New York Court to Consider ZEC Challenge

By Michael Kuser

The Albany County Supreme Court on Monday rejected New York’s motions to dismiss outright a lawsuit challenging the state’s Clean Energy Standard and provisions for zero-emission credit subsidies for nuclear plants.

ZEC zero-emission credits clean energy standard — New York State Supreme Court in Albany | *NYCourts*

The decision means that ZEC opponents will get their day in court, although the presiding judge did dismiss a handful of their complaints — as well as a number of the plaintiffs themselves.

Environmental group Hudson River Sloop Clearwater and 60 other litigants last year challenged the New York Public Service Commission’s August 2016 order (15-E-0302) adopting the CES and creating the ZEC program.

The petitioners filed suit in response to a December 2016 PSC ruling that rejected nearly all requests to rehear the order. The PSC in that ruling noted that issues raised in other requests would be “further explored” in the future.

Chief among their complaints is that the commission rushed the CES without allowing sufficient time for public comment, violating provisions of New York’s State Administrative Procedures Act and Public Service Law.

The suit challenges the provision of ratepayer subsidies in the form of ZECs to four nuclear plants in the state, including Entergy’s Indian Point north of New York City and Exelon’s three upstate plants: James A. Fitzpatrick, R.E. Ginna, and Nine Mile Point Units 1 and 2.

ZECs zero-emission credits clean energy standard — Indian Point

In his Jan. 22 ruling, Judge Roger D. McDonough declined to comment on the merits of the procedural claims made by the environmentalists and consumer advocates.

“In the absence of a proper motion for summary judgment or even a request for [procedural review], the court declines to entertain such discussions without the benefit of answers and the full administrative record,” said the ruling, which provided the PSC 35 days to file its answers.

Procedural Review

McDonough did grant the PSC’s motion to dismiss the petitioners’ claims on Indian Point, finding them “unripe because they are wholly dependent upon Indian Point applying and being approved for ZEC payments.”

The judge also dismissed 56 plaintiffs from the litigation for procedural reasons such as ripeness, standing and statute of limitations. He also dismissed a claim premised on the State Environmental Quality Review Act.

The plaintiffs, however, cheered the decision to reject the state’s motion to dismiss the suit altogether. Manna Jo Greene, environmental director of Hudson River Sloop Clearwater, called it a “David versus Goliath” victory.

“We were opposed by the PSC, the nuclear energy plant owners … but we prevailed and proved our issues are substantive and triable,” Greene said in a statement.

The PSC declined to comment on the case.

The decision comes at the same time federal courts are hearing — or soon will hear — appeals on prior ZEC rulings in other states.

A three-judge panel of the 7th U.S. Circuit Court of Appeals on Jan. 3 heard oral arguments on Illinois’ 2016 law. The Electric Power Supply Association and retail ratepayers are asking the court to overturn a district court ruling that dismissed their challenge last July. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)

The 2nd Circuit Court is likely in March to hear an appeal on a similar district court ruling in New York.

January 25, 2018March 22, 2024

FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014

WASHINGTON — Generation operators fared better during the early January cold snap than in the 2014 polar vortex, officials told Congress on Tuesday, but New England needs to take urgent action to prevent major reliability problems.

“Although we are still receiving and reviewing data, it appears that, notwithstanding stress in several regions, overall the bulk power system performed relatively well,” FERC Chairman Kevin McIntyre told the Senate Energy and Natural Resources Committee. “There were no customer outages resulting from failures of the bulk power system, generators or transmission lines. … With limited exceptions, the RTOs/ISOs had sufficient reserves to ensure reliable operations.” (See related story, McIntyre Wades into Capitol Hill Fuel Wars.)

Temperatures between Dec. 28 and Jan. 7 were 20 to 35 degrees Fahrenheit below average in many regions, but peak load in eastern markets was slightly below that in 2014, FERC said.

PJM recorded three of its top 10 winter peak demand days of all time. SPP set a new winter demand peak of 42.71 GW on Jan. 16, besting a record set Jan. 2. ERCOT set a new winter peak of 65.73 GW on Jan. 17 — almost 3 GW higher than the previous record of 62.86 GW on Jan. 3. (See ERCOT, SPP Extend Winter Peak Records.)

The MISO South region set a new winter peak of 32.1 GW on Jan. 17, just short of the all-time (summer) peak of 32.6 GW.

Reserves

Only MISO (Jan. 1-5) and NYISO (Jan. 5-7) saw reserve shortages, McIntyre said. Reserve prices for resources that can respond within 10 minutes were more than $1/MWh during 41% of hours in PJM, 39% in NYISO and 72% in MISO.

McIntyre said initial data suggest that generator performance was better than in 2014 but that “a definitive assessment cannot be made at this time.”

PJM reported that forced outages during the peak demand hour of the recent cold blast were less than 23 GW (11%), half the 22% rate during the polar vortex.

Prices

Between Dec. 28 and Jan. 7, ISO-NE recorded the highest average day-ahead prices at $177/MWh, while PJM hit the highest maximum at $375/MWh. (See chart.) Prices last winter ranged from the low $30s to low $40s.

The energy market prices are consistent with the spike in natural gas prices during the period, McIntyre said, although FERC staff are conducting routine screening of market data for any signs of manipulative behavior.

Natural gas spot prices hit $140/MMBtu in New York on Jan. 4, and seven other trading points in the Northeast and Mid-Atlantic had averages above $100. Gas demand on Jan. 1 hit 150.7 billion cubic feet, exceeding the previous single-day record set in 2014, the Energy Information Administration reported.

Oil, LNG Save New England — This Time

Pipelines in the Northeast and parts of the Midwest had frequent delivery limitations during the period. Operational Flow Orders (OFOs) — requiring shippers to balance their supply with their customers’ usage daily within a specified tolerance band — were declared on the Algonquin, Dominion, Iroquois, Tennessee and Texas Eastern pipelines in the Northeast. Most of the OFOs declared during the cold were lifted on or before Jan. 9, FERC said.

New England survived its gas pipeline capacity constraints thanks to LNG shipments and plants switching to oil.

ISO-NE CEO Gordon van Welie, who also testified to the committee Tuesday, expressed frustration that New England has not taken steps to address threats to its reliability given the growth of gas-fired generation since he first told Congress of his concerns in 2013. Since 2000, oil- and coal-fired generation’s share of ISO-NE’s power production has fallen from 40% to less than 10%, while natural gas has risen from 15% to about 50%.

The region will have lost much of its nuclear power with the retirement of Pilgrim in 2019 (Vermont Yankee closed in 2014), leaving only the 2,100-MW Millstone station in Connecticut and the 1,200-MW Seabrook plant in New Hampshire. Dominion Energy has threatened to shutter Millstone if it does not begin earning higher revenues. (See Conn. Regulators Signal Support for Millstone.)

