President Trump on Wednesday nominated the Department of Energy’s Bernard McNamee to replace former FERC Commissioner Robert Powelson — a pick that could be crucial to the administration’s efforts to support at-risk coal and nuclear generation.
Powelson, who left the commission in August to head a trade organization, was a vocal opponent of the Trump administration’s bid to provide price supports to coal and nuclear generators. McNamee, a former aide to Sen. Ted Cruz (R-Texas), was among the DOE officials who designed and lobbied on behalf of the plan.
Lobbying for Price Supports
Last November, McNamee joined FERC Chief of Staff Anthony Pugliese to make the case for coal and nuclear price supports at a breakfast meeting of the Consumer Energy Alliance (CEA) on the sidelines of the National Association of Regulatory Utility Commissioners’ Annual Meeting in Baltimore. Watchdog group the Energy and Policy Institute has described CEA as “a fossil fuel-funded advocacy group.” (See DOE, Pugliese Press ‘Baseload’ Rescue at NARUC.)
In January, FERC voted 5-0 to reject Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to save at-risk coal and nuclear plants and instead opened a docket to consider resilience concerns. In June, however, Trump ordered Perry to save coal and nuclear plants under an obscure Korean War-era law. That effort is still pending, although the Washington Examiner reported Friday that it may have stalled in the face of opposition by conservative, free-market groups.
A graduate of the University of Virginia and Emory University School of Law, McNamee has had a variety of political and legal jobs in Texas, Virginia and D.C. In addition to stints at the law firms of Hunton & Williams (now Hunton Andrews Kurth), Williams Mullen and McGuireWoods, he spent time in the attorney general’s offices in Texas and Virginia and was policy director for former Gov. George Allen’s (R-Va.) 2000 U.S. Senate campaign.
After serving as Cruz’s senior domestic policy adviser and counsel from July 2013 to November 2014, he spent a year as chief of staff to the Texas attorney general, where his LinkedIn profile said his work included “challenging the federal government on environmental regulations, defending religious liberty and promoting federalism.”
He first joined DOE as deputy general counsel for energy policy in May 2017 but left after 10 months to become the director of the Texas Public Policy Foundation’s Center for Tenth Amendment Action and Life: Powered, a project to “reframe the national discussion” about fossil fuels.
‘Blessed’ by Coal, Natural Gas
In an op-ed published in The Hill on Earth Day in April, McNamee defended fossil fuels against criticism over their environmental damage. “America is blessed with an abundant supply of affordable natural gas, oil and coal. When we celebrate Earth Day, we should consider the facts, not the political narrative, and reflect about how the responsible use of America’s abundant resources of natural gas, oil and coal have dramatically improved the human condition — and continue to do so,” he wrote.
He returned to DOE in June as executive director of the Office of Policy.
In July, McNamee defended the administration’s plans for price supports in a hearing of the Senate Energy and Natural Resources Committee. “A lot of the organized markets have distortions in them that aren’t representative of an actual free-serving market, so the thought is you need to remove some of those distortions and get some more parity,” McNamee said.
Reaction
Michelle Bloodworth, CEO of pro-coal group ACCCE, called Wednesday for McNamee’s “swift confirmation.”
“FERC has a critical role in assuring that wholesale markets value resilience attributes, especially fuel security. McNamee’s background and experience at the state and federal levels make him well qualified to be the next FERC commissioner,” she said. ACCCE says about 120 GW of coal-fired generating capacity, about 40% of the remaining fleet, has retired or announced plans to do so.
“If McNamee is confirmed to FERC, he will abuse that authority to lead the charge to force taxpayers to spend tens of billions of dollars to bail out old, expensive coal and nuclear plants, at the expense of cleaner, cheaper competitors like solar, wind and grid storage,” Mary Anne Hitt, senior director of Sierra Club’s Beyond Coal campaign said in a statement when McNamee’s name was floated as a potential nominee in August. “Trump is hoping to install a crony at FERC who will unfairly tip the scales in favor of propping up those failing industries.”
“Powelson’s departure was widely seen as opportunity for the White House to more closely align FERC with its own policies,” said Stoel Rives partner and FERC practitioner Jason Johns. “It is my belief that Powelson’s opposition to certain policy efforts came as a surprise to the White House, particularly the White House’s efforts to subsidize coal and nuclear facilities. I’m confident the White House is looking to address those surprises with this choice. ”
“FERC has a longstanding commitment to fuel-neutral regulation, but Mr. McNamee’s past writings and career track record suggest that he would seek every opportunity possible to support fossil fuels,” said John Moore of the Sustainable FERC Project.
Strategy
ClearView Energy Partners suggested McNamee, a Republican, might be paired with a Democratic nominee to replace Commissioner Cheryl LaFleur if the GOP retains a majority in the Senate. LaFleur, whose term expires June 30, 2019, is unlikely to be renominated, ClearView said.
However, Senate Majority Leader Mitch McConnell (R-Ky.) could push McNamee’s confirmation more quickly to restore the 3-2 Republican FERC majority, the consultants said.
Although LaFleur and fellow Democrat Richard Glick have repeatedly been on the losing end of 3-2 natural gas pipeline orders, the departure of Powelson has raised the prospect that pipeline approvals could stall in the face of 2-2 deadlocks.
Last month, E&E News reported that the Trump administration also was vetting Florida Public Service Commission Chairman Art Graham, a self-described conservative and nuclear power supporter, for a FERC seat.
CAISO is asking FERC for expedited review of a revised proposal to protect electricity ratepayers from funding shortfalls in the ISO’s congestion revenue rights market.
The ISO filed the revision Monday after FERC last month rejected an earlier plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges (ER18-2034). (See FERC Rejects CAISO Congestion Revenue Scaling Plan.)
CAISO’s most recent filing notes that CRR revenue shortfalls have continued into this year, and it urged the commission to quickly approve the revised plan to relieve ratepayers from paying costs for fully funding CRRs in 2019. The ISO’s Department of Market Monitoring has estimated that CRR revenue shortfalls — which are allocated based on power consumption — cost California ratepayers about $100 million a year.
Under the scaling plan FERC rejected on Sept. 20, CAISO proposed to compare the CRR auction revenue and revenue from counterflow CRR holders for each constraint to the payments due to prevailing CRR holders for the constraint. When it does not collect enough revenue to pay prevailing flow CRRs the full value for an interval, the ISO would have reduced the payments proportionally.
The plan called for scaling only the payments to holders of CRRs in the prevailing flow direction, while not scaling the payments due from counterflow CRR holders on the same constraint. The ISO contended that discounting counterflow CRRs would increase revenue insufficiency because those CRRs help fund prevailing flow CRRs.
