Page 1245 – RTO Insider

November 21, 2017

Downstate NY to Pay 90% of AC Tx Projects

By Rich Heidorn Jr.

FERC on Thursday approved NYISO Tariff revisions ordering downstate residents to pay 90% of the cost of AC transmission projects stemming from public policy needs (ER17-1310-001).

The projects, which include the estimated $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, are intended to relieve downstate congestion by upgrading the AC transmission systems north and west of New York City.

The cost allocation was proposed by the ISO at the direction of the New York Public Service Commission, which said 75% of the costs should be allocated solely to the downstate load zones that will benefit from the congestion relief, with the remaining 25% allocated regionally based on load-share ratio. “According to the New York commission, this method will allocate approximately 90% of the transmission project’s cost to ratepayers in the downstate region, and about 10% to upstate ratepayers,” FERC said.

FERC rejected a protest by four State Assembly members, who said the regional allocation of 25% was too low to account for “some of the financial and societal benefits to ratepayers statewide.”

The commission said the proposed allocation satisfies Order 1000’s requirement that it be “roughly commensurate” with the benefits that the load zones receive, citing a study published by the PSC that found 89.5% of the costs should be allocated to the downstate load zones.

However, the commission added that the ISO’s filing “does not prevent the selected transmission developer from submitting its own proposed cost allocation method for the AC transmission upgrades. The Tariff specifically provides that the selected transmission developer may also file, for the commission’s approval, an alternate cost allocation method or request that NYISO use the default cost allocation method (i.e., load-share ratio).”

ROE Settlement

In a related order, the commission approved a settlement with New York Transco — affiliates of the New York Transmission Owners, Consolidated Edison of New York, National Grid, Iberdrola USA and Central Hudson Gas & Electric — to decide questions regarding their potential compensation for the projects (ER15-572).

The commission had set the matter for hearing in April 2015. (See Divided FERC Trims ROE on NY Tx Projects, Orders Hearing.)

The settlement, which will apply only if NY Transco is selected as the developer, includes a 9.65% base return on equity and a 100-basis-point adder that will apply up to the cost cap, which was defined as the capital cost bid plus an 18% contingency and an inflation factor of 2% per year.

The commission said the settlement, which was unopposed and endorsed by both the New York PSC and FERC staff, “appears to be fair and reasonable and in the public interest.”

Cost Containment

FERC did not rule on state regulators’ proposed cost-containment mechanism, under which ratepayers would be responsible for 80% of any overruns above the estimated cost of the project and retain 80% of any savings.

The commission said it couldn’t rule because the ISO had provided only a description of the risk-sharing proposal without Tariff language. “As such, [the mechanism] is not properly before us,” the commission said. “NYISO states that it plans to file Tariff sheets for the 80/20 risk-sharing mechanism after concluding its stakeholder process.

“In regard to implementing the 80/20 risk-sharing mechanism, because the New York commission recognizes that [FERC’s] policy on cost recovery allows transmission developers to recover costs that are prudently incurred, it proposes to limit the selected transmission developer’s ability to recover costs associated with cost overruns by reducing the allowed return on equity for the transmission project,” FERC added.

Selection Process

NYISO received 16 proposed projects from six developers in response to a February 2016 solicitation for solutions to address the transmission congestion. In a January order, the PSC told the ISO it “should proceed to a full evaluation and selection, as appropriate, of the more efficient or cost-effective transmission solution to meet the” public policy transmission need.

NYISO spokesman Michael Jamison said the ISO hopes to release draft results of its analysis by the end of the first quarter of 2018. “Subsequent to that, the NYISO will select the more efficient or cost-effective project. At that time the NYISO will work out a developer agreement with the chosen party, and that party can initiate actions with the state under the Article 7 transmission siting process.”

November 21, 2017

ISO-NE Planning Advisory Committee Briefs: Nov. 16, 2017

WESTBOROUGH, MA — Boston leads large, northeastern cities in economic growth, outpacing both New York and Philadelphia in payroll employment, Moody’s Analytics economist Ed Friedman told the ISO-NE Planning Advisory Committee on Thursday.

According to figures compiled by Moody’s from the U.S. Bureau of Labor Statistics, Boston posted better than 2% growth in payroll employment for the three months ending September 2017, compared to approximately 1.7% growth in Philadelphia and less than 1.5% in New York City.

“The job growth in Boston is quite strong and significantly above the U.S. pace, which is around the 1.5% mark,” Friedman said.

Friedman characterized New England job creation in the aggregate as “slow but steady” at 1% per year and said that housing price gains in the region are mostly keeping up with the national average of just more than 6% for the year ending in August 2017. Of the six states in the region, only New Hampshire and Massachusetts exceeded the national average; housing prices in Massachusetts, where health care remains a strong economic driver, increased by almost 7%.