On Jan. 17, ISO-NE released its Operational Fuel-Security Analysis, which examined 23 fuel-mix scenarios using current pipeline infrastructure to determine whether enough fuel would be available to meet demand.

The report concluded that power shortages attributed to inadequate fuel would occur in 19 of the scenarios by winter 2024/2025, requiring use of emergency actions such as voluntary energy conservation and involuntary load-shedding. (See Report: Fuel Security Key Risk for New England Grid.)

“What our study [shows] is we’re really close to the edge in New England, and we need to find a way of relieving this constraint one way or the other,” van Welie told the committee. “Either through investment in pipeline infrastructure or continuing to invest in other sources of energy that will take the pressure off the gas pipelines or reducing demand on the system. Those are the three avenues available to the region.”

Costly

“It will be costly to remedy these fuel-security challenges — whether the region chooses to invest in renewable energy (and related transmission), fuel infrastructure with long-term contracts, or further measures to reduce demand for wholesale electricity and natural gas,” he continued.

“A key question to be addressed will be the level of fuel-security risk that New England is willing to accept.”

Failing to invest, van Welie said, will result in “chronic price spikes during cold weather, higher emissions when it’s more economic to burn oil than natural gas, and the possibility of further interventions by ISO-NE in the wholesale electricity market to try to delay critical resources from retiring.”

With FERC approval, the RTO can sign reliability agreements to delay generator retirements that would cause transmission overloads. Van Welie said the RTO could change its Tariff for authority to delay retirements because of fuel-security risks, but “generation owners may choose to retire their assets regardless of the offer of a reliability agreement.”

In addition to considering Tariff changes, the RTO will be looking at the impact of a pending rule change: The Pay-for-Performance program, which increases penalties for generator nonperformance, takes effect June 1.

ISO-NE also will be looking at the impact of its Competitive Auctions with Sponsored Policy Resources (CASPR) proposal, filed with FERC on Jan. 8. “While this is a positive step toward accommodating policy-driven resources in the wholesale markets, it may exacerbate the fuel-security challenge if certain non-natural gas-fired generation were to retire before the region has addressed the fuel infrastructure constraints highlighted in the Operational Fuel-Security Analysis,” van Welie said. (See ISO-NE Files CASPR Proposal.)

PJM Pushes Price Formation Plan

PJM said it “had an abundance of reserves and capacity” during the cold spell.

“In most respects, the recent cold snap was much milder than the polar vortex,” PJM CEO Andy Ott said in his written testimony to the committee. “The temperatures were not as low, the wind chill was much less and the demand for electricity was lower, in part due to the cold snap occurring during a holiday week. On the flip side, the cold snap did last for much longer, which led to some degrading of generator performance over time.”

Ott used some of his time before the committee to promote the RTO’s proposal to allow inflexible generators, including coal and nuclear plants, to set LMPs. (See “PJM Wins Examination of Price Formation,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)

He said the proposal would increase energy prices while reducing uplift and capacity prices.

“While out-of-market payments have improved since the polar vortex (approximately $16 million per day) we still saw significant payments during the recent event (approximately $4 million per day),” Ott said. “By contrast, on a typical day, out-of-market payments may be approximately $400,000 to $500,000.”

The ‘Next Level’ for Gas-Electric Coordination

Ott also called for “bringing gas-electric coordination to the next level.”

“To reach this next level, we believe it is important that FERC, [the Department of Energy] and, in some cases, this committee look into some key dichotomies in the regulation of these vital infrastructures.”

While the electric industry is subject to mandatory physical and cybersecurity standards under FERC, the gas pipeline industry uses “high-level voluntary guidelines” from the Transportation Security Administration “augmented with yet a different level of regulation by the Pipeline and Hazardous Materials Safety Administration,” Ott said.

“I say this not to impugn work that the pipelines have done in this area but to point out that the two industries face vastly different compliance obligations, particularly in the area of cybersecurity. By definition, these dichotomies will inevitably hinder an optimal integrated and coordinated approach to common threats from both physical and cyberattack.”

Tightening CEII?

Ott also suggested changing the handling of critical electric infrastructure information (CEII) to balance transparency with security concerns.

“The CEII rules utilized at FERC and at the state level are designed around a ‘right to know’ approach, with some verification of the bona fides of the requestor. Yet, the federal government doesn’t approach classified information this way,” Ott said. “Rather, that system is based on the provision of access based on a demonstrated ‘need to know.’ It may be time to consider evolving our release of a limited set of highly sensitive infrastructure information from a ‘right to know’ to a ‘need to know’ basis.”

January 25, 2018

FERC Grants PJM Waiver of MOPR Exemption Deadlines

By Robert Mullin

Some PJM generators will have additional time to submit unit-specific exemptions to the minimum offer price rule (MOPR) before the RTO’s capacity auction next month under a Tariff waiver approved by FERC on Monday.

The decision (ER18-489) comes a month after the commission for a second time again rejected PJM’s 2012 MOPR compromise, which would have permitted categorical exemptions to the price rule (ER13-535-004). FERC had ruled that it was unreasonable for PJM to remove unit-specific exemptions and also directed the RTO to eliminate the proposed categorical exemptions. (See On Remand, FERC Rejects PJM MOPR Compromise.)

The commission issued last month’s order on remand after the D.C. Circuit Court of Appeals last July found FERC had overstepped its “passive and reactive role” in undoing the compromise and suggesting the inclusion of unit-specific exemptions to the MOPR, which PJM had adopted in a compliance filing. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

In response to the December ruling, PJM asked for a one-time waiver of a Tariff provision that requires sellers to apply for unit-specific MOPR exemptions 135 days in advance of the third 2018/19 Incremental Auction slated for Feb. 26. Unsure of the outcome of FERC’s remand order, some sellers preparing for the auction opted last October to apply for the categorical exemptions — leaving them outside the deadline for seeking unit-specific exceptions once the commission had rejected PJM’s proposed rules.

The timing of the remand order also meant that Tariff-based deadlines had slipped for PJM and its Independent Market Monitor to provide a seller their respective determinations on the unit-specific request — and for the seller to commit to an offer price.

“As a result of these already-passed or plainly impracticable deadlines, parties that reasonably relied on the categorical exemptions, but that could also qualify for a unit-specific exception, would be barred by the current Tariff deadlines from submitting justifiably competitive offers in the auction,” PJM wrote in its Dec. 20 waiver request.

“Without waiver, resources that followed the then-effective Tariff language would be unfairly penalized for simply adhering to the Tariff,” the commission wrote in granting the request. “PJM’s waiver request remedies the timing conflict between the remand order and the effective Tariff rules, thus allowing these affected resources to submit unit-specific review requests.”

FERC rejected LS Power’s request to broaden the scope of the waiver to include generating resources that had not applied for categorical exemptions by the October 2017 deadline. The company contended that some of its affiliates had only recently acquired some new resources “or faced uncertainties regarding interconnection service for those resources,” the commission noted.

