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February 6, 2018November 13, 2023

SPP Board of Directors/Members Committee Briefs: Jan. 30, 2018

OKLAHOMA CITY — Southwest Public Service last week withdrew its appeal of a rejected revision request, saying it was satisfied with SPP’s direction to address reporting behind-the-meter network load.

Staff told the Board of Directors and Members Committee on Jan. 30 that it will continue to foster discussion and educate its members, with the intent of determining consistent reporting practices of network load. SPP is digging into the data from a recent survey of members with network integration transmission service (NITS) load and said it will work through the Strategic Planning Committee to develop a common methodology. It hopes to produce a final report in April.

The RTO’s legal staff have met separately with FERC to gain a better understanding of what is and what isn’t net metering, and are continuing their effort to clarify BTM rules. (See SPP Stakeholders Still Struggling on BTM Reporting.)

That was enough for SPS, which filed an appeal with the board after the Markets and Operations Policy Committee rejected a proposal in October that would have required a 1-MW threshold for reporting BTM retail load. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)

In its appeal, SPS said RR241 was “critical to ensuring that the costs of network service are fairly distributed to SPP network service customers and to prevent some SPP customers from subsidizing network service used by other customers.”

“Our retail tariff requires everybody to follow the tariff and enter an interconnection agreement with us, so we do track that [load],” SPS President David Hudson said. “By others not reporting it, it is creating some sort of cost shift. We just want to ensure we take care of this problem.”

“We’re not opposed to working through the stakeholder group,” said Bill Grant, SPS’ vice president of regulatory and strategic planning. “If the stakeholders want to do that and make an attempt at consensus and file something at FERC, we’ll participate in that. Once we understand what the requirements are and the stakeholders want to come together, we will embrace that effort.”

Board Chair Jim Eckelberger summarized stakeholders’ agreement to move forward, saying the board’s point of view is “equity across the system.”

Staff, MWG ‘Looking into’ Cold-Weather Price Spikes

Bruce Rew, SPP’s vice president of operations, said staff are “looking into” several five-minute price spikes that occurred Jan. 16-17, when the RTO set several new highs for winter peak demand. (See ERCOT, SPP Extend Winter Peak Records.)

“The story is related to scarcity pricing,” said Nebraska Public Power District’s Tom Kent. He said he was concerned about “volatility in the market,” but that staff have been “very helpful.”

The Market Working Group (MWG) has also taken up the issue.

Rew said unit trips and outages on the neighboring MISO South system during a Jan. 2 cold weather event “created extra flows on our system that were quite challenging.”

When the meeting ended, Rew handed out lapel pins celebrating 20 years of SPP’s reliability coordinator (RC) function.

“It would not have been a pretty picture two weeks ago, but for the consolidation of balancing authorities, the regionalization of the Tariff and the Integrated Marketplace, that has enabled us to commit units in the day-ahead [market],” SPP CEO Nick Brown said. “I think it’s most appropriate we mark 20 years as an RC.”

Stakeholders Remember Gerry Burrows

Stakeholders opened the meeting with a moment of silence for SPP Regional Entity Trustee Gerry Burrows, who died of cancer on Jan. 9. Burrows had a long industry career, much of it with Kansas City Power & Light. (See “SPP RE Trustee Gerry Burrows Dies,” Company Briefs.)

“No one understood the importance of working together to consensus like Gerry did,” Brown said. “Frankly, it was people like him who made me want to come and work at this corporation and help drive people to consensus.”

“This organization is going to miss Gerry, and we already are,” Trustees Chair Dave Christiano said.

Board Clears 13 Revision Requests

The board approved a Supply Adequacy Working Group revision request (RR251) that addresses three issues FERC cited in rejecting SPP’s resource adequacy package last year. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)

The working group said the measure responds to FERC with numerous changes, while maintaining the previously approved foundational policy. It also moves the planning reserve margin percentage to the SPP planning criteria and keeps the study process for determining the margin in the Tariff.

Westar Energy’s Kelly Harrison and Brent Baker abstained from the members’ vote.

The board also approved an MWG proposal (RR257) that responds to a FERC compliance requirement (EL16-110) obligating 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.)

The board and members approved 11 other revision requests on the consent agenda:

- BPWG-RR250: Documents market import service (MIS) as a transmission product in the Tariff (it has been offered in SPP’s Integrated Marketplace since 2014) and places all information related to reserving and scheduling MIS in one location as a new business practice.
- CPWG-RR249: Corrects, updates and clarifies unclear or outdated letter of credit language to make it more acceptable to financial institutions.
- MWG-RR182: Removes the term “control area,” which is no longer used by SPP, from the market protocols and Tariff.
- MWG-RR200: 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-RR245: 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 and recover true variable costs.
- 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-RR253: Changes how dispatchable variable energy resources (DVERs) provide regulation down service. 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-RR256: Cleans up language in RR116 to eliminate a potential gaming opportunity and make clarifications necessary to implement the new quick-start logic correctly and with its true intent.
- 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 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.

The consent agenda’s acceptance also resulted in the approval of a sponsored upgrade study for Central Power Electric Cooperatives, several staff recommendations on transmission projects and adjusted baseline costs for three previously approved projects. (See “North Dakota Sponsored Upgrade Study Approved,” “MOPC Agrees to Pull Basin Electric Project’s NTC-C” and “Consent Agenda Clears 10 Revision Requests,” SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018.)

