lower structural barriers to DVERs providing regulation service and allow the system to operate more efficiently in times of high wind when SPP could use online turbines rather than requiring uneconomic commitments of other resources.
  - MWG-RR254: Updates the data requirements requested from SPP’s forecasting vendor to improve the wind and solar power forecast. Additional data requirements include individual wind turbine coordinates, turbine model characteristics, cold-weather packages, and turbine availability and de-rate submissions.
  - MWG-RR258: Recommends modifications to the list of frequently constrained areas (FCAs) and resources from the Market Monitoring Unit’s 2017 study. FCAs are electrical areas with one or more transmission constraints or reserve zone constraints that are expected to be binding for at least 500 hours during a given 12-month period and within which one or more suppliers are pivotal.
  - MWG-RR265: A compliance filing in response to FERC’s order on handling ramp shortages under Order 825. (See FERC Approves SPP Shortage Pricing Changes.) Modifies the methodology through which scarcity pricing reflects the value of regulation and operating reserves. The Tariff language was filed in October (ER17-772).
  - ORWG-RR162: Requires phasor measuring units (PMUs) at new generator interconnections to aid in oscillation detection, generator model validation and post-event analyses, as has become common practice among SPP’s peers.

The consent agenda’s approval also resulted in MOPC’s endorsement of:

- - A 34.9% decrease in SPS’ escalated baseline cost of $17.67 million to rebuild 22.1 miles of 115-kV line and a 115-kV circuit.
  - A 23.2% decrease, to $58.8 million, in the escalated baseline cost for SPS to build a new 47.2-mile, 345-kV line and a 345-kV substation.
  - A 23.4% decrease, to $28.5 million, in the escalated baseline for Nebraska Public Power District to build a new 35-mile, 115-kV line and complete various upgrades.
  - Charter revisions to the Reliability Compliance Working Group reflecting the SPP Regional Entity’s dissolution.

— Tom Kleckner

January 23, 2018

Texas Regulators Noncommittal After LP&L Hearings

By Tom Kleckner

Texas regulators concluded two days of hearings on Lubbock Power & Light’s proposal to move 70% of its load from SPP to ERCOT last week, still debating whether the migration is in the public interest.

A partial settlement between LP&L and consumer groups resolved several issues before the Public Utility Commission’s hearing began. Yet to be settled is whether SPP and its members will be compensated for the loss of load and who will pay for the transmission facilities necessary to integrate Lubbock into ERCOT (Docket 47576).

ERCOT SPP LP&L Lubbock Power and Light — PUCT, intervenors gather for Day 1 of hearings on LP&L’s migration from SPP to ERCOT | *PUCT*

“I don’t want anyone to leave here thinking I’ve approved this,” warned PUC Chair DeAnn Walker in drawing the two days to a close Thursday. “I have not made a decision. There are things I’m going to need to have, if we do move forward. Without those things, there’s no moving forward.”

Walker was joined in her uncertainty by Commissioner Brandy Marty Marquez, who agreed the commission has “a lot to do here.”

“I’m not sure where I am on the public-interest finding,” she said. “If we get there, that’s a big hurdle.”

Commissioner Arthur D’Andrea was not as vocal on his position. The PUC will take up the issue again this week during its open meeting, though a final decision is not expected.

The commissioners also asked LP&L and several parties to formalize an agreement in principle reached following a weekend of “diligent” negotiations. The utility announced the agreement during a prehearing conference on Jan. 17.

ERCOT SPP LP&L Lubbock Power & Light — LP&L counsel Chris Brewster questions SPP’s Antoine Lucas (middle), SPS’ Bill Grant (far right) | *PUCT*

The utility, Texas Industrial Energy Consumers, the Office of Public Utility Counsel and PUC staff agreed that LP&L’s move to ERCOT is in the public interest, with the utility agreeing to paying $22 million annually to hold harmless the ISO’s transmission customers over five years. LP&L also agreed to cover the costs of an SPP study (about $172,000) to determine the effects losing its load would have on its members.

The agreement would also eliminate the proposed South Plains Project, a $247.5 million, 345-kV initiative that overlaps with the facilities necessary to integrate LP&L. Sharyland Utilities has proposed the transmission line as an economic project, but ERCOT’s analysis has not been able to justify the project.

The ISO has estimated it will cost approximately $360 million to connect the partial Lubbock load to its system.

LP&L is not an SPP member, but its total load of approximately 600 MW is served through a pair of long-term contracts with Southwestern Public Service. The Xcel Energy subsidiary says it is not opposed to LP&L’s efforts to join ERCOT, but it considers the move an economic one.

“Our efforts are focused on protecting the economic interests of our customers, who will bear a greater share of costs for transmission facilities that were built to serve Lubbock,” said SPS spokesman Wes Reeves.

For its part, SPP wants to protect its members from incurring additional financial liabilities. “We hope the SPP footprint is held harmless from any costs associated with Lubbock’s potential move to ERCOT,” General Counsel Paul Suskie said.