PJM FERC waiver LS Power MOPR exemption — FERC rejected LS Power’s bid to extend PJM’s original MOPR exemption waiver request to accommodate plants the company had acquired late last year, such as the Ironwood Plant above | *TransCanada*

“LS Power does not explain why expanding the scope to entities that were not affected by the timing of the remand order is justified. Accordingly, we grant PJM’s waiver request and reject LS Power’s request to expand it,” the commission said.

The waiver sets these one-time deadlines to remedy the issue:

Jan. 12: Deadline for markets sellers that had submitted categorical exemption requests to submit a unit-specific request;
Feb. 2 (Monitor) and Feb. 16 (PJM): Deadlines for proposed determinations on the exemption request; and
Feb. 22: Deadline for the seller to provide its commitment on a unit-specific offer price.

January 25, 2018

MISO Staff, Stakeholders Envision Expanded Storage Participation

By Amanda Durish Cook

CARMEL, Ind. — MISO officials Tuesday suggested more ways for energy storage devices to participate in the footprint in the future but didn’t commit to any final courses of action.

The measures could involve generator-and-storage interconnection combinations and competitive bidding on storage projects that solve transmission issues, stakeholders learned at a Jan. 23 Energy Storage Task Force meeting. Created last year, the task force’s mission is to identify storage-related grid and market obstacles and forward them to the Steering Committee for assignment to other stakeholder committees. (See MISO in 2018: Storage, Software, Settlements and Studies.)

MISO energy storage task force — Webb | © *RTO Insider*

MISO Director of Planning Jeff Webb told the storage task force that the Interconnection Process Task Force later this year will discuss how “hybrid interconnections” — where, for example, wind generation and energy storage join the grid at the same point of interconnection — would proceed through the interconnection queue.

“The hybrid systems are a really big deal, so I’m happy to see co-located systems on the screen,” task force Chair John Fernandes said, gesturing to the presentation.

No Traction

Wind on the Wires’ Rhonda Peters said the hybrid interconnection discussion failed to gain much traction in the task force last year, in part because MISO staff said they had to run proposals past the RTO’s legal department.

MISO also hasn’t added a storage option to the requirement that its planners consider alternatives to transmission construction, according to Webb. It finalized its non-transmission alternatives Business Practices Manual in August without including storage devices.

Webb said MISO will have to make several decisions before storage solutions can be pursued instead of new wires, including how many peak hours per day a storage device will be available to solve congestion.

Storage projects could be cost-shared and competitively bid if they solve issues typically handled by market efficiency projects, Webb said; MISO’s 345-kV minimum requirement will have to be reassessed, he added.

MISO also must address its practice of only allowing transmission developers to propose projects to address transmission reliability issues, he said. Webb also said MISO has yet to explore how it can gauge the adjusted production costs of storage projects or how storage-as-wires dispatch will be handled — that is, whether the RTO or the storage owner will take functional control.

Indiana Utility Regulatory Commission staffer Dave Johnston said that if storage owners elect to have their devices function as transmission service, MISO should assume dispatch control.

MISO DER energy storage MISO Annual Stakeholders' Meeting — Fernandes | © *RTO Insider*

“I’m not certainly going to sit here and say it’s this task force’s duty to try and change that,” Fernandes replied.

Webb also said stakeholders must consider retirement provisions for storage-as-transmission, saying that a “suitable” lead time might be the current three-year lead notice required of traditional transmission assets. “You can’t replace it with a transmission solution overnight. It takes years,” he said.

“This all could very well be a ‘be careful what you wish for’ for storage owners,” Fernandes said. “These are excellent points that need to be considered.”

MISO energy storage devices DER — Sperry | © *RTO Insider*

Storage could be eligible to provide black start service in MISO, if resource owners pledge a three-year commitment and MISO adjusts some restrictions it imposes beyond the NERC definition of black start resources, said Kim Sperry, the RTO’s director of market engineering.

Customized Energy Solutions’ David Sapper urged MISO and stakeholders to consider how storage could earn auction revenue rights and financial transmission rights.

Current Options for Storage

Sperry said the RTO currently has only one market definition unique to storage: Stored Energy Resource Type I, which can participate only as regulating reserves. Sperry said storage can also participate as either a demand response, emergency DR or load-modifying resource.

MISO asked FERC in April to allow creation of a Stored Energy Resource Type II Tariff definition following Indianapolis Power and Light’s complaint against the RTO’s restrictive storage participation rules (ER17-1376). (See MISO Rules Must Bend for Storage, Stakeholders Say.) A Type II resource must be able to continuously discharge for four consecutive operating hours across a coincident peak each day. In return, it will be able to function as DR in the day-ahead market and can participate in the annual capacity auction.

We Energies’ Tony Jankowski asked if MISO would create provisions to prohibit a storage device from withdrawing at will from markets to operate as a behind-the-meter resource. Sperry said the idea was to create rules that incent storage devices enough to participate visibly in MISO markets, in front of the meter.

Future task force talks will involve FERC’s pending Notice of Proposed Rulemaking, which would require RTOs to allow storage resources of 100 kW and above to participate in capacity, energy and ancillary services markets (RM16-23). (See FERC Rule Would Boost Energy Storage, DER.)

But Fernandes warned task force attendees “not to rely too heavily” on the rulemaking to guide the task force’s work. Only one of the current commissioners — Cheryl LaFleur — took part in drafting the NOPR, Fernandes noted, and the newcomers could make changes in the final order.

January 24, 2018

McIntyre Wades into Capitol Hill Fuel Wars

By Rich Heidorn Jr.

WASHINGTON — In his first Capitol Hill appearance as FERC chairman, Kevin McIntyre said Tuesday that he still sees a place for coal and pledged the commission would maintain its independence as it conducts its new resiliency inquiry.

FERC’s resiliency docket (AD18-7) was mentioned frequently during a two-hour hearing at which the Senate Energy and Natural Resources Committee heard from McIntyre and the heads of PJM, ISO-NE, and NERC. The commission launched the initiative Jan. 8 after rejecting the Department of Energy’s Notice of Proposed Rulemaking (NOPR) for price supports.

Panel (left to right): Kevin McIntyre, FERC; Bruce Walker, DOE; Charles Berardesco, NERC; Allison Clements, Goodgrid; Andy Ott, PJM; Gordon van Welie, ISO-NE | © *RTO Insider*

Coming after a two-week cold spell that stressed grid operators in much of the country, the hearing gave coal-state senators disappointed over the commission’s rejection of the NOPR a chance to score points for their favorite fuel.

Coal Is Still Needed

Would the system have had enough power without the coal-fired generation that contributed during the cold spell, Sen. Joe Manchin (D-W.V.) asked McIntyre.

