ISO-NE on Wednesday askedFERC to approve a limited Tariff waiver that would allow market participants to adjust or withdraw their retirement or permanent delist bids for Forward Capacity Auction 15, which are due March 13.
In seeking the flexibility for its participants, the RTO noted the potential for its Energy Security Improvements (ESI) market design to change after the submission deadline.
FCA 15 covers the capacity commitment period beginning June 1, 2024, when the grid operator now intends to implement ESI.
The 680-MW Pilgrim nuclear plant in Plymouth, Mass. | NRC
ISO-NE said that if FERC grants the waiver, retirement bids will remain due March 13 and that the waiver would apply in the event the RTO makes a non-clerical change to the ESI market rules, in which case a participant could either update or withdraw its delist bid.
“It is very possible” that the RTO will not have completed the market design and Tariff revisions for ESI by the existing capacity retirement deadline, it said in its request.
The Markets Committee will likely take an initial vote on ESI before March 13, but the design may evolve further before a final vote by the full NEPOOL Participants Committee is taken on or around April 2, 2020, the RTO said.
“Should this occur, the delist bids might not accurately reflect the impacts of the ESI market rules, in the form in which the rules are filed with the commission on April 15, 2020,” it said.
State regulators from the SPP and MISO footprints continue to discuss opportunities to contribute to the RTOs’ transmission planning analysis, Adam McKinnie, chief regulatory economist for the Missouri Public Service Commission, told the Seams Steering Committee on Tuesday.
McKinnie, who also serves as a contact between regulatory staff and the SPP Regional State Committee and Organization of MISO States’ Liaison Committee, said commissioners are interested in whether larger projects could resolve reliability issues along the seams.
“They’re trying to figure out if there’s a role for states to play in encouraging wider solutions, rather than each RTO solving its own reliability problems,” McKinnie said.
SPP and MISO have taken three stabs at interregional projects but have failed to agree on a single solution.
The Liaison Committee, composed of regulators from both footprints, commissioned SPP’s Market Monitoring Unit and MISO’s Independent Market Monitor to analyze seams issues. The MMU produced a MISO, SPP Regulators Nibble Away at Seams Issues.)
The regulators have sought stakeholder feedback to a series of questions on the two studies. McKinnie assured the SSC that the responses are read. “That’s why we tried to provide ‘kitchen-sinky’ questions,” he said.
The Liaison Committee will hold a conference call Jan. 13 to discuss responses to the monitors’ reports. It will also meet Feb. 9 during the National Association of Regulatory Utility Commissioners’ Winter Policy Summit in D.C.
M2M Settlements Reach $68.1M in SPP’s Favor
SPP earned more than $870,000 in market-to-market (M2M) payments from MISO during November, cracking $68 million in favorable settlements since the process began in 2015.
Permanent flowgates were binding for 315 hours and more than $878,000 in SPP’s favor. Temporary flowgates were binding for 813 hours and more than $7,848 in MISO’s favor.
November market-to-market summary | SPP
Staff’s Will Ragsdale said two permanent flowgates along the Kansas-Missouri border — “our old friend,” the 161-kV Neosho-Riverton, and the 161-kV Moberly-Overton — accounted for more than $809,000 in M2M settlements to SPP. The Neosho-Riverton flowgate has racked up more than $30 million in settlements, four times the second-most constrained flowgate.
SPP has realized $68.1 million in M2M settlements since the two RTOs began the process of using the RTO with the most economic dispatch to address market flows. Staff are reviewing flowgates in western North Dakota to determine allocated property rights, or firm-flow entitlements, on M2M constraints and also comparing allocated M2M settlements with LMPs in market settlement areas.
Committee Reviews 2019, Preps for 2020
Committee members spent much of the meeting discussing the group’s organizational effectiveness, based on SPP’s annual stakeholder survey results. A suggestion to hold quarterly meetings because of a lack of voting items went nowhere.
Members also reviewed their 2019 accomplishments — including oversight of the MISO-SPP coordinated system plan improvements and study — and major pending issues. The latter includes joint studies with MISO and Associated Electric Cooperative Inc.; identifying the administrative processes that lead to inefficiencies between the SPP and MISO markets; and continued pursuit of coordinated projects to address historical M2M congestion between the RTOs.
Staff are working to set up SPP’s annual issues-review meeting with MISO, tentatively scheduled for March 10.
Dominion Energy might have finally met a “bill” it does not like.
Virginia delegates on Tuesday announced a bipartisan bill that would end the electric market monopoly in the state, allowing consumers to choose their electric provider and requiring distribution utilities to divest their generation. The legislation takes aim at Dominion, which serves two-thirds of the state’s consumers, and which the state Corporation Commission says has overcharged customers by $1.3 billion since base rates were frozen in 2015.
The bill was announced at a press conference by Del. Mark Keam (D–Vienna) and Del. Lee Ware (R–Powhatan) and endorsed by groups including the conservative R Street Institute and anti-poverty group Virginia Poverty Law Center. It’s the latest sign that Dominion will face tougher scrutiny from state lawmakers than it has in the past.
In December, Ware joined another Democrat in introducing a bill to reverse the General Assembly’s decision to freeze base rates for seven years, a change Dominion claimed it needed to ensure it could fund carbon emission reductions under the Obama administration’s Clean Power Plan. The CPP was cancelled by the Trump administration, which has proposed much less stringent regulations. (See EPA Finalizes CPP Replacement.)
