Page 1164 – RTO Insider

November 26, 2019

ERCOT Technical Advisory Committee Briefs: Nov. 20, 2019

AUSTIN, Texas — ERCOT staff last week told the Technical Advisory Committee that they will be reviewing and improving their market pricing processes as they bring price-correction issues to the Board of Directors in December.

ERCOT will be asking the board for permission to correct real-time and day-ahead prices for three weeks’ worth of operating days, accumulated following several software issues that led to pricing errors over three different time periods. Staff can revise pricing errors if they are caught within two business days of the operating day but must otherwise go to the board to correct the mistakes.

Kenan Ögelman, ERCOT’s vice president of commercial operations, told the committee during its meeting Wednesday that the grid operator is intent on improving the quality and delivery of its services.

“I don’t find these kinds of [market] outcomes acceptable relative to the disruption it causes,” he said. “We really want to go through our processes and … review our end of it.”

The pricing errors have resulted in resettled amounts as large as $123,000 and as small as $4, according to ERCOT’s preliminary data.

“I don’t know what ‘significant’ is, but I think I know what it isn’t,” said Morgan Stanley’s Clayton Greer, jerking his thumb at a slide filled with double-figured numbers.

Ögelman agreed with Greer. He said he would propose to the board that staff “look at making some cuts on significance” and see what the directors say.

“We have to do this work anyway to determine what the magnitude is,” he said. “There might have to be some better definitions.”

ERCOT’s Kenan Ögelman (left) explains numbers behind price corrections as Clif Lange, South Texas Electric Cooperative, listens. | © *RTO Insider*

Staff told the TAC in October it would be taking the Sept. 16-23 day-ahead operating days’ prices to the board for its review after mistakes in modeling outages. ERCOT then issued a market notice on Oct. 24, saying that an update to the energy and market management system led to incorrect real-time prices for certain settlement points and energy-metered prices, requiring another board review for the Oct. 16-20 operating days. (See “ERCOT Likely to Reprice 13 Operating Days,” ERCOT Technical Advisory Committee Briefs: Oct. 23, 2019.)

In November, staff added another eight days to the pricing review when software intended to capture the list of electrical buses that are fully disconnected from the grid under a contingency incorrectly included additional buses between Oct. 22 and Nov. 6.

ERCOT has said it will begin resettling prices about a week after the Dec. 10 board meeting.

Staff, Stakeholders to Study Summer Issues

Ögelman and committee members divvied up a list of issues for further discussion following another summer of slim reserve margins and record demand.

“There are legitimate needs to discuss a lot of these items,” Ögelman said, imploring the TAC to help make the assignments.

Most of the issues will be taken up by the committee’s Reliability and Operations and Wholesale Market subcommittees. Topping the list was the use of switchable generation resources (SWGRs), units that participate in both ERCOT and its RTO neighbors and which Ögelman said are not “working exactly as intended.”

The subcommittees will ensure the SWGRs’ settlement, operator interactions and offers align with the Protocols and intended market design. The two subcommittees will also look at the use of emergency response service and whether it can be self-deployed.

“Would ERCOT be willing to put in the Protocols that self-deployment is allowed for these resources?” Reliant Energy Retail Services’ Bill Barnes asked. “If this is behavior you want to allow, maybe it should be in the Protocols.”

Calling it a “fair question,” Ögelman said he owed stakeholders an answer.

Other issues include:

the use of operating condition notices;
evaluation of the Texas Commission on Environmental Quality’s enforcement-discretion process;
the summer demand response process; and
continued improvement of gas-electric coordination.

Comptroller to Waive QSEs’ Resale Cert Obligation

ERCOT legal staff shared with the TAC a l etter from the Texas Comptroller of Public Accounts that General Counsel Chad Seely said backed up his argument that electricity is tangible personal property and that qualified scheduling entities (QSEs) are required to provide resale certificates to the grid operator.

Teresa Bostick, the director of the comptroller’s tax policy division, said that under current law and policy, the QSEs are required to provide a valid resale certificate to ERCOT. However, she also noted that because “QSEs have no use for the electricity themselves and must sell it to another entity,” she would waive the requirement.

Seely said in an email to the committee that staff will work with the comptroller’s office to amend the Tax Administration Code and exempt QSEs from the certificate requirement. He thanked members for their feedback and “interest in this topic,” which resulted in vigorous stakeholder pushback during the TAC’s October meeting. (See “Stakeholders Push Back on Sales Tax Certifications,” ERCOT Technical Advisory Committee Briefs: Oct. 23, 2019.)