LP&L announced in September its intention to integrate 470 MW of its load within ERCOT by June 2021, after its SPS wholesale contract expires. A second SPS deal that expires in 2044 serves the remainder of its load.

The utility is hoping for a decision before March to remain on schedule. City leaders say moving into ERCOT will give most of its citizens access to the ISO’s competitive market and lower rates.

“I’m still struggling with the [megawatts] left behind,” Walker said. “Lubbock, as a city, is going to have citizens treated differently. I’m concerned about not knowing what the impact of that ultimately is going to be, and us making a decision without knowing what that’s going to be.”

The commissioners directed staff to prepare a preliminary order. It will include language designed to prevent LP&L from switching back to SPP or another RTO and likely settle the issue of who will build the transmission facilities connected to ERCOT. LP&L has proposed working with Sharyland on that project.

January 23, 2018

OMS Urges FERC to Pass Tax Cut Benefit to Ratepayers

By Amanda Durish Cook

The Organization of MISO States on Monday called on FERC to order the nation’s utilities to cut rates in response to a recent reduction in federal corporate taxes.

OMS board members last week unanimously approved sending the commission a letter outlining their position after Executive Director Tanya Paslawski introduced the idea during a conference call.

“I don’t think it’s anything controversial here … but we want to make sure everyone is comfortable,” Paslawski said. “We’re looking to file this fairly quickly.”

North Dakota Public Service Commissioner Julie Fedorchak was the first to express her support.

FERC OMS corporate tax rate ratepayers — OMS President Ted Thomas in 2017 | © *RTO Insider*

The letter, signed by OMS Chairman Ted Thomas (also chair of the Arkansas Public Service Commission), encourages FERC to move quickly to ensure customers receive the maximum benefits associated with the recent reduction in the federal corporate tax rate. The tax reduction “directly impacts the cost of service for regulated utilities across the country,” the letter said.

OMS noted that many of its members have already taken steps “to preserve the value of these cost reductions” for ratepayers within their own jurisdictions and that it is in the public interest that the savings be realized by all customers, including those for electric transmission.

“As such, the OMS members join the chorus of parties urging FERC to take all necessary action to preserve the benefits of the cost reduction from lower corporate tax rates for customers in the form of lower transmission rates for entities within its jurisdiction,” the organization said.

Ever since President Trump last month signed the Tax Cut and Jobs Act, reducing the corporate tax rate from 35% to 21%, state officials across the country have called on utilities to pass the savings to their ratepayers — and some utilities have vowed to do so. The Organization of PJM States Inc. has already sent a similar letter to FERC. (See Utilities Likely to Pass Tax Bill Gains to Customers.)

Several OMS associate members elected to join in the letter, including the Indiana Office of Utility Consumer Counselor, the Office of Consumer Advocate of Iowa, the Michigan Agency for Energy, the Minnesota Office of the Attorney General and the Citizens Utility Board of Wisconsin. The Alliance for Affordable Energy in Louisiana also said it supported the letter.

At Thursday’s open meeting, Commissioner Robert Powelson expressed his support for a measure. “I hope we do our part to make sure these tax benefits are accrued to energy users here in America,” he said.

Chairman Kevin McIntyre told reporters after the meeting that he agreed with Powelson’s sentiment and that the commission was considering its options.

January 23, 2018

SPP Strategic Planning Committee Briefs

OKLAHOMA CITY — SPP’s Strategic Planning Committee last week decided it will respond to FERC’s request for a definition of “resilience,” rather than losing valuable time turning the effort over to a newly created task force.

The commission on Jan. 8 rejected Energy Secretary Rick Perry’s call for cost-of-service payments to coal and nuclear generators, instead creating a new docket (AD18-7) requiring RTOs and ISOs to answer two dozen questions about how they define and assess resilience. FERC said it will use the response to determine whether additional action is necessary. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)

Grid operators must respond by March 9.

American Electric Power’s Richard Ross, stressing the importance of stakeholder feedback, asked, “Will the creation of a task force end up consuming two-thirds of the time needed to get feedback?”

SPP strategic planning committee resilience — SPP’s Strategic Planning Committee conducts its January meeting | © *RTO Insider*

During the SPC’s Jan. 18 meeting, SPP staff initially suggested creating a forum in which they could solicit member concerns and input on resiliency issues, but they eventually yielded to the SPC’s management role to save time.

“Let’s start the discussion and see what happens,” SPP CEO Nick Brown said. “Using the whole Strategic Planning Committee is the best approach. Let’s let our team of experts put straw comments together, and see where they fly.”

Brown assured the committee he is, and will be, in “constant contact” with his counterparts to track progress at other RTOs, and said there was little appetite for asking FERC for an extension.

“I suggest we move ahead as best we can, using our existing stakeholder process,” he said.