Both Connecticut and Vermont lost population in the past two years. Nonetheless, Moody’s expects economic growth in the region to continue in 2018 at about 1.3%, with “some deceleration consistent with the demographic challenge” of lost population, Friedman said.

RTO Readies Maine Resource Integration Study

ISO-NE on Thursday presented a draft of its Maine Resource Integration Study to the PAC, its first transmission planning study to employ queue clustering under Tariff revisions approved by FERC Approves ISO-NE Queue Clustering.)

The Northern and Western Maine grid was built to serve the small loads in the area and lacks capacity for the more than 5,800 MW of proposed new resources, mostly wind, that have filed interconnection requests. The 5,800 includes duplicate requests.

The resource integration report will provide the basis for system impact and facilities studies, which will identify the upgrades required for resources that proceed to interconnection and their cost allocations, said Al McBride, ISO-NE director of transmission strategy and services.

Maine 2027 Needs Assessment Moves Forward

The RTO’s draft Maine 2027 Needs Assessment study is ready for stakeholder comment, Jinlin Zhang, ISO-NE lead engineer for transmission planning, told the PAC.

Comments and notifications by proponents of state-sponsored requests for generation should be submitted to pacmatters@iso-ne.com by Dec. 3.

The study identifies reliability-based needs in Maine for the year 2027, considering future load distribution, resource changes in New England based on Forward Capacity Auction 11 results, and 2017 solar and energy efficiency forecasts.

Planners look at reliability over a range of generation patterns and transfer levels, how the study coordinates with the New Hampshire Needs Assessment, and all applicable NERC, Northeast Power Coordinating Council (NPCC) and RTO transmission planning reliability standards.

The completed draft report and intermediate study files will be presented to the PAC in the first quarter of 2018.

RTO Begins Zone Planning for FCA 13

ISO-NE has begun assessing transmission transfer capability, generation retirements and new resources to set capacity zone boundaries ahead of FCA 13 for 2022/23.

The process includes evaluation of the zones as determined for FCA 12, McBride said.

Each year, the RTO must identify weaknesses and limiting facilities that could impact the transmission system’s ability to reliably transfer energy in the planning horizon. Any new boundaries require a filing with FERC, McBride said.

The process of certifying transmission projects begins in October and is coordinated with that month’s Regional System Plan (RSP) Project List update to ensure consistency. Transmission owners are required to provide models and contingency definitions. The RTO will determine certifications by January; the list of certified projects will be presented at the January Reliability Committee meeting.

Transmission upgrades identified for Southeast Massachusetts/Rhode Island (SEMA/RI) are not expected to change the boundaries of the area. Planners do not expect such upgrades to be fully certified for FCA 13, nor will transfer limits be updated in time for that auction in 2019.

Any major resource retirements received for FCA 13 will be considered in the zone formation process, McBride said. No major retirements were received for FCA 12.

Time-Sensitive Tx Needs Determination

Pradip Vijayan, ISO-NE senior transmission planning engineer, made a presentation on how the RTO identifies time-sensitive transmission upgrades — those required within three years and thus not subject to the competitive solicitation process.

RTO officials consider when an upgrade will be required after identifying improvements in a needs assessment.

Needs identified from a short-circuit analysis are considered time sensitive unless they are driven by future projects that have an in-service date beyond three years of the completion of the needs assessment.

Steady-state needs observed at off-peak load levels are considered time sensitive. Those seen at peak load levels may or may not be time-sensitive.

The RTO will add a document detailing the process to its Transmission Planning Technical Guide, Vijayan said.

Tx Planning Assumptions Update

ISO-NE is continuing to update the probabilistic methodology and minimum load level used in its transmission planning assumptions, Director of Transmission Planning Brent Oberlin said.

The generator dispatches used in base cases in his report showed the potential for a significant number of generators to be simultaneously unavailable, especially in the Eastern Connecticut (ECT) area. ISO-NE said in October that it would revise the scope of its 2027 needs assessments for ECT, Southwest Connecticut and New Hampshire over stakeholder questions about dispatch modeling assumptions. (See “Tx Planners Rethink 2027 Needs Assessment,” ISO-NE Planning Advisory Committee Briefs: Oct. 18, 2017.)

The ECT data showed that up to 488 MW of generation could be unavailable at peak load. The largest generator in the ECT study area is Montville 6 (413 MW), with 13 other generators totaling only 253 MW, which shows that the presence of a single large generator in an area with a low number of smaller generators can skew the results, Oberlin said.

The new methodology solves the issue by recalculating the upper limit of generation outages using the probabilistic method by excluding the large generator for dispatches in which it is assumed in service. By applying this method to ECT, the maximum amount of generation unavailable is limited to 115 MW in cases with Montville 6 in service.

The new methodology lowers the minimum load level to 8,000 MW from 8,500 MW, correcting an error on the handling of Maine mill loads (currently 320 MW) in the evaluations, Oberlin said.