Senior Corporate Counsel Erika Kane, who bore the brunt of October’s heat, good naturedly accepted apologies from several TAC members.

“I feel I may have been a little harsh on you,” Barnes said, echoing others’ comments.

Staff also told members they are not proposing any changes to the methodologies, which rely on historic data, used to determine ancillary service quantities for 2020. Based on feedback from stakeholders, the ERCOT will compute responsive reserve service quantities with an updated resource contingency criteria of 2,805 MW.

TAC Endorses Storage, RTC Principles

The TAC unanimously endorsed the Battery Energy Storage Task Force’s first key topic/concept (KTC) recommendations as the principles that will be used in writing Nodal Protocol revision requests (NPRRs).

The task force reached consensus on all five KTCs. The documents recommend energy storage resources (ESRs) be treated like other short lead-time resources and security-constrained economic dispatched resources using nodal shift-factors and settled using nodal pricing when charging and discharging. The task force also determined the reliability unit commitment engine should evaluate ESRs based on the values in their current operating plans, reflecting their available capacity.

KTC 2: Physical responsive capability and operating reserve demand curve reserve.
KTC 3: ESR dispatch, pricing and mitigation.
KTC 4: Technical requirements.
KTC 6: ESR options to maintain desired level of state of charge.
KTC 10: ESR study and capacity assumptions changes.

Beth Garza, director of ERCOT’s Independent Market Monitor, waved off stakeholder concerns that KTC 6, which allows ESRs to submit energy offer curves immediately prior to the operating hour’s start, would lead to potential gaming.

“Personally, I’m willing to accommodate the widest range of behavior we can accommodate,” she said. “Battery owners shouldn’t expect free rein forever. We’ll be looking at their behavior in the first years. If there are problems, we will need to address them.”

The TAC also endorsed 11 additional key principle (KP) documents that will guide ERCOT’s real-time co-optimization (RTC) design. The committee will hear the Real-Time Co-optimization Task Force’s final group of principles during its January meeting:

KP 1.3 (8)c, (9), (12), (13): Outlines the key mechanisms and timelines for submitted ancillary service (AS) offers and the AS considered and awarded under RTC.
KP 2 (1)-(6): Analyzes any changes to RTC’s suite of AS products.
KP 5 (7): Identifies the AS virtual offers in the day-ahead market changes necessary to align their procurement with RTC’s implementation.

Members Approve Rio Grande Valley Hub

The committee approved the creation of a 138/345-kV trading hub for the Lower Rio Grande Valley that will allow additional trading liquidity and forward-price discovery in the area.

Staff and stakeholders’ review of NPRR941 indicated that it does not require changes to credit-monitoring activity. The NPRR’s cost ($250,000 to $350,000) is related to removing constraints that exist in the original system design.

Staff said work on the hub is not likely to go live until mid-2021.

The committee also approved three additional NPRRs and single revisions to the Planning Guide (PGRR), Retail Market Guide (RMGRR) and Verifiable Cost Manual (VCMRR).

NPRR 92 8: Defines “cybersecurity incident” and “cybersecurity contact,” classifying the former as protected information, and creates a form for notifying ERCOT of a cyber incident. The change also allows ERCOT to notify state or federal law enforcement of a cybersecurity incident and to notify market participants in order to mitigate further effects.
NPRR957: Establishes the terms “energy storage system” (ESS) and “energy storage resource” (ESR). ESS is the umbrella term for storage assets. ESRs are ESSes eligible to participate in SCED and/or provide AS. ESRs must be registered with ERCOT as both a generation resource and a controllable load resource.
NPRR9 72: Gives ERCOT the authority to decline to open a transaction-adjustment period for a congestion revenue right auction, even if the transactions submitted exceed the limit announced prior to the auction, as long as the number of transactions submitted does not exceed the number that can be processed by ERCOT’s systems.
PG RR 07 1: Updates the Planning Guide to align with N PRR 926, which removed the 90-day period between subsynchronous resonance study approval and initial synchronization and was approved by the board in June.
RMGR R 162: Clarifies the purpose and appropriate use of the safety-net move-in process for competitive retailers and revises the timing for submitting such a request.
VCMRR02 5: Removes the ESR definition from the manual, aligning it with NPRR957.

— Tom Kleckner

November 25, 2019

MISO Continues Honing Wind Forecasts

By Amanda Durish Cook

CARMEL, Ind. — Continuous improvement of MISO’s wind forecasting is more important than ever now that more than 90% of wind farms in the footprint rely on the RTO’s short-term predictions, officials said during a special conference call Thursday.