Asked whether this was the commission’s effort to end up with resiliency standards, Brown said he didn’t know. “I think FERC is just looking for guidance on this. It’s a new commission, and there’s a lot of different thoughts on that commission.”

FERC has started the dialogue by inviting feedback on its suggested definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”

SPP strategic planning committee — Paul Suskie, with Mike Ross to his left, explains SPP’s response to FERC’s resiliency directive | © *RTO Insider*

SPC Chair Mike Wise, with Golden Spread Electric Cooperative, said he would work with the committee’s staff secretary Michael Desselle and SPP General Counsel Paul Suskie to create a timeline and process for gathering input.

Energy-only Resources Report Leads to Discussion, not Results

A staff report on including energy-only resources in SPP’s transmission planning process generated significant debate but did not result in an action item.

Staff reminded the committee several times that it was only presenting a status report, and that it would provide more information in the future.

“It’s pretty clear from the discussion we have some concerns,” Wise said. He and Desselle “want to spend some time looking at this before we get back to you.”

Staff said they are attempting to develop and adopt policies that better align SPP’s generation interconnection, transmission service and integrated transmission planning processes to “provide value proportional to cost when considering capacity and energy-only resources.”

Jay Caspary, SPP’s director of research, development and special studies, said this will address a perception that there is an “inequity of costs associated with market access and transmission expansion” allocated to load-serving entities when compared to non-LSE interconnection customers.

As the discussion dug deeper into the weeds, it was evident that stakeholder concerns ranged in many different directions, from the meaning of firm and non-firm transmission service to the length of time it takes proposed projects to get through the interconnection queue.

Caspary highlighted one equity issue as the “big one”: LSEs or merchants with energy resources compete equally in the market with those that have capacity resources and typically incur lower costs with associated market access.

“We could determine all network load in the footprint is firm,” Wise said. “That’s one way to eliminate much of this issue.”

“That may be very well where we end up,” said Lanny Nickell, SPP vice president of engineering. “We were trying to limit our creative thinking to what we felt we could accomplish. These are just ideas, not the end-all, be-all solutions to all the concerns we’ve been hearing.”

Staff said they would narrow a list of “modification considerations” — and “not proposals,” Nickell clarified — and incorporate the SPC’s feedback into a whitepaper, to be presented to the committee in the future.

Until then, much of the project’s burden could fall onto the Generator Interconnection Improvement Task Force (GIITF), which has been asked to address the overloaded interconnection queue and new requirements from FERC’s proposed rulemaking initiatives.

The GIITF in April intends to share with the Markets and Operations Policy Committee details on its three-stage process to clear the queue’s backlog. The group expects its next major issue to be rules accommodating battery storage, following a “dozen or so” requests for storage in the latest queue.

“That’s a bigger and bigger item for us to deal with,” said SPP’s Steve Purdy, the GIITF’s staff secretary. “We have a lot to accomplish by October.”

The MOPC recently granted the task force a one-year extension to develop a replacement for SPP’s current interconnection process. (See “Generator-Interconnection Task Force Extended for 1 Year,” SPP Markets and Operations Policy Committee Briefs.)

Governance Committee Reviewing SPP’s Committee Structure

Brown told the SPC that the Corporate Governance Committee is reviewing SPP’s governance structure to ensure it still matches where the RTO is today — and will be soon with the possible integration of the Mountain West Transmission Group.

SPP’s footprint touches 14 states, stretching from East Texas to the Canadian border, having added Nebraska utilities and the Integrated System since 2009.

“We need to put some thought into the governance structure as we continue to grow,” Brown said. “Is a committee structure we put in place in 2003, and changed incrementally, appropriate for where we are today? It’s time. We just haven’t sat down and taken a detailed look.”

The Finance Committee is also moving forward with changes to increase transparency into SPP’s budget, which Brown said raises questions about the RTO’s withdrawal fee.

“All those things fit together,” he said, promising the SPC and Board of Directors will stay informed of the progress.

— Tom Kleckner

January 23, 2018November 9, 2023

Oroville Dam Faces Lawsuit, Relicensing Threat

By Jason Fordney

Controversy is swelling over the February 2017 spillway collapse at the Oroville Dam in Northern California, after local officials last week filed a scathing lawsuit alleging corruption at the state’s main water agency and lawmakers called for FERC to delay the facility’s relicensing.

“Decades of mismanagement and intentional lack of maintenance” by the California Department of Water Resources led to the federally declared disaster, according to allegations in the Jan. 17 lawsuit filed by the City of Oroville against the department. Filed with the California superior court in Butte County, the suit describes maintenance issues and a culture of poor supervision, fabricated inspection reports and corruption at the agency.

“For years, DWR supervisors were more interested in lining their own pockets than ensuring the safety of the facility and its workers. Important maintenance projects were delayed or never completed, and substandard supplies were used to address vulnerabilities in the dam’s armored spillway,” the lawsuit alleges.

