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January 23, 2018January 17, 2024

Connecticut Regulators Signal Support for Millstone

By Michael Kuser

Dominion Energy could be one step closer to winning state financial support for its 2,111-MW Millstone nuclear plant in Connecticut.

The Department of Energy and Environmental Protection and Public Utilities Regulatory Authority on Monday issued a draft final report on the economic viability of the plant and signaled their support for state procurement of its energy output under a program reserved for renewable energy resources such as large-scale hydropower, wind and solar (S.B. 106).

The regulators concluded that the public procurement process for Millstone should “go forward” and asked industry stakeholders to submit comments on the report within three days — by Jan. 25 — so they can deliver a final report on Feb. 1.

“The competitive solicitation process created by the legislature is reasonable, and we will propose to the General Assembly that they pursue that process,” DEEP Commissioner Robert Klee said in a teleconference with reporters.

The legislature failed to pass a bill last June that would have allowed the Waterford plant to bid into the procurement process, unlike Illinois and New York, which last year voted to support nuclear plants through zero-emission credits.

The regulators said the procurement should go forward “with certain conditions to ensure that the state’s ratepayers are protected from paying above-market costs for resources that are not verified to be at risk of retirement.”

Conflicting Advice

Gov. Dannel Malloy in July ordered the agencies to assess the current and future viability of the Millstone plant and determine whether the state should provide financial support (17-07-32). In reaching their preliminary conclusion, regulators said they considered confidential documents from Dominion, and stakeholder comments on a study by Levitan Associates that found the plant will likely remain profitable through 2035. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)

In the past few months, state regulators have heard conflicting advice on the issue. The Electric Power Supply Association earlier this month filed comments with the state contending that Millstone’s profitability made any ratepayer subsidy unnecessary. EPSA cited a study by Energyzt Advisors that characterized Millstone as “perhaps the most profitable nuclear plant in the United States.”

The General Assembly submitted comments in January encouraging PURA and DEEP to “hedge against natural gas by opening a bidding process to receive bids from nuclear generating facilities, including Millstone, to purchase power directly by long-term contract.” (See Conn. Regulators Hear Conflicting Advice on Millstone.)

DEEP Analysis

The draft report said the current and projected economic viability of Millstone hinges on energy market revenues and plant operating costs.

PURA Chair Katie Dykes said the Levitan study used the best available public information to develop cost assumptions for the two Millstone units but lacked precision because of the absence of cost information from Dominion. The company submitted a two-page summary of short-term, forward financial projections in November and a longer, redacted document on Jan. 10.

While Millstone’s retirement would not trigger the need for new capacity in Connecticut specifically, it would spur a need for new generation capacity in New England as a whole. Replacement capacity procured through ISO-NE would likely be natural gas-fired, exacerbating security and system reliability issues because of the region’s heavy reliance on gas for power generation.

“It’s important that we are issuing this report just a few days after ISO New England released their own evaluation of the region’s exposure to risks of rolling blackouts if facilities like Millstone or Seabrook or LNG facilities were to be offline for a prolonged period or retire,” Dykes said. (See Report: Fuel Security Key Risk for New England Grid.)

A Regional Issue

If Millstone’s two units stopped operating, CO₂ emissions for the entire New England electric sector would increase by 80 million short tons, or 25%, through 2035, according to the regulators’ report. Replacing at least 25% of Millstone’s output with hydropower, demand reduction, energy storage and zero-emission renewable energy would be necessary for Connecticut not to backslide on its statutory greenhouse gas emissions reductions targets, and would cost the state’s ratepayers an estimated $1.8 billion, it said.

Even with that investment, regional emissions would increase by 20%. Replacing 100% of Millstone’s output with zero-carbon resources would cost Connecticut ratepayers approximately $5.5 billion, the draft report said.

In theory, regulators could use a variety of mechanisms to provide revenue stability for new and existing zero-carbon resources, including long-term power purchase contracts and ZECs.