“I think in this recent weather event, we wouldn’t have seen any widespread outages absent coal,” McIntyre responded. “That said, coal was a key contributor. It wasn’t exempt from operational problems … but it was no question a key contributor. I share in your overall of view of [the] ‘all-of-the-above’” strategy.

“Coal needs to have a place?” Manchin continued.

“Absolutely,” McIntyre obliged.

PJM CEO Andy Ott said his system could not have met its load without coal, which represents about a third of its fuel mix — about even with nuclear and slightly above natural gas.

“We could not survive without natural gas. We could not survive without coal. We could not survive without nuclear,” Ott said later, in response to a question from Sen. John Barrasso (R-Wyo.). “We need them all.”

Charles A. Berardesco, who was making his first appearance before the committee since being named NERC’s interim CEO, expressed a similar view.

“NERC recommends policymakers and regulators should consider measures promoting fuel diversity and supplemental fuel sources as they evaluate electric system plans, consistent with policy objectives,” he said. “Additionally, regulators and policymakers should expedite licensing of new transmission and natural gas infrastructure to diversify and distribute risk.”

No to ‘All of the Above’

Kevin McIntyre — van Welie | © *RTO Insider*

But ISO-NE CEO Gordon van Welie refused to take the “all of the above” pledge.

Van Welie acknowledged that coal — which Barrasso said provided 7% of New England’s power at the height of the coal snap — had contributed to the system’s performance.

But, he said, “the prospect of coal in New England is limited” because of the region’s desire to decarbonize. Only three coal generators took capacity obligations in its 2017 auction, one of which — the 383-MW Bridgeport Harbor Station — has announced its retirement.

“By definition, we have to reduce the amount of fossil fuel burned in the region,” van Welie said.

Van Welie also said the goal of fuel diversity is inconsistent with least-cost dispatch. “The term ‘fuel diversity’ is at odds with the idea of competitive wholesale markets, which is why you don’t hear us using the term ‘fuel diversity,’” he said. “We use the term ‘fuel security.’”

Allison Clements, president of energy policy firm Goodgrid, cited the conclusion of a National Academies of Sciences, Engineering and Medicine’s DOE-funded report, which she said “cautions about the difficulties of creating cost-effective and non-redundant rules for something as unpredictable and varied as resilience needs.” Clements participated in the study. (See DOE Panel Hears Results of Academies’ Resilience Study.)

“The idea that this new set of [renewable] resources coming on can’t be reliable is a false place to start,” she said.

“At this point nationally, only 7% of the resource mix is non-hydro renewables. … Every kind of resource has a set of benefits and issues … so narrowing the conversation to just gas vs. coal and LNG vs. new pipelines is an overly narrow view of the opportunity,” she said.

Clements was one of several panelists and senators who gave shout-outs to renewables, energy efficiency, demand response, and storage. But van Welie said none of those are likely to solve New England’s long-term fuel supply problem. (See Report: Fuel Security Key Risk for New England Grid.)

He also said, “Grid-level storage, in terms of today’s technologies, [is] not really useful in multi-day, multi-week events.”

Cantwell: Political Pressure, Ex Parte ‘Troubling’

Ranking member Sen. Maria Cantwell (D-Wash.) praised FERC for resisting what she called “undue political pressure” to provide coal and nuclear plants a “bailout” through the NOPR.

But she said she was disturbed by Commissioner Neil Chatterjee’s disclosure of an ex parte communication by an attorney lobbying for FirstEnergy’s request to transfer a struggling coal plant from its merchant unit to a regulated utility. (See McInty r e: Won’t Commit to Probe Leak to ‘Good Friend’.)

“The news was troubling to me because it said to me that there are those who are trying to influence FERC on a political aspect as opposed to the thorny economic issues,” she told McIntyre. “What do you plan to continue to do to ensure FERC is an independent agency?”

“I intend to do my utmost to ensure that FERC lives up to [its statutory] independence,” said McIntyre, who cited the commission’s unanimous vote to dismiss the DOE NOPR and open the new docket. “I’m so pleased that we were able to see a common path forward in … pursuing this very important issue.” (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

McIntyre (left) and Walker | © *RTO Insider*

“So, you’ll make sure the politics stays out of it?” Cantwell asked.

“Thus far, honestly, it hasn’t been a problem,” McIntyre responded. “I have not personally felt any undue influence from anyone to affect my decisionmaking and I would expect that to continue.”

Chairwoman Lisa Murkowski (R-Alaska) pressed McIntyre on how quickly FERC will act in the new docket. She noted the commission still hasn’t completed work in the price formation docket it opened following the polar vortex in 2014. She said she had been raising concerns over the reliability impact of plant retirements for at least eight years.

The commission gave RTOs and ISOs 60 days to answer more than two dozen questions on their efforts to ensure resilience and other parties 30 days to file comments in response.

“When you say FERC is going to take prompt action, does this mean that it’s technical conferences or staff memos and whitepapers? What action can be expected?” Murkowski asked. “ … I would hope that FERC recognized that we need to move beyond technical conferences and more white papers, that we actually need to see that action.”

McIntyre said he shared Murkowski’s frustration with FERC’s pace before joining the commission.

“I cannot say now how much time” it will take FERC to act following the comments, he said. “But it’s something where I have declared it — and our order declares it — to be a matter of priority for the commission. Those are not words we utter very often.”

DOE Proposes National ‘Model’

Kevin McIntyre DOE Resiliency Coal — Walker | © *RTO Insider*

Bruce J. Walker, assistant secretary in DOE’s Office of Electricity Delivery and Energy Reliability, told the panel DOE will be seeking funding to develop “a single North American energy infrastructure model of the ongoing resilience planning efforts at the local, state, and regional level, including interconnections that reach into Canada and Mexico.”

Walker said the goal of the model will be to fill “gaps” and “harmonize” inconsistencies in local, state, and regional resilience efforts.

“I understand that we currently do not have funds appropriated for such a task,” he said. “So, I am taking this opportunity to make my position clear: I believe building this resilience model should be the top priority for DOE’s Office of Electricity Delivery and Energy Reliability over the coming years.”

January 24, 2018

Critics: Trump Tariff to Cut Solar Growth, Jobs

By Jason Fordney

President Trump’s new tariff on imported solar cells and modules will slash domestic solar output by 6.7 GW by 2021 and wipe out tens of thousands of jobs, a major solar trade industry association said Tuesday.

“We are not happy with this decision,” Solar Energy Industries Association (SEIA) CEO Abigail Ross Hopper said during a conference call.

The move could have a “significant impact” on new solar markets and eliminate 23,000 U.S. manufacturing jobs this year, Hopper said. She anticipated the decision could spur a complaint with the World Trade Organization over the tariff, and “we should be watching with great interest should another country choose to pursue that path.”