Oroville is home to the Hyatt and Thermalito power plants totaling 933 MW of capacity, which had to be shut down during the incident. During the dam’s 2005 FERC relicensing proceeding, three environmental groups requested that the state pave the hillside below the emergency spillway to avoid erosion. The spillway failure generated criticism of both the DWR and FERC for ignoring the previous warnings. (See Local Officials Appeal to FERC as Oroville Water Levels Recede.)

The court filing alleges a “toxic culture” at the department, describing incidents of racist and sexist behavior, employee theft and other corruption. It describes how events around the incident unfolded, including the interaction of local law enforcement with DWR officials prior to and during the evacuation, which caused chaotic and dangerous road conditions and massive traffic jams. A complaint filed through the state Government Claims Program over the Oroville situation was rejected last July because it was determined it would be better resolved by the courts, the lawsuit says.

The lawsuit does not specify financial damages but does cite physical damage to city infrastructure, equipment and personal property as well as costs related to the evacuation, loss of tax and tourism revenue, and emergency and law enforcement services.

DWR spokesperson Erin Mellon said the department does not comment on pending litigation.

On Friday, U.S. Rep. John Garamendi (D), whose district is near Oroville, petitioned FERC to postpone the pending relicensing of the dam, citing the incident and saying “a failure by FERC to delay relicensing of the Oroville Dam would be a serious abdication of its regulatory responsibility.” A week earlier, nearly two dozen California state legislators filed in support of delaying the license.

Blowback over New DWR Director

The DWR has had four directors since the beginning of 2017, when Bill Croyle took over as acting director after Mark Cowin’s nearly seven-year stint. Cindy Messer briefly took over from Croyle in July 2017 until Gov. Jerry Brown appointed Grant Davis to the role.

Davis only led the department until this month, resigning after an independent forensics team released its report on the dam failure. (See Report: Regulatory Failure Caused Oroville Incident.) He was the signatory to the department’s Dec. 20 relicensing application to FERC, and he noted that the spillway incident followed California’s wettest January and February in more than a century.

Brown appointed Karla Nemeth to replace Davis on Jan. 10. That decision has stirred controversy, as The Sacramento Bee reported last week, because Nemeth is married to Tom Philp, executive strategist of the Metropolitan Water District of Southern California, a key member of a group of public agencies known as the State Water Contractors, which are the main recipients of water stored behind the Oroville Dam.

The City of Oroville’s lawsuit alleges the State Water Contractors “lobbied DWR to defer maintenance at [State Water Project] facilities, in order to reduce their own costs” and used their influence to defer needed maintenance at the facility.

Metropolitan Water District is also involved with negotiations around Brown’s $17.1 billion water tunnels proposal, a large-scale project opposed by many Northern California officials and environmentalists.

January 23, 2018

ISO-NE Planning Advisory Committee Briefs: Jan. 18, 2018

Real-time price data from 2018 indicate the ISO-NE grid is nearly free of congestion, stakeholders learned during a Planning Advisory Committee teleconference last week.

ISO-NE System Planning Engineer Victoria Rojo presented the PAC with an analysis of historical market and operational data, saying “the small congestion component of the locational marginal prices suggests there is little congestion on these interfaces.”

ISO-NE congestion critical load level — | *ISO-NE*

The analysis showed that interface flows typically operate closer to the limit during on-peak hours and that portions of the system far from load centers — especially northern Maine — have high negative loss components. Rojo attributed the Maine negative line losses to new wind energy resources.

“We are effectively close to a congestion-free system,” said Michael Henderson, the RTO’s director of regional planning and coordination.

West Central Mass 2027 Tx Needs Assessment

ISO-NE will conduct a 2027 needs assessment for the Western and Central Massachusetts (WCMA) study area to examine any potential transmission needs 10 years out and determine their time sensitivity.

ISO-NE congestion — West Central Mass Study Area | *ISO-NE*

The study will consider future load distribution; resource changes in the area based on Forward Capacity Auction 11 results; 2017 solar and energy-efficiency forecasts; reliability over a range of generation patterns and transfer levels; and all applicable NERC, Northeast Power Coordinating Council and ISO-NE transmission planning reliability standards.

Comments on the preliminary draft study are due by Feb. 4 and the study should be complete in the second quarter.

Critical Load Level and Need-by Date Determination

Senior transmission planning engineer Pradip Vijayan presented staff analysis to determine the critical load level (CLL) and a need-by date (NBD) for steady-state, peak-load needs on short circuits.

The study noted that in past needs assessments, a “year of need” was used to denote summer peak load needs likely to be required within three years. However, for time-sensitive needs, the Tariff requires a specific NBD.

ISO-NE critical load level congestion — New England Subarea Model | *ISO-NE*

The RTO performs a CLL analysis for each identified need, and the results inform market participants about the quantity and general location of resources that would either satisfy the need or defer it for regulated transmission solutions.