MISO Manager of Forecast Engineering Blagoy Borissov said the RTO will continue to refine its wind forecasting to make it “more transparent and more available.”

Forecast Engineer Cameron Saben said only about 8 to 9% of market participants still submit their own five-minute interval forecasts to MISO, a turnaround from a year ago when only a small amount of wind generators relied on the RTO’s forecasts. MISO’s short-term wind forecast is generated every five minutes for the next six hours.

“So far, we were in the background where we were used as the backup,” Senior Operational Forecast Engineer Dorsana Desai said.

MISO Wind — Fenton wind farm near Chandler, Minn.

Saben said more wind operators using MISO’s forecasts helps cull inaccurate information in their own forecasts.

“What we saw is bad inputs coming into MISO, which affected our ability to forecast,” said Saben, adding that market participants tended to forecast their output too optimistically, creating forecasts “on the high side.”

MISO has put more focus on improved wind forecasting for much of the year, ever since it misjudged output during a cold spell in January. At the time, the RTO lacked details on its wind generation’s ability to operate in extreme temperatures. (See MISO Looks to Get Better Read on Wind.)

Since its April workshop on the subject, MISO said it has improved its forecast by synching up wind forecast intervals with its five-minute market intervals and its dispatch system, allowing the RTO to factor more real-time market data into its wind forecasting.

“All of these process improvements might not have been that significant on their own, but taken together, they were more impactful than we expected,” Desai said.

Saben said MISO has also collected data on the cold-weather shutoff thresholds of nearly all its wind fleet.

“Our vendor is now using this to forecast more accurately,” Saben said.

MISO is working to anticipate extreme temperatures and weather events in forecasting. “All of these situations which were rare before are becoming more common,” she said.

The RTO is still considering a complete redesign of it short-term wind forecasting and is contemplating using either a recent performance-based or probabilistic forecast. It also reported that it’s still working through its own tendency to over-forecast wind output during ramp-down times.

“Because our capacity has grown, our wind forecast error has grown as well,” Saben said. But he said the improvements MISO has made over 2019 should reverse the trend.

Desai said MISO will develop forecast accuracy metrics and start sharing accuracy reports at its monthly Informational Forums.

Saben said during MISO’s all-time 16.3-GW wind record about 1 a.m. on March 15, wind generation served 25% of total MISO load.

“This is quite a large portion, and we expect to see this number grow,” he said.

MISO currently has about 220 wind farms totaling 20 GW and expects to see almost 29 GW by 2023. Over 2019, the RTO said its day-ahead wind production has increased by about 0.5 GW.

Desai said the goal is not perfection.

“Errors are going to persist. All we can do is reduce the magnitude of the errors,” Desai said.

MISO staff said they would continue to hold wind forecasting workshops over the next few years.

November 25, 2019

TerraForm Exempted from Certain PUHCA Rules

By Christen Smith

FERC on Thursday exempted TerraForm Power from certain requirements of the Public Utility Holding Company Act of 2005, ruling that it doesn’t need access to the renewable energy company’s accounting records, including that of its fuel cell subsidiaries.

However, TerraForm must still notify FERC of material changes regarding its acquisition of electric utility companies not also considered public utilities, the commission clarified in its order (EL19-94).

TerraForm, headquartered in New York City, indirectly manages an international portfolio of wind and solar projects, including distributed generation and behind-the-meter solar facilities. In its petition filed in August, the company said that each of its public utility subsidiaries hold qualifying facility (QF) or exempt wholesale generator (EWG) exclusions from PUHCA reporting requirements. Some of these holdings sell power on the wholesale market, subject to Federal Power Act regulations, while others “operate solar photovoltaic facilities that sell energy only at retail.”

Its fuel cell subsidiaries, however, cannot qualify as EWGs “because they will sell energy at retail to commercial and industrial customers under contracts negotiated with such customers,” thus their rates are not subject to the commission’s jurisdiction, TerraForm argued. FERC’s regulations also disqualify others from a QF exemption because they use natural gas as fuel. Finally, the company said, its affiliation with utilities that provide jurisdictional transmission service — Smoky Mountain Transmission and Wind Energy Transmission Texas — will also extend to its fuel cell subsidiaries, contradicting the commission’s longstanding policy on granting PUHCA exemptions.

FERC granted the exemption, saying that although the company is affiliated with transmission companies providing jurisdictional service, its fuel cell subsidiaries will “make only retail sales and do not have franchised service territories or captive customers.”