— Tom Kleckner

February 6, 2018

NECA Panelists Talk Carbon Pricing, Northern Pass

By Michael Kuser

AUBURNDALE, Mass. — Speakers at the Northeast Energy and Commerce Association Renewable Energy Conference on Feb. 1 discussed the merits and viability of different methods to achieve New England’s aggressive emission reduction goals.

These topics included carbon pricing, the Northern Pass transmission project and offshore wind energy. Utility and energy service representatives were joined by state and federal officials.

ISO-NE Northern Pass Carbon Pricing — NECA’s Annual Environmental Conference was held on February 1, 2018 | © *RTO Insider*

Carbon Tax, Anyone?

NECA Northern Pass — Gardner | © *RTO Insider*

Michelle Gardner, Northeast director of regulatory affairs for NextEra Energy Resources, promoted her company’s alternative market model, the Forward Clean Energy Market, developed with the Conservation Law Foundation and Brookfield Renewable Partners. The model is designed to attract new clean energy resources and also retain existing clean energy resources to reduce greenhouse gas emissions in New England.

Gardner said the first question of any state policy is: Does it work?

“To date, the answer has been yes,” Gardner said. “But over time, now in the [ISO-NE] system we’re seeing wind displace wind. We’re not necessarily seeing the same synergies moving forward that mean, if you build a wind farm you move the ball towards a clean energy future.”

NextEra’s alternative market proposal could work with a carbon tax, or carbon pricing, “though to date we have not received a warm reception from the other New England states about moving a carbon tax,” Gardner said.

In fact, many Massachusetts legislators favor a carbon tax, said state Rep. Jennifer Benson (D), who spoke during the conference lunch.

Benson’s bill, H.1726, calls for a $20 tax on every ton of carbon produced by corporations, with 80% of the revenue rebated to taxpayers and the other 20% going to fund a green bank for the state. It and a competing Senate bill are scheduled for a vote Feb. 7.

The bill weights a larger proportion of the rebates to low-income residents, who often miss out on the benefits of existing energy-efficiency programs. “Because if we can’t touch them, our 2050 goals will never be met,” Benson said. “And we really are not on track to meet those today. We have to do something.

“So is it a tax?” Benson said. “Is carbon pricing a tax? This is the debate. I don’t care. Because we have to start putting real money behind these issues. We’re not going to solve the problem of coastal communities that we just saw a few weeks ago drowning in seawater.”

Pass on Northern Pass

Several speakers expressed disappointment at Massachusetts’ decision to award Eversource Energy and Hydro-Québec a contract to deliver 1,090 MW of hydropower each year via the Northern Pass transmission project. (See Northern Pass Cleans up in Mass. RFP.)

They spoke before word buzzed through the crowd near the end of the conference Thursday that New Hampshire siting officials had voted unanimously to reject the project. (See related story, New Hampshire Rejects Permit for Northern Pass.)

Benson said “a legislator cannot go in and try to regulate … but it’s wild that they could find an option that met none of the criteria.”

Colin Schofield of Altenex, an Edison Energy subsidiary that advises non-utility energy buyers, said corporate buyers were largely “agnostic” about the Massachusetts solicitation.

Northern Pass “is probably somewhat of a lost opportunity to pair a utility procurement with some corporate deals that could enable transmission to move resources, but on the other hand, there may be projects out there that would have been contracting with the utility that maybe sharpen their pencil and get creative about other ways to fund and bring a project to market,” he said

“We’re also disappointed in the decision and have the same process concerns that were mentioned,” said Jamie Howland, director of climate and energy analysis at the Acadia Center. “We certainly would have preferred a project that picked up other renewables along the way if you’re building a new transmission line. It also picked the highest-impact transmission line of all the ones that were on the table.”

“I think there was disappointment from a lot of people, but I don’t think there was a lot of surprise,” said Peter Zaborowsky, managing director of Evolution Markets, an institutional brokerage service for energy and environmental markets. “If the issue is meeting the Clean Energy Standard at the lowest cost, [Northern Pass] probably is a low-cost solution … Economics were the big driver likely.”

Massachusetts Assistant Secretary for Energy Patrick Woodcock did not address the Northern Pass issue but spoke on a panel about the grid of the future.

“While the state has been very successful with deployment of clean energy performance-based rate design, more sophisticated price signals and additional grid modernization are areas of focus for Massachusetts to provide a stronger foundation for long-term growth,” Woodcock said. He added that since taking office last April, he’s seen the state focus especially on energy storage and promoting electric vehicles. (See Mass. Prepares for EV Growth, Alternative Energy Standard.)

Offshore Wind has ‘Turned the Corner’

New England has “the trifecta with regard to wind resources and wind energy,” said Jim Bennett, chief of the Office of Renewable Energy Programs at the Bureau of Ocean Energy Management. “First off, we have world-class winds on both the East Coast and on the West Coast, but particularly up here in the Northeast.”

ISO-NE REV Northern Pass Transmission carbon emissions — Bennett | © *RTO Insider*

The second piece of successfully developing wind energy projects is “a buildable environment, and we have a shallow slope on the outer continental shelf, particularly up here in the East and the Northeast, which is not the case where there are other good resources, like out on the West Coast,” Bennett said.

Finally, the recipe for success must include market demand, and the Northeast has world-class markets, he said.

As a result, BOEM has conducted a number of sales over the last several years and now has 13 leases for offshore wind farms. Seven competitive lease sales generated $68 million, and nearly 1.4 million acres are under lease.

“We have at least one commercial lease off every state from Massachusetts to North Carolina, from Cape Cod to Cape Hatteras,” Bennett said. “We think the wind industry has turned the corner. It’s economically viable, and we should be looking, as the industry tells us, to have a steady stream of leases for years to come.”