For a time-sensitive need, the calculated CLL signals at what load level an identified need would be eliminated — which may call for additional reduction in New England load.

— Michael Kuser

January 23, 2018

SPP Working to Respond to FERC’s Quick-Start Directive

By Tom Kleckner

OKLAHOMA CITY — SPP told members last week it and its Market Monitoring Unit will file separate reply briefs in response to FERC’s December order that found the RTO was suppressing investment signals by not allowing quick-start resources (QSRs) to set LMPs.

The commission issued a Section 206 order requiring SPP to change its Tariff to address quick-start pricing (RM17-3). FERC said it found the RTO’s approach to the resources’ pricing to be “inconsistent with minimizing production costs” and suggested several changes it could implement. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)

SPP quicks-start resources FERC — Richard Dillon explains SPP’s position | © *RTO Insider*

Under a 206 filing — “fairly new to SPP,” said Market Design Director Richard Dillon — FERC can unilaterally make changes to an RTO’s or ISO’s rates, terms or conditions. The reply briefs are due by Feb. 12, with a final order expected within six months of that. The MMU will file its brief after the RTO. Neither Dillon nor MMU Executive Director Keith Collins revealed what they will say in their briefs.

“A quick-start unit provides a product other [resources] can’t,” Dillon said. FERC “wants the value of the product to be reflected in the LMP itself.”

In the meantime, SPP staff said it will continue its work on three open revision requests addressing QSRs. Securing the Markets and Operations Policy Committee’s unanimous approval last week of a revision request that corrected and clarified a previous revision was a first step.

Staff developed RR 256 as it began working on the previous revision request’s implementation details. It said the revision addresses a market inefficiency “inadvertently” created in RR 116 and eliminates a potential gaming opportunity. RR 116 was approved in October 2015 but has yet to be filed with FERC. Two other quick-start related Tariff changes, RR 137 and RR 142, have also been approved by SPP stakeholders but not yet filed.

Dillon said the revision requests are built on top of each other and reflect stakeholders’ “desires and corrections,” but they will not be filed with FERC until the commission rules on the Section 206 docket.

RR 116: Provides the primary language for the new QSR logic and replaces “quick-start resource” with “offline supplemental reserve resource” for those resources supplying offline supplemental reserve.
RR 137: Updates previously removed enhanced combined cycle language referencing QSR limits and the Tariff’s Appendix G for QSR changes.
RR 142: Clarifies that QSRs are ineligible to register as multiconfiguration combined cycle resources.

In its order, FERC said SPP should:

Commit and dispatch QSRs in real time consistent with minimizing production costs, subject to operational and reliability constraints;
Remove the option for enhanced energy offers for QSRs that incorporate commitment costs in the incremental energy curve; and
Consider both registered and unregistered QSRs in quick-start pricing to ensure prices reflect the cost of the marginal resource.

Golden Spread Electric Cooperative’s Mike Wise said the revision requests are unresponsive to the FERC order and “come very short of the mark.” Dillon admitted the changes do not cover everything in the 206 order, “but they’re moving in the same direction.”

Dillon said addressing all of FERC’s directives in the 206 filing would result in significant market changes for SPP. He pointed out SPP’s pricing is ex ante (planned), and that an ex post market (actual outcomes) would require major software changes.

“We don’t know what the final order will look like,” he said. “When we get an actual order from FERC, we’ll have another RR incorporating additional direction from FERC.”

Oklahoma Gas & Electric’s Greg McAuley said his company would prefer SPP file the revision requests, rather than wait on FERC. “The concern is stakeholders have already indicated a willingness to do this. As an entity with brand new quick-start resources coming online and available, what we’ve been working on is very important to us.”

“A bigger issue is credibility,” Dillon countered. “We used to have a reputation of knowing what we were doing and being really sharp. If we make some filings inconsistent with the very 206 filing FERC gave us, that calls into question we know what we’re doing. We don’t want to dig that hole any deeper.”

Complicating matters is SPP does not yet have a definition for QSRs in its Tariff, as do the other RTOs. Stakeholders have suggested a minimum run time of one hour or less to qualify as a QSR.

January 23, 2018

Counterflow: The Devil Went Down to Georgia

Counterflow

By Steve Huntoon

Georgia Public Service Commission Vogtle — Huntoon

“Johnny, rosin up your bow and play your fiddle hard,
’Cause hell’s broke loose in Georgia and the Devil deals the cards.”

There’s a process problem with the Georgia Public Service Commission’s Vogtle decision, and there’s a substance problem.

Process Problem

Georgia commissioners publicly and vehemently stated that Vogtle should be completed.^[1] And then they had a hearing on whether Vogtle should be completed. See the problem?

Regulators are supposed to make reasoned decisions based on records. It’s hard to do that before you have a record.

“Sentence first! Verdict afterwards,” as the Queen said in “Alice in Wonderland.”