Del. Mark Keam | Virginia Energy Reform Coalition
“Over the past couple of decades, innovation and technological advancements have allowed consumers around the nation to choose when, where and how they obtain affordable and reliable energy. But in Virginia, we are stuck with a century-old business-as-usual model that benefits monopolies while suppressing competition and consumer choice. It’s time to reform the rules of the road,” said Keam. “We are done and are tired of ‘business-as-usual.’”
Under the current system, monopolies such as Dominion and Appalachian Power own and operate all segments of the state’s vertically integrated system, including generation, distribution and retail services. The bill announced Tuesday, which is set to be discussed in the 2020 General Assembly, would:
Establish a competitive market for electricity retailers to allow customers to shop on price or on environmental attributes (e.g., renewable energy);
Establish a nonprofit independent entity that has no financial stake in market outcomes to coordinate operation of the distribution system;
Remove existing interconnection and financing barriers to customer-owned energy resources; and
Add additional consumer protections and education to ensure smart energy choices.
Dominion and American Electric Power, parent of Appalachian Power, did not immediately respond to requests for comment.
“This legislation, which I trust will gain broad bi-partisan support, will chart a course toward engendering much-needed competition in the retail sales of vital electricity services,” said Ware. “This is a time of new opportunity.”
Keam and Ware claim Virginians have the seventh-highest electricity bills in the country. The utility has had its rates frozen since 2015 when the then Republican-led General Assembly removed state regulators’ ability to review base rates and set profit levels.
“It wasn’t until the rate freeze of 2015 that I came to the realization that this is really bad and really wrong. But only a handful of us said, ‘Why are we doing it this way?’ And the answers weren’t adequate,” Keam said. “So, from that point on until last year when we had that big fight over grid modernization, I think that’s awoke a lot of peoples’ understanding that we don’t have to take this.”
Dominion has long been one of the biggest political contributors in the state, having donated about $1.8 million in 2018-19 and $7.1 million since 2010, according to Virginia Public Access Project. In the past, most of the donations went to Republicans. In the most recent cycle, however, the utility donated slightly more ($949,000 to $870,000) to Democratic candidates.
Dominion Energy headquarters in Richmond, Virginia | Timmons Group
But most Democratic legislative candidates agreed last year to reject funds from Dominion and made their opposition to the utility part of their campaigns. Nearly 50 of the 61 candidates that rejected Dominion money won their elections in November. With that, the Democrats took the majority in both the House and the Senate. The state’s governor also is a Democrat.
The bill proposed Tuesday is being backed by the Virginia Energy Reform Coalition, a group formed last year that includes both environmental organizations (Appalachian Voices, Clean Virginia and Piedmont Environmental Council) and right-leaning free market organizations (R Street Institute, Reason Foundation and Virginia Institute for Public Policy).
Devin Hartman, the director of energy and environmental policy at the R Street Institute, said the time is now for Virginia to embrace innovation.
“Virginia is shackled to a monopoly utility model that stifles innovation, increases costs and puts government in the difficult role of replacing competition,” he said. “It’s time for Virginia to liberate market forces, empower consumers and shift the role of government to facilitate competition. Competitive markets are the path to an innovative and consumer-friendly clean energy future. It’s time for Virginia to make the right choice.”
By now we’ve all been told that FERC’s recent order on PJM’s minimum offer price rule is the death knell for renewables and a big hit to consumers.
This is the spin from renewable advocates who didn’t actually read the order before firing off press releases.[efn_note]The order was posted at 5:51 p.m. ET on Dec. 19, 2019, after press releases were issued. Other groups also didn’t read the order before firing, but their shots in the dark weren’t so far off the mark.[/efn_note]
Let me explain four elements of the order that are positive for renewables, and then discuss the consumer rate hike that isn’t.
The Death Knell for Renewables that isn’t
Existing Renewables are Grandfathered, Fossil and Nuclear Aren’t
This is a big preference for renewables. It also means that to the extent uneconomic subsidized fossil and nuclear units retire, energy prices for renewables increase.
Renewables Depend Much less on Capacity Revenues for Project Viability
Renewables’ nameplate capacity is heavily discounted for Reliability Pricing Model purposes because of their intermittency. As a consequence, renewable projects are much less dependent on RPM revenue for project viability.
By the way, those complaining that renewables will lose project-critical RPM revenues are some of the same wanting to get rid of RPM altogether. Which is it?
The Unit-specific Exemption Favors Renewables
There is an exemption for projects that can show financial viability even without a state subsidy. And it would seem many renewable projects will be able to satisfy the test because of the generic nature of their subsidies.
State subsidies for fossil and nuclear units are tailored to providing just enough money to keep specific units around. So by definition — or at least by representations to state legislators — they have to have the subsidies to be financially viable, which in turn would mean no unit-specific exemption for them.