February 6, 2018

SPP FERC Briefs: Week of Feb. 6, 2018

FERC approved an SPP waiver request that allows the RTO to forego performing standalone evaluations in favor of a time-saving cluster scenario for three generator interconnection study groups (ER18-421).

The RTO asked for a limited waiver of its Tariff to enable it to expedite interconnection study requests in its Definitive Interconnection System Impact Study (DISIS) queue, which evaluates the effect of proposed generators on transmission system reliability. The request was limited to three DISIS clusters: DISIS-2016-002, DISIS-2017-001 and DISIS-2017-002.

SPP said the standalone scenario has proven costly, requiring significant time and resources to perform while providing minimal value to interconnection customers. The RTO noted standalone results are informational and not binding, unlike the cluster scenario’s results, and said that as the size of its queue continues to grow, the standalone will become less valuable.

The RTO told FERC it intends to revise its Tariff to eliminate the standalone evaluation and will make the base case study models available earlier in the study process, allowing interconnection customers to perform their own standalone analysis. Several generation developers said their concerns about the loss of information from the standalone scenario would be mitigated by accessing the base case study models earlier, SPP said.

NextEra Energy Resources, Westar Energy, Sunflower Electric Power and Mid-Kansas Electric intervened in the proceeding.

SPP Granted Waiver Request to Resolve Billing Dispute

The commission granted a second SPP waiver request to help resolve a billing dispute over approximately $175,000 in transmission charges and penalties with Missouri’s Carthage Electric & Water Plant (ER18-385).

SPP filed the request with the commission in December, along with revised transmission service agreements showing Carthage as the customer and the Southwestern Power Administration as the host transmission owner. The agreements included terms and conditions that did not conform to the RTO’s Tariff, but they were included to implement the results of SPP’s dispute resolution process related to Carthage’s unreserved use of the transmission system.

The RTO said the agreements were intended to correct errors “made in good faith” and limited to only penalty amounts assessed to Carthage for instances of unreserved use between March 2014, when SPP’s Integrated Marketplace came online, through February 2015. SPP said its billing process was delayed because of changes made in implementing the new markets.

FERC found the revised agreements’ nonconforming changes “appropriately reflect” SPP’s dispute resolution process, enabled the RTO to resolve the billing dispute and will not “lead to undesirable consequences, such as harming third parties.”

MRES Escapes Obligation for QF Purchases

FERC approved a request by Missouri River Energy Services to terminate a mandatory obligation to purchase electric energy or capacity from qualifying facilities within SPP’s footprint and with a net capacity larger than 20 MW (QM18-2).

SPP FERC Tri-County Electric Cooperative ZECs — The Missouri River | *American Rivers*

MRES, an organization of 60 member municipalities that own and operate their own electric distribution systems, made the request on behalf of itself and 33 of its members, which are all SPP members. It said QFs within SPP have nondiscriminatory access to a market that satisfies the requirements of the Public Utility Regulatory Policies Act and warrants termination of a utility’s mandatory purchase obligation under the act.

The commission agreed, rejecting a protest from a wind farm developer as being outside the proceeding’s scope. FERC said the protest did not rebut MRES’ application by showing factors unique to individual QFs, such as operational characteristics and transmission limitations that prevent them from having nondiscriminatory access to markets.

Tri-County CEO Loses Bid to Serve on 2 Boards

The commission denied a rehearing request from a utility CEO prohibited from serving on the boards of directors for both South Central MCN and Golden Spread Electric Cooperative (ID-8117).

SPP FERC Tri-County Electric Cooperative — Tri-County CEO Zac Perkins | *Tri-County*

FERC denied Zac Perkins, who has served as Tri-County Electric Cooperative’s CEO since May 2016, from holding the interlocking positions in April 2017. He claimed a position on the Golden Spread board by virtue of being a CEO at one of its distribution co-op members, and he said a long-term agreement between South Central and Tri-County entitled him to serve as the co-op’s designated board member with South Central.

The commission said it “generally disfavors” interlocks between two or more unaffiliated public utilities, and that Perkins’ justifications did not distinguish themselves from Federal Power Act’s rules intended to curb corporate relationships.

Perkins said FERC did not satisfactorily explain why its findings were appropriate and did not substantively address the arguments in his application. He said no public or private interests would be adversely affected by his holding interlocking board positions.

The commission disagreed, saying his arguments did not overcome its “well-documented concerns” about interlocks among unaffiliated public utilities and the “arm’s-length bargaining process” that could adversely affect competition and consumers.

Both South Central and Golden Spread are SPP members.

— Tom Kleckner

February 6, 2018

NYISO Management Committee Briefs; Jan. 31, 2018

RENSSELAER, N.Y. — Soaring natural gas prices, customer satisfaction and credit requirements were all on the agenda during a meeting of NYISO’s Management Committee on Wednesday.

The committee also approved several measures recommended by the ISO’s Business Issues Committee, including modifying price correction deadlines to use business rather than calendar days in the period calculation, and changing the Tariff to recover costs related to acquiring solar forecasts for front-of-the-meter, utility-scale solar facilities in New York. (See NYISO Business Issues Committee Briefs: Jan. 17, 2018.)

Cold Snap Spikes Natural Gas Prices 1,374%

This winter’s cold snap saw New York City’s Transco Zone 6 natural gas prices surge to an average $47.34/MMBtu during a 13-day period, a 1,374% increase over the average for the period in December before the deep freeze hit on Christmas Day.