— Michael Kuser

November 20, 2017

Cauley Resigns; NERC Launches Search for Replacement

By Rich Heidorn Jr.

NERC announced Monday that its Board of Trustees had accepted the resignation of CEO Gerry Cauley, effective immediately, following his arrest for domestic abuse.

The organization said General Counsel Charles Berardesco will continue to serve as acting CEO while the board seeks a search firm to recruit a replacement.

“NERC has a talented staff and an experienced leadership team that is well-equipped to continue the forward momentum on key initiatives,” Board Chair Roy Thilly said in a statement. “I am confident we will continue to meet milestones and expectations going forward. NERC remains committed to maintaining the reliability and resilience of the bulk power system.”

A NERC spokeswoman declined to comment when asked whether Cauley would receive any severance payment. “Any personnel action is confidential,” she said.

nerc gerry cauley — NERC CEO Gerry Cauley (center) and General Counsel Charles Berardesco (to Cauley’s left) attend a NERC board meeting in New Orleans Nov. 9, hours before Cauley’s arrest for domestic abuse. Also pictured are Board Chair Roy Thilly (to Cauley’s right), and board members Jan Schori (left) and Frederick W. Gorbet (foreground). | *NERC*

NERC had placed Cauley on a leave of absence after his arrest for battery, a misdemeanor, for allegedly assaulting his estranged wife in the early morning of Nov. 10. The police report documenting his arrest states that his wife, Jean Cauley, sustained bruises and scratches and was experiencing a great deal of pain in her back.

The report quoted Jean as saying he attacked her after she discovered him having cybersex with a “young female employee of his.” (See Cauley Arrest Tied to Relationship with NERC Subordinate.)

Jean, a former probation officer and child abuse investigator for the state of Florida, posted a comment about the incident on her LinkedIn page Sunday: “Who knew that when I married a CEO — and me with a background in law-enforcement — [I] would be a victim of a violent crime by her husband to the point of a back being broken,” she wrote. “It shows that no one is exempt from domestic violence and that we should all support each other as women.”

Cauley, 64, had served as NERC CEO since January 2010, and was often the face of the reliability agency in hearings before FERC and Congress. By Monday afternoon, however, his biography and photo had been removed from the web page listing the organization’s management.

November 19, 2017

No End Seen to State-Federal Tensions

By Rich Heidorn Jr.

BALTIMORE — State-federal tension over electricity policy is likely to continue even after current debates over nuclear and coal subsidies end, speakers told the National Association of Regulatory Utility Commissioners’ Annual Meeting last week.

In fact, said former FERC Commissioner Tony Clark, “things are probably going to get more tense and more difficult before they get easier.”

Clark, an adviser for Wilkinson Barker Knauer who left the commission in September 2016, said there will be pressure for additional state interventions because of the impact of renewables on energy market prices. “Increasingly we see even … relatively new gas units that are stressed in certain markets. Any resource that has higher fixed costs and variable operating costs is going to be challenged in any sort of market where you have price takers with zero variable cost units that are at the margins.”

In addition, he said, FERC may begin asserting its authority on power “from the edge of the grid,” such as rooftop solar.

“Up until this point, FERC has kind of walled that off and basically … been able to ignore what happens since that’s been on the state jurisdiction side of things,” he said.

“It’s hard to argue that all of these exponentially growing resources at the edge of the grid — in which a sale is by default a sale for resale — [is not] federally jurisdictional activity. To this point it hasn’t been that big a deal. It’s becoming a very big deal.”

Ari Peskoe, of Harvard Law School’s Environmental Policy Initiative, said legal challenges to Illinois’ and New York’s zero-emission credits for nuclear plants “expose a question that courts have not addressed in the 20 years of restructuring: May a state provide an incentive for energy production without intruding on FERC’s exclusive jurisdiction over energy sales? Perhaps the state authority over generating facilities means just that — the facilities themselves, and not the energy that they produce,” he said.

“There’s little doubt that states can enact all sorts of command-and-control regulations over pollution from those facilities. States can issue emission limits or simply prohibit the burning of fossil fuels within their borders. But what about financial regulation of pollution and avoided pollution? And what about state regulation of utility portfolios? ls there some limit on state power that limits states just to those traditional integrated resource plan tools?”

Peskoe filed an amicus brief defending the Illinois ZECs. “Expanding the scope of FERC’s exclusive jurisdiction to swallow up ZECs, [renewable energy credits] and other emissions taxes and allowances will disrupt how the industry and how regulators have understood jurisdictional limits,” he said.

If the courts accept opponents’ reading of the Federal Power Act, “we can expect lawsuits about a range of state programs,” he said, adding, “Now concerns about market distortions from ZECs seem pretty quaint in light of [the U.S. Department of Energy’s] recent Notice of Proposed Rulemaking.”