Substance Problem

Last September, my column showed that the original “need” for Vogtle, in the form of a projected increase in customer demand, had basically disappeared.^[2] And with simplifying assumptions favorable to Vogtle, and using Lazard cost estimates, completing Vogtle would impose excess costs of $23.6 billion on Georgia consumers over the next 40 years.

Here’s a quick quiz: After eight years of construction, what percent of Vogtle is constructed? Answer in footnote below.^[3]

So there was a hearing. Or more like Kabuki theater. The Public Interest Advocacy Staff (PIA Staff) of the Georgia commission showed:^[4]

Because of multiple flaws in Southern Co.’s case, “the project is uneconomic on a going forward basis by $1.6 billion.” The commission’s Advisory Staff agreed with PIA Staff that completing Vogtle is uneconomic at the cost estimated by Southern.^[5]
“Certain costs [$1.5 billion, excluding Toshiba’s parental guarantee] for which the company is seeking recovery from ratepayers resulted from project mismanagement.”
“Had the commission been more accurately informed by the company as to the depth of the problems facing the project, the commission would have had the opportunity to assess the project status and make different decisions earlier on in the construction, when sunk costs were not so daunting an issue.”
Giving Vogtle co-owners “the right to abandon the project if any company costs are disallowed for any reason, including fraud, failure to disclose a material fact or criminal misconduct” was a “threat” and “unconscionable.”

Southern, of course, disputed all this.

Given the enormity of these issues and the long-term consequences of a decision to complete or not complete Vogtle, one would have expected a deliberate, careful analysis of the record and a reasoned decision.

Instead, the last day of hearings was Dec. 14, briefs were required five days later and the commission made its decision two days after that. Speed readers, I guess.

Are you ready for the decision itself? The Georgia commission without any explanation at all simply proclaims:^[6]

“Based upon careful consideration of all the evidence in the record, the commission finds as a matter of fact and concludes as a matter of law that it is appropriate to continue construction of Vogtle Units 3 & 4 under the terms set forth in this order.”

Georgia, that’s all the explanation you get. C’est la vie.^[7]

But what should consumers expect from regulators who had announced their decision before the hearing? Why waste ink?^[8]

More Project Delays Rewarded

Going forward, Georgia consumers have no protection against continuing project delays and overruns.^[9] The Georgia commission order claims that it incents performance by reducing return on equity if target dates aren’t met.

Unfortunately that is just wrong. Reduced ROE during delays is only for the periods of delay. After the project is in commercial operation, that ROE becomes part of the rate base, upon which Southern gets a generous return for at least 40 years. That is why Southern already will make an extra $5.2 billion over the life of the project from the delays to date.^[10] Nice work if you can get it.

The longer Vogtle takes to complete, the more Southern makes.

And every electric consumer in Georgia is on the hook for whatever Vogtle ends up costing.

What site selection advisor for a large consumer of electricity will recommend locating a new facility in Georgia? Because there is no competition in Georgia,^[11] any new business would have unlimited exposure to the Vogtle plant. Moody’s Investor Service already downgraded JEA because it owns 206 MW of Vogtle.^[12]

Customer Refund Gimmick

One last note on the Georgia commission decision: It directed that Southern refund part of the Toshiba/Westinghouse Electric settlement payment to consumers, $25 per customer per month for three months, with a bill line item saying “Vogtle Settlement Refund.” Great PR, but this refund money isn’t coming from Southern. It’s money that otherwise would have been credited against the cost of Vogtle.

So consumers effectively will be paying Southern a generous return on their refunds for decades. Sort of like your credit card company sending you a $75 gift card, but then that $75 shows up on your next bill as a cash advance. Which you can’t pay off for the next 40 years.

Oh, sorry, one more thing: The Georgia commission authorized a token 5-MW solar project to be located at, you guessed it, Vogtle. No consideration of whether that project size or location made any sense. But even more rate base for Southern.

The Sad Reality

The sad reality is that Vogtle never made sense, and this became obvious years ago. The Vogtle owners failed to oversee the failures of Toshiba and Westinghouse, failed to report the failures to the Georgia commission, and failed to provide realistic project costs and schedules. The hole became billions deeper as a result, and Southern’s past and future profits grew as a result.

Instead of holding the Vogtle owners accountable for their failings, the Georgia commission is more concerned with not appearing to have made consumers pay something for nothing. So the Georgia commission approves continuing an uneconomic project, gives Southern and the new project contractor an even bigger blank check than before, and maintains the incentive of higher profitability from greater delays.

The flogging will continue until morale improves.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.