But grid operations were largely unhindered by the price jump, according to NYISO Vice President of Operations Wes Yeomans, who presented a cold weather operations report to the committee.

credit requirements natural gas prices NYISO — | *NYISO*

“Transmission was really excellent this time around, and transmission owners rescheduled maintenance outages to after the cold snap,” Yeomans said. “The two Ramapo [phase angle regulators] really provided value. We saw full utilization of the 500-kV line, which definitely wouldn’t have been possible without the replacement of the second PAR last fall.”

Yeomans noted that the Central East interface was the primary binding constraint — as predicted in the ISO’s winter preparedness report. Load-weighted electric locational-based marginal prices averaged $135.96/MWh during the cold snap, a 297% increase over December’s pre-Christmas average of $34.27/MWh. Power prices did not increase in line with gas prices because NYISO market systems selected lower-cost resources, primarily dual-fuel units capable of operating on lower-cost oil.

The recent cold snap differed from the January 2014 polar vortex in occurring over 13 consecutive days rather than spread over a month of fluctuating temperatures, Yeomans said. New York City went two weeks with temperatures never rising above freezing, but interstate and local delivery company gas pipelines all remained in service.

The period of extreme cold ended with a Jan. 4-6 blizzard that “originated in Florida, which is hard to believe, but that’s what the weatherman said,” Yeomans said.

NYISO’s load peaked at 25,081 MW on Jan. 5, exceeding the seasonal forecast of 24,365 MW but falling short of the high of 25,738 MW recorded in January 2014. Hydro-Québec registered a new all-time peak of 39,710 MW on Jan. 6, Yeomans said, noting that Montreal relies heavily on electric baseboard heating.

FERC early last month granted NYISO’s request to waive incremental energy offer caps for Jan. 4 through Feb. 8, allowing generators to recover minimum costs in excess of $1,000/MWh. As of Jan. 24, the ISO had not received any such cost recovery requests, Yeomans said. (See FERC Grants NYISO ‘Cold Snap’ Offer Cap Waiver.)

Customer Satisfaction and Performance Assessment

Don Levy, director of the Siena College Research Institute, presented a full-year 2017 survey of customer satisfaction and assessment of NYISO performance showing respondents are satisfied overall with the ISO.

NYISO has now completed two full cycles of the program, with about 27% of market participants responding to the survey, Levy said.

“I’d love to get up to a full third, and would be doing cartwheels if we got to 35%, but the participation we get is a statistically significant response. When we did it monthly, the fatigue was palpable,” Levy said. The new method entails surveying market participants twice a year.

The satisfaction survey comprises three platforms: a customer inquiry survey, a market participant survey and a CEO strategic outreach survey. An “assessment of performance” combines the CEO survey and the performance portions of the market participant surveys, which have stayed consistent throughout the year.

Respondents said they liked the professionalism of NYISO personnel and saw the ISO and its procedures as fair and efficient, but the results suggested the ISO could improve on how it explains policies and procedures and how it conducts long-term planning for New York’s electric power system.

Projected True-Up Exposure Enhancement

The Management Committee approved changes to the ISO’s credit requirements implemented in February 2015 after the 2014 polar vortex. The changes, recommended earlier in the month by the BIC, are slated to be deployed in June following approval by the board in April and FERC in May.

Corporate Credit Manager Sheri Prevratil presented the proposed filing under Section 205 of the Federal Power Act, which would revise Attachment K of the Tariff.

Under the current methodology, NYISO calculates the projected true-up exposure credit requirement for all market participants in the energy and ancillary services markets. A market participant is required to post credit support in the amount of its projected true-up exposure if its four-month true-up shows an average credit exposure greater than 10% of the initial settlement, or if the participant is no longer active in the markets but will still be subject to unsettled true-up obligations.

The alternate methodology would still retain the 10% trigger and require market participants to post credit support in the amount of the projected true-up exposure, but it would simplify the method for calculating the true-up to better align the credit requirement with market risk.

— Michael Kuser

February 4, 2018

FERC Orders Review of PJM, MISO, SPP Generator Studies

By Rich Heidorn Jr.

FERC on Friday ordered a technical conference on how PJM, MISO and SPP coordinate generator interconnection studies on projects near their seams, saying their practices may not be just and reasonable.

The commission called the conference to address issues raised in an October complaint by EDF Renewable Energy, which contends that inconsistencies and a lack of clarity in the RTOs’ rules for “affected systems” interferes with developers’ ability to judge the commercial viability of proposed projects (EL18-26).

MISO SPP gas-electric coordination pjm — EDF Renewable Energy’s 200-MW Red Pine Wind Project in Minnesota began operating in January | *EDF Renewable Energy*

FERC Order 2003 requires a transmission provider to coordinate interconnection studies and planning meetings with affected systems — electric systems other than the host transmission provider that may be affected by a proposed interconnection.

EDF complained that the RTOs’ tariffs and the MISO-SPP and MISO-PJM joint operating agreements lack detail regarding: the timing of affected system analyses; the standards applied to determine impacts from proposed interconnections; and how network upgrade costs are assigned.

The company said the lack of clarity regarding the RTOs’ study delivery requirements and modeling standards violates the commission’s requirement for transparent open access interconnection service and its purpose for establishing pro forma interconnection processes.

The commission rejected the RTOs’ requests to dismiss the complaint, saying their “tariffs and JOAs do not fully explain the guidelines and timelines that the RTOs use to coordinate with affected system RTOs during the interconnection process.”

It noted that the MISO-SPP and MISO-PJM JOAs require SPP and PJM to provide MISO with affected system results twice a year — in conflict with MISO’s Tariff, which requires four to five system impact studies, including affected system results, each year, per sub-region.