CAISO said the trend of CRR revenue insufficiency has persisted into this year despite a recent uptick in congestion rents due to unusually high flow patterns. | CAISO
In denying CAISO’s proposal, the commission noted that it “has long held that counterflow and prevailing flow CRRs should be netted against one another such that the expected net value of two obligation CRRs of equal megawatts from A to B and B to A will be equal to zero.” The commission added that “we continue to believe that a symmetric approach is just and reasonable, while an asymmetric approach has not been shown to be just and reasonable.”
FERC also pointed out that the proposal would have the “undesirable” effect of reducing transparency in the CRR market.
“Market participants could face difficulties valuing a counterflow hedge relative to a prevailing flow hedge, since one would be discounted while the other would not,” the commission said.
In its Oct. 1 filing, CAISO acknowledged that its revised proposal relies on “essentially the same methodology” found in its prior proposal, with one “important” modification: a provision to net CRRs with both prevailing flow and counterflow CRRs within a holder’s portfolio before scaling the payment to that holder.
“In this Tariff amendment, the CAISO proposes a methodology that ensures that a CRR holder with a prevailing flow CRR from A to B can offset its obligation by holding a counterflow CRR from B to A,” the ISO said. “The CAISO proposes to first net a CRR holder’s portfolio of obligation CRRs of prevailing flow and counterflow CRRs with modeled flows on a particular constraint. After it nets these flows, the CAISO then would implement the same procedure it previously proposed through which it would scale CRR payments based on day-ahead market congestion revenue collected on individual constraints.”
CAISO said that it was addressing the commission’s concerns by creating “a procedure through which it can ensure a CRR holder’s modeled flow in both the prevailing and counterflow direction on a specific constraint offset each other.” It contended that complete symmetrical treatment of CRRs would prevent it from addressing the CRR funding issue by Jan. 1, 2019, because it would require greater redesign of software enhancements already underway to support the rejected proposal.
“The CAISO is able to follow the commission’s guidance without a major redesign with the proposal it submits here today because it can net the prevailing flow and counterflow a CRR holder’s CRRs place on a constraint upstream in the process and then feed that information into the scaling methodology the CAISO developed as part of its original CRR Track 1B proposal,” the ISO said.
CAISO contends its proposal “completely addresses” the concerns spelled out in the commission’s Sept. 20 order.
“Because the CAISO’s proposal is just and reasonable and it can be implemented by Jan. 1, 2019, it is unjust and unreasonable to force the CAISO and market participants to have to deal with the risks of revenue inadequacy for another year,” the ISO said.
CAISO asked that FERC set a shortened comment period ending no later than Oct. 11 and issue a ruling by Nov. 9.
Transmission planning in the Eastern Interconnection is well-coordinated among its planning authorities, ensuring NERC reliability requirements are met, according to a report released Wednesday by the Eastern Interconnection Planning Collaborative (EIPC).
The “State of the Eastern Interconnection” doesn’t get into the nitty gritty. At only 21 pages, it summarizes EIPC’s efforts since its formation in 2009 to examine the interconnection from the bottom up and ensure that planning coordinators’ individual regional transmission plans do not conflict with each other.
“The EIPC has completed a comprehensive description of Eastern Interconnection Planning Collaborative activities over the last decade, including results from its studies and analyses on the regional transmission plans of the major systems that make up the Eastern Interconnection,” said Stephen Rourke, vice president of system planning for ISO-NE and chairman of the EIPC Executive Committee. “The report details how the Eastern Interconnection grid is being planned in a coordinated manner, facilitated in part by the work of the EIPC.”
The Eastern Interconnection also includes the Canadian Maritime provinces: New Brunswick, Nova Scotia and Prince Edward Island. | ERCOT
EIPC is made up of 20 planning coordinators — including the five Eastern RTOs — in FERC-designated planning regions: the RTOs’ territories, the Florida Reliability Coordinating Council, South Carolina Regional Transmission Planning and Southeast Regional Transmission Planning. FERC Order 1000 only requires pairs of neighboring regions to coordinate their planning. SPP and MISO work together, for example, as do MISO and PJM — but PJM and SPP do not.
“EIPC efforts provide an additional forum to complement interregional coordination of the combined plans of the regional planning coordinators from an interconnection-wide basis,” according to the report. “While reliability requirements are achieved in the first instance at the regional level through regional processes, the work undertaken at EIPC confirms that the regional plans mesh properly into a combined plan for the interconnection.”
The heart of the collaborative’s work are its two “roll-up” studies, which involved combining the individual regional plans and their underlying data, such as resource mix and projected demand, into an integrated, interconnection-wide model.
The first study was conducted in 2014 for the summer peak hours in 2018 and 2023. The second, released in 2016, covered the 2025 winter and summer peaks.
As part of the latter study, EIPC identified several interconnection-wide power-flow interactions resulting from the regional plans that could cause constraints, leading planning coordinators to develop “conceptual upgrades” for inclusion in future planning cycles.
Another analysis in the study to locate potential constraints simulated 5,000-MW transfers between regions.
“The roll-up analyses demonstrate that the respective planning coordinator transmission planning and interconnection processes, which explicitly include requirements for coordination, have yielded transmission plans that are well coordinated on a regional and interconnection-wide basis,” the report says.
By Rory D. Sweeney, Amanda Durish Cook and Rich Heidorn Jr.
The first round of filings in FERC’s “paper hearing” on revisions to the PJM capacity market showed wide disagreement over the best way to address the impact of out-of-market subsidies on clearing prices.
Much of the debate in the dozens of filings focused on broadening the minimum offer price rule (MOPR) and modifying the fixed resource requirement (FRR), which were the basis of the hearing. But many stakeholders also proposed alternatives.
FERC ordered the hearing June 29 after concluding that increasing state subsidies for renewable and nuclear power were suppressing capacity prices. The commission’s 3-2 ruling required PJM to expand the MOPR to cover all new and existing capacity receiving out-of-market payments, including renewable energy credits (RECs) and zero-emission credits (ZECs) for nuclear plants. The MOPR currently covers only new gas-fired units.
The commission’s ruling rejected PJM’s April “jump ball” capacity filing (ER18-1314), granted in part a 2016 complaint led by Calpine (EL16-49) and initiated a Section 206 proceeding in a new docket (EL18-178). FERC also recommended creating an “FRR Alternative” allowing states to pull subsidized resources — and associated loads — from the capacity auction. (See FERC Orders PJM Capacity Market Revamp.)
PJM’s brief on Oct. 2 outlined its proposal for an “extended resource carve out” that builds on ideas it floated to stakeholders in August. (See PJM Unveils Capacity Proposal.)
The proposal would allow subsidized resources to obtain capacity commitments without clearing the capacity market, while creating a mechanism to restore prices to “the theoretically correct competitive level.”