Federal Subsidies are Excluded
This is a big preference for renewables because their federal subsidies per megawatt-hour are enormous, averaging $21.50, with fossil and nuclear subsidies less than 1/10 of that. Here’s a chart with the data:[efn_note]https://live-energy-institute.pantheonsite.io/sites/default/files/UTAustin_FCe_Subsidies_2017_June.pdf, page 23, Table 7, FY 2019 (“HC” stands for hydrocarbons oil and natural gas). By the way, historical subsidies that no longer exist, and aggregate dollar amounts of subsidies, are irrelevant to relative subsidy value among resources. What is relevant is amount of subsidy per unit of generation.[/efn_note]
Yet, renewable advocates complained about federal subsidies for fossil being excluded. OMG.
The Consumer Rate Hike that isn’t
At some point, we’ll have some rigorous modeling of the consumer impact. There are a lot of moving parts, including how significant the unit-specific exemption turns out to be.
There are fatal flaws in that study. First is that at least 16,416 MW of the 24,000 MW didn’t clear in the last RPM auction.[efn_note]The 16,416 MW is composed of 14,300 MW of future renewable resources and 2,116 MW of Ohio nuclear units that did not clear in the last RPM auction. https://www.prnewswire.com/news-releases/firstenergy-solutions-comments-on-results-of-pjm-capacity-auction-300654549.html.[/efn_note] So the study is estimating a price increase by subtracting capacity resources that weren’t there to subtract in the first place.
Now let’s look at what’s left after subtracting the nonexistent 16,416 MW from the 24,000 MW. The roughly 7,600 MW that’s left is made up of three nuclear plants (Hope Creek and Salem in New Jersey, and Quad Cities in Illinois) and one coal plant (Ohio Valley Electric Corp.). The FERC order requires that offer prices be adjusted to the net avoidable cost rate, which is the gross going-forward cost net of estimated energy, capacity and ancillary services market revenues. Independent Market Monitor data show that none of the nuclear plants in question needs revenues in excess of estimated total energy and capacity revenue in order to remain financially viable.[efn_note]http://www.monitoringanalytics.com/reports/PJM_State_of_the_Market/2019/2019q3-som-pjm-sec7.pdf, Tables 7-20 and 7-21 (The MMU didn’t include ancillary services, which would add to revenue.)[/efn_note] The necessary implication of this is that their minimum offer price will be below the locational deliverability area clearing price for the respective units.
As for the coal plant, generic PJM data show a gross going-forward cost of $171/MW-day and very conservative energy and ancillary services revenue of $45/MW-day.[efn_note]Initial Submission of PJM Interconnection, LLC, Docket No. EL16-49-000, https://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=15059002, pdf pages 118 and 120.[/efn_note] Netting the $45/MW-day from the $171/MW-day gives a MOPR replacement rate of $126/MW-day, which is below the $140/MW-day RTO clearing price in the last auction. Thus, the coal plant clears without affecting the RTO clearing price.
Although not part of the study reviewed above, let me add a note on Commissioner Richard Glick’s estimate that 25% of demand resources that cleared in the last auction won’t clear in the next one allegedly because a curtailment service provider (effectively an aggregator) will need to know its specific end-use customers three years in advance. This does not consider that the FERC order exempted all demand response resources that cleared in a prior auction, i.e., all the DR resources that Glick says are subject to the MOPR. Moreover, CSPs already live with some uncertainty about their ultimate end-use customers; no state subsidy for DR has been identified; and DR resources could alleviate uncertainty for CSPs by certifying to current and future nonreceipt of state subsidies (which, as noted, don’t even seem to exist).
To sum up: No effect on the last RPM auction results.
Yes, you read that right. No increase in RPM consumer costs relative to the last auction.
Speaking of reading, might I recommend the order?
Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.
Pioneer Transmission can recover about $10 million in precommercial operation costs used to develop a high-voltage transmission line in Indiana, FERC decided last week.
The joint venture of Duke Energy and American Electric Power incurred the costs March 2009 through Dec. 31, 2019, while planning and constructing the $347 million, 765-kV Greentown-to-Reynolds transmission line between Kokomo and Reynolds, Ind. FERC approved Pioneer’s October filing to include the asset in its formula rate on Dec. 31 (ER20-159).
However, the commission also told the transmission company it must update its capital structure from the hypothetical 50% debt and 50% equity to the 2018 year-end actual of approximately 51.1% debt and 48.9% equity.
The 70-mile Greentown-to-Reynolds project is the first segment of the $1 billion, 290-mile Greentown-to-Rockport line that has been in the works for more than a decade. The completed line is expected to traverse MISO into PJM. Pioneer began construction on the segment in 2013 and finished work in June 2018; the segment is one of the 17 multi-value projects MISO approved in 2011.
The Greentown-to-Reynolds line | Duke Energy
In a related order issued the same day, FERC also denied Pioneer’s request to rehear its first request to amortize and recover the precommercial operation costs of the Greentown-to-Reynolds line (ER18-2119).
Pioneer first filed to recover precommercial operation costs in July 2018, but the commission rejected the filing without prejudice a year later, finding that the company included a 150-basis-point return on equity adder for new transmission in its carrying charges. FERC had previously said in 2009 that Pioneer could not receive the adder unless the project was approved by both MISO and PJM. Pioneer has not yet obtained PJM approval for the project. (See FERC Lowers ROE for Segmented Pioneer Tx Project.)
Pioneer said FERC should revisit the decision because the commission did not act within the 60-day period prescribed by the Federal Power Act, thus making the filing legal on Sept. 30, 2018.