FERC trump solar cells tariffs — Critics say the Trump Administration’s new tariff on solar equipment will hurt the domestic industry

“This administration really grappled with understanding that solar is creating jobs,” Hopper said.

Bill Vietas, president of RBI Solar in Cincinnati, Ohio, said: “There’s no doubt this decision will hurt U.S. manufacturing, not help it. The U.S. solar manufacturing sector has been growing as our industry has surged over the past five years. Government tariffs will increase the cost of solar and depress demand, which will reduce the orders we’re getting and cost manufacturing workers their jobs.”

But the Trump Administration contends that China has used its own incentives and subsidies to flood the United States with underpriced solar cells and modules, hurting domestic manufacturers. Based on recommendations from the International Trade Commission (ITC), the tariff starts at 30% for the first year and drops by 5% each year over the following four years, with the first 2.5 GW of imported solar equipment exempt.

The White House on Monday issued an announcement from U.S. Trade Representative Robert Lighthizer that Trump approved the ITC’s recommendation to impose the tariff on imported solar cells and modules, as well as washing machines. ITC found that “artificially low” priced solar cells and modules from China has spurred solar growth in the United States and that China has used incentives, subsidies, and tariffs of its own to dominate the global solar equipment supply chain.

Chinese manufacturers’ share of global solar production grew from 7% in 2005 to 61% in 2012, according to U.S. government statistics. The United States imposed anti-dumping and other duties in 2012 and 2013, but Chinese producers evaded those tariffs by moving production to other countries.

“The ITC determined that increased solar cell and module imports are a substantial cause of serious injury to the domestic industry,” the White House said. “Although the commissioners could not agree on a single remedy to recommend, most of them favored an increase in duties with a carve-out for a specified quantity of imported cells.”

Prices for solar cells and modules fell by 60% between 2012 and 2016, and “by 2017, the U.S. solar industry had almost disappeared, with 25 companies closing since 2012. Only two producers of both solar cells and modules, and eight firms that produced modules using imported cells, remained viable,” the notice said.

The tariffs are not as high as those proposed by solar companies Suniva and SolarWorld Americas. ITC initiated the investigation in May 2017, after Georgia-based Suniva filed a petition citing domestic solar industry job losses and wage declines. The company, majority-owned by privately-held Chinese firm Shunfeng International Clean Energy, declared bankruptcy last April.

SEIA said that out of 38,000 solar manufacturing jobs in the United States, all but about 2,000 make something other than cells and panels, producing products such as “metal racking systems, high-tech inverters, [and] machines that [improve] solar panel output by tracking the sun and other electrical products.”

Section 201 of the Trade Act of 1974 authorizes the president to create tariffs or take other actions in response to an ITC determination that increased imports are a substantial cause of serious injury to domestic producers.

January 24, 2018

CAISO Moves Ahead With Load-Shifting, DR Products

By Jason Fordney

CAISO is delving into the next phase of a years-long effort to integrate more storage and demand response (DR) into its markets.

Up next: a new load-shifting product intended to reduce renewable curtailment and overgeneration, among other ideas.

CAISO FERC Demand Response energy storage — Storage is seen as critical for enabling integration of more renewables onto the CAISO-grid | *SCE*

The ISO Board of Governors last year approved Energy Storage and Distributed Energy Resources Phase 2 (ESDER 2), which will provide distributed energy resources and a storage foothold in the ISO’s markets. (See Ne w CAISO Rules Spell Increased DER Role.)

CAISO and its market participants now will confront new complexities during the scoping phase of ESDER 3. Storage companies are heavily involved in developing a load-shifting product to allow behind-the-meter (BTM) resources to participate in DR, but CAISO also will evaluate resources other than storage. The ISO is focused on BTM storage where charge and discharge can be metered and monitored directly.

The industry’s goal is to have a product launched by spring 2019, Ted Ko, of storage company Stem, said at a Jan. 16 ESDER workshop. The intent is to have the “minimum necessary design” to allow storage and other resources to participate in load shifting — the practice of charging batteries during periods of low demand and negative prices and discharging during ramps. During previous meetings and workshops, stakeholders developed a definition of a “shift resource” that can demonstrate its ability to shift loads. Stakeholders also are exploring issues around registration, metering, bidding, and settlement.

“This is 1.0,” Ko said of the load-shifting product. “We are not trying to design the full product.” He also said the ISO should not intend to solve all the problems in the first round.

“Let’s try really, really hard to not make the perfect be the enemy of the good,” he said

Storage companies have increased their pressure on CAISO to develop the load-shifting product, which was deferred from ESDER 2. (See Storage Advocates Urge CAISO on DR Pr o duct and CAISO Load-Shifting Product to T arget Energy Storage.)

Aside from the load-shifting product under the ESDER 3 demand response track, CAISO is also addressing DR modeling limitations, dealing with weather-sensitive demand response resources and recognizing load curtailment provided from BTM vehicle charging equipment.

ESDER 3 will also examine “multiple-use applications” that allow DR and DER to “stack” services across different wholesale and retail market segments, increasing their potential for compensation. CAISO wants to use that track of the initiative to enable 24×7 participation for distributed energy resources and create a wholesale market participation model for microgrids.

CEC Announces Microgrid Grants

DER last week got another boost when the California Energy Commission issued a notice of propo s ed a ward of $22 million in grants to deploy microgrids, the first batch in its latest $44-million competitive microgrid solicitation. (See Californ i a Aw a rding $45 Million for Microgrids.)

The proposed recipients include Native American tribes, Lawrence Berkeley National Laboratory, University of California, San Diego Unified Port District, Electric Power Research Institute, and others. The funding is contingent upon approval by the full commission.

January 23, 2018January 24, 2024

Calls Grow for Capturing Utilities’ Tax Savings

The number of state officials and utilities announcing actions because of the Tax Cut and Jobs Act signed by President Trump last month keeps growing.

The bill cut the federal corporate tax rate from 35% to 21%, and many public officials want to make sure utilities pass their savings from the bill on to their customers.

As of Jan. 8, regulatory bodies in at least 11 states had opened proceedings or taken other actions related to the tax bill, and elected officials in at least two other states had called for them to. Also, at least nine electric and gas utilities had said they planned to pass their savings on to their customers. (See Utilities Likely to Pass Tax Bill Gains to Customers.)

Since then, a coalition of elected officials, consumer advocacy officials and utility regulators from 18 states has written FERC a letter calling for an investigation into the “justness and reasonableness” of utility rates considering the tax act. (See “States Asking FERC to Investigate Rates in Light of Tax Cut,” Federal Briefs.)

The Organization of MISO States joined the chorus on Monday. (See related story, OMS Urges FERC to Pass Tax Cut Benefit to Ratepayers.)

At Thursday’s open meeting, Commissioner Robert Powelson expressed his support for a pass-through of utilities’ savings. “I hope we do our part to make sure these tax benefits are accrued to energy users here in America,” he said.