EDF cited several problems it said have resulted:

The timing mismatch delayed MISO’s system impact studies for its February 2016 West, February 2016 East and August 2016 Central interconnection study groups; MISO will not receive affected system information from PJM for its August 2016 Central study group until this month.
Affected system data were provided late to generation being studied in the PJM queue.
Affected systems information sent to MISO from SPP erroneously included a $38 million affected system network upgrade to be assessed to generation projects in the MISO February 2016 West study group, although the line SPP listed had already been included in its Integrated Transmission Plan.

The company also said it is unclear whether MISO and SPP are using the same base case models for their studies and that there is no clarity over the process the three RTOs use to assign network upgrade costs for interconnection projects located near their seams.

In the MISO February 2016 West study process, for example, EDF said SPP’s 2016 study of new generation near its MISO seam (SPP DISIS 2016-1) identified network upgrades near the Cooper South constraint in SPP.

SPP’s studies were completed before the MISO February 2016 West studies began, yet the MISO February 2016 West SIS included SPP affected systems costs of $311 million for a new line to upgrade the Cooper South constraint. EDF said the RTOs inappropriately shifted costs for upgrades identified in the SPP study from generation locating within SPP to generation locating within MISO.

The commission ruled that EDF had provided sufficient evidence that the lack of transparency and clarity may result in “inappropriate affected system network upgrade costs; a lack of information necessary to accurately estimate the cost of interconnection service; and delayed interconnection study results.”

The commission also rejected the RTOs’ request to dismiss EDF’s complaint as duplicative of the commission’s December 2016 Notice of Proposed Rulemaking on its pro forma large generator interconnection rules (RM17-8). The commission said EDF’s complaint raised issues specific to the MISO, SPP and PJM tariffs and JOAs that were not raised in the NOPR. (See FERC Proposes Changes to Interconnection Rules.)

“We find that a technical conference is an appropriate vehicle to develop a more complete record concerning these issues and the specific reforms proposed by EDF in the complaint,” FERC said. “We note that commission staff at the technical conference will also consider issues related to affected systems coordination that were raised in response to the Generator Interconnection NOPR. We find that holding a joint technical conference on affected systems issues identified both in this complaint and in the Generator Interconnection NOPR will offer the commission and interested parties the opportunity to consider specific reforms in MISO, SPP and PJM at the same time as more generic reforms.”

FERC said it expects to issue a ruling within 12 months of the technical conference.

Chairman Kevin McIntyre did not participate in the ruling.

February 4, 2018

CAISO Overhauling CRR Auctions

By Jason Fordney

CAISO last week unveiled a plan to restructure its congestion revenue rights auction to address long-running complaints that the process has saddled California electricity ratepayers with more than $500 million in excess costs over the past five years.

The debate over CRRs has pitted the ISO’s Department of Market Monitoring against the interests of financial traders, which the department says are the biggest beneficiaries of the current CRR market design.

The department has previously called on CAISO to disband the auctions and replace them with a bilateral market for forward contracts-for-differences, and it is becoming increasingly public about its opposition. (See CAISO Monitor Proposes to End Revenue Rights Auction.)

CAISO CRR congestion revenue rights — Eric Hildebrandt, Director of CAISO’s DMM, insists that the current CRR auction process must change | © *RTO Insider*

“We have stopped beating around the bush when we speak publicly about the auction,” DMM Group Manager Ryan Kurlinski said at a Feb. 2 meeting of the CAISO Market Surveillance Committee, at which the ISO introduced its proposal. He added that the problems are also present in other RTOs. (See Role, Value of Financial Trading Debated by OPSI Panel.)

CAISO last May said it needed to undertake a detailed study of the CRR process before dealing with the issue. (See CAISO: Analysis Needed Before Reforms on CRR Auctions.)

The department, headed by Eric Hildebrandt, is adamant that the CRR auctions are bad for consumers, and on Friday provided the MSC with eight sets of comments, white papers and presentations it has published on the matter. A presentation by the Monitor described “the myth” and “stories” advanced by proponents of the current auction structure.

Proposal Restricts CRR Auctions

While CAISO is still refining the details of a draft proposal it plans to issue this week, its own presentation to the MSC laid out a two-track approach to tackling CRR auction reforms. The first track would consist of “stopgap” measures to be developed in time to be submitted to the Board of Governors for approval in March. The second would be a more extensive set of changes submitted to the board in the middle of the year.

CAISO BRA CRRs Clean Power Plan — CRR auction revenues and payments, 2012-2017 | *CAISO*

The ISO is proposing to restrict the allowable sources and sinks of CRR transactions to only those pairs that are needed to hedge the physical delivery of energy. Currently, there is no such limitation and market participants can purchase any pair of CRRs, such as between generators or load aggregation points, CAISO noted in its presentation.

The proposal would limit source and sink pairs of CRR transactions to nodes between generators and interties, as well as between trading hubs, loads and interties. The purpose: to align the auction with hedging of physical energy delivery and increase the competitiveness of the auction.

CAISO has also proposed to decrease the amount of system capacity released in the CRR auction process from 60% to 40% in the long-term allocation, and 75% to 45% for the annual allocation and auction process — a move intended to reduce overselling of transmission capacity. The ISO would also eliminate disclosure of certain modeling information and align existing outage reporting rules with the annual CRR process.