But FERC said Pioneer’s regulatory asset filing was not properly filed electronically and therefore was not subject to a statutory action date.
“If we were to vacate the commission’s rejection of Pioneer’s filing in this docket as Pioneer requests, it would be permitted to accrue an unauthorized 150-basis-point ROE adder to its regulatory asset carrying charge and thus profit through its own failure to comply with the commission’s filing regulations,” FERC explained, pointing out that Pioneer was able to submit its October filing correctly.
“Evolutionary, not revolutionary,” Southwest Power Pool executives like to say about their RTO. It’s written into SPP’s corporate culture, the idea being that it takes time “to do the right thing, for the right reason, in the right way every time.”
The RTO’s emphasis on continuity will be tested in 2020, however. By midyear, SPP will be without five of the key figures who have helped expand the grid operator’s footprint into 17 states and implement a day-ahead market. Former Board of Directors Chair Jim Eckelberger and Directors Harry Skilton and Phyllis Bernard left the board at year-end after having served together since 2003. COO Carl Monroe will follow them out the door after January.
Come April, CEO Nick Brown, who joined the RTO 35 years ago as employee No. 7, will retire. SPP, having identified both internal and external candidates, says it is on track to announce his replacement during January’s board meeting in Santa Fe, N.M. (See SPP’s Brown to Retire as CEO in 2020.)
Larry Altenbaumer replaced Eckelberger in January 2019, seeking to place his own stamp on the RTO by shortening board meetings and focusing them on strategic discussions with members and the Regional State Committee. In addition to taking over the chairmanship of the Strategic Planning Committee, he also headed the Affordability and Value Task Force, which identified “meaningful opportunities to enhance other aspects of performance.” (See SPP Value Group Finds No ‘Silver Bullets’.)
Dennis Florom, manager of energy and environmental operations for Lincoln Electric System, said that as SPP grows in size and membership, “it gets more difficult to keep things member-driven,” referencing the RTO’s preference to serve as advisers to members.
“This is what sets SPP apart, and SPP prides itself on that. The new CEO will need to work with the board to make sure that SPP maintains its identity and that members continue to set the direction as forks in the road present themselves,” Florom said.
SPP’s expansion into the Rockies and beyond has already reached the crossroads.
In early December, the RTO became the reliability coordinator for 15 Western Interconnection utilities, representing about 12% of the region’s load. (See Westward Ho: SPP Now a Western RC Provider.) However, shortly thereafter, SPP’s ambitions to run an energy market in the Western Interconnection took a hit with news that Colorado’s largest utility (Xcel Energy) and three others chose CAISO’s Western Energy Imbalance Market over its own competing market offerings. (See EIM Lands Xcel, 3 Other Colo. Utilities.)
The RTO is still plugging ahead with its Western Energy Imbalance Service, which is scheduled to go live in early 2021. Two additional utilities, Municipal Energy Agency of Nebraska and Wyoming Municipal Power Agency, have announced they will join the five that signed contracts in September to fund WEIS’s development: Basin Electric Power Cooperative; Tri-State Generation and Transmission Association, and three Western Area Power Administration entities, Colorado River Storage Project; Rocky Mountain Region and Upper Great Plains. (See SPP Board OKs $9.5M to Build Western EIS Market.)
“Discussions continue with other interested parties, but no additional contracts have been signed at this point,” SPP spokesman Derek Wingfield said.
CAISO’s EIM, which currently has nine members, is expected to grow to 23 by the end of 2022.
Competing for Load
In the meantime, there’s plenty for the grid operator and its members to chew on. The explosive growth of renewable energy shows no signs of easing. Wind farms and, more recently, solar installations and energy storage, continue to add more energy than SPP — with a reserve margin of around 25% — knows what to do with.
SPP set a new wind peak record of 17,861 MW on Dec. 11, breaking a mark set two months earlier by 266 MW. In the early-morning hours of Oct. 9, the RTO produced 73.67% of its energy from wind, hydro and other non-fossil resources, fulfilling predictions a year before that it would reach the 70% threshold.
Florom said that a peek at the generation interconnection queue “shows a level of renewables that SPP load can’t handle.” The RTO had more than 22 GW of installed wind capacity as of October, with more than that in the queue.
Florom suggested storage and new transmission could “present opportunities for addressing more renewables.”
“Tariff changes and working with other entities outside of SPP to export these renewables are ways that SPP can address this challenge in ways that might benefit everyone,” Florom said.
But exporting energy could require additional transmission construction, which comes with a cost. Altenbaumer is keenly aware that members are still digesting the $10 billion in transmission construction and upgrades over the previous decade.
“The big concern [stakeholders] have is what happens with the next wave of transmission projects and making sure they pass a very tight metric to provide value,” he said in November.
Some of the answers may lie in the implementation of the Holistic Integrated Tariff Team’s recommendations. (See SPP Board Approves HITT’s Recommendations.) State regulatory staff are working on some of the key recommendations, including creating larger transmission pricing zones and sub-zones; evaluating the byway facility cost allocation review process; and evaluating cost allocation and rates for storage devices classified as transmission assets.