Chairman Kevin McIntyre told reporters after the meeting that he agreed with Powelson’s sentiment and that the commission was considering its options.

Also, the Texas Public Utility Commission has taken its first steps in determining how to share the tax cuts with ratepayers. (See PUCT Briefs: Regulators Begin Addressing Utility Tax Savings.)

Here’s a round-up of other recent actions by regulators and companies:

Midwest

The North Dakota Public Service Commission on Jan. 10 ordered Montana-Dakota Utilities, Otter Tail Power and Xcel Energy to let it know by Feb. 15 their savings from the tax bill so it can return the money to ratepayers.

Ameren Illinois said it filed a petition with the Illinois Commerce Commission to be allowed to pass its tax bill savings on to its natural gas customers and planned to file one to be allowed to pass them on to its electric customers too.

Oklahoma Gas & Electric said savings it realizes from the tax act will cover about $68 million of a $72 million rate increase it asked for on Jan. 16.

Kansas City Power & Light and Westar Energy said they will file requests with their state regulators to be allowed to pass their savings on to their customers. Kansas City Power & Light’s parent, Great Plains Energy, and Westar Energy are continuing to pursue their merger. (See Great Plains, Westar File Revised Merger Plan.)

East

The Delaware Public Service Commission on Jan. 16 approved a petition filed by the state’s Public Advocate to make sure consumers receive the benefits of any savings realized by utilities. The order directs utilities to estimate the impact of the new tax law on their cost of service, and to propose procedures for reducing their rates to reflect those impacts by March 31.

Delmarva Power, which had already committed to pass along its savings from the tax bill to Maryland ratepayers, said it would adjust its natural gas and electric rate increase requests in Delaware to reflect its savings from the bill.

Dominion Energy said Jan. 2 if its deal to purchase SCANA goes through, it will reduce the rates of SCANA’s South Carolina Electric & Gas subsidiary by more than $7/month with some of the money coming from savings from the tax bill.

Public Service Enterprise Group said in an 8-K filing Jan. 11 that it will realize a one-time benefit of $660 million to $850 million from the tax bill. A day later its Public Service Electric and Gas subsidiary asked New Jersey regulators to approve a 1% increase in its base electric and gas rates, which it said reflects the fact that it is “passing along savings from recent tax law changes.”

National Grid said on Jan. 11 it would reduce its request for an electric and gas base distribution rate in Rhode Island from $71 million to $45 million because of savings from the tax bill.

The company on Monday said its Niagara Mohawk Power subsidiary has filed a request with the New York Public Service Commission to boost its revenue by $206 million in 2018-2019, before the impact of deferred credits. The request includes an estimated customer savings of $76 million from the tax cuts.

West

Pacific Power said Jan. 3 it will work with its regulators and stakeholders to pass its savings from the tax bill on to its customers.

Arizona Public Service said Jan. 9 it wants to use its savings from the tax bill to reduce its average residential customer’s monthly bill by about $4.70.

Green Mountain Power CEO Mary Powell said Jan. 10 that the company would pass along all its savings from the tax bill to its customers.

South

The Mississippi Public Service Commission has asked its Public Utilities Staff to consider possible rate reductions available to residents.

The Georgia Public Service Commission on Jan. 16 ordered Georgia Power to submit a report to it by Feb. 20 detailing how the utility will be affected by the tax bill.

Florida Power & Light said Jan. 16 it plans to use its savings from the tax bill to cover its $1.3 billion in Hurricane Irma restoration costs and may be able to use them to delay future rate increases.

— Peter Key

January 23, 2018April 11, 2024

McIntyre: Won’t Commit to Probe Leak to ‘Good Friend’

WASHINGTON — FERC Chairman Kevin McIntyre declined to say Thursday whether the commission will investigate how attorney William S. Scherman allegedly learned the contents of a pending order before its issuance Jan. 12. McIntyre described Scherman, a former FERC general counsel now with Gibson Dunn, as a “good friend.”

Commissioner Neil Chatterjee filed a memo on Jan. 12 reporting that Scherman had attempted to privately lobby him a day earlier on FirstEnergy’s request to transfer a struggling coal-fired generator from its merchant unit to a regulated affiliate. The commission’s order rejected the request as not in the public interest (EC17-88).

Chatterjee reported that Scherman called him on Jan. 11, “indicating his concern that the commission would shortly issue an order adverse to the interests of [FirstEnergy affiliate] Monongahela Power. Mr. Scherman also stated that he would prefer that the commission set the issue for hearing instead of issue an adverse order. As soon as I realized that Mr. Scherman’s communication concerned the merits of the contested proceeding, I terminated the communication and did not respond to Mr. Scherman’s statements. I then drafted this memorandum to memorialize the ex parte communication for the record.”

McIntyre Press Conference

RTO Insider asked McIntyre at his press conference following Thursday’s open meeting whether the commission would investigate who may have leaked the information to Scherman.

“I read that in [Chatterjee’s] statement and I am going to be discussing that with my staff,” McIntyre responded. “In the meantime, I just want to say that the system that we have in place for situations just such as that where there’s an ex parte communication worked perfectly. We have a system in place. Commissioner Chatterjee did exactly the right thing and the system worked. So as far as I’m concerned, I’m very satisfied with where it came out.”

Commissioners Cheryl LaFleur, Robert Powelson and Richard Glick told RTO Insider on Jan. 16 that Scherman had not attempted to contact them on the case. McIntyre said Thursday that he also had not been contacted.

“Bill Scherman and I are old friends. I consider him a terrific lawyer and a good friend,” McIntyre said. “In this instance, I had no contact with him about the matter.”

FirstEnergy merchant affiliate Allegheny Energy Supply had requested permission to transfer ownership of the 1,159-MW Pleasants Power Station to regulated affiliate Mon Power, with the latter assuming a $142 million obligation for pollution controls Allegheny installed at the plant. The commission’s unanimous Jan. 12 order concluded the deal was not in the public interest because it resulted from an “overly narrow” solicitation. (See FERC Blocks FirstEnergy Sale of Merchant Plant to Affiliate.)

Ex Parte Communications Common

Ex parte communications (one side only) are quite common at FERC — so frequent, in fact, that FERC’s secretary publishes a list of disclosures about every two weeks (RM98-1).

Most of the dozens of communications reported in the last year concerned pipeline projects and involved letters or flyers sent to commissioners rather than filed as formal comments in the dockets. Residents near the projects were the most frequent offenders, but chambers of commerce, economic development authorities and labor unions also were listed. The communications are filed in the dockets to document them but are not considered part of the evidence before the commission.

The commissioners also hear frequently from state and federal elected officials, but such communications are exempt from ex parte rules.

No Foul?

Ex parte phone calls to commissioners by members of the energy bar are not common, however.

