Page 1208 – RTO Insider

January 8, 2020March 6, 2026

Bipartisan Bill Looks to End Va. Electric Monopolies

By Shawn McFarland

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.)

Virginia Monopolies Bill — 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.

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 Re f orm 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.”

January 6, 2020October 21, 2025

Counterflow: When All Else Fails, Read the Order

By Steve Huntoon

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.

One thing we know now is that the consumer rate hike claimed by some advocates is a fantasy. They rely on a study that claimed an increase in RPM consumer costs of $5.7 billion compared to the last RPM auction.[efn_note]https://www.sierraclub.org/press-releases/2019/12/ferc-costs-consumers-billions-hobbles-clean-energy-economy-help-coal-and; https://www.eenews.net/stories/1061856193; https://www.vox.com/energy-and-environment/2019/12/23/21031112/trump-coal-ferc-energy-subsidy-mopr. The study relied upon is here: https://gridprogress.files.wordpress.com/2019/08/consumer-impacts-of-ferc-interference-with-state-policies-an-analysis-of-the-pjm-region.pdf.[/efn_note] This estimate was based on 24,000 MW being subject to the MOPR.

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.

January 6, 2020

Pioneer Tx OK’d to Recover $10M in Development Costs

By Amanda Durish Cook

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.

Pioneer Transmission — 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.

January 6, 2020

Changes at the Top for SPP in 2020

By Tom Kleckner

“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.)

Southwest Power Pool Board Chair Larry Altenbaumer — SPP Board Chair Larry Altenbaumer | © *RTO Insider*

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.

Dennis Florom, Lincoln Electric, at a Southwest Power Pool stakeholder meeting — Dennis Florom, Lincoln Electric | © *RTO Insider*

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.

January 6, 2020

GreenHat Claims Fund Opens After FERC OKs Settlement

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.

— Christen Smith

January 6, 2020

ISO-NE Energy Security Plan Looms Large in 2020

By Michael Kuser

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.

ISO-NE’s activities now center on the grid’s transition to renewable resources, a topic to which the grid operator devoted a conference in May. (See ‘Grid Transformation Day’ Highlights ISO-NE Challenges.)

“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.

ISO-NE Energy Security — 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.

January 5, 2020

FERC OKs $450,000 Avangrid Penalty

By Holden Mann

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 N otice of P enalty 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 Penalty — 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.”

January 5, 2020

FERC: NorthernGrid Merger Needs More Work

By Hudson Sangree

A proposed merger of two Pacific Northwest transmission planning groups fell short of the requirements of FERC Order 1000, a landmark measure meant to introduce more competition into transmission development while achieving efficiencies and cost savings, the commission ruled Dec. 27 (ER19-2760).

Seven member utilities of ColumbiaGrid and Northern Tier Transmission Group — including PacifiCorp, Avista and Portland General Electric — filed proposed tariff revisions with FERC in September seeking to combine the two entities to form a regional planning organization (RPO) called NorthernGrid. They said the merger would reduce member expenses and allow for collaborative planning.

The effort had the backing of state regulators, several U.S. senators and the Bonneville Power Administration, among others.

FERC, however, sided with independent transmission developer LS Power, which argued that the utilities’ proposed revisions were flawed under the requirements of Order 1000. (See Tx Developer Calls for Closer Look at NorthernGrid.) The company said it didn’t oppose the merger but contended the filings had failed to demonstrate the new RPO would meet transmission needs more effectively than the status quo.

NorthernGrid Merger — The proposed NorthernGrid regional planning organization would consolidate the areas covered by ColumbiaGrid and Northern Tier Transmission Group. | *ColumbiaGrid*

The commission agreed. It stressed that it was rejecting the proposal without prejudice, inviting the parties to refile after correcting the deficiencies.

“We find that the proposed NorthernGrid regional transmission planning process does not satisfy Order No. 1000’s requirement to evaluate alternative transmission solutions that might meet the needs of the transmission planning region more efficiently or cost-effectively than solutions identified by individual public utility transmission providers in their local transmission planning processes,” FERC wrote.