Peskoe said that if ZECs survive the current legal challenges, “existing state policy would be relatively safe from these pre-emption challenges going forward. Then the action turns back to FERC and what FERC is going to do.”

He said FERC’s May 1-2 technical conference on integrating wholesale markets and state public policies “was a really positive step … so I hope that the DOE NOPR and whatever happens after it doesn’t sort of suck the air out of the room and that conversation keeps happening.” (See RTO Markets at Crossroads, Hobbled FERC Ponders Options.)

Clark said FERC must determine when state actions reach a “tipping point” for its markets. “Whether you think the ZEC is the tipping point or the DOE NOPR is the tipping point, there is a tipping point that FERC has to be concerned about in terms of its maintenance of the integrity of the wholesale market,” he said.

“What happens when say … coal-friendly states decide, ‘It looks like RECs and ZECs are the way to go. What we need now is a coal energy credit,’” Clark asked.

“We are called the Environmental Policy Initiative, so we don’t love the idea of coal credits,” Peskoe responded. “I’m somewhat comforted by the fact that about 30 states actually enacted RPS and, so far, zero states have enacted coal standards.”

Former Commissioner Marc Spitzer (2006–2011) was more succinct: “If they’re zero-emission coal, go for it!” he joked.

Spitzer, a partner with Steptoe and Johnson, also supported ZECs, saying states are “entitled to deference and forbearance.”

November 19, 2017

Policy Churn, Voting Rules Raise Questions on RTO Governance

By Rich Heidorn Jr.

BALTIMORE — Speaking last week to an audience of consumer advocates, John P. Hughes, CEO of the Electricity Consumers Resource Council (ELCON), led off his critique of RTO stakeholder processes with a blunt assessment: “The main takeaway is it can’t be fixed.”

Other participants who joined Hughes in a panel discussion at the National Association of State Utility Consumer Advocates (NASUCA) annual meeting Wednesday were more optimistic.

rto governance — Panelists left to right: Simeone, Foster, Hughes and Malcolm | © *RTO Insider*

Unfortunately, the speakers’ opening presentations at the discussion — cheekily titled “20 Years of RTO Meetings and We’re Still Not Done?” — swallowed up the entire 70-minute session. As a result, Denise Foster, PJM’s vice president of state and member services, never got a chance to respond to the critiques.

Room for Improvement

AARP’s Bill Malcolm, a former MISO manager of state regulatory affairs, opened his presentation by praising RTOs for improving generation dispatch and eliminating rate pancaking.

But he said they should be required to follow open meetings laws and enact ethics reforms, including a ban on revolving-door hiring. He also called for tightening cost controls. “RTOs don’t print money,” said Malcolm, AARP’s senior legislative representative for state advocacy and strategy integration. “It’s ratepayer dollars at the end of the day.”

He also said RTOs should add ways to better represent residential ratepayers in stakeholder proceedings, including establishing an RTO-funded organization like the Consumer Advocates of PJM States (CAPS).

“Let’s make a good thing better,” Malcolm said.

Unstable Market Design

Hughes, whose organization represents industrials, said a large manufacturer might have only one or two electricity buyers for national or international operations — making it impossible to monitor the hundreds of RTO stakeholder meetings annually.

“The market design has never — and may not ever — be stabilized. Therefore, the stakeholder process will forever be the resource hog that it is today,” he said, citing capacity markets as an example.

“It is the wrong solution to the problem, caused by not having shortage pricing or surge pricing. And since the capacity market doesn’t really work, it’s under continual attack for tweaks and fixes that will go on forever unless we come up with a different market design — which I don’t think will happen.”

Hughes said almost all the proposals that go through the stakeholder process are efforts to increase charges to ratepayers. “The current driver of market design changes — which is [the call for] price formation, including the new [Department of Energy Notice of Proposed Rulemaking] — is very low-cost shale gas. There seems to be a conspiracy to deny consumers the benefit of this resource,” he said.

Hughes said ERCOT — which has a board seat reserved for industrial consumers — is the only governance structure his group likes. Industrials’ presence on the board means “you gain respect in the whole food chain,” he said.

PJM Study

Christina Simeone, director of policy and external affairs for the Kleinman Center for Energy Policy at the University of Pennsylvania, spoke about her May 2017 study on PJM’s governance, which asks “Can Reforms Improve Outcomes?”

Among her conclusions: PJM’s stakeholder process is very effective on less contentious issues but is less effective on the most contentious issues that are subjected to sector-weighted votes.

Because of affiliate voting, the lower committees are subject to a “huge supply-side bias,” she said, citing the now-closed Seasonal Capacity Resources Senior Task Force, where 190 votes were cast by 34 respondents. Just 10 companies can prevent any proposal from passing at the lower level, she said.