“Everyone else in the FERC bar manages to follow the rules. FERC shouldn’t let cheaters get away scot-free,” said a former member of the commission’s general counsel’s office who asked not to be identified to protect his working relationships. “And Commissioner Chatterjee’s description gives the lie to the assertion that this was a gray area. Setting a matter for hearing as opposed to denying it is about as substantive as it can get.”

Scherman told RTO Insider last week that he had done nothing wrong and said the commission should change its ex parte rules, which prohibit private communications with commissioners in contested case specific proceedings. “Based upon my experience, I do not believe I engaged in any ex parte communications,” Scherman said in an email. (See FirstEnergy Lawyer Sought to Lobby Chatterjee on Plant Deal.)

Scherman declined to answer additional questions Monday morning but later asked that the story include comments on an unrelated matter (see Editor’s Note, below). First Energy has declined to comment.

Rule 2201, revised by FERC Order 718 in 2008, states that “in any contested on-the-record proceeding, no person outside the commission shall make or knowingly cause to be made to any decisional employee, and no decisional employee shall make or knowingly cause to be made to any person outside the commission, any off-the-record communication. … Commission employees who are found to have knowingly violated this rule may be subject to the disciplinary actions prescribed by the agency’s administrative directives.”

Who is the Mole?

FERC draft orders are typically circulated among the commissioners’ aides and staffers in divisions who are responsible for writing the legal and technical language of the ruling. The drafts are generally not secured with any kind of watermark that would indicate where a leaked copy originated.

The commission’s ethics rules state that staff “may not disclose nonpublic information, including draft orders and internal discussions, to the public.” Staff are also barred from disclosing “the nature or the time of any proposed action by the commission to anyone outside the commission.”

But Washington’s revolving door culture means that those who depart FERC leave behind former colleagues able to share information with them — carelessly or maliciously — in social settings.

A former FERC policy adviser who now works as a consultant said he thinks such disclosures are “very rare.”

“I feel like it would harm relationships to even put staff in that position by asking a question” regarding a pending matter, he said. “But clearly others do, and somebody [on FERC staff is] playing ball.”

The former adviser speculated that Chatterjee, a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), was slow to realize what he had gotten into when he agreed to talk to Scherman. “In the legislature, intelligence is the coin of the realm. And sharing intelligence is how you get intelligence. It wouldn’t surprise me if he started to get into that game a little bit and realized his entire reputation could be damaged” by sharing information.

An industry analyst agreed that improper disclosures are rare.

“The commission goes out of its way not to discuss matters with parties to a case,” the analyst said. “I tell my clients, ‘If you bring this up [in a meeting with FERC officials], you can expect to be shut down.’ FERC is fairly discreet. I think they are cognizant that [their comments] can move a stock.

“You can talk in hypotheticals [with FERC officials], but then you may find that what you have been told is not something you can take to the bank. I’ve had conversations where someone says, ‘Commissioner so-and-so told me X.’ It’s just one person’s opinion. A staffer close to one commissioner saying, ‘I think this is going to happen.’ That’s only one of five votes.

“My guess is somebody probably tipped Bill and that was inappropriate,” the analyst said. But FERC’s “pretty aggressive” deficiency letter, filed in the docket in June, indicated the commission’s skepticism of the Pleasants deal, the analyst added.

“The commission should be investigating whether Scherman did in fact obtain nonpublic information,” Tyson Slocum, director of Public Citizen’s Energy Program, said in an email. “If FERC refuses, the Senate Energy and Natural Resources Committee should step in.”

The Department of Energy’s Inspector General also has authority to investigate the commission. (See DOE IG Warns FERC Information Security ‘Severely Lacking.’)

An IG spokeswoman on Monday declined to say whether it was investigating the Scherman incident. “We are an independent organization. We take a number of factors into consideration when deciding to initiate an investigation,” she said.

Penalties, Prior Incidents

Rule 2201 allows the commission to bar Scherman from practicing before it: “If a person knowingly makes or causes to be made a prohibited off-the-record communication, the commission may disqualify and deny the person, temporarily or permanently, the privilege of practicing or appearing before it, in accordance with Rule 2102 (Suspension).” [See 18 CFR section 385.2201 (i)(2).]

Rule 2102 permits FERC to disqualify a person who is found “to have engaged in unethical or improper professional conduct.”

This is not the first time Scherman has been accused of flouting the commission’s ex parte rules. In 1992, congressional investigators suggested Scherman — then FERC general counsel — had whitewashed an ex parte meeting at which FERC staff discussed with sponsors of the Iroquois Gas Transmission System pipeline project ways to expedite the commission’s approval without notifying opponents of the project.

The meeting, on March 15, 1990, was requested by commission staff, according to an account in the Energy Law Journal, which said the applicants also met with at least one commissioner about the status of the application.

Martin Fitzgerald, special assistant to the general counsel at the General Accounting Office, told the House Government Operations Committee panel in 1992 that the discussions involved amendments to the application, the timetable for the commission’s review of new aspects of the project and a change in the project’s gas capacity, according to the Journal of Commerce.

Scherman, who was assigned to investigate the issue, reported on June 29, 1990, that the meeting dealt only with procedural matters and thus did not violate FERC rules.

But Environment, Energy and Natural Resources Subcommittee Chairman Mike Synar (D-Okla.) released a memo Scherman had written to FERC Chairman Martin L. Allday weeks before that report was issued — and before the investigation was complete — indicating Scherman had already reached that conclusion. A second GAO investigator told the subcommittee that FERC employees who were at the meeting said Scherman asked them only perfunctory questions about it, according to a Washington Post account.

The commission’s ruling on the pipeline application sided with Scherman on the characterization of the meeting (CP89-634), as did the D.C. Circuit Court of Appeals.

Second Incident

Scherman also was criticized for not disclosing that Transcontinental Gas Pipe Line Corp. had asked him and the commission’s deputy general counsel for oral argument prior to commission action on a rehearing request. A divided commission ruled in January 1992 that the request should have been treated as an ex parte communication and made public.

According to the order, the request was made following the commission’s September 1990 order denying Transco’s request for an oral argument. “Counsel for Transco orally asked the general counsel and the deputy general counsel of the commission for an oral argument prior to the commission acting on rehearing in this case. That oral request was not disclosed to the parties or to the commission. Subsequent to these communications, the general counsel and the deputy general counsel recommended to the commission that it grant an oral argument.”

Citing the Iroquois opinion, the majority said, “this is the kind of doubtful situation that should be treated as involving comments related to the merits in order to protect the integrity of the decision-making process.” The dissenting commissioners concluded the request for oral argument was procedural and thus permissible (TA85-3-29).

Editor’s Note from Rich Heidorn Jr.

After saying Monday morning that he had no further comment on the Chatterjee incident, Scherman emailed RTO Insider in the afternoon, saying he wanted to go on the record with criticism of me over my role as a FERC whistleblower in a 2006 incident.