The RTO said its proposal is intended to ensure both capacity offers and prices remain competitive and recognizes a bifurcated market will result in tradeoffs. “Making room, outside the auction, to accept subsidized generation as a PJM ‘capacity resource’ ineluctably will degrade auction prices. Unless the commission is prepared to accept a mechanism to adjust prices to their ‘correct’ level, this trade-off must be understood as an unavoidable consequence that comes once uneconomic resources are relieved from having to participate in the market.”
The Maryland Public Service Commission proposed what it called a “competitive carve-out approach” in which “a certain amount of load associated with the implementation of state policies is carved out of the existing capacity market and a separate competitive carve-out auction [is held] to meet the capacity needs associated with this amount of load.”
“This capacity would be provided by resources eligible to meet any state’s environmental policies,” the PSC wrote. “In effect, this proposed approach recognizes that, in the aggregate, resources eligible to meet states’ environmental policies and receive revenues for environmental attributes, may be capable of providing capacity to help meet the reliability requirements of all states and the region.”
It noted that the Organization of PJM States Inc. (OPSI) supported development of the idea.
‘Hokey Pokey’
The Electric Power Supply Association said the commission should prioritize protecting the capacity market from price suppression over accommodating state policies. It said the FRR Alternative would “effectively nullify” an expanded MOPR and could lead to the unraveling of the market.
“The FRR Alternative will actively push states towards the path of partial reregulation by letting them choose to be part in and part out of the [capacity] construct and, more importantly, away from reliance on competitive, organized markets,” EPSA said. It said the order would allow a state “to play the capacity market hokey pokey, putting its left foot into the [Reliability Pricing Model] market and pulling its right foot out.
“Even if the FRR Alternative provides greater transparency, that transparency does not make the resulting reregulation any more planned or any less damaging to what remains of the market,” EPSA said. “The only advantage of the transparency afforded by the FRR Alternative is that ‘investors, consumers and policymakers’ will have the opportunity to watch the collapse of the markets on the equivalent of a live-feed.”
Carbon Pricing
Eastern Generation, an EPSA member, filed a brief calling on the commission to treat the expanded MOPR as a “bridge” to PJM developing a mechanism for incorporating carbon pricing into its markets. “Carbon pricing is a more durable and sustainable long-term approach that will improve the efficiency of PJM’s capacity and energy markets while accommodating state and federal clean energy policies.”
A coalition of consumer advocates, environmentalists and industry stakeholders filed a joint brief arguing for prioritization of state interests.
“We frequently disagree on many issues before this commission, and some of us even disagree on certain aspects of this proceeding, such as the circumstances that should trigger a minimum offer price rule,” said the group, which includes consumer advocates from D.C. and Illinois, the Sierra Club, Natural Resources Defense Council, PSEG Energy Resources & Trade, Talen Energy, Exelon and the Nuclear Energy Institute.
“But as to the commission’s proposal regarding a resource-specific fixed resource requirement alternative (FRR-RS), the joint stakeholders strongly agree the commission’s decision should reflect certain basic principles: The commission should protect customers from paying for duplicate capacity and should preserve states’ ability to achieve clean energy policy goals without forcing states to withdraw altogether from the PJM market.” (See Zero-Emissions Backers Propose PJM Capacity Principles.)
In its standalone brief, Exelon called on the commission to “express its willingness to entertain a Section 205 filing from PJM incorporating carbon pricing.”
“Integrating a carbon price into PJM’s markets would reduce or eliminate the need for states to address carbon emissions from the power sector in other ways,” the company said.
PURPA Resources
Allco Renewable Energy said qualifying facilities under the Public Utility Regulatory Policies Act should have the option of choosing the FRR Alternative but should not be subject to the expanded MOPR, which it said would “unlawfully restrict, interfere and diminish the congressionally mandated right of a qualifying facility to sell energy and capacity.”
Columbia University’s Sabin Center for Climate Change Law insisted state environmental policies do not interfere with FERC-regulated markets. “Unless implemented with care, FERC’s proposed Tariff revisions could interfere with the operation of state clean energy policies, effectively preventing states from exercising their authority over generation,” it said. “There is no valid basis for concluding that REC, ZEC and other clean energy policies interfere with wholesale market operation.”
A Matter of State Jurisdiction
The Governors’ Wind and Solar Energy Coalition said FERC’s minimum bid requirement would intrude on states’ historical right to choose their own energy mix: “If the commission pre-empts or restricts the states’ ability to regulate environmental effects from energy power production, it would constitute a dangerous shift in the balance between state and federal authority.”
However, the Natural Gas Supply Association said it was “heartened” by what it called FERC’s “strong defense of the competitive markets it regulates.”
NGSA said PJM’s status quo would create an “untenable” environment where investment uncertainty erodes reliability and regulators pick winners and losers.
“It is no easy task to achieve a balance that allows states to make their own procurement decisions, while still ensuring those decisions do not harm the wholesale markets in your jurisdiction. Despite considerable pressure to disregard actions that erode the integrity of PJM’s capacity market, the commission had the courage to say, ‘no more,’” NGSA CEO Dena Wiggins wrote.
The American Coalition for Clean Coal Electricity and the National Mining Association also commended FERC on what they viewed as an effort to keep PJM’s market functioning through an expanded MOPR applied to all subsidies.
However, the groups asked for an exception to the MOPR: an exemption on a possible fuel security valuation in the PJM capacity market. They said a new MOPR shouldn’t “counteract federal efforts to ensure grid resilience and promote national security.” The groups urged FERC to require PJM to create a separate capacity auction for resources that can guarantee fuel security for a minimum number of days.
PJM’s “current market design is contributing to the loss of fuel-secure electricity resources, while encouraging reliance on pipeline-dependent and intermittent resources,” ACCCE and NMA said.
EPSA countered that any federal price supports for nuclear and coal units should subject them to the MOPR.
Other Out-of-Market Payments?
In arguing against an expanded MOPR, the Union of Concerned Scientists said PJM’s proposal “would arbitrarily provide an exemption for resources that have one kind of state-supported revenue, but not for other kinds of state-supported revenue.”
State RPS and impact on PJM | PJM
UCS argued PJM’s fleet of existing resources with state-sponsored out-of-market payments is “substantial” and greater in number than PJM has characterized.
“If the fundamental principles presented by both PJM and the commission are as important as suggested, and the commission has found that any price suppression due to out-of-market payments makes the PJM capacity auction results unjust and unreasonable, then there cannot be MOPR exemptions for investor-owned plants that have been receiving cost-recovery through state-administered rates,” UCS wrote. It also said PJM did not collect the list of states with out-of-market revenues for investor-owned generation through either a renewable portfolio standard, zero-emission credit program or regulated cost-of-service.