But while suppliers can muscle their proposals through the lower committees, she cited a Pennsylvania State University study that found a load-side bias at the upper levels, where End Use Customers and Electric Distributors have formed a tight voting coalition. “What ends up happening is all the proposed solutions are supply-side biased and then they get knocked down by the load-side bias at the higher level. This is a phenomenon I think we’re seeing more and more,” she said.

She said RTO management has an interest in preventing political backlash over price volatility and blackouts, “so the organization may seek to prevent those things, perhaps at any cost.”

She recommended that states have a vote through their governors and that PJM review the makeup of its five sectors, noting the dispersion of stakeholders representing the fastest-growing industry segments: renewable energy (Generation Owners), energy efficiency (Electric Distributors, Transmission Owners and Other Suppliers) and demand response (Other Suppliers).

“In competitive markets, new market entrants are very important. However, they’re being lumped in with everybody else and that does a disservice to both the larger firms and the new market entrants because of vote dilution. The larger the sectors get, the less impact any individual firm can have on the process.”

She said FERC should require RTOs to re-evaluate their governance process regularly to comply with the “ongoing responsiveness” principle of FERC Order 719.

November 19, 2017

FERC Upholds MISO Transfer Limit Policy

By Amanda Durish Cook

FERC on Thursday rejected a rehearing of MISO’s subregional flow limits and accepted the RTO’s method for calculating the limits.

The commission declined to rehear its December 2016 dismissal of a complaint seeking to overturn the results of MISO’s 2016/17 planning year capacity auction. A coalition of transmission customers had argued that subregional transfer constraints where MISO flows must cross FERC Backs MISO on Transfer Limit, Seeks Details.)

MISO calculates the transfer limits between its Midwest and South regions by deducting firm reservations from 2,500 MW of available capacity flowing from South to Midwest and 3,000 MW estimated to be available in the opposite direction. The initial limits were set out in a settlement with SPP that became effective in early 2016.

Several MISO stakeholders and the Independent Market Monitor argued that the RTO’s subregional constraint calculation is flawed, with a group of transmission-dependent utilities in Wisconsin arguing that the subtraction of all firm transmission service reservations “incorrectly assumes that those holding the reservations will use them all the time, even when it would be counter to their economic interest.” The Monitor agreed that the calculation is too conservative.

In its Nov. 16 order, FERC pointed out that while it’s possible that not all firm transmission customers will use their service simultaneously, it’s also possible they could.

“All parties appear to agree that the regional directional transfer limits established in the settlement agreement are a reasonable starting point for the calculations,” FERC wrote. “We agree … MISO’s proposal requires it to make two reductions, when applicable, to the regional directional transfer limits: (1) a reduction, based on a feasibility analysis, for reliability purposes; and (2) a reduction by the amount of firm transmission service reservations in the prevailing direction.”

Multiple companies submitted alternative proposals for calculating subregional constraints, but FERC declined to examine their fairness.

“There may be more than one just and reasonable methodology that MISO can use to calculate subbegional constraints. We need not analyze whether the various alternative proposals are also just and reasonable,” the commission said.

FERC also clarified — at WPPI Energy’s request — that its finding regarding the 2016/17 auction should not be construed as “conclusive proof” that MISO’s approved methodology will be considered the best course for future capacity auctions.

Monitor Concerned with Cost of Midwest-South Constraint

The order comes as the Monitor is reiterating concerns about the cost of the SPP contract path with respect to make-whole payments.

“We’ve been coming at MISO with concerns about the RSG [revenue sufficiency guarantee] on the North-South constraint for some time now,” Monitor David Patton said.

Patton said the constraint contributed to $3 million in revenue sufficiency guarantee payments in April 2017 alone.

“It’s a vexing constraint because it’s not a physical constraint; it’s an agreement,” Patton said during an October Market Subcommittee meeting.

He said the constraint created about $9 million in RSG payments from September through mid-October, with $6 million of that paid to a single company. “These are wasteful costs,” he added.

Earlier this year, MISO conducted a study to evaluate the benefits of constructing transmission to link the Midwest and South areas. The RTO concluded that not one of 35 potential projects could pass the 1.25-to-1 benefit-cost criteria based on adjusted production cost benefits. (See “No Tx Coming for North-South Constraint,” MTEP 17 Proposal: 343 New Transmission Projects at $2.6B.)

November 19, 2017

Investigations up Sharply in FY 2017, FERC Report Shows

By Michael Brooks

FERC’s Office of Enforcement opened 27 investigations in fiscal year 2017, 10 more than the year before, according to its 11th annual report released last week.

The report includes for the first time examples of surveillance inquiries that did not lead to investigations.

In a presentation to the commission Thursday, Enforcement staff said the brief summaries of several instances in which the office’s Division of Analytics and Surveillance (DAS) contacted market participants about potential violations were included in the report in response to requests by several regulated entities. They are similar to the examples the Division of Investigations (DOI) has provided on investigations closed without action in past reports. (See Market Manipulation Cases Dominate FERC Enforcement.)