Other stakeholder groups are working on an uncertainty market product, improvements to the day-ahead market — including a multiday, longer-term market product — and establishing uniform local planning criteria within the Tariff’s Schedule 9 pricing zones.
SPP’s staff take a deeper view into the future. During a Strategic Planning Committee meeting in November, Senior Engineering Vice President Lanny Nickell said the RTO and its stakeholders should be “thinking about” competition between RTOs and keeping its own load while competing for other loads.
“How do we compete, as a region, for loads that love the renewable resources and [their] low prices?” he asked. “They’re looking for opportunities to add warehouses and data centers. How do we compete for those?”
“Given concerns with costs, we can’t afford to lose much load as we calculate administrative costs and move forward in a world that is changing rapidly,” said Bruce Rew, senior vice president of operations. “We can’t afford to lose megawatt one.”
Change is coming. Whether it’s evolutionary or revolutionary, a new cast of characters at the top will be the ones to address it.
PJM last week sent members directions on how to file claims against the $5 million fund established in the GreenHat Energy settlement just days after FERC accepted the terms of the agreement.
In October, PJM filed its plan with the commission to pay two trading firms $12.5 million to settle claims of economic harm that resulted from the RTO’s decision to not liquidate GreenHat’s entire 890 million MWh portfolio of financial transmission rights during the 2018/19 planning period (ER18-2068).
After the company defaulted in June 2018, PJM reran only the July FTR auction — a decision the RTO says kept costs to members down and avoided a cascade of market violations that would increase uncertainty for years to come. (See PJM to Pay $12.5 million to Settle GreenHat Dispute.)
GreenHat’s significant growth in exposure and MTA loss | PJM
As part of the settlement, members agreed to fund a separate account that would pay out additional claims if PJM’s analysis verified those market participants also suffered economic harm. If PJM discovers instead that a claimant benefited from prior actions, it will owe a fee equal to 50% of the amount of the benefit. The RTO said in October that it doesn’t expect additional claims, based on the limited protest filings it received during the proceeding.
In its email to members Thursday, PJM directed potential claimants to submit an email to FTRPayeeFund@pjm.com with “Payee Fund Claim” in the subject with the name of the market participant in the body of the email on or before Feb. 1. Claimants should not include a dollar amount for which the market participant was harmed.
PJM said it will notify claimants by Feb. 10 of the harm or benefit for the market participant and what amount will be credited or charged, respectively, to its monthly billing statement following the notification.
ISO-NE kicks off 2020 with a key deadline looming to file a long-term fuel security mechanism with FERC — a project two years in the making.
The New England Power Pool Markets Committee worked double-time through the fall to complete the Energy Security Improvements (ESI) program to address winter fuel security concerns. This year, it will meet three days a month to complete the work before FERC’s revised deadline of April 15 (EL18-182). (See FERC Extends ISO-NE Fuel Security Filing Deadline.)
Stakeholders are discussing LNG supplies, market mitigation and a second demand curve to ensure the RTO can meet forecast load throughout the next operating day.
The Participants Committee likely will vote on the new market construct at its April 2 meeting, and stakeholders will learn of any schedule additions early this month.
Based on regular surveys on generator fuel supplies for this winter, the RTO estimates that more than 4,500 MW of gas-fired generating capacity could be unable to get fuel when needed. (See “RTO Cautions on Availability of Fuel in Cold Snaps,” ISO-NE Projects Adequate Resources for Winter.)
This is the first winter season since the 680-MW Pilgrim nuclear plant retired in May. The RTO said the plant’s capacity is being replaced by several new resources, including three dual-fuel plants, as well as solar and wind resources.
Stakeholder Proposals
What’s taking so long to complete the plan? To begin with, stakeholders have varying opinions and have offered several proposals.
Calpine proposed a Forward Enhanced Reserves Market that would procure fuel-secure winter energy three years in advance.
The Massachusetts attorney general’s office, which recommended a call option that would be sold in a simple auction of sealed bids with a uniform clearing price, withdrew its proposal in August. In September, it said it was keeping its options open on several amendments to the ESI proposal, depending on the flow of analyses and discussion in the lead-up to April’s filing.
Eversource Energy presented an amendment to address the company’s concern that the RTO’s Inventoried Energy Program would overlap with ESI for winter 2024/25.
The Connecticut Public Utilities Regulatory Authority and Department of Energy and Environmental Protection jointly presented an amendment to the Tariff language concerning quarterly certification of the competitiveness of the energy call option offers in the day-ahead market.
FirstLight Power Resources proposed that the option strike price — intended to estimate the marginal price of energy to meet next day’s forecasted load plus operating reserves — needs to vary by hour, just as marginal energy prices do.
Market Concerns
Even the U.S. Senate got in on the act in November, as seven senators from New England urged ISO-NE to “return to the table with stakeholders” and more closely align its fuel security initiative with state policies seeking to speed the transition to renewable energy resources. (See Senators Ask ISO-NE to Heed States on Clean Energy.)
In a letter to the RTO, the senators criticized it for “pursuing a patchwork of market reforms aimed at preserving the status quo of a fossil fuel-centered resource mix” and having “charted its own path forward and pursued unpopular initiatives” such as Competitive Auctions with Sponsored Policy Resources (CASPR) and the Inventoried Energy Program.