RPS National Map | National Conference of State Legislatures
“All of the states in PJM have one or more of these mechanisms that provide the means for generation to either enter or remain viable in PJM’s capacity market,” UCS said.
UCS said the fact that PJM’s Tariff allows zero-priced offers is evidence of state-supported cost recovery to keep resources viable in the capacity market.
APPA: Start Over
The American Public Power Association went for a scorched-earth approach, challenging PJM’s RPM itself.
The group argued PJM’s mandatory capacity market with a strict MOPR is “ill-suited” to achieving a diverse resource mix. It said PJM’s MOPR “now threatens to become an all-purpose restriction on any support for generation outside of revenues obtained through the PJM energy and capacity markets” and could “ultimately raise capacity prices without achieving any clear benefits.”
“The time is ripe to revisit the RPM construct in a comprehensive manner,” APPA said, rather than “doubling down” on a mandatory capacity construct with a “vastly expanded MOPR.”
APPA also argued self-supply resources used to meet the load of public power and cooperative utilities should not fall under an expanded MOPR, arguing vertical integration and tax-exempt financing do not constitute out-of-market support.
IMM’s ‘Sustainable Market Rule’
PJM’s Independent Market Monitor also suggested re-envisioning the RTO’s structure with what it calls a “sustainable market rule” that it argues is simple enough to be implemented in time for the next Base Residual Auction. While the Monitor attempted to differentiate its proposal from a MOPR, it would require all resources to offer into the BRA at their avoidable cost rate (ACR).
“A competitive offer in the capacity market is the marginal cost of capacity, or net ACR, regardless of whether the resource is planned or existing,” the Monitor wrote. “All capacity has a must-offer requirement and all capacity offers are included in the supply curve in the capacity market at competitive levels. All megawatts required for reliability are included in the capacity market demand curve (VRR curve).”
The Monitor acknowledged that load-side fears might be realized with this approach, but that “the possibility that customers may pay twice has been accepted by the courts” and FERC.
CASPR Appears
Vistra Energy and Dynegy Marketing and Trade proposed the Capacity Performance with Sponsored Supply (CaPSS), which it said is based on ISO-NE’s FERC-approved Competitive Auctions with Sponsored Policy Resources (CASPR) structure.
The two-stage auction would require all resources to offer in at their going-forward costs. PJM would create a table of resource-type ACRs, and any resource that believes its going-forward costs are below its applicable value in the RTO’s table would request a review to validate its argument. The second stage would be “purely voluntary” and allow existing resources that received a capacity obligation but are willing to permanently exit PJM’s markets to “give up” their obligations “in their entirety” to resources seeking subsidies that didn’t receive obligations in the first stage.
Next Steps
FERC faces a daunting task of threading the needle between at least eight proposed options for the MOPR and numerous modifications on both its FRR concept and PJM’s carve-out. Reply briefs in the docket will be due Nov. 6.
FERC on Monday granted MISO a two-year lead time to implement a new offer cap into its fast-start pricing mechanism, while also directing the RTO to submit yet another compliance filing to meet Order 831 requirements.
The commission’s ruling set an Oct. 1, 2020, deadline for MISO to incorporate a $2,000/MWh hard cap for verified cost-based incremental energy offers into fast-start pricing (ER17-1570-002).
In a March ruling on a previous compliance filing, FERC accepted much of MISO’s plan to permanently double its hard offer cap, but it also required the RTO to pledge to apply the new hard cap to adjusted energy offers from fast-start resources. (See FERC OKs MISO’s Doubled Offer Cap, Orders Alterations.)
In the event FERC denied the extra time for implementation, MISO had also sought rehearing of the commission’s March order, warning it would otherwise need permission to “resort to manual processes” to enforce the caps. Citing the ongoing replacement of its market system platform, MISO contended it would likely need more time to “make appropriate adjustments to automate the requirements of Order No. 831” and “complete necessary system software changes.” The RTO also pointed out FERC granted ISO-NE a similar two-year lead time last November.
“We find that MISO has shown good cause for the granting of this requested effective date because it will allow MISO sufficient time for the development, testing and implementation of software needed to enable MISO’s existing market platform to apply the offer cap requirements to fast-start pricing,” FERC said.
One More Compliance Filing
Monday’s order also approved other revisions FERC had ordered in the March compliance filing, although it directed MISO to refine its proposed rules to address adders to the soft offer cap.
FERC accepted MISO’s fuller description of the data verification process for offers, how it would determine make-whole payments under the new offer cap and the process allowing market participants to dispute potential revenue sufficiency guarantee make-whole payments. The commission also accepted MISO’s clarification that its Independent Market Monitor will use data from its operating cost survey to determine facility reference levels. The IMM relies on the survey to collect operating cost data for market participants.
But in siding with the argument of a group of Midwestern transmission-dependent utilities (TDUs), FERC also directed MISO to submit another compliance filing to clarify that adders included in cost-based incremental energy offers above the soft cap of $1,000/MWh must be limited to a combined $100/MWh. MISO must also make clear those adders cannot be included in a resource’s after-the-fact make-whole payment, the commission said .
FERC also denied a request for a rehearing of its March order from the same group of TDUs, who argued the commission was too quick to accept MISO’s stance that outage risk is a verifiable component of energy cost rather than part of the $100/MWh adder above the soft offer cap. The TDUs argued it was arbitrary and capricious for FERC to find that outage risk is not an above-cost adder when it only used MISO’s rationale that outage risk is already included in a resource’s reference level in its current mitigation processes.
FERC didn’t bite at their argument.
“MISO explained that outage risk is a legitimate short-run marginal cost calculated separately for each resource based on validated data provided by market participants,” the commission wrote. “MISO also explained that incorporating this risk in a resource’s reference level continues MISO’s existing mitigation processes. As such, outage risk is a proper component of MISO’s reference level and is not an adder to verifiable costs pursuant to Order No. 831. Midwest TDUs have not proffered any arguments or evidence that contradicts MISO’s explanation of these risks.”
MARLBOROUGH, MASS. — Fuel security public policy and the role of traditional and non-traditional fuels in New England highlighted discussions at the Northeast Energy and Commerce Association’s 2018 Fuels Conference on Thursday.
“Natural gas is as pertinent and important as ever, particularly in New England,” Day Pitney attorney Joseph Fagan said.
“If it’s not easy — in this region especially — to site pipeline or gas infrastructure, it only makes sense that we’ll see virtual transportation become more important. It makes sense that LNG is going to become more of an issue,” Fagan said. “How is [ISO-NE] going to address fuel security and reliability when we have the reality that we have no new pipelines coming into this state … and we have a large plant [Mystic] that — unless things change — may be retired?”