“Therefore, there is no significant potential for transmission service customers to subsidize commission-jurisdictional wholesale sales,” FERC wrote. “In addition, Smoky Mountain’s transmission facilities are subject to a commission-jurisdictional open access transmission tariff, and the commission has access to the books, accounts, memoranda and other records concerning Smoky Mountain’s jurisdictional transmission rates under Section 301 of the Federal Power Act. Finally, we note that granting the requested exemption will not change the commission’s oversight of those holding companies with direct or indirect ownership interests in Smoky Mountain and Wind Energy.”

But FERC denied TerraForm’s request to waive it from change-in-fact reporting requirements for the acquisition of nonpublic utilities after it unsuccessfully argued that such information is already submitted via the FERC-65 notice.

“While TerraForm is correct that the FERC-65 filing requirements serve an informational purpose, ‘the addition of a new subsidiary company that is a public utility company or holding company of a public utility company represents a material fact that should be reported to the commission,’” FERC wrote. “This requirement includes public utility companies that may not be public utilities under PUHCA 2005, such as new electric utility companies that are part of the TerraForm [holding companies’] retail operations.”

November 25, 2019

Slow Year for FERC Enforcement, Report Shows

By Michael Brooks

WASHINGTON — FERC’s Office of Enforcement opened 12 new investigations and negotiated two settlement agreements worth $14.4 million in civil penalties and disgorgements in fiscal year 2019, according to its latest annual report released last week.

The number of investigations represented a 50% drop from last year, while the number of settlements was four fewer than FY 2018.

The bulk of penalties and disgorgements this year came in May from Dominion Energy Virginia, which paid $14 million to settle allegations that it had manipulated PJM’s energy market to maximize its receipt of lost opportunity costs (LOCs) between April 2010 and March 2011 (IN19-3).

The RTO pays LOCs to combustion turbine units that clear its day-ahead market but end up not being committed in the real-time market. Enforcement found that Dominion intentionally discounted its incremental energy offers to obtain more day-ahead commitments but increased its start-up values in order to reduce the chance its units would be committed in the real-time market. FERC has dinged multiple PJM members for such a scheme; the RTO tightened its LOC rules in 2015 in order to discourage such behavior. (See PJM Members Committee Briefs: May 2015.)

Enforcement did see a slight increase in self-reports — 149 this year compared to 137 last year — but, as usual, “the vast majority of those self-reports were concluded without further enforcement action because there was no material harm,” it said.

The office’s annual reports always include examples of such self-reports, and it has been steadily adding examples of other activities that did not lead to investigations over the years, saying they “can be helpful to companies seeking to comply with the commission’s regulations and orders.” For example, in 2017, it included cases in which its Division of Analytics and Surveillance contacted market participants about potential violations. (See Investigations up Sharply in FY 2017, FERC Report Shows.)

In this year’s report, the office also included examples of the 16 referrals it received this year from RTO/ISO market monitors. Of those, 11 involved potential market manipulation, seven involved potential tariff violations and four involved misrepresentations prohibited by the commission’s market behavior rules. Three of the monitor referrals were the source of investigations opened this year. Though the report includes summaries of the alleged behavior, it does not reveal the identities of the members flagged by the monitors.

“This report highlights how the commission’s enforcement program has matured, how staff has increased efforts to engage in outreach and provide transparency to industry, and how we’ve improved our ability to detect market anomalies early,” FERC Chair Neil Chatterjee said at the commission’s open meeting Thursday.

In September, Chatterjee announced the commission had shifted several employees out of Enforcement and eliminated its Division of Energy Market Oversight. (See FERC Shuffles Enforcement Staff, Disbands DEMO.)

Disposition of investigations, FY 2019 | *FERC*

The move prompted a letter from several U.S. senators that expressed “concern over the apparent erosion of the vital role the Federal Energy Regulatory Commission plays in preventing fraud and manipulation in our nation’s energy and financial markets” (PL10-2 -003). The senators — four Democrats and independent Sen. Angus King (Maine) — also noted the commission’s rescission of Notices of Alleged Violations in May. (See FERC Ends Notices of Alleged Violations.)

At the September open meeting, Commissioner Richard Glick said he had no concerns with the division’s elimination, calling it “a simple matter of administrative efficiency.” In his remarks Thursday, Glick said he responded to the senators with three recommendations for legislation to improve the commission’s enforcement work:

Impose a duty of candor on FERC-jurisdictional financial traders. Glick said the commission had proposed such a requirement in 2015 but dropped it in July when it issued several new rules regarding market-based rate authority data requirements, a move he dissented on. (See “Connected Entity Info Tossed,” FERC Reduces MBRA Data Requirements.)
Clarify that FERC has the authority to ban recidivist market manipulators. “We see in several cases … that there’s entities and individual traders that engaged in manipulative acts, go to a different employer or form their own trading operation, and go on to continue to do the same thing again,” Glick said.
Require a vote by the entire commission on whether to terminate an Enforcement proceeding. Currently, the chairman can unilaterally end a probe at their discretion, something Chatterjee did in July in the case of alleged manipulation by Dynegy in MISO’s 2015/16 Planning Resource Auction. (See FERC Clears MISO 2015/16 Auction Results.)