“CASPR was really just a mechanism we invented and work around to allow such resources to enter the market without crashing the price in the primary auction capacity market,” ISO-NE CEO Gordon van Welie said at a conference in November. (See Overheard at NECBC 2019 Energy Conference.) “When we set out to change anything in our markets, it’s at least a three-year market design, stakeholder journey … with anything substantive likely to be litigated.”
Energy market values vary with fuel prices, while capacity market values vary with changes in supply ($ billions). | ISO-NE
Former FERC Chair Joseph T. Kelliher, now executive vice president for federal regulatory affairs at NextEra Energy, said at the same event that “to the extent there’s a crisis in the industry, it’s a crisis of low energy prices.”
At another conference, Massachusetts Department of Public Utilities Chair Matthew Nelson said, “I don’t think markets are broken; it’s just that the world has changed around the markets. Regardless of our personal or political positions, the reality in the market is one of increasing demand for clean resources.”
Nelson likened today’s market to a three-legged stool balancing clean energy, cost and reliability.
“Reliability today is king in the electric market, but the relationship between reliability and clean energy is not binary,” he said. “The narrative that a clean future can only come at the expense of reliability is false. It’s not a zero-sum game.”
Speaking at the Northeast Energy and Commerce Association’s Power Markets Conference in November, FERC Commissioner Richard Glick said, “I never realized until I got to FERC how complicated some of these markets have grown … and we see a lot of proposals to tinker with the markets, particularly the capacity markets.” (See Overheard at NECA 2019 Power Markets Conference.)
Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides in December said that she is focused on bringing new renewable resources into the market and electrifying the transportation and building sectors to take advantage of new hydro, wind and solar resources as they come online. (See Overheard at the 1st New England Energy Summit.)
“We really feel you need to do those two pieces at the same time. You don’t just clean up your power and then do electrification next,” Theoharides said.
Big, Slow Clean Energy Projects
Massachusetts has been facing delays in some of its larger state-sponsored renewable energy projects, as has Avangrid, which is partnered on two of the projects.
Avangrid said in November that it expects “in the not too distant future” to get the final permits on its New England Clean Energy Connect (NECEC) project to bring 1,200 MW of Canadian hydropower to Massachusetts. The company expects to begin construction in the second quarter this year and to be operational by 2022.
NECEC has been plagued by delays, controversy and opposition since it received the state contract following the failure of Northern Pass, a competing project by Eversource, to win regulatory approval in New Hampshire.
Avangrid’s offshore wind joint venture, Vineyard Wind, also saw trouble last year, as the U.S. Bureau of Ocean Energy Management in August delayed issuing a final permit in order to expand environmental impacts analysis for all such offshore projects. (See Renewable Backers Decry Vineyard Wind Delay.)
“All of the developers have agreed to 1 nautical mile of turbine spacing, so we hope the fishermen can do their fishing, and we expect a decision by the secretary of the interior by early January so we can start construction,” Avangrid CEO James P. Torgerson said.
“It’s a much different grid from 10 years ago,” said Anne George, vice president for external affairs and corporate communications at ISO-NE, speaking at a public forum in December.
“The amount of wind in our interconnection queue is the greatest we’ve ever had,” she said, citing 13,720 MW, or 65% of the queue total of 21,138 MW. “And over the next 10 years, we’re going to see a lot more activity with battery storage.”
FERC in December conditionally accepted ISO-NE’s Order 841 compliance filing (ER19-470), requiring additional changes to how the RTO dealt with the application of transmission charges to storage resources and rejecting its approach for handling the state of charge and duration of those resources in day-ahead markets. (See Storage Plans Clear FERC with Conditions.) The RTO has requested a rehearing on the latter finding, contending that the commission’s recommended approach is “inferior” to its own proposal and could “jeopardize critical ISO-NE projects.”
The RTO’s next compliance filing is due Feb. 10.
Competitive Transmission
ISO-NE in December announced its first-ever competitive transmission solicitation to address peak load condition overloads in the Boston area and system restoration concerns with the underground cable system in the area.
The RFP seeks to address reliability concerns associated with the upcoming retirement of the Mystic Generating Station in Everett, Mass. (See ISO-NE Issues First Competitive Tx RFP.) The RTO will review all proposals in a two-step process before selecting the preferred solution, with a March 4 deadline for submissions.
Potential New England 2050 load profiles by end use | EPRI
FERC earlier in December approved Tariff revisions refining ISO-NE’s rules for conducting competitive transmission solicitations in compliance with Order 1000, a process being tried for the first time for solutions to non-time-sensitive needs identified in the RTO’s 2028 Boston Needs Assessment Update and Needs Assessment Addendum (ER20-92). (See FERC OKs ISO-NE RFP Rules.)
But the commission in October instituted Federal Power Act Section 206 proceedings, concerned that ISO-NE may be implementing the immediate-need reliability exemption in a manner “inconsistent with what the commission directed, and therefore may be unjust and unreasonable, unduly preferential and discriminatory” (EL19-90).
The RTO on Dec. 27 filed its response to the proceeding, concluding that “the exception is working as intended” and that no changes are necessary.
However, the RTO promised to conduct a “lessons learned” process following the completion of the Boston RFP to determine if improvements can be made.