In July, FERC tentatively accepted a cost-of-service agreement between ISO-NE and Exelon for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues related to cost justification (ER18-1639). (See “Fuel Security,” Overheard at ISO-NE Consumer Liaison Group Meeting.)
The goal to reduce greenhouse gas emissions is driving policy in the region, said Brian Jones, senior vice president of energy consultancy M.J. Bradley & Associates.
“A lot of the resources that ISO New England manages today are a product of that and have to do with air quality and GHG,” Jones said. “Fuel supply is an obvious one, and pipeline constraints into the region are another. We face a lot of challenges, with six states that have pretty aggressive policies on energy and environmental issues, and I don’t think that’s going to change.”
A big chunk of heating demand met by gas cannot be substituted with renewables or energy storage, and Elon Musk has not yet invented a battery-powered heater, said Andrew Bradford, CEO of energy consultancy BTU Analytics.
“What the latent natural gas demand is in New England is a good question,” Bradford said. “We look at 0.75 Bcfd in winter, 1.5 Bcfd max, and 0.5 Bcfd on the peak price day and see there could be demand for around 2 Bcfd.”
Given the constraint on pipeline supplies, “for natural gas end-users in New England, there is no silver bullet,” he said.
There could be a large truck though. The lack of gas infrastructure has created a market for Xpress Natural Gas, a compressed natural gas distributor that now sends trailer trucks from its 40-Bcfd capacity terminal in Montrose, Pa., to inject into the Iroquois Pipeline at a terminal in New York.
Gary Ritter, XNG’s vice president of sales, said the company serves customers from Prince Edward Island to the Mid-Atlantic states, both companies lacking pipeline access and “to facilities on the pipeline grid, bringing incremental supplies to capacity-constrained areas.”
The Montrose terminal last winter loaded approximately 25 MMcfd filling some 60 trailers at an average capacity of 400 Mcf each.
Shaving of natural gas peak demand is the top use of LNG in New England, such as at National Grid’s waterfront facility in Salem, which holds 12 million gallons of LNG, the equivalent of 1 Bcf of natural gas, said Jonathan Carroll, director of U.S. business development for Energir, formerly Gaz Metro, the largest gas distributor in Quebec.
“This facility or facilities like it are very common in New England,” Carroll said. “As a matter of fact, there are close to 40 of these peak-shaving facilities in the region. Some actually have liquefaction and can produce their own fuel; others do not.”
In addition, he said there are currently three LNG projects under development in the region: Granite Bridge, Northeast Energy Center and REV LNG.
McKenzie Schwartz, a National Grid gas analyst, said the market for renewable natural gas (RNG) is taking off because of support from state and federal policies, such as EPA’s Renewable Fuel Standard.
RNG is derived from biomass and is fully interchangeable with natural gas.
“We believe this can help National Grid move our industry toward a lower-carbon future,” Schwartz said.
National Grid pioneered technology in 1982 as the first utility to allow an RNG project to interconnect. Its Staten Island Landfill project is still in operation, injecting 2,000 dekatherms/day into the distribution system.
Emily Lewis, senior policy analyst for Acadia Center, an environmental advocacy organization, said that if states push renewable energy policies, wind and solar energy could generate 45% of New England’s electricity in 2030, versus 24% under current trends.
Lewis and Richard Murphy, energy markets director at the American Gas Association, debated how much electric heat pumps can reduce GHG emissions.
Repeating findings she shared earlier in the month at the ISO-NE Consumer Liaison Group meeting in Connecticut, Lewis said electrification of space heating, under current trends, would reduce GHG by 3% by 2030 and by as much as 16% under an accelerated policy scenario. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)
Murphy countered with an AGA study that contends aggressive residential electrification of heating and cooling would reduce national GHG emissions by only 1 to 1.5% in 2035. (See State Regulators Hear Challenges, Promise of Electrification.)
There are three common themes in efforts to achieve deep decarbonization of the energy sector, he said. One is to dramatically increase efforts around energy efficiency. The second is to advance policies that would require up to 100% of all the electricity generated in the U.S. to come from renewable resources. The third is to replace all end-use applications from natural gas or fuel oil to electric alternatives, he said.
“The region uses more than twice as much energy in peak winter months as in the summer, so what would the overall cost be of converting residences away from natural gas and to electrification?” Murphy said. “When we look at the data in the residential market, we really start to think about the impacts on consumers.”
Approximately 60 million homes in the U.S. would have to be converted from natural gas heating to electricity, he said, which is a “massive undertaking” for such a modest environmental gain.
Oil comprises only 1% of New England’s power generation on average. But the fuel remains relevant at times, such as a cold snap last winter when oil accounted for 37% of the region’s electricity generation, said Kevin Grant, an oil trader at Sprague Energy.
The ability of oil to fill the fuel gap in winter is compromised by the cost of maintaining inventory, delivery logistics and the changed nature of the market, he said.
“Power generators, while still important, no longer drive the commercial oil market,” Grant said. “A fuel supplier is going to gear their operations to the customer who comes in 300 times a year, not once a year. Logistics is also an issue, with a limited number of barges and trucks. Transportation companies have right-sized their assets in response to market demand the same as everyone else.”
Stephen Leahy, vice president of the Northeast Gas Association, said, “Natural gas is the last fossil fuel left standing for power generation, but oil is still the No. 1 fuel consumed overall in Massachusetts in terms of total Btus. It’s mostly in the form of gasoline, but it’s still oil.”
How are we going to balance energy needs with environmental goals? asked Nancy Seidman, senior adviser to the Regulatory Assistance Project.
“The first principle is to put energy efficiency first,” Seidman said. “What it’s done for New England has been huge. … To have demand actually dropping is fabulous.”
VALLEY FORGE, Pa. — The PJM Markets and Reliability and Members committees on Thursday approved Operating Agreement revisions that would eliminate the requirement that the RTO liquidate a member’s financial transmission rights when it falls into default.
The proposed changes are in response to the June default of GreenHat Energy, which could cost other members more than $145 million. (See Doubling Down — with Other People’s Money.)
PJM presented stakeholders with four packages of revisions at the MRC. Two of those had received a majority sector-weighted vote out of 24 proposals at a special committee session Sept. 18. Option B, Thursday’s winner, received 3.8 out of 5 in support, while Option J1 — which would have liquidated all of a defaulting member’s long-term positions except those remaining in the 2018/19 planning year, allowing them to go to settlement — received 3.3.
After the special meeting, Macquarie Energy, with support from Apogee Energy Trading and Vitol, offered two more proposals: B’ and J1′ (read as “B prime” and “J1 prime”), identical to B and J1 except that they would only apply to GreenHat’s portfolio. Macquarie said these proposals would allow for continued discussion of PJM’s liquidation process after dealing with GreenHat.