November 25, 2019

NYISO Management Committee Briefs: Nov. 20, 2019

NYISO Business Issues Committee Briefs: Nov. 6, 2019.)

Thinh Nguyen, senior manager for interconnection projects, presented the proposed changes, which would hasten the class year portion of the interconnection study and also limit the potential for delays from some projects.

Nguyen said a key objective of the proposal is to identify system upgrade facilities for projects to reliably interconnect, including detailed design, engineering and construction estimates. It also seeks to produce binding, good-faith cost estimates that provide reasonable closure on upgrade costs, as well as equitable allocation of upgrade costs.

Matt Schwall, director of market policy and regulatory affairs for the Independent Power Producers of New York, thanked the ISO for providing a “thorough and well-run stakeholder process.”

Competitive Entry Exemptions

The committee also voted unanimously to recommend the board approve Tariff changes to competitive entry exemption (CEE) rules. The proposal would make CEE available to existing generators — called “examined facilities” — requesting additional capacity resource interconnection service (CRIS) megawatts in a manner consistent with the underlying rationale for the exemption. Those facilities are currently subject to the mitigation net cost of new entry offer floor.

Senior ICAP Mitigation Analyst Jonathan Newton presented the revisions to the CEE rules, which would also facilitate the repowering and replacement of existing generators by allowing existing portfolio owners that have entered into competitive short-term hedging contracts to qualify for the CEE.

The proposal also includes a change in the consequences for withdrawing a CEE request or providing false and misleading information.

NYISO intends to make the proposed rules effective for class year 2019 projects, Newton said. If the board approves the queue redesign proposals in December, the ISO anticipates making Federal Power Act Section 205 filings with FERC on or before Dec. 20, seeking a decision by the third week of February 2020.

New System Software by March

Chief Information Officer Doug Chapman said NYISO is working to deploy by February or early March a new energy management system (EMS) and business management system, both delayed last month because of problems related to both stability and synchronization of data. (See NYISO Management Committee Briefs: Oct. 30, 2019.)

“We expect to have the software in a completed state in mid-December, at which point we’ll resume the parallel testing, which we expect to be completed by mid-January,” Chapman said. “We’re targeting a cutover to EMS in the first week of March but want to be ready in case we can move sooner, in February, as we’re keen to begin testing new energy storage software.”

The testing is projected to take six months and will lead to deployment of the new software in September 2020. The deployment could potentially be moved to August — weather permitting — if detailed test planning results in a shorter test period than the projected six months.

Chapman noted that FERC “would throw a wrinkle in our schedule” if it directs NYISO to make changes to its Order 841 energy storage compliance proposal. The ISO has not yet received an order from the commission after submitting a May 1 letter in response to questions about its storage plan. It is the only RTO/ISO whose compliance filing has yet to be ruled on. (See related story, Storage Plans Clear FERC with Conditions.)

Grid Ready for Winter

NYISO expects to meet reliability criteria throughout the coming winter with projected capacity margins of 10,900 MW for 50-50 peak winter conditions and 9,299 MW for 90-10 conditions.

“While we are projecting 10,900 MW of surplus available installed capacity, the day-ahead market only commits and schedules sufficient capacity to meet the next-day peak load forecast plus the reserve requirement; hence we would not expect to have 10,900 MW of excess capacity in real-time operations,” said Vice President of Operations Wes Yeomans, who presented the winter capacity assessment. “The projected 10,900 MW of surplus installed capacity indicates more than sufficient capacity is available for the NYISO to schedule generation resources for cold-weather conditions.”

The ISO’s baseline forecast shows total capacity resources of 43,346 MW, minus assumed unavailable capacity of 5,703 MW, for net capacity resources of 37,643 MW to meet a total capacity requirement of 26,743 MW.

NYISO also models natural gas supply limitations scenarios and projects a 2,156-MW capacity margin for 90-10 peak winter conditions and loss of all gas supplies, and 4,067 MW for 90-10 peak winter conditions and retaining only units with firm gas supplies.

Existing minimum oil burn procedures defined by the New York State Reliability Council’s Reliability Rules and Compliance Manual establish fuel-switching requirements for certain generators at specific cold-weather thresholds to secure electric reliability for both New York City and Long Island gas pipeline contingencies.