“OE anticipates that regulated entities can leverage the example surveillance inquiries to achieve a better understanding of when and why DAS makes inquiry calls, the principles and evaluations used by DAS in making a determination to refer an inquiry to DOI and transactional behavioral patterns that were not deemed by DAS to be problematic or potential violations,” Enforcement’s John Miller told the commission.

The report masks the identities of the market participants and the markets in which the incidences occur. In one example, DAS flagged large, loss-making increment offers (INCs) at an RTO hub made by a market participant who held a leveraged financial transmission rights path sourced at the hub.

“The market participant explained that the observed INCs covered a period of a planned outage, and that the virtual position shifted a non-leveraged real-time position to the day-ahead market where the market participant hedged commodity risk,” the report said. “After verifying the relevant information, the inquiry was closed with no referral to DOI.”

DAS’ computerized triggers produced more than 300,000 alerts on RTO and bilateral trades, only 31 of which resulted in inquiries. Of those, four resulted in referrals to DOI.

The report also included examples of and statistics on violations that were self-reported. The Office of Enforcement received 80 self-reports last fiscal year, most of which were made by RTOs/ISOs. Most of these were minor violations resulting from human or software error. The examples were included to “emphasize the importance of self-reporting by providing credit that can significantly mitigate penalties if a self-report was made,” the report said. “Staff continues to encourage the submission of self-reports, and views self-reports as showing a company’s commitment to compliance.”

Of the 27 investigations opened last year, 15 involve potential market manipulation, 16 involve potential tariff violations, four involve potential violations of a FERC order and two involve potential violations of a FERC filing requirement.

Staff closed 16 investigations, 11 without further action because of lack of evidence. One of these was into bidding behavior in ISO-NE’s eighth Forward Capacity Auction in 2014, the results of which stood because of a tie vote of the commission. Commissioners Tony Clark and Norman Bay had voted to throw out the results. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)

The other five were closed through commission-approved settlements that resulted in more than $51 million in civil penalties. The largest of these, $41 million, was paid by GDF SUEZ Energy Marketing for offering generation below cost to capture make-whole payments in PJM. GDF also disgorged $40.8 million in unjust profits to the RTO. (See GDF SUEZ to Pay $82M in PJM Market Manipulation Settlement.)

The settlements also included $2.7 million assessed on K. Stephen Tsingas and $9 million on his company, City Power Marketing, for making risk-free up-to-congestion trades to profit off PJM line-loss rebates. However, the company is defunct, and FERC agreed not to pursue Tsingas for the additional amount. (See Trader Agrees to Pay $2.7M in Win for FERC.)

They did not include the $105 million Barclays Bank recently paid to settle claims it manipulated the Western markets a decade ago, which occurred after the end of FY 2017. FERC had originally sought $470 million. (See FERC Settlement Cuts Barclays Market Manipulation Fine.)

Asked by reporters on Thursday why FERC agreed to such a steep cut, FERC Chairman Neil Chatterjee said he wanted to avoid years of litigation. “My priority was to get the disgorgement money back to those that have been harmed and deter similar conduct in the future,” he said. He noted that the $70 million civil penalty against the bank was the third largest the commission had ever levied. Barclays also disgorged $35 million to states’ low-income home energy assistance programs.

November 19, 2017

FERC OKs Amended Entergy PPAs, Ups Bandwidth Refund

By Amanda Durish Cook

FERC OKs 6 Amended Entergy PPAs

FERC last week accepted six revised power purchase agreements among Entergy subsidiaries following Entergy Arkansas’ withdrawal from the company’s multistate system agreement.

The company sought in May to amend the PPAs, each of which had been previously filed with FERC because they are being transferred under provisions of the company’s tariff and involve the Grand Gulf Nuclear Station in Mississippi. Under the tariff that replaces the longstanding Entergy system agreement, the resale of power purchased from Grand Gulf must earn FERC approval.

Entergy Arkansas withdrew from the agreement in late 2013 when it joined MISO; the rest of the company’s Gulf Coast operating companies followed suit and set staggered dates to abandon the agreement, prompting Entergy to create a company-wide tariff that governs PPAs among its affiliates. (See FERC OKs 2018 Entergy System Agreement Exit.) The system agreement had been the basis for planning and operating the Entergy utilities’ generation and transmission facilities as a single system since 1982.

ferc entergy — Grand Gulf station | *Entergy*

In accepting the amended PPAs, the commission determined that the language is similar to Entergy’s previously approved agreements and in compliance with Nuclear Regulatory Commission requirements (ER17-1160, et al.). In addition to Entergy Arkansas, the PPAs include Entergy Louisiana, Entergy New Orleans and Entergy Mississippi.