Traders Question CRR Changes

Speaking for the Western Power Trading Forum, Ellen Wolfe of Resero Consulting said the ISO had not properly explained how the proposal would address its stated problems. For example, the DMM had identified low participation as one of its concerns about the auction, but the proposal to restrict auction parameters would possibly exacerbate that, she said.

“You are taking precision out of the auction, supposedly for some benefit,” Wolfe said, adding that the MSC should help determine whether the proposal would actually solve the problems. “In a way, you are kind of dumbing down the functionality to prevent something that is not perfectly articulated yet,” she said.

MSC member Scott Harvey, of FTI Consulting, replied that “we are interested in facilitating hedging. We are not trying to force people to buy risky financial instruments at a discount and price them that way.

“We need to understand what type of hedging activity would be infeasible in this approach” and then address any issues in the proposal, he said.

CAISO said it will issue the draft proposal on Feb. 7 and has scheduled a Feb. 13 meeting for market participants to weigh in.

February 4, 2018

Sempra, Oncor Reach Agreement with Texas Intervenors

By Tom Kleckner

Sempra Energy and Oncor have reached a settlement with all parties involved in Sempra’s proposed $9.45 billion acquisition of Energy Future Holdings, the two companies said Thursday.

The companies said Texas Legal Services Center (TLSC) has joined nine other intervenors in resolving all issues in the proceeding before the Public Utility Commission of Texas, with Oncor filing a request that the commission cancel a scheduled Feb. 21 hearing on the merits of its acquisition (Docket 47675). (See Sempra, Oncor Reach Deal with Texas Stakeholders.)

ERCOT Oncor Sempra Energy — Oncor’s Dallas headquarters | © *RTO Insider*

“The revised stipulation has the unanimous support of commission staff and the nine intervening parties, and there are no outstanding requests for a hearing,” Oncor said. The company asked that the settlement agreement be presented to the PUC for consideration “as soon as reasonably practicable.”

TLSC, a nonprofit law firm that provides free legal representation and advice to low-income persons and Medicare recipients, had opposed the acquisition because the electric rates of low-income consumers “may be adversely affected.” The firm had filed a brief two days before the agreement was reached, responding to joint objections by the companies and a motion to strike the testimony of its key witness.

FERC ERCOT Oncor Sempra Energy — Sempra CEO Debbie Reed | *Sempra Energy*

Sempra CEO Debra Reed said gaining unanimous stakeholder support “represents an important milestone for our proposed acquisition.”

“We and many others in our state believe that Sempra Energy will be a great partner for Texas,” Oncor CEO Bob Shapard said.

Besides TLSC and PUC staff, the other intervenors include: the Office of Public Utility Counsel; Steering Committee of Cities Served by Oncor; Texas Industrial Energy Consumers; Energy Freedom Coalition of America; Golden Spread Electric Cooperative; Nucor Steel; the Alliance for Retail Markets; and the Texas Energy Association for Marketers.

EFH, which declared bankruptcy in 2014, holds an indirect 80% interest in Oncor. Hunt Consolidated, NextEra Energy and Berkshire Hathaway Energy have all come up short in previous attempts to acquire Oncor, the largest electric utility in Texas.

San Diego-based Sempra announced its intentions to acquire EFH last August, and received approval from the U.S. Bankruptcy Court for the District of Delaware in September. FERC gave its approval for the acquisition in December, but the transaction remains subject to further approvals by the bankruptcy court and the PUC.

February 4, 2018

Patriots Drive Unique Super Bowl Load Spikes

By Michael Kuser

It seems that New England’s grid reacts just as excitedly as the region’s fans when the Patriots play for the NFL championship.

On Thursday, ISO-NE’s newsletter, Newswire, featured a timely article about the Patriots’ ninth Super Bowl appearance last year, which saw the team come from behind in a dramatic overtime win.

As the game moved into overtime, grid operators saw demand suddenly level off and then inch back up. At times, demand increased by as much as 50 MW during overtime, the RTO said.

“We can definitely see the demand changes on the system, in real time, by what’s happening in the Super Bowl,” said John Norden, the RTO’s director of operations. “Whether it’s the beginning of the game, halftime or the end of the game, we can see changes in levels of consumer demand. Understanding what is going on in real time, from a societal level, is very important to us, and we monitor that from our control room.”

Sounds like someone has a very good excuse to watch the big game on company time.

ISO-NE has had plenty of chances to study the “Patriots effect” — and ran a similar analysis prior to last year’s Super Bowl.

ISO-NE super bowl patriots effects — | *ISO-NE*

The RTO is not alone in its interest in the topic. Matt Chester, an energy and policy professional in D.C., posted a Jan. 31 blog piece analyzing electric power usage data during the last five Super Bowls showing that “versus a typical Sunday afternoon/evening in the winter, home power usage was 5% lower during the Super Bowl, with big consequences for overall energy use.”

ISO-NE said Super Bowl load curves have formed consistent patterns over the years, with upticks in demand coinciding with halftime, commercials and the end of the game. These mini spikes occur when millions of people all choose the same moment to open their refrigerators, use microwave ovens and flush toilets. Many homes in New England use wells, and any use of water triggers an electric pump.

For its part, PJM showed its support of the underdog Philadelphia Eagles by posting photos of pregame festivities on Twitter. It also promoted its new PJM Now mobile app for tracking the load curve and LMPs in real time during the game.

February 4, 2018

CAISO, Stakeholders Debate RMR Revisions

By Jason Fordney

FOLSOM, Calif. — Current flashpoints over grid reliability, market outcomes and ratepayer costs were on full display last week at a CAISO forum to discuss how the grid operator should overhaul its backstop procurement policies.