“I do want to see this project completed,” said PSC Commissioner Lauren “Bubba” McDonald. “I do not like to see failure.” http://www.ajc.com/business/georgia-power-told-its-homework-vogtle-nuke-options/mnHqeJ7BdDza0U25xAxfbP/. “As an unabashed supporter of nuclear power,” [PSC Chairman Stan] Wise wrote, “I intend to be present for that vote and will resign shortly thereafter so that you may appoint my successor prior to the (candidate) qualifying period for the 2018 elections.” http://politics.myajc.com/news/state–regional-govt–politics/psc-wise-quit-after-vogtle-vote-governor-can-appoint-successor/Dv6bJbPTpNupmLUUe83f8J/. Commissioner Tim Echols said: “The last thing I want to do to my ratepayers is to say, ‘Look, I spent $4.5 billion of your money, and you have nothing to show for it.’ That’s a formula for getting unelected, as far as I’m concerned.” https://www.greentechmedia.com/articles/read/the-nuclear-power-war-isnt-over-yet#gs.1G0g8AQ. Echols went on to write an op-ed for The Wall Street Journal and an article for Public Utilities Fortnightly in full-throated advocacy for completing Vogtle, all before the hearing on whether to complete Vogtle. ↑
http://energy-counsel.com/docs/Vogtle-the-Law-of-Holes-and-Two-Modest-Proposals.pdf. The column also showed that the fuel diversity argument for Vogtle was vacuous. ↑
Reportedly, 40%. A shocking audit report on Vogtle’s sister nuclear units in South Carolina was prepared by Bechtel in 2016. It was never meant to see the light of day, but the link to it is in the news story here: https://www.postandcourier.com/news/audit-highlighted-problems-with-south-carolina-nuclear-project-a-year/article_9ac96112-9185-11e7-9979-977331ac2233.html. ↑
http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=170562. In this proposed order, the PIA Staff provides a damning “just the facts” recitation of everything wrong about Vogtle. ↑
https://www.youtube.com/watch?v=JtycWKqQVk8 ↑
http://www.psc.state.ga.us/factsv2/Document.aspx?documentNumber=170765. ↑
Adding to the incredulity is that terms of the commission decision were reviewed with Southern in advance of the commission meeting. “Although Echols said he did not want to get into details about his interaction with Georgia Power over the new conditions, he added, ‘Ultimately, they were read in and gave feedback’ on those restrictions.” http://chronicle.augusta.com/news/2017-12-21/georgia-public-service-commission-vote-allows-plant-vogtle-proceed. ↑
Not part of the decision is a motion by one of the commissioners on what the decision should be. This motion refers to the uncertainty of future natural gas prices, and how Vogtle can be a hedge against high gas prices.Of course future energy prices can’t be known. But the salient fact is that a forecast of future natural gas prices is effectively a mean. Lower gas prices would mean Vogtle is even more uneconomic. Higher gas prices would mean Vogtle is less uneconomic and might even be economic. But decisions need to be based on the mean, not on one extreme or another. And here’s another important point: If the gas price hedging value is significant the right thing to do is suspend Vogtle at a relatively trivial cost of $112 million for up to 10 years, which cost comes from Southern’s own consultant. http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=169459 (Black & Veatch Deferral Study). The Georgia Commission decision makes no mention of this option. ↑
The original project completion date was in 2017. In December 2016, Southern promised completion by 2020. Then nine months later, the completion date was pushed back almost two more years. And that date is likely more fantasy than reality. As of late 2016, two AP1000 plants in China were supposed to go into commercial operation in early 2017. https://www.reuters.com/article/us-westinghouse-nuclear/westinghouse-to-start-first-china-reactor-in-2017-sees-tens-more-idUSKCN11M1Q7. Somehow that didn’t happen, and last month the China state agency said they “will hopefully begin commercial operation next year.” http://www.nicobargroup.com/news-views-1/. “Hopefully”? ↑
“As a result of the delays experienced by the project, the company will make considerably more profit over the lifecycle of the units than it would have had the project been completed on time. The company’s profit will increase from approximately $7.4 billion to approximately $12.6 billion over the unit’s entire lifecycle.” http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=170562 (page 8). ↑
As I’ve pointed out before, Vogtle and the lack of competition are joined at the hip. ↑
https://www.moodys.com/research/Moodys-assigns-Aa2-and-Aa3-to-JEA-FL-sr-and–PR_904363490 ↑

January 23, 2018

MISO Looks to Align Load Forecasting, Tx Planning

By Amanda Durish Cook

CARMEL, Ind. — MISO is seeking to more closely harmonize its load forecasting process with the four 15-year future scenarios it creates to support long-term transmission planning, but stakeholders are wary of two ideas being floated by the RTO.

MISO load forecasting — Lawhorn | © *RTO Insider*

“I think it’s time we move to where the … load forecast is future-dependent,” John Lawhorn, MISO senior director of policy and economic studies, said at a Jan. 17 Planning Advisory Committee meeting.

Lawhorn said that the futures created for the MISO Transmission Expansion Plan could link up with the load forecast in one of two ways: require load-serving entities to supply detailed planning-level data for each of the futures; or use the RTO’s “independent” load forecast as a starting point to create forecasts for each future.