The commission also directed the company to submit a compliance filing specifying the date on which the amended PPAs began to fall under the new tariff rather than the system agreement. FERC noted that Entergy may have meant to fill in Dec. 19, 2013, the date of Entergy Arkansas’ withdrawal from the agreement.

The commission’s order makes the PPAs’ acceptance official. FERC staff had provisionally accepted the company’s filing in June when the commission still lacked quorum.

FERC Orders Compound Interest Refund in Entergy Bandwidth Issue

Entergy’s fading system agreement was at the center of another FERC ruling last week when the commission rejected a compliance filing the company made to provide refunds on the bandwidth payments it received from its operating companies (ER10-1350-006). Entergy submitted the filing a year ago to comply with a commission order to calculate interest on refunds related to the payments. (See FERC: Further Compliance Filings for Entergy, MISO.)

FERC determined the company miscalculated the interest on the refund due back to its Louisiana affiliate. In February 2016, Entergy refunded Entergy Louisiana $27 million in payments, paying the principal but not the interest, and recording the amount in its refund compliance filing. The parent company last November additionally refunded compounded interest, but only up until the Feb. 16 principal payment date. The Louisiana Public Service Commission noticed that the company did not pay interest on the initial missing interest payment and protested the filing, asking that interest-on-interest payments of $25,761 be made for most of 2016.

Entergy argued that interest should have only been calculated from the date of collection until the date refunds are made.

FERC last week ordered another compliance filing, ruling that the company must “calculate interest compounding on the interest component of the payments at issue until the date the interest payment is actually made.”

Entergy’s allocation of production costs among its half-dozen operating companies under its system agreement has been a source of disagreement for a decade. Payments are made annually by the company’s low-cost operating companies to the highest-cost company in the system, using a “bandwidth” solution that ensures no operating company has production costs more than 11% above or below the system average.

November 19, 2017

PJM Stakeholders Split on Request to OK MOPR Compromise

By Rory D. Sweeney

An appellate court ruling remanding back to FERC its 2013 order on PJM’s minimum offer price rule (MOPR) has created disagreement among stakeholders about how to move forward.

PJM requested in October that FERC approve its initial 2012 filing on the issue (ER13-535). The RTO had submitted a “hard-fought compromise package” that included two new categorical exemptions to the rule and eliminated a unit-specific one. FERC rejected the initial proposal but said it would approve it if PJM retained the unit-specific exemption and reduced a proposed three-year imposition of the MOPR on affected units to the existing one-year mitigation.

FERC approved PJM’s amended filing, but several stakeholders challenged the action and the D.C. Circuit Court of Appeals ruled in July that FERC overstepped its legal authority in telling the RTO what it would accept. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

PJM asked FERC to, on remand, “simply accept PJM’s original Section 205 proposal, unchanged, as just and reasonable.”

The commission’s requirements on the unit-specific exemption and mitigation period “have had no practical impact … on the auction results in the five annual auctions conducted since the commission’s initial order in this case,” PJM said in its Oct. 23 request.

FERC’s concern was “to catch possible future competitive offers that might fall through the cracks theoretically left by the two categorical exemptions,” PJM said, but five Base Residual Auctions and nine Incremental Auctions have occurred since then with no unit-specific offers submitted.

“We now know that those cracks, if they exist at all, are quite narrow,” PJM said. The commission can conclude that its “concern” about competitive offers slipping through “was overstated.”

Stakeholders were split on their opinions of PJM’s request. The Independent Market Monitor, NRG Energy and Public Service Enterprise Group argued that FERC had already rejected the RTO’s 2012 filing. Several generators said the filing should be approved but with a requirement that PJM address deficiencies in its MOPR within 90 days.

ferc pjm mopr — PSEG’s Sewaren 7 natural gas generator is expected to go into operation in summer 2018. | *PSEG*

American Municipal Power and Old Dominion Electric Cooperative supported PJM’s plan, with ODEC arguing that the new self-supply and competitive-entry exemptions “must be maintained.”

“Otherwise, [load-serving entities] like ODEC face the unreasonable prospect of their loads paying twice for capacity, once through the investment in resources (owned or purchased bilaterally outside of the [Reliability Pricing Model] construct), and then a second time when those resources do not clear in the RPM auctions because they are unreasonably subject to the MOPR,” ODEC said.

FERC “upset the balance that had been struck by conditioning acceptance” on retaining the unit-specific exemption, it said.

“The commission’s authority to issue an order in the form PJM recommends is not in question,” AMP said. “That PJM’s stakeholders overwhelmingly supported the competitive-entry exemption and the self-supply exemption should weigh heavily in the commission’s consideration of how to proceed on remand.”

The PJM Power Providers Group (P3) said it supported the RTO’s request “in the interest of market certainty” and noted that other dockets exist or likely will come before FERC on the topic “to address broader issues.”