Representatives of generators, power traders and the California Public Utilities Commission are raising questions about the scope of an overhaul CAISO outlined in a straw proposal for its reliability-must-run (RMR) and capacity procurement mechanism (CPM) programs. While the ISO is saying changes for 2019 will only address must-offer requirements, most stakeholders contend it should move more quickly to make broader changes.

CAISO RMR — CAISO held a January 30 workshop on RMR/CPM revisions | © *RTO Insider*

The ISO is in Phase 1 of the 2018 “RPM/CPM” initiative, saying it needs to get certain changes in place quickly before more fundamental changes are made in a future Phase 2. (See CAISO Floats Reliability Programs Revamp.) Phase 2 will include development of a cohesive RMR/CPM framework and a possible merging of the programs.

CAISO has already filed with FERC a set of updates to CPM that was approved by the Board of Governors in November. (See Board Decisions Highlight CAISO Market Problems.) The ISO’s Keith Johnson said that set of changes will not be modified in the current process but will be informed by it.

“We are not changing the filing as a result of this process,” Johnson said. CAISO’s filing of the CPM changes at FERC is due to be approved later this year, when the new package of enhancements will still be in the proposal stage.

But some at the forum pushed back at Johnson, saying that there seems to be more fundamental issues with the RMR programs, which are unpopular in the market. Two developing debates are whether RMR and CPM units should have a must-offer requirement, and whether settlement terms requiring a broad look at CPM have been triggered.

“We would agree that perhaps there are some things that should be addressed,” Johnson said as forum participants raised various issues, adding that they could consist of clarifications or more substantial changes. He pointed out that the current RMR provisions took years to develop. “I can imagine we will get all kinds of comments as to where we should take this initiative.”

The RMR and CPM have different designs and provisions and are used to keep generators online that want to retire but are still needed for reliability. Misalignments between RMR, CPM and the CPUC’s resource adequacy (RA) programs are creating reliability gaps that are costing consumers and creating tensions in the market.

But utilities such as Pacific Gas and Electric object to the hastily forged RMR agreements and their increasing usage. The ISO signed up 687 MW of Calpine generation to RMRs in 2017, including the 593-MW Metcalf Energy Center and the Yuba City and Feather River gas plants, each with 47 MW of capacity.

CPUC Staff, WPTF Disagree on Must-Offer

The ISO has proposed that Phase 1 explore whether resources under both of the RMR designations — condition 1 and condition 2 — be subject to a must-offer requirement. CAISO’s Department of Market Monitoring has recommended the measure because the condition 2 units are kept online by ratepayers but only used in certain hours.

During the forum, Resero Consulting’s Carrie Bentley, representing the Western Power Trading Forum (WPTF) debated with CPUC staff member Michele Kito over whether generators being paid to supply capacity should be subject to a must-offer obligation in the energy market. WPTF argues that the payments drive down LMPs, reducing incentives to build new generation or keep existing plants online, while the CPUC contends that units kept online 24/7 by ratepayers should be utilized more.

Bentley told RTO Insider that “WPTF believes that requiring 24/7 at-cost offers into the energy market is a means of subsidizing the fixed costs of the RMR resource on the backs on other generators. Forcing in at-cost energy into a market setting will unnecessarily distort prices downward in an already struggling ancillary service and energy market.”

Settlement Provisions Triggered?

Kito also contended that recent actions by CAISO had triggered a provision in a 2014 CPM settlement agreement that requires the ISO to open a stakeholder process to ensure that load-serving entities are not relying on the CPM as a means to meet RA obligations. Section 7 of that agreement stipulates the ISO will open the process “with the first occurrence of use of CPM by an LSE for either an annual or monthly LSE deficiency to meet 50% or more of the LSE’s RA obligation for the annual or monthly period.”

It wasn’t immediately clear what LSE Kito was referring to, and she did not return a follow up email. CAISO in November announced 2018 CPM designations for 1,055 MW of capacity in the PG&E and San Diego Gas & Electric areas. In November, CAISO said LSEs were about 2,000 MW short of local RA requirements for 2018. (See California Utilities Short on Local RA Capacity.)

“I didn’t realize that the conditions of the settlement had been triggered, at least arguably,” said Mark Smith, Calpine vice president of regulatory affairs. He told Johnson that “the scope of Phase 2 could be dramatically larger than what you have said here.”

Smith added that “the whole structure is in question. We have a clean slate, I think is what I’m hearing could occur here.”

PG&E representative Peter Griffiths asked whether the changes in the RMR process are in the scope of Phase 1, adding that he would be “concerned” if they aren’t.

“The history that the ISO has with the latest RMRs leaves a lot to be desired,” Griffiths said, noting that the process could be changed without changing the ISO’s Tariff. “If it is not going to be discussed in this stakeholder process, I would like to know that, because there are other grounds by which the process could be changed.”

Throughout the forum, Johnson advised that the scope of Phase 1 will be limited and will apply to new RMR units as of Jan. 1, 2019. The ISO is taking comments on the straw proposal through Feb. 20 and hoping for approval of Phase 1 by the board in May.

February 4, 2018

MISO Touts $3 Billion in 2017 Savings

By Amanda Durish Cook

MISO says it saved its members upward of $3 billion last year, but some stakeholders are questioning whether the RTO is overstating some of the benefits it provides.

The grid operator last week released a 2017 Value Proposition study showing that its members reaped net benefits ranging from $3 billion to $3.7 billion over the year, after accounting for the RTO’s $278 million in operating costs.