Seasonal generator fuel surveys indicate oil-burning units have sufficient start-of-winter oil inventories along with arrangements for replacement fuel.

NYISO has performed on-site visits of generating stations to discuss past winter operations and preparations for the upcoming winter, Yeomans said.

— Michael Kuser

November 25, 2019

FERC Finds Partial Compliance on Order 845

By Tom Kleckner and Rich Heidorn Jr.

FERC ruled last week that six utilities have partially complied with the requirements of Orders 845 and 845-A, directing the companies to address their shortcomings within 60 days.

The commission approved Orders 845 and 845-A to increase the transparency and speed of the generator interconnection process. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

The commission last week ruled in compliance filings by:

Golden Spread Electric Cooperative (ER19-1900);
Tampa Electric Co. (ER19-1920, ER19-1920-001);
Cheyenne Light, Fuel & Power (ER19-1924);
Black Hills Colorado Electric (ER19-1925);
Black Hills Power (ER19-1926); and
Portland General Electric (ER19-1927; ER19-1927-001).

FERC found the utilities to have “generally” met the requirements of the orders. It evaluated the filings against 845’s and 845-A’s 10 reforms, grouped into three categories: improved certainty for interconnection customers; promoting more informed interconnection decisions; and process improvements.

The commission said the companies largely adopted its pro forma large generator interconnection procedures as is but failed to include some language that was required by Order 845.

Contingent Facilities

The commission also ordered several of the utilities, including Golden Spread, PGE, Black Hills Power and Cheyenne Light, to identify the “thresholds or criteria” they will use to identify “contingent” facilities — unbuilt interconnection facilities and network upgrades on which the interconnection request’s costs, timing and study findings are dependent.

“Without this information, an interconnection customer will not understand how [a utility] will evaluate potential contingent facilities to determine their relationship to an individual interconnection request,” FERC said.

FERC Order 845 — Gas turbine at Golden Spread’s Elk Station plant | GE

It also said Golden Spread’s surplus interconnection service proposal omitted language providing that the original interconnection customer, the surplus interconnection service customer and the transmission provider will agree to surplus interconnection service before it begins.

The commission also ordered PGE to add a 30-day deadline for it to conduct any studies needed to review an interconnection customer’s request to incorporate certain technological advancements to its interconnection request prior to the execution of a facilities study agreement, without risking the loss of their queue positions. The commission said PGE’s proposal to use “reasonable efforts” to meet the deadline failed to comply with Order 845.

FERC also faulted Golden Spread, saying it did not justify its proposal to accept technological change requests until the system impact study ended, rather than before a facilities study agreement’s execution.

November 25, 2019

FERC: NYPA Must Pay PJM for Tx Upgrades

By Christen Smith

FERC dismissed a complaint from the New York Power Authority last week that alleged it was not responsible for PJM’s upgrade charges incurred after one of its merchant transmission facilities relinquished firm transmission withdrawal rights (TWRs) (EL17-94).

The complaint dates to 2017, when FERC forced PJM to modify interconnection service agreements with Hudson Transmission Partners and Linden VFT to convert firm TWRs to non-firm, relieving the companies from hundreds of millions in costs under PJM’s Regional Transmission Expansion Plan. (See NJ Tx Operators Win Relief on Upgrade Costs.)

HTP owns a 660-MW, 345-kV underwater HVDC line that connects PJM in northern New Jersey and NYISO in New York City. FERC issued a show cause order after Public Service Electric and Gas rejected HTP’s request to convert 320 MW of firm TWRs to non-firm. (See Rejecting PJM ‘Wheel’-related Requests, FERC Sets Inquiry.)

Linden VFT, which operates three 105-MW variable frequency transformers between the PSE&G system and Consolidated Edison, also filed a complaint after PSE&G rejected its request to convert 330 MW of firm TWRs to non-firm.

The two merchant projects were part of a decades-old service agreement between PSE&G and Con Ed that the latter terminated in April 2017. The service “wheeled” 1,000 MW from upstate New York through PSE&G’s facilities in northern New Jersey and into New York City.

Hudson notified NYPA of the relinquishment of its TWRs with PJM on June 2, 2017, but the commission did not approve the change until Dec. 15 of that year. PJM continued to bill NYPA for RTEP upgrades between June and December — a practice that NYPA called “unjust and unreasonable.”