Several P3 members, including Calpine, Congentrix Energy Power Management, Dynegy and Eastern Generation, agreed with the group’s comments but voiced concern about “deficiencies with [PJM’s] MOPR process” and argued that FERC should give the RTO 90 days to address them.

“Recognizing that threats may exist to the efficient operation of PJM’s wholesale markets is an understatement, to say the least,” the generators said, noting the zero-emission credits for nuclear generation in Illinois and proposals for similar subsidies in Ohio, Pennsylvania and New Jersey.

“PJM must have in place an effective MOPR, applicable to both new and existing resources, to combat the very real threat of these state actions. It is incumbent on the commission to take decisive action on the issue of state-subsidized existing units by extending the MOPR to those units. Continued failure to do so is an abdication of the commission’s duties and responsibilities.”

PJM had acknowledged in its filing that its finding about unit-specific exemptions “does not rule out the possibility of future low-price competitive offers that do not qualify for the categorical exemptions” and that “that the nature of the potential threats to the efficient operation of its wholesale markets may have evolved since 2012, and accordingly, prospective changes to its MOPR, or its Tariff more generally, may be warranted — but not in this proceeding. PJM has an ongoing stakeholder senior task force considering such issues.”

The Monitor argued that FERC was correct to deny PJM’s original filing and that the court’s order didn’t vacate that decision.

“The commission’s determination that the MOPR was not just and reasonable without an exception for unit-specific cost review was logical,” the Monitor said. “The motion should be denied for the same reasons that the commission denied it initially.”

NRG and PSEG agreed that the court decision required PJM to return to its original MOPR rule, but split on what other mitigations are necessary. NRG said PJM should just move on with the original rule without retroactively examining the auctions since it was replaced. PSEG suggested a method to recreate the auctions and compensate affected participants.

PJM had argued that because all resources that sought a MOPR exemption pursued categorical exemptions rather than unit-specific ones, the auctions had not been impacted.

“NRG sees something very different: clear evidence that PJM’s proposed MOPR is toothless and does nothing to prevent uneconomic entry,” NRG said in its filing. “New entrants are making an already over-supplied market even more over-supplied — and are being totally exempted from any review to ensure that their low bids are economically justified. … In order to have a meaningful MOPR that protects the market from artificially low prices, there simply cannot be categorical exemptions so broad that any new generator could drive a truck through them.”

PSEG argued the issue is whether the categorical exemptions impacted auction prices differently than how the pre-existing unit-specific one alone would have. PJM should recreate the auctions using commission-approved proxy values for units “inappropriately granted one of the two categorical exemptions to establish the ‘but for’ auction price,” PSEG said.

Any “underpayments” that result would be payable to affected generators by zone; “however, the new entrants that relied upon the no-longer-available MOPR exemptions for a particular auction year would not be eligible for any additional amounts.”

November 19, 2017

FERC Denies BGE Recovery of $38M in Deferred Taxes

By Rory D. Sweeney

FERC denied Baltimore Gas and Electric’s bid to recover $38 million in taxes deferred over decades, saying that “contrary to BGE’s assertion, we find that utilities do not have unfettered discretion to defer these tax amounts on their books for decades without timely seeking regulatory approval to collect them.”

ferc bge — BGE CEO Calvin Butler Jr. | © *RTO Insider*

BGE sought approval for three adjustments to its formula rate for how taxes are recovered (ER17-528). The revisions would have returned $4 million to customers related to tax rate changes but also collected approximately $42 million. The collections broke down to $29 million related to deferred tax liability for the equity component of allowance for funds used during construction (AFUDC) and approximately $13 million for an accounting adjustment to claw back tax benefits that were flowed through to customers at the time they originated, rather than relying on BGE’s current tax normalization methodology that collects tax liabilities and distributes benefits over time.

FERC said BGE took too long to make the adjustments.

“Although these accumulated amounts may represent legitimate deficiencies in accumulated deferred income taxes, we find that these deficiencies should have been captured in BGE’s formula rate since its implementation in 2005,” the commission said.

FERC cited 1981’s Order 144, which stipulated that all utilities use the normalization methodology. It additionally required them to begin the process of accounting for any tax excesses or deficiencies through rate adjustments. The order called for companies to make the adjustments in their next rate case following the order’s implementation or at least “within a reasonable period of time.”

“Had BGE properly addressed the tax deficiencies when its formula rate was initially filed in 2005, BGE may have been allowed to collect some portion of these deficiencies over the remaining life of the underlying plant assets that created the deficiencies,” the commission said.

BGE’s failure to “match” tax effects with the revenues that created them in a timely manner was “particularly noticeable” regarding the flow-through items because they are related to assets from prior to 1976, “most of which have been either fully depreciated or retired by 2016.”

“It is unclear if there are any relevant assets left on BGE’s books in 2017 to match the amortization period over the next 28 years,” FERC said.