At present, there are no mechanisms to retain Millstone and allocate the costs regionally. The RTO has indicated in this proceeding that Millstone would not be eligible for a reliability-must-run contract on a transmission security basis. And FERC earlier this month rejected the U.S. Energy Department’s Notice of Proposed Rulemaking that would have required RTOs to compensate nuclear and coal-fired facilities on a cost-of-service basis.

“It’s been unfortunate that the regional discussions at [the New England Power Pool] and at the ISO have not produced any actionable mechanisms to date that could ensure that the region’s ratepayers would be able to do their share in paying to retain these kinds of critical facilities, given that the entire region shares an incentive,” Dykes said.

Klee said the General Assembly would have 30 days to respond to the agencies’ proposal and that details of any forthcoming request for proposals would be worked out in the standard regulatory process.

January 23, 2018

NY Siting Board Approves 126-MW Cassadaga Wind Farm

The New York Board on Electric Generation Siting and the Environment last week approved a 126-MW wind farm to be built and operated by EverPower Wind in the state’s westernmost county.

The Cassadaga Wind project will occupy about 77 acres in Chautauqua County and consist of up to 48 high-capacity, 500-foot-tall wind turbines. The wind farm would interconnect to the state’s electrical grid along the 115-kV Dunkirk-Moon transmission line.

NYISO EverPower Wind Cassadaga Wind Project — | *EverPower Wind*

EverPower had proposed installing up to 62 turbines but lowered the number during the public review process, which included opposition comments from Amish residents and local equestrians. Many Amish do not use electricity from the grid, and the equestrians argued that siting huge wind turbines near their riding trails could spook horses, potentially injuring both animals and riders.

In May 2016, EverPower was the first company to apply for a siting certificate from the multiagency Siting Board, which was established under the Power NY Act of 2011 to streamline the permitting process for power plants 25 MW or greater. John B. Rhodes, chair of the Public Service Commission, also chairs the board.

The board said that the wind farm will improve fuel diversity, grid reliability and modernization of grid infrastructure, as well as benefit the host communities. The developer said the new wind farm will create “nearly 470 construction and full-time jobs with an annual payroll of more than $80 million, while paying more than $10 million to local governments and school districts over a 20-year period.”

— Michael Kuser

January 23, 2018

SPP, Mountain West Resolving ‘Contentious’ Issues

By Tom Kleckner

OKLAHOMA CITY — SPP COO Carl Monroe told the Markets and Operations Policy Committee last week that the RTO’s integration of Mountain West Transmission Group is on track to meet its October 2019 consummation timeline, pending reaching final agreement among the various parties.

A small negotiating team tasked with resolving a subset of five “real contentious” issues has reduced the list to two after an initial meeting, Monroe said. He would not elaborate on the issues at play, but Mountain West entities have suggested several governance changes that would emphasize the differences between the two interconnections. (See SPP, Mountain West Integration Work Goes Public.)

SPP Mountain West Peak Reliability — | *Colorado Public Utilities Commission*

Monroe said the team is “intent” on coming up with a recommendation that can be brought back to the Board of Directors and Members Committee here next week. “It does look like we’re getting closer,” he said.

Complicating matters somewhat, Monroe said, was Peak Reliability’s recent announcement that it would work with PJM to offer market services, and CAISO’s desire to offer reliability coordination in its footprint for half the price of Peak. (See CAISO to Depart Peak Reliability, Become RC.)

“That’s created a whole bunch of ripples in the West on the reliability side, and market side too,” he said. “We continue to have conversations as to what this means to Mountain West going forward.”

SPP’s Strategic Planning and Corporate Governance committees have been meeting with Mountain West representatives behind closed doors since October. Monroe assured members they would have a chance to add their input to any protocol and Tariff changes as they bubble up through the RTO’s normal stakeholder process.

SPP working groups will handle the Tariff changes, while the CGC will be responsible for the governance changes. Monroe said financial obligations won’t be discussed until both parties “are comfortable with the policy level.”

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