FERC last week accepted a $450,000 settlement between the Northeast Power Coordinating Council and three Avangrid utilities for violations of NERC transmission operations (TOP) standards. The commission indicated in a notice last week that it would not review the penalty (NP20-4).
According to a Notice of Penalty filed Nov. 26, the violations involving New York State Electric and Gas and Rochester Gas & Electric took place Nov. 17-28, 2017, while the Central Maine Power violation occurred Jan. 11, 2019. Both situations posed a moderate risk to the reliability of the bulk power system, though neither is known to have caused actual harm.
In the first violation, a server failed, affecting a transmission network analysis (TNA) tool used by both NYSEG and RG&E for several monitoring and assessment applications. A backup server also failed, leaving the TNA tool inoperative. As a result, both utilities were unable to perform real-time assessments every 30 minutes as required by the TOP-001-3 standard.
Avangrid’s New York and New England utilities serve 3.2 million natural gas and electricity customers. | Avangrid
Initially both utilities were unaware of the TNA failure and loss of monitoring and assessment capabilities, but at 1 a.m. — six hours after the incident began — the RG&E system operator discovered the breakdown and notified his counterpart at NYSEG. Neither operator notified reliability coordinator NYISO, which could have performed a real-time assessment. The server failure was not corrected until nearly four hours later, when monitoring and assessment capabilities returned. NYISO was not notified for more than 14 hours after the utilities became aware of the failure.
“The RC would not necessarily be aware that it may have to take support actions to address the lack of NYSEG/RG&E monitoring and assessment capabilities,” NERC said in its filing. “The risk posed is that if a system event occurred during this time frame, neither RG&E, NYSEG nor NYISO would have had the necessary situational awareness to respond.”
CMP’s violation of TOP-001-4 was similar, involving an accidental interruption of connectivity that led to the failure of a state estimator and a real-time contingency analysis tool. The outage lasted more than an hour, during which time CMP did not notify ISO-NE of the loss or request the RC perform a real-time assessment on its behalf. ISO-NE was informed of the outage after connectivity had returned and the tools were functional again.
In both cases, NPCC faulted the utilities for “lack of effective management oversight, including training,” with NYSEG and RG&E also criticized for lack of controls that would have detected the failure of monitoring and assessment capabilities. NPCC said the penalty was increased by an unspecified amount because CMP was already aware of the earlier incidents at the time of the January failure and hence should have known the importance of ensuring that the RC was notified and real-time assessments continued.
NPCC credited Avangrid for being cooperative throughout the enforcement process and accepting responsibility for the violations. The regional entity noted that the risk to the grid was moderate. NYSEG, RG&E and CMP have also implemented several mitigating measures, including hardware and software changes to detect faults with the reporting system, additional system operators, and new methodologies for training and staffing.
As a result, NERC’s Board of Trustees Compliance Committee approved the penalty as “appropriate for the violations and circumstances at issue.”
New York started 2019 with big promises around renewable energy that it fulfilled in summer as it quickened the pace of the most ambitious decarbonization goals in the country.
New York Gov. Andrew Cuomo speaks offshore of Jones Beach State Park in August 2019. | NYDPS
Gov. Andrew Cuomo last January announced that New York would aim to get 70% of its electricity consumption from renewable energy resources by 2030, with a 100% carbon-free electricity target for 2040. He also nearly quadrupled the state’s offshore wind energy target to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
The state’s clean energy goals also included doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and upping its energy efficiency savings to 185 trillion BTU by 2025.
Leading the Transition
Talk became action on July 18 when Cuomo signed the Climate Leadership and Community Protection Act (A8429), the same day he announced the state was awarding a combined total of 1,700 MW in offshore wind contracts to Equinor’s Empire Wind project and to Sunrise Wind, a joint venture of Ørsted and Eversource Energy.
Regional setting and bathymetry of the New York Bight study area for offshore wind | NYSERDA
“We want to get to a 100% renewable, clean economy — no fossil fuels, no gas,” Cuomo said in August while expanding an artificial reef program off Jones Beach State Park, on Long Island. “How do you power cars? How do you heat a home? How do you fly a plane? Where do the renewables come from?”
Cuomo emphasized that those “details” constitute the essence of the decarbonization effort.
“We have not made this major a transition in society in this short a period of time probably ever. So, the ‘How do you do it?’ is not just a tedious question; it is actually everything,” he said.
“Now, how do you do it? That’s where New York has to lead,” he continued. “New York already leads in the most aggressive goals. We have to lead in this transition: how you actually make it happen.”
Carbon Pricing
Meanwhile, NYISO market participants hashed out how the state’s new energy law and mandated influx of renewables would affect a parallel effort to price carbon in the ISO’s wholesale electricity markets.
In order to include the new statutory energy targets in the modeling, NYISO over the summer delayed wrapping up its 30-month carbon pricing effort. (See “New Energy Law Could Affect CO2 Market Design,” NYISO Business Issues Committee Briefs: June 20, 2019.)
NYISO’s Market Issues Working Group took over last January from the Integrated Public Policy Task Force, a joint effort between the ISO and the state’s Public Service Commission that spent a year-and-a-half developing the carbon pricing proposal released last December.
The state must put a price on carbon in its electricity market if it hopes to meet the aggressive timelines of the decarbonization goals set out in the new law, the co-author of NYISO’s carbon pricing study said in October. (See Carbon Pricing Vital to NY Goals, Study Author says.)