“Because Hudson (and therefore NYPA) held firm transmission withdrawal rights until Dec. 15, 2017, and received service pursuant to those firm transmission withdrawal rights, we find no basis to support NYPA’s contention that PJM should not invoice NYPA for the period prior to Dec. 15, 2017,” the commission wrote in its ruling Thursday.

In a related ruling, FERC dismissed a consolidated docket of proceedings that contested ever-changing cost allocations for the Bergen-Linden Corridor (EL15-67). State agencies in New York and New Jersey, as well as PJM transmission owners, requested rehearing of FERC’s decision to set the dispute for settlement judge procedures last year. (See FERC Rethinking DFAX for Stability Tx Projects.) The protesters argued that the commission should have given them a chance to comment on how the revisions to Hudson and Linden’s TWRs and the canceled wheeling agreement should impact cost allocation.

Settlement negotiations were terminated in July and the original rehearing requests were punted back to FERC. The commission dismissed the filings as “moot,” saying “the requests for rehearing do not challenge the commission’s authority to establish settlement judge procedures.”

November 25, 2019

FERC Affirms MISO-PJM Pseudo-tie Decisions

By Amanda Durish Cook

FERC last week dismissed a second round of complaints over overlapping pseudo-tie congestion charges between MISO and PJM, rejecting a call that the Midwestern RTO rework its solution and denying rehearing requests over its refund decision.

No MISO Solution Rejection

American Municipal Power had called for a retroactive rejection of the second phase of MISO’s solution to address overlapping congestion charges on pseudo-tied generation, arguing that the RTO failed to prove that all overlapping congestion charges had been resolved (ER19-34-003). The utility also said FERC’s acceptance of PJM’s second-phase solution was conditioned on an expectation that MISO would also develop a voluntary schedule-cutting mechanism like its eastern neighbor.

The RTOs in 2018 agreed to first make limited software changes to account for pseudo-tie transactions in their respective day-ahead markets, then filed separate second-phase solutions to eliminate double-charging. While PJM now provides rebates for deviations from day-ahead commitments and created a new transaction type to hedge exposure to financial risk, MISO added pseudo-tie transaction interchange schedules so pseudo-tied resources can use the day-ahead market to hedge against real-time congestion. (See FERC Approves MISO Pseudo-tie Proposal.)

Contrary to AMP’s claims, pseudo-tie double-charging has been wiped out, FERC said in its order Thursday.

The commission’s decision relied on reports from the RTOs. It said AMP failed to point out any specific Tariff changes in MISO’s second-phase solution that it believed was unreasonable. FERC also said it would not require MISO to restyle its hedging mechanism after PJM’s, noting that several types of hedging mechanisms could be just and reasonable.

The commission also pushed back on AMP’s contention that MISO promised to address any leftover overlap “through rebates or other means” even after the full solution was in place. FERC said neither RTO ever committed in filings to additional rebate mechanisms as part of their second-phase solutions.

FERC also expressed confusion about why AMP was calling for rebates at this point given that PJM now charges or credits congestion where pseudo-tie paths overlap between the RTOs.

The commission in October also rejected a trio of complaints from AMP over how the RTOs eliminated their overlapping congestion charges. The commission said their phased-in pseudo-tie solution did not constitute prohibited “piecemeal” ratemaking. (See MISO-PJM Pseudo-tie Fix Challenges Rejected.)

MISO PJM — PJM and MISO footprints | *MISO, PJM*

No Rehearing of Refund Decision

FERC also batted away several requests to rehear its May decision that ordered settlement proceedings to determine how much the RTOs must remit to address redundant congestion costs incurred from 2016 onward. (See Refund Hearing Ordered in Pseudo-Tie Complaint.)

The complainants — including Tilton Energy, AMP, Northern Illinois Municipal Power Agency and Dynegy — relied on a variety of arguments to seek rehearing.

FERC held firm that MISO didn’t violate its Tariff when it began using its financial schedules for pseudo-tied customers without prior approval. The commission said the RTO had the authority to assess congestion charges “in the absence of an explicit Tariff section that applied to the situation” (EL16-108-001).

The commission additionally found that PJM was not in violation of its Tariff for calculating congestion charges from nodal points inside the MISO footprint. The companies had argued that PJM overstepped its authority by reaching into MISO territory to calculate congestion.

“The fact remains that the PJM Tariff explicitly gives PJM the authority to utilize either the source nodal point or the MISO-PJM interface,” FERC said.

The commission also affirmed that only named complainants are entitled to whatever amount of congestion charge refunds stem from settlement. The Illinois Municipal Electric Agency interceded to argue that refunds should extend to everyone affected by the unjust and unreasonable charge — including itself.