All four proposals included two identical provisions. One would ensure that the maximum $10,000 default allocation assessment is charged only once for a default that spans multiple years, rather than each year.
The other would allow those who sold FTRs to the defaulting member in a bilateral trade to take them back if their most recent auction clearing prices were less than the purchase prices.
Brian Wilkie of Rockland Electric Co. moved for considering B without the bilateral provision, which Exelon’s Jason Barker seconded. This proposal was dubbed B” (“B double prime”).
Dean Bickerstaff of Hartree Partners moved, with CPower’s Bruce Campbell seconding, that the MRC also consider Option K1B, which had only received 1.99 in support at the special meeting. K1B would have also allowed the 2018/19 positions to go to settlement, but it would have canceled all defaulting long-term FTRs. It also would have forced counterparties to the defaulters’ bilateral trades to reassume those positions.
Only B received the 3.34 sector-weighted supermajority support necessary to move on to the MC, with 3.73 in favor. B” received 1.88, B’ and J1 each received 1.8, J1′ got 1.44 and K1B 0.44.
At the MC later Thursday, Bob O’Connell of Panda Power Funds moved that the committee vote to accept the MRC’s vote as its own, but he withdrew the motion when DC Energy’s Bruce Bleweis called for a sector-weighted vote on it. Committee Chair Michael Borgatti, of Gabel Associates, called for a sector-weighted vote on B anyway, and the proposal passed with 4.01 in favor.
CFO Suzanne Daugherty explained that PJM will submit B as three separate “prongs” to FERC, with the $10,000 maximum and bilateral provisions in their own filings. Daugherty said this was done so that if the commission ends up rejecting one provision, it would not be forced to reject the entire package.
Members also reaffirmed their opposition to the status quo, with only 0.5 in support. If FERC rejects the proposal to eliminate the liquidation requirement, the RTO will ask in an amendment to a pending filing that the commission allow all of GreenHat’s positions to go to settlement until the end of February to allow for additional stakeholder discussion of alternatives to the status quo. PJM has asked the commission to allow the positions to go to settlement through Nov. 30, but FERC has not acted on the filing, nor on the RTO’s waiver request seeking permission to only liquidate prompt month FTRs.
PJM, Monitor Come to Agreement on Opportunity Cost Calculator
VALLEY FORGE, Pa. — Stu Bresler, PJM senior vice president of operations and markets, announced at the Members Committee that he and Independent Market Monitor Joe Bowring had signed an agreement regarding the use of the Monitor’s opportunity cost calculator.
Under the agreement, Monitoring Analytics will continue to use its calculator to calculate the opportunity costs for market participants and will explain its inputs and logic to PJM to demonstrate that the unit-specific opportunity costs are compliant with the OA.
In return, PJM acknowledged that the calculator is the Monitor’s intellectual property, that the agreement is not a license for PJM to use the calculator and that the RTO will not attempt to reverse engineer it.
In response to stakeholder questions, Bresler said he was not sure how long it would take for PJM to get the Monitor’s data, but he estimated it would take two weeks.
The agreement is the culmination of a yearlong dispute between PJM and the Monitor over opportunity cost calculations, which came to a head in August when the Markets and Reliability Committee approved Tariff revisions, proposed by Bob O’Connell of Panda Power Funds, allowing participants to use the Monitor’s calculator. The RTO said it would be willing to allow its use but needed to understand the details of how it worked, something at which the Monitor balked. (See PJM Monitor Holding Firm on Opportunity Cost Calculator.)
The Monitor has repeatedly criticized PJM’s calculator as inaccurate and the RTO’s process for verifying inputs as flawed.
Calpine’s David “Scarp” Scarpignato asked what would happen to a generator if the calculators gave different results, and the generator used the one that gave it a higher price. Bowring answered: “It is still our responsibility to calculate opportunity costs, and if you propose to use an opportunity cost that is too high, we will let you know and refer you to FERC as necessary.”
O’Connell, who had originally been scheduled to speak before Bresler on the topic and had deferred, moved to postpone the vote on his proposed revisions to the next meeting to give PJM and the Monitor time to put the new process in effect. The motion was approved by acclimation with no objections or abstentions.
Quadrennial Review
The MRC voted on four packages of revisions as part of PJM’s quadrennial review of the variable resource requirement (VRR) curve, but none of the proposals received majority support.
The committee’s sector-weighted votes were advisory to the Board of Managers, which has ultimate approval of what is filed with FERC.
The MRC voted on proposals by PJM, the Monitor, Calpine and the D.C. Office of the People’s Counsel. Several stakeholders noted that their support hinged on the reference unit used in the calculations. PJM and the Monitor have proposed changing it from General Electric’s 7FA combustion turbine to the new 7HA, while the OPC proposed using an F- and H-class combined cycle. Calpine’s proposal maintains use of the 7FA.
Exelon’s Jason Barker said his company was against the HA being used, noting that GE has had trouble with its newest turbine class.
Reports of problems with the H-class began coming in last year, and Exelon recently had to shut down two power plants in Texas after GE identified a flaw in the design.
PJM’s proposal came in first with 2.32 in favor, followed by Calpine’s with 2.14, the Monitor’s with 1.96 and the OPC’s with 1.42.
At the MC, Carl Johnson, representing the PJM Public Power Coalition, moved to adopt the MRC’s votes for the sake of efficiency. This was quickly approved by acclimation, with only one objection.
VOM Proposal Rejected by MC
A revised proposal by PJM to include certain variable operations and maintenance (VOM) costs in cost-based energy offers failed to win supermajority endorsement from the MC, garnering only 2.92 of a sector-weighted vote.
At last week’s MRC, PJM’s Melissa Pilong presented several revisions to an RTO proposal that had been rejected, along with four others, by the MRC in July. (See PJM Ponders Advancing VOM Effort over Objections.) The changes included removing the ability for resources that did not clear the capacity auction to recover their fixed costs in their energy offers.
Originally, the proposal included only changes in Manual 15, which would only require MC endorsement and approval by the Board of Managers. As part of the new proposal, PJM would also add clarifying language to the Tariff and OA, meaning it would have to be approved by FERC.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said that while he appreciated the additional FERC provision, he was frustrated that the VOM proposal kept coming up with little change. In a sector-weighted vote motioned for by Poulos, the MRC advanced PJM’s new proposal, with 3.4 in favor.
Later at the MC, Poulos motioned to delay a vote on the proposal, which Chairman Borgatti set for a sector-weighted vote. Before members voted on whether to vote, however, Bresler noted that because of the Oct. 12 deadline for filing changes stemming from the quadrennial review, PJM had set both matters for that day. CEO Andy Ott also urged members to vote, saying “it would be helpful to the board if you resolved this today.”