“Specifically, the proposed NorthernGrid regional transmission planning process does not provide transmission developers, including nonincumbent transmission developers, with a reasonable opportunity to submit project proposals after local and regional needs are identified and made available to stakeholders through the regional transmission planning process,” the commission said.

In addition, the proposal required “the contemporaneous submission of both needs and proposed transmission projects,” FERC noted. As LS Power pointed out, Order 1000 requires the identification of regional needs followed by specific project proposals, the commission said.

“The proposed [tariff revisions] would require developers to submit proposed transmission projects to address regional transmission needs prior to the identification of those needs by the regional transmission planning process,” FERC wrote. “We find that this structure deprives developers and stakeholders of a sufficient opportunity to propose solutions in response to needs identified through the regional transmission planning process.”

FERC also criticized the utilities’ proposal for failing to meet the openness and coordination components of Order 890’s local transmission planning principles, now incorporated regionally in Order 1000.

“The coordination principle requires public utility transmission providers to provide customers and other stakeholders with the opportunity to participate fully in the transmission planning process, which must provide for timely and meaningful input and participation of customers and other stakeholders regarding the development of transmission plans (including at the early stages of development),” FERC said. “The openness principle requires that transmission planning meetings be open to all affected parties including, but not limited to, all transmission and interconnection customers, state authorities and other stakeholders.”

The filing parties’ proposed revisions didn’t satisfy the coordination and openness principles because they “exclude broad stakeholder participation in the initial review of the development of the draft study scope, draft regional transmission plan and draft final regional transmission plan,” FERC said.

The commission identified additional flaws in the utilities’ proposed cost allocation methodology and said they failed to meet the posting requirements for transmission needs driven by public policy requirements of state, local and federal governments.

Order 1000 has had a rocky path to implementation since FERC adopted it in 2011. (See PSEG, GridLiance Spar over Order 1000.) The commission said it welcomed the creation of the RPO, which it said could help the region meet the order’s goals of regionalization and competition.

“We recognize that, by combining the existing ColumbiaGrid and [Northern Tier] transmission planning regions, the establishment of NorthernGrid would be a significant step forward for regional transmission planning in the Northwest,” FERC wrote. “The commission has long recognized that transmission planning over a broader footprint has the potential to yield benefits for customers, and we appreciate the efforts by the region’s stakeholders to establish NorthernGrid as a new transmission planning region.

“If filing parties refile their proposal,” FERC wrote, “the revised process should provide a meaningful opportunity for transmission developers to submit project proposals after regional transmission needs have been identified through the regional transmission planning process, and for that process to evaluate those proposed projects for possible selection in the regional transmission plan for purposes of cost allocation.”

January 5, 2020

TOs Challenge New MISO ROE Rules

By Amanda Durish Cook

FERC’s new methodology for calculating return on equity for transmission owners drew several requests for rehearing from TOs dismayed and perplexed that the commission would use a MISO-centric order to set national policy.

The commission adopted the new methodology in late November under two MISO proceedings (EL14-12., et al.). (See FERC Adopts ROE Methodology in MISO Complaints.) Under Opinion 569, the commission set the TOs’ ROE at 9.88%, a figure it determined via both the discounted cash flow (DCF) and capital asset pricing models (CAPM). The new base ROE sheds 250 basis points from the TOs’ prior rates.

Calls for rehearing were filed around the holidays, with several TOs calling the 9.88% base ROE too low to attract investment and wondering why FERC would use the circa-2013 MISO proceeding as a platform to set policy when it had already collected opinions through a Notice of Inquiry.

Some sought assurances that the commission wouldn’t apply the new ROI methodology universally.

‘Artificially Deflated’

FirstEnergy characterized Opinion 569 as “a prime example of government regulation that is arbitrary, capricious, and contrary to law and commission policy.” The company — along with several others — said that by limiting ROE to the DCF and CAPM models while ignoring the expected earnings and risk premium models, transmission ROEs would fall below the capital attraction standards established in 1923’s Bluefield Waterworks Improvement Company v. Public Service Commission of West Virginia and 1944’s Federal Power Commission v. Hope Natural Gas Company.