“The commission has held that ‘allowing a third party to join in a complaint by filing comments would circumvent our public notice requirements and deprive the respondent of the opportunity to address the assertions of that third party,’” FERC said.

It also declined to extend its usual 15-month refund period as the companies had requested, saying they did not show that the RTOs were slow to act on complex solutions to the duplicative charges.

The commission repeated its stance that the separate administrative charges MISO and PJM assessed on pseudo-tied generation cannot be considered duplicative.

“By taking transmission service in both RTOs, complainants were causing administrative costs to be incurred by both RTOs,” the commission wrote.

Finally, the commission again denied AMP’s previously failed argument that MISO couldn’t guarantee that its phase two solution fully eliminated the double charging.

November 25, 2019

NERC Certifies SPP as RC Provider in West

NERC has certified SPP’s reliability coordination offering in the Western Interconnection, allowing the RTO to offer those services effective Dec. 3.

SPP said the certification, which it received Nov. 15, confirms it has the necessary tools, processes, training, procedures and personnel to operate as a RC in the West. (See “Staff Prepping for 2nd Certification Visit, Shadow Ops,” SPP Western Reliability Briefs: Week of Sept. 16, 2019.)

The RTO has agreements with 13 customers, representing about 12% of the Western Interconnection, which has been managed by Peak Reliability. Peak announced last year it would be going out of business by the end of 2019, opening the door to SPP and CAISO to provide RC services to its previous customers.

SPP has been a NERC-certified RC in the Eastern Interconnection since 1997, managing about 40 GW of load. Its RC service territory now extends from the Canadian border to the Texas Panhandle.

The RTO also plans to open a Western real-time market in 2021 as an alternative to CAISO’s Western Energy Imbalance Market. Five regional organizations are helping fund the market’s development. (See WAPA, Basin, Tri-State Sign up with SPP EIS.)

— Tom Kleckner

November 25, 2019

AEP Rejected on Ohio Renewable Projects

By Christen Smith

Regulators in Ohio last week denied American Electric Power’s request to recover costs from ratepayers for proposed wind and solar projects totaling 900 MW, saying that PJM’s diverse resource mix already provides enough access to renewable generation.

The Public Utilities Commission of Ohio said in a ruling Thursday that “we are not persuaded that the energy or capacity markets have, in fact, failed, as AEP Ohio asserts” and instead suggested the utility seek state subsidies or solicit competitive bids for the projects.

“Today’s decision is not about any particular generating technology,” PUCO Chairman Sam Randazzo said. “Rather, it is about what must be demonstrated by an electric distribution utility before Ohio law might allow the PUCO to approve the proposed charge. Indeed, Ohio’s ‘customer choice’ framework provides AEP Ohio customers with the individual right to do directly what the proposal would have compelled all such customers to do regardless of their individual preferences.”

AEP last year asked for cost recovery under the state’s renewable generation rider (RGR) for 500 MW of wind and 400 MW of solar, arguing that the projects would fulfill a growing desire for clean energy, offset the price volatility in PJM associated with fossil fuels and enhance the state’s economy.

AEP — Exelon’s Antelope Valley Solar Ranch in the desert near Los Angeles | *U.S. Department of Energy*

The proceeding was split into two parts, with PUCO first determining the need for the projects before settling on a cost-recovery mechanism. AEP stalled the ruling in September in order to update its arguments to reflect the impacts of the recently passed House Bill 6, which curtails the state’s current renewable portfolio standard and tacks on monthly fees — ranging from 80 cents for residential customers to $2,400 for large industrial plants — to electricity bills, mostly for FirstEnergy Solutions’ Davis-Besse and Perry nuclear facilities. Some $20 million of the fees collected will support six solar power projects, including AEP’s proposals, in rural areas of the state. (See Ohio Approves Nuke Subsid y.)

Protesters — including the Ohio Consumers’ Counsel, Kroger, Ohio Coal Association, Direct Energy, IGS and IGS Solar — urged the commission to rule in the case anyway, calling the bill irrelevant to “the statutory issue of whether Ohio utility consumers need electricity from the proposed solar plants.” The companies further alleged that AEP didn’t need a second revenue stream on top of the money afforded to the projects via HB 6. (See PUCO Delays Ruling on AEP Solar Projects.)

“We note that our conclusion on the question of need is not intended to address the merits of the Willowbrook or Highland [solar] projects, which may provide significant benefits to the region,” the commission wrote. “Nothing in our decision today precludes AEP Ohio (or its affiliates) from investing in the Willowbrook or Highland projects and pursuing the projects’ claimed social and economic benefits through means other than a nonbypassable surcharge.”