PJM’s proposal would allow major maintenance costs to be included in the VOM costs in energy offers. That would mean that they would be not included in the cost of new entry, which is set as part of the quadrennial review. Without the vote, Deputy General Counsel Chris O’Hara said that it would be difficult for PJM to justify the quadrennial review. “We would have to tell FERC we lack sufficient information to ensure the quadrennial review is just and reasonable,” he said.
With only a simple majority needed, members resolved to vote that day, with 3.1 in favor, before the actual proposal failed in a subsequent vote. Bresler later told RTO Insider that PJM will discuss with the board whether it should file the proposal under Federal Power Act Section 206, which is done when a proposal lacks member support. The RTO would have to show that its existing OA language regarding VOM costs is unjust and unreasonable, rather than just show that its proposal is just and reasonable.
Liaison Committee Meeting to be Closed to Nonmembers
Near the end of the MC meeting, a motion by Poulos for a temporary waiver to the Liaison Committee’s charter to allow some nonmembers to attend its upcoming Oct. 3 meeting as listening-only participants failed in a sector-weighted vote, with only 2.43 in favor.
According to PJM’s Dave Anders, it has been accepted practice to allow nonmembers — such as state regulators and their staff, FERC staff, PJM management and staff, and the Monitor — to attend since an LC meeting in D.C. one year coincided with a meeting of the National Association of Utility Regulatory Commissioners several years ago. State regulators and FERC staff had asked to be allowed to attend the LC, and “how could we say ‘no’ to that?” Anders said.
In an email to RTO Insider after the meeting, Poulos said his motion was prompted by a member’s request to enforce the charter during a “prep call” for the upcoming meeting. Poulos declined to name the individual who made the request.
“It was not the first time I’ve heard this request, but this time the request was gathering support from the others on the call,” he said. “I thought the decision was important enough to be heard by the entire stakeholder body.”
At Thursday’s meeting, Barker said he was disappointed that PJM had been lax in its enforcement of the charter. “This is our private discussion with the board,” he said. “This is our one opportunity.”
Alex Stern of Public Service Electric and Gas, who participated in the formation of the Liaison Committee and its charter several years ago, echoed the statements of other stakeholders. He said the charter should be respected and that it had been thoroughly developed to allow members direct and unfettered access to the board.
Before voting on Poulos’ motion, O’Connell moved to keep individual members’ votes private, only allowing the board to view them. This passed with 3.42 in favor.
Ott said PJM would notify members of the charter’s stricter enforcement going forward.
“Member actions at PJM’s September Members Committee reduced transparency in PJM governance,” said Illinois Commerce Commissioner John Rosales, president of the Organization of PJM States Inc., in a statement provided to RTO Insider. “This is an issue which needs examination going forward.”
On the left side of each page is a sidebar with links to each section in a document, and each page contains hyperlinks to referenced sections and attachments. Every term on a page has a clickable pop-up containing its definition.
There’s even a search bar.
The web versions are technically unofficial versions, as PJM changed the formatting and removed redundancies from the official, FERC-approved PDFs to make them more readable.
PJM staff presenting the new pages at the MRC were enthusiastic, and stakeholders expressed gratitude.
The Tariff PDF is a 3,554-page, 58-MB file. Its Table of Contents alone runs for 29 pages.
The PDFs for the OA and RAA are a bit more manageable at 630 and 251 pages, respectively.
RENSSELAER, N.Y. — NYISO experienced six days with peak loads of more than 31,000 MW this summer, compared with last summer’s actual peak of 29,677 MW, the ISO’s Management Committee learned last week.
New York ambient temperatures were above the 20-year average in May, July and August, and near average in June. Albany registered 19 days over 90 degrees Fahrenheit this summer, which has occurred only 10 times since 1874, Wes Yeomans, vice president of operations, said as he delivered the Summer 2018 Hot Weather Operations report.
Total load (GWh) was above 50/50 projections this summer, while peak load was below the 50/50 projection for the 5th consecutive summer. | NYISO
Total New York Control Area load was above 50/50 projections this summer, while peak load was below the 50/50 projection for the fifth consecutive summer. The summer 2018 50/50 forecast was 32,904 MW, while actual peak load hit 31,861 MW on Aug. 29. The all-time peak of 33,956 MW occurred on July 19, 2013.
NYISO on Aug. 29 activated 481 MW of demand response for Zone J to support New York City transmission security from noon to 6 p.m., while utilities in the state also activated their DR programs. The ISO will report scarcity pricing outcomes at the Market Issues Working Group meeting in October.
Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, said the ISO called DR in Zone J for the two largest contingencies, not just the single largest.
“So, these DR resources are needed to meet the reserve requirements for Zone J — which is a real reliability requirement, but it’s not reflected in the market,” LeeVanSchaick said. “It’s really a failure of the market to procure reserves for this requirement, not an operational issue of activating excessive demand response.”
Yeomans replied that the ISO is engaged in a project to review reliability criteria.
Significant summer transmission outages were the 345-kV Hudson-Farragut B and C Lines, the 230-kV St Lawrence-Moses L33P and the 345-kV Dunwoodie-Mott Haven 71, which was forced out on July 1 in New York City near the beginning of a six-day heatwave and remains out of service.
Many more outages occurred, but the ISO only reports those that were out for a long time and impacted power availability during a heatwave, Yeomans said.
NYISO’s behind-the-meter solar installations have increased six-fold since 2013, with total registered nameplate capacity around 1,200 MW, Yeomans said. “But you’d need all of the panels aimed south and working in full sun to achieve that.”
Yeomans said pop-up showers on a hot day can reduce load by around 500 MW, prompting Mark Younger of Hudson Energy Economics to suggest that the weather normalization program at the ISO should try to account for this effect on net load.
Weather normalization refers to smoothing chaotic weather data from several years in order to provide a useful model for load forecasting.
AC Transmission Project on Hold
NYISO CEO Brad Jones informed the MC about why the ISO’s Board of Directors had not yet voted on the AC Public Policy Transmission Project approved by the committee in June.
“The board has looked at this and asked for additional data,” Jones said. “We hope to get as much as we can to them for the October board meeting but are not sure we’ll have all of it.” (See NYISO MC Supports AC Transmission Projects.)
The MC in June approved joint proposals by North America Transmission and the New York Power Authority to build two 345-kV transmission projects that could cost $900 million to $1.1 billion.
NYISO Proposes 8.5% Budget Increase
The ISO’s draft 2019 budget totals $168.2 million, including an 8.03% increase in revenue requirement from this year’s budget and a 0.45% decrease in projected megawatt-hours, for an overall Rate Schedule 1 increase of 8.51%.
Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the review of a budget allocated across a forecast of 157.1 million MWh, for a Rate Schedule 1 charge/MWh of $1.071, compared to $155.7 million allocated across 157.81 million MWh for a Rate Schedule 1 charge/MWh of 98.7 cents this year.
The ISO has held the budget to an approximately 1% average increase in revenue requirement for the past four years, “but this trend is not sustainable for the 2019 budget,” Ackerman said.
One big factor driving up spending is repayment of a $30 million loan to finance an Energy Management System/Business Management System upgrade project, Ackerman said. Other factors include debt service, new software needs, professional consultant fees, and salaries and benefits. The ISO plans to add 15 new positions over the coming year.
The board will review the draft budget Oct. 15, the MC will vote on a new budget Oct. 31, and the board will consider the final proposal on Nov. 13, 2018.
MC Approves 2018 Reliability Needs Assessment
The committee approved the ISO’s 2018 Reliability Needs Assessment (RNA), which identified no reliability needs on the state’s bulk power system over the coming decade. The board will consider the RNA in October.
Resource Planning Manager Laura Popa reported that the 2018 RNA is based on information from the 2018 Gold Book (the annual transmission planning and evaluation report filed with FERC), historical data and market participant data.
The 2018 RNA is based on information from the Gold Book 2018, the annual transmission planning and evaluation report (Form 715) filed with FERC, historical data, and market participant data. | NYISO
For transmission security, planners evaluated Year 1 (2019), Year 5 (2023) and Year 10 (2028) for summer peak baseline power flow cases, and found no reliability needs for Years 1 and 5. However, for Year 10 they identified one preliminary reliability need: a 3-MW deficiency in Eastern Long Island.
The deficiency would stem from a 1% overload on the 138-kV Brookhaven-Edwards Avenue line (Line 864), the contingency being the loss of the 138-kV Wildwood-Riverhead line (Line 890) and returning the system to normal criteria. PSEG Long Island presented an updated and firm long-range transmission plan at the June 28 Electric System Planning Working Group/Transmission Planning Advisory Subcommittee that involved scheduling terminal upgrades at the Brookhaven 138-kV substation to be in service in June 2019. With these upgrades the overload is resolved, according to NYISO.
LeeVanSchaick elaborated on MMU comments filed with the ISO that markets are generally well designed, noting an inconsistency between the assumed value of certain resources needed for reliability transmission planning purposes and how NYISO’s capacity market compensates those resources.
The MMU recommends the ISO periodically reassess the assumed relief from land-based wind generators and special case resources (SCRs) in transmission security planning assessments to ensure levels are commensurate with their expected performance and availability. It also asked the ISO consider using different assumptions for offshore wind generators than for land-based wind units, and possibly further discount the capacity ascribed to wind generators and SCRs, which represent load capable of being interrupted upon demand or a distributed generator rated 100 kW or higher.
Failure to maintain consistency between planning reliability criteria and capacity market requirements may increase the need for regulated transmission solutions and reliability-must-run contracts to satisfy reliability needs, which becomes particularly important as more wind generation is built in import-constrained areas over the coming decade, the MMU said.
“It’s important to think about this as the resource mix is turning over,” LeeVanSchaick said.
ISO Customers Mostly Satisfied with Query Response
Customers and market participants continue to be pleased with how NYISO interacts with them and are nearly 100% satisfied with how the ISO answers their questions, according to a biannual customer satisfaction survey conducted by the Siena College Research Institute (SRI).
SRI Director Don Levy told the MC his group recorded a 98% “customer inquiry satisfaction” score on the survey, which combined a market participant satisfaction score (89.9%) with assessment of performance (76.8%) for an overall approval rating of 84.7%.
Levy said the surveys identified several areas for improvement, including tariff, legal and regulatory webpages; ISO manuals, technical bulletins and user’s guides; market mitigation and analysis interactions; transparency of operations; and increasing the consideration of stakeholder input.
MC Approves Revisions to OATT Attachment L
The MC approved revisions to Attachment L of NYISO’s Open Access Transmission Tariff updating terms regarding transmission congestion contracts (TCCs).
Gregory R. Williams, manager of TCC market operations, said the updates to Section 18.1.1 (Table 1A) of Attachment L followed an annual review. Among the changes were revising contract expiration dates from Dec. 31, 2017, to Dec. 31, 2027, for two specified agreements.
If authorized by the board at its meeting in October, the ISO will file the revisions with FERC.
MC Approves Change to Unsecured Credit Scoring Model
The MC approved changes to the ISO’s unsecured credit scoring model following its first review of the methodology since 2009.
John Jucha, senior credit analyst for corporate credit, said that under the new model, the 12.7% weighting for revenue/market capitalization in predicting a default will be replaced with a measure of total assets. The review found that asset size variables were not represented in the model despite their “strong predictive power.”
Rating all market participants — including corporations, financial institutions and government entities — on the same scorecard may mask differences between them, the analysis found.
If authorized by the board in October, the ISO will file the revisions to Attachment K of the Market Administration and Control Area Services Tariff with FERC.
FERC on Thursday approved Emera Maine’s proposal to provide discounted transmission service to two ReEnergy biomass plants in northern Maine (ER18-2123, ER18-2124).
The commission’s Sept. 27 order also found that a protest from Maine Gov. Paul LePage lay outside its jurisdiction. LePage alleged that Emera would recover the cost of the discounts from the state’s retail customers, but FERC said retail rates are regulated by the Maine Public Utilities Commission. “Our findings here are limited to whether Emera Maine’s proposed commission-jurisdictional wholesale rates are just and reasonable,” FERC said.
ReEnergy employee leads tour of Fort Fairfield biomass generator. | Biomass Power Association
ReEnergy owns a 39-MW biomass-fueled power plant in Ashland and a 37-MW biomass plant in Fort Fairfield. Both facilities have market-based rates and are allowed to sell their output into ISO-NE’s energy, capacity and ancillary services markets.
Under the agreements, Emera will provide non-firm transmission service from the two ReEnergy facilities to ISO-NE for $0/MW-month for Oct. 1, 2018, through Dec. 31, 2019, and $1,132/MW-month for Jan. 1, 2020, through Dec. 31, 2020.
ReEnergy said the discounts were needed to remain in business because of the pancaked transmission charges they pay to move energy to the ISO-NE market.
Emera would provide service to the plants through the Maine Public District transmission system, which is not directly interconnected with any portion of the U.S. transmission grid. Entities interconnected with it can only access the New England grid over transmission facilities in New Brunswick, Canada, which NB Power owns and operates.
Emera said it agreed to the discounts because ReEnergy provides jobs in northern Maine.