“If New York does not do this in the electric-sector engine that the law hopes to rely upon to decarbonize the economy, it’s tying two hands behind the state’s back,” Analysis Group’s Sue Tierney said Oct. 22 in delivering a summary of the study to ISO stakeholders. “You will not get the efficiency, or timing, or depth, or pace of change without having this electric system engine on acceleration to get it.”
In addition, the state Department of Environmental Conservation last year revised its Clean Air Act regulations to lower allowable NOx emissions from simple cycle and regenerative combustion turbines during the ozone season. The rules are effective May 1, 2023, with generator compliance plans due by March 2, 2020. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
Aligning Plans and Law
The carbon pricing study was not the only thing affected by the new energy law. Meeting for the first time in two years, the New York State Energy Planning Board last month approved the issuance of proposed amendments to the state’s energy plan for public comment.
New York State Energy Research and Development Authority CEO Alicia Barton, who serves as chair of the planning board, highlighted “tremendous growth in the clean energy sector,” with employment for 2019 expected to have grown 7.7% year-over-year to nearly 171,000 jobs.
The Climate Act mandates a minimum of 35% of overall benefits from clean energy investments be realized by disadvantaged communities, which Barton said “are inured to” injustice. The benefits include spending on clean energy and energy efficiency programs, and investments in housing, workforce development, pollution reduction, low-income energy assistance, transportation and economic development.
The planning board also directed the PSC to arrange stable funding for the transition of power plants through the state’s Electric Generation Facility Cessation Mitigation Program, which supports localities that lose 20% or more of their tax base through the closure of a power plant.
“We’ve already seen communities turn to the fund since retirements have occurred, so that leads to a need to be thoughtful about the effect on host communities,” said PSC Chair John Rhodes, who also serves on the planning board. “The time is right to work on stability for those future needs.”
For example, this year will see Entergy shutter the first of two units being decommissioned at its Indian Point nuclear plant on the Hudson River, with the second reactor scheduled to go offline in 2021. A third reactor at the site was decommissioned in 1974. Cuomo had pushed to shut down the nuclear plant because it is only 24 miles from New York City.
Indian Point nuclear plant | Entergy
ZEC Program Stands
Far from the city, Exelon’s three upstate nuclear power plants — James A. FitzPatrick, R.E. Ginna and Nine Mile Point — all qualified for the state’s zero-emission credits (ZEC) program approved by the PSC in 2016 to prevent their retirements. The commission created the program as part of the state’s Clean Energy Standard (CES).
Acting Justice Roger D. McDonough of the New York Supreme Court in Albany County dismissed a challenge to the state’s ZEC program by Hudson River Sloop Clearwater and others, a decision that in November was appealed to the state’s highest court, the Court of Appeals. (See NY Court Rejects Challenge to ZEC Program.)
The 2nd U.S. Circuit Court of Appeals in September 2018 also upheld the ZEC program, rejecting the argument that it intrudes on Appeals Court Upholds NY Nuclear Subsidies.)
The PSC said the ZEC program avoided the issues behind the U.S. Supreme Court’s April 2016 ruling in Hughes v. Talen, which voided Maryland regulators’ contract with a natural gas plant as an intrusion into federal jurisdiction over wholesale power markets.
“Plaintiffs point to nothing in the CES order that requires the ZEC plants to participate in the wholesale market,” the 2nd Circuit said. “As the district court concluded, a generator’s decision to sell power into the wholesale markets is a business decision that does not give rise to pre-emption concerns.
“Until 2019, the ZEC price cannot vary from the social cost of carbon, as determined by a federal interagency workgroup. After 2019, the ZEC price is fixed for two‐year periods and does not fluctuate during those periods to match the wholesale clearing price,” the court said.
Public Policy Tx
NYISO’s Board of Directors in April selected two 345-kV transmission projects intended to address persistent transmission congestion in New York and foster delivery of renewable energy to population centers in the southeastern part of the state. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)
New York’s AC Public Policy Transmission projects are intended to relieve congestion in key corridors. | NYISO
The projects — part of the broader AC Public Policy Transmission Project — address transmission capacity at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (UPNY/SENY or Segment B) interface.
“The projects will add the largest amount of free-flowing transmission capacity to the state’s grid in more than 30 years,” the board said in a statement.
In December 2018, the board rejected one of two project selections made by the NYISO Management Committee, which along with ISO staff had backed two joint proposals by North America Transmission and the New York Power Authority. Cost estimates for each project ranged from $900 million to $1.1 billion.
Storage Rules
FERC in December partially accepted NYISO’s plan to comply with a mandate that grid operators provide energy storage resources (ESRs) full access to their wholesale markets. (See FERC Partially Accepts NYISO Storage Compliance.)
The commission found that “NYISO has demonstrated that all [ESRs], including those located on the distribution system or behind the meter, will be eligible to provide all capacity, energy and ancillary services that they are technically capable of providing” (ER19-467).
However, the Dec. 20 order also faulted NYISO’s filing for a lack of details on its “metering methodology and accounting practices for [ESRs] located behind a customer meter,” directing the ISO to add descriptions to its Tariff within 60 days of the issuance of the order.