The company said that under the new rate, transmission ROEs could fall below state-approved distribution ROEs, rendering them “artificially deflated” and “grossly inadequate to incentivize new transmission build that is desperately needed.”

MISO TOs also argued that FERC was violating the Bluefield and Hope standards and said the investor community was voicing “very serious doubts about the future ability of commission-regulated energy companies to attract capital should the commission stand by [the position] that transmission investment warrants only single-digit equity returns.”

The Edison Electric Institute said FERC’s decision “sends mixed signals to investors and transmission owners about the commission’s commitment to ensuring that needed transmission is built.”

Further, FERC circumvented the Administrative Procedure Act by making new ROE policy through the order, FirstEnergy said, adding that several entities weren’t “on notice that the commission intended to use the MISO proceeding to establish new policy.”

Trade association WIRES also expressed surprise that the commission used the “proceeding-specific” MISO dockets to establish a new ROE methodology instead of the NOI it opened in March to collect opinions on using a combination of the DCF, CAPM, expected earnings and risk premium models. (See Tx Incentives NOI Brings Calls for Broader Reforms.)

2 or 4 Models?

WIRES said using only two of the four financial models paints an incomplete picture of the information used to make transmission investments. Transource Energy also urged FERC to adopt the four-model framework it originally considered. PJM TOs said FERC’s new ROE approach “removes half of the models from the methodology and thereby magnifies the flaws in the remaining models and decreases the diversity of the new methodology.”

“Despite receiving approximately 175 initial comments and 30 reply comments in the NOI docket, the commission opted instead to use Opinion No. 569 to make drastic changes to its proposed ROE methodology without substantively addressing the comments in the generic NOI proceeding or taking comment on the new approach,” WIRES said in its request for rehearing. “A specific contested proceeding is not the most appropriate docket for the commission to announce broad policy changes that will impact the methodology for determining transmission ROEs for all FERC-jurisdictional public utilities.”

“The commission adopted a new two-method approach on which it never sought comment, barely mentioning the still-open inquiry docket,” Ameren chimed in, insisting that FERC address the record in the NOI. PJM TOs likewise said the commission should explain its reasoning behind “issuing a potential industry-wide policy change … while the generic NOI docket remains open.”

Other non-MISO TOs, including PPL Electric and American Electric Power’s Indiana Michigan Transmission Co., lodged motions to intervene in the proceedings, explaining that they had expected a new ROE methodology to emerge from the NOI, not dockets limited to MISO TOs.

Southern California Edison and a group of SPP TOs also filed motions to comment. SCE said the commission abandoned “its previous robust and legally sound proposal to rely on four financial models without addressing the questions it raised in the ROE NOI and disregarding the extensive record it requested.”

The SPP TOs were equally bewildered as to why FERC would rely on a proceeding involving “a small subset of the industry” to make changes impacting all jurisdictional public utilities, calling it “legal infirmity.” The group asked for confirmation that Opinion 569 was intended to set national policy and pointed out that the record in the MISO proceeding closed more than three years ago. Exelon also asked FERC if the new ROE method was to be applied universally.

The New England Transmission Owners (NETOs) also seemed unsure as to whether FERC meant for the new ROE method to extend to them and filed correspondence in the MISO proceedings and a supplemental brief in their own ROE complaint dockets that have been ongoing since 2011. (See FERC Discloses Data Behind New England ROE Order.)

San Diego Gas & Electric similarly asked the commission in a motion for clarification if it meant for the decision to apply outside of MISO. If it did, SDG&E also included a request for rehearing, echoing concerns over the departure from the proposed four-model approach and possible violations of the Hope and Bluefield standards and the Administrative Procedure Act.

January 5, 2020February 12, 2025

New York Advanced Clean Energy Goals in 2019

By Michael Kuser

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 grow n 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.