“In both cases, the level of information would be the same; it would include a 20-year forecast, energy efficiency, demand response [and] distributed generation,” Lawhorn said.

“It’s a paradigm shift,” he said. “It’s becoming increasingly evident that a long-term forecast is needed to study the futures,” citing the potential for MISO to swing from summertime peak planning to possible hour-by-hour planning for a future in which smaller distributed generators provide scatterings of energy.

The biggest hitch with the current forecasting approach is that MISO can’t get a clear picture of demand-side management programs, which will be instrumental in forecasting future demand, Lawhorn said.

“This is driving our planning process to areas that we haven’t yet been forced to look at in this level of detail,” he added.

Developed by Purdue University’s State Utility Forecasting Group, MISO’s independent load forecast does not draw on any of the futures, which include “limited,” “continued” and “accelerated” fleet change predictions, as well as a scenario in which distributed generation and emerging technologies gain popularity. The independent forecast also does not account for individual load forecasts produced by MISO’s LSEs, but instead relies only on publicly available information to predict summer and winter peak energy demand for the RTO’s 10 local resource zones along with systemwide peaks.

Unlike the 10-year forecasts produced by LSEs, the Purdue forecast is for informational purposes only — not tied to any official MISO predictions — with an Applied Energy Group study lending the independent load forecast its projections for EE, DR and DG. But the RTO now thinks either the Purdue or LSE forecasts could perform a larger role in transmission planning.

MISO says its pace of fleet evolution “highlights the need to create a new source of load forecasts tailored for long-term economic planning.”

“Our process lacks transparency and it lacks … the detail needed to effectively and efficiently move energy to all areas of the MISO footprint,” Lawhorn said. He also said the 140-plus separate LSE load forecasts currently lack a common set of assumptions.

Two Approaches

If the RTO decides to have LSEs prepare more detailed forecasts, they would have to ready four separate 20-year forecasts, a total of 8,760 hourly load shapes, 20 years’ worth of demand-side management growth predictions, and four iterations of program penetration for EE, DR and DG.

MISO could adopt the LSE-centered approach by the 2021 MTEP at the earliest, Lawhorn said, noting that it would take a minimum of two years to modify the RTO’s member website to accept more detailed information.

Currently, LSEs submit 10-year demand and energy forecasts, extrapolated for another 10 years to develop a 20-year forecast.

“By having a 20-year forecast, you might be outrunning the headlights of state regulators and local planners,” said David Harlan, president of consulting firm Veriquest Group.

“That level of specificity is where the industry is heading,” Lawhorn replied.

MISO’s second load forecasting option involves a third-party consultant like Purdue developing a 20-year demand and energy forecast for each local resource zone by future scenario. Such a system could be in place by MTEP 19.

MISO load forecasting transmission planning — MISO PAC meeting on Jan. 17, 2018 | © *RTO Insider*

PAC Chair Cynthia Crane asked whether MISO plans to calibrate a long-term third-party forecast against the shorter forecasts furnished by LSEs if it takes the second route.

“Oh, absolutely,” Lawhorn said.

LSE Ability to Forecast

Stakeholders are divided over how difficult it would be for LSEs to provide more detailed forecast data.

Indianapolis Power and Light’s Lin Franks said there’s no reason MISO couldn’t begin now to use more detailed LSE information for load forecasts.

Lawhorn responded that it’s a “fairly considerable task” to coordinate forecast information from more than 140 LSEs, noting that not all of them are prepared to offer that level of detail. MISO will instead issue a survey to determine the feasibility of producing 20-year forward-looking data, he said.

Customized Energy Solutions’ Ted Kuhn pointed out that forecasts are only worthwhile if MISO develops a process for historically assessing their accuracy. He said the RTO must be able to compare forecasts with actual demand.

Minnesota Public Utilities Commission staff member Hwikwon Ham said he thinks “the independent load forecast is as good as the input used.”

American Electric Power’s Kent Feliks said it’s a “daunting amount of work to require all 140-plus LSEs to provide 20-year forecasts.”

“It seems like an awful lot of resources spent … for little improvement,” he said.

Other LSE representatives at the meeting said creating a load forecast would be a nominal challenge, as they already collect the data needed to prepare forecasts for each MTEP future.

WPPI Energy’s Steve Leovy asked MISO to be more specific about what kind of forecasting information LSEs will be asked to provide. “I’m concerned with what I see, to be blunt, is a half-baked proposal,” he said.

Other stakeholders questioned what came of a 2017 presentation aimed at blending Purdue’s independent load forecasting with LSEs’ 10-year forecasts. (See Bigger Role Seen for Independent Forecast in MISO Tx Plan.)

Madison Gas and Electric’s Megan Wisersky said that LSEs will not be able make an informed choice between the two approaches until they research the costs of preparing more in-depth forecasts.

Lawhorn said MISO is collecting input on the new pair of proposals, and that he would return to the PAC in June to discuss the RTO’s take on the prevailing stakeholder opinion.