MISO estimates overall benefits increased by $366 million, or 12%, when compared to 2016, when the benefit ranged from $2.6 billion to $3.3 billion.

“Again in 2017, our value proposition demonstrates the value members receive through improved reliability, market efficiencies and footprint and resource diversity,” CEO John Bear said in a statement.

During a Jan. 31 special conference call, RTO staff said the value propositions represent a range of savings because of the many variables in estimating total savings.

“An exact benefit for each of these would be extremely difficult to pinpoint,” business adviser Leonard Ashley said. The RTO excludes savings that are difficult to quantify, including energy price transparency and seams management efforts with other balancing authorities.

MISO estimates that it has provided about $20.8 billion worth of cumulative net benefits since 2007.

“Our work helps members evaluate the impact of environmental regulations, improve coordination with neighboring systems and develop new products and services to adjust to a transitioning grid,” said Wayne Schug, vice president of strategy and business development.

Ashley said the MISO South region experienced “meaningful benefit” throughout 2017, with RTO membership providing Entergy and other generators anywhere from $800 million to $900 million, accounting for $67 million in region-specific operating costs. South’s benefit increased $60 million, or 3%, over the previous year, according to MISO.

Ashley said those amounts are better than MISO’s 2013 projections, prepared when Entergy was in the process of integrating into the RTO.

Indiana Utility Regulatory Commission staffer Dave Johnston asked if MISO has ever performed a study evaluating the administrative costs for Midwest members since the addition of South. He said he remembered the RTO promising to reduce costs for its Midwest membership during a 2011 meeting. Staff responded that they might conduct more research to isolate those costs.

Show Me the Benefits

MISO attempted to break down exactly what factors contributed to the $3 billion-plus in benefits.

In terms of increased transmission availability and reliability, the RTO estimated it saved its membership $234 million to $261 million last year through avoidance of blackouts. Each likely saved megawatt was valued between $11,000 and $13,000.

MISO touted that its centralized dispatch system and modeling software resulted in a cost savings between $229 million and $259 million from improved unit commitment among the RTO’s 30 balancing authorities.

Use of the RTO’s ancillary service market reduced regulation needs by 1,162 MW, resulting in a $53 million to $58 million in savings. Ashley said each single megawatt decrease equated to about $40,000 in savings.

MISO also said its control of spinning reserves saved local balancing authorities $25 million to $27 million, compared with what BAs would have spent carrying their own reserves. Ashley said the use of spinning reserves resulted in a 530-MW reduction, with each megawatt worth $45,000 to $50,000 in production costs.

Northern Indiana Public Service Co.’s Bill SeDoris asked if MISO might be inflating the benefit of centralized spinning and contingency reserves, as many local balancing authorities had already engaged one another in a reserve sharing group prior to MISO’s creation.

Ashley said MISO could look into that, but he warned it is often difficult to unearth statistics on such collaborative efforts among utilities before the RTO’s creation.

“A footnote on the facts of life before MISO would be appreciated, so it doesn’t look like you’re trying to take credit for something you shouldn’t,” Indianapolis Power and Light’s Lin Franks added.

MISO also monetized a wind integration benefit, derived from its studies to model and pinpoint the most economic placement of wind generation to meet state renewable goals. The RTO said its economic studies avoided the construction of 9,300 MW of excess wind generation, preventing $348 million to $413 million in additional spending.

The RTO also estimated it saved members about $104 million to $132 million in compliance work throughout 2017 based on the average compliance needs for its small, medium and large generators. MISO keeps pace with about 4,000 Tariff requirements and 1,000 NERC requirements.

Customized Energy Solutions’ Ted Kuhn asked MISO to consider balancing those compliance cost savings with the money and man-hours member companies spend to attend stakeholder meetings and follow the RTO’s FERC filings. Kuhn said several members have hired dedicated employees to monitor and report on MISO’s activities and projects.

“We do have a cost of engagement,” Franks said. “You might want to talk with stakeholders to get an idea of how much is spent. … In our case, we actually hired people.”

Footprint Diversity

MISO said the single biggest financial benefit from membership stems from the RTO’s footprint diversity, which enables load-serving entities to carry just enough supply to meet its peak one-day-in-10 standard, instead of the peak estimates for each balancing area, saving customers $2 billion to $2.5 billion in avoided costs for building new generation.

Using the avoided costs of building an average combustion generator, MISO valued each avoided megawatt at $13,200 to $15,200. If LSEs went it alone, MISO estimated that they would have to carry an average 22.15% planning reserve margin instead of the 15.8% requirement the RTO used in 2017.

But some stakeholders again asked if MISO’s footprint benefit was based on the assumption that each utility would function as a complete island, rather than considering the pre-MISO tendency to share resources. Wisconsin Public Service’s Chris Plante said that prior to MISO’s formation, some utilities created planning reserve sharing programs to create some measure of peaking diversity.

MISO also estimated $135 million to $142 million in benefits for members through generator availability improvements in a networked system versus LSEs going it alone, based on the value of deferred generation construction. The RTO said last year it delayed the need for 882 MW of new capacity.

Franks asked if MISO’s estimates accounted for the RTO’s more nuanced dispatch method, which calls for increased stops and starts that increase wear on generators — and for the monetary penalties that unit owners incur for not responding to dispatch instruction.

“There are some downsides to this increased performance. We’ve always been ready to provide generation. With this so-called generator availability improvement comes some wear and tear on the generator,” Franks said.

MISO staff promised to consider factoring maintenance costs and penalties into the benefit calculation.

Finally, MISO said its demand response management efforts yielded anywhere from $97 million to $163 million in savings.