The incident occurred after then-FERC Chief of Staff Daniel Larcamp negotiated a settlement to end an investigation by the commission’s Office of Administrative Law (OAL) under circumstances that suggested that Southern Co. and FERC management had engaged in ex parte communications.

As a staffer in FERC’s Office of Enforcement, I had been loaned to OAL’s trial staff to aid in the investigation, which concerned whether Southern was improperly sharing nonpublic information with the company’s marketing affiliate.

When I confirmed with my superiors that Larcamp’s settlement would have improperly allowed Southern to continue sharing nonpublic information — but was unable to persuade them to block it — I consulted with an attorney with the Government Accountability Project, an organization that represents whistleblowers.

Based on my attorney’s advice, I went public with my concerns through Rep. Henry Waxman, then the ranking Democrat on the House Oversight and Government Reform Committee. I also was quoted in the press. The commission ultimately rejected the settlement Larcamp negotiated and imposed tougher conditions.

Larcamp’s Entry

Larcamp entered the case in September 2005, after trial staff had obtained evidence indicating that Southern’s subsidiary, Southern Power, attended meetings at which sensitive information (i.e., plant retirements, present and future load characteristics, expected resource additions and industrial energy sales) was exchanged. This is information that Southern Power would not have been allowed to receive were it properly classified as a “marketing” affiliate under FERC’s regulations.

On Sept. 21, 2005, Larcamp declared himself “non-decisional,” meaning that, like trial staff, he was not prevented from talking to Southern under ex parte rules. Doing so, however, meant he could not discuss the matter with any commissioners or other “decisional” FERC staff.

Larcamp never met with the trial team to discuss the evidence in the case before beginning his settlement talks with Southern. The team did not even know Larcamp was talking to Southern until he abruptly informed OAL managers in November, while team members were deposing Southern officials in Birmingham and Atlanta. Staff were ordered to cancel the remaining depositions and return to D.C.

Larcamp said he was settling the case at the behest of then-Chairman Joseph Kelliher, who took the gavel two months after the case was initiated under Chairman Pat Wood.

“[Larcamp] said Southern thinks it has two votes on the commission in its favor on this issue,” according to an internal memo I provided to Waxman. “He said that if that didn’t work, Southern would likely apply political pressure. … But he said that even if the case goes forward, the chairman would not be eager to expedite it, and it would likely languish through 2007.”

Scherman’s Statement

Here is Scherman’s statement in full:

“In your short time at FERC, it was public information that you engaged in unethical and unlawful actions. As you know, at that time, I, along with others, publically [sic] stated that on the record. As you know, I, along with those who were at the FERC at that time, were highly critical of your improper and unethical conduct. As a result, you should recuse yourself from any potential story where I am involved given your obvious prejudice and bias. Seeking to settle an old score is unethical and unscrupulous conduct that exhibits actual malice. Any reputable ‘journalist’ would be disreputable by failing to include fully this on-the-record comment in any story that might run.”

For the record, I worked for FERC for eight years, from 2002 to 2010 (and had frequent contact with Scherman on matters concerning his client, Entergy). FERC never took any disciplinary action against me for my role. In October 2006, the commission unanimously rejected the settlement Larcamp negotiated and imposed tougher conditions (EL05-102).

Commissioner Suedeen G. Kelly, writing in a concurring statement, said, “It is well-known that the process leading up to the filing of this settlement was highly unusual and caused great controversy.”

Kelly cited comments that Administrative Law Judge Edward M. Silverstein made to a member of the commission’s trial staff during oral arguments following the settlement. “I’ve been here almost 15 years, and I’ve never been involved in a case in which somebody representing the commission — other than trial counsel — negotiated a settlement. And so, I think your position is unique and maybe even dangerous,” Silverstein said.

Six months after FERC’s ruling, Larcamp left the commission for a new job — with Southern’s law firm, Troutman Sanders.

January 23, 2018

ISO-NE Seeks Path to Mass. GHG Cost Recovery

By Michael Kuser

Massachusetts generators are worried they won’t be able recover the costs of purchasing additional greenhouse gas allowances after state regulators last month implemented stricter limits on emissions from fossil fuel plants.

ISO-NE is floating a proposed solution.

In a memo issued Friday to the New England Power Pool Markets Committee, the RTO said the early January cold spell has provoked concern among some generators “that they may consume all of their initial allocation of allowances and emit beyond that allocation before the end of the year.”

The generators are questioning their ability to recover costs for buying more allowances through bilateral trading once their initial allowances from the state are exhausted. The new rules require the utilities to purchase at least 16% of their electricity from clean energy sources in 2018, stepping up by a minimum of 2 percentage points annually until 2050. (See Massachusetts Tightens GHG Limits for Generators.)

ISO-NE GHG cost recovery — The 1,113 MW Canal Generating Station in Sandwich, MA is owned and operated by NRG Canal, an affiliate of GenOn Energy Management and NRG Energy | *EPA*

ISO-NE is proposing a possible recovery mechanism for instances when allowance costs cannot be reflected in a participant’s energy market supply offer. The proposal hinges on a waiver request that GenOn Energy Management filed with FERC earlier this month.

Immature Market

While generators can purchase additional GHG allowances from other participants through secondary markets, the Massachusetts program is only in its first year, and secondary trading is not mature — nor are there reasonably forecasted price ranges, ISO-NE said.

That contention mirrors one made by GenOn, an NRG Energy subsidiary, in its FERC filing requesting a limited, one-time waiver enabling it to seek additional cost recovery for purchases of emissions allowances required under the Massachusetts rule. The company said the waiver would allow purchases that might be needed for the continued operation of its 1,113-MW Canal Generating Station in Sandwich, Mass., “including operation this winter, if and as they become available from other allowance holders later in 2018 and into 2019 or, as a last resort, in an auction for 2019 Massachusetts GHG allowances (which could be used to cover a 2018 shortfall on a three-to-one basis).”

GenOn asked the commission to issue an expedited order on its request by Feb. 2 and sought a shortened comment period of 14 days (with comments due on Jan. 22).

Both ISO-NE and its Internal Market Monitor support the company’s request.

Possible Remedy

GenOn worked with the Monitor last fall to devise an additional GHG cost recovery mechanism under an ISO-NE rule that permits a participant to request additional cost recovery in the event its supply offer is mitigated in the energy market, leaving it unable to recover variable production costs.

The provision requires the participant to initiate a cost recovery request within 20 days of receipt of the first invoice for allowances for the applicable operating day. If additional allowances are bought more than 20 days after operation, the regulatory timing requirements would preclude their use for cost recovery of the additional allowances.

The RTO said it would support such a waiver, provided it can review the waiver request in advance and ensure it is limited only to an extension of time to file for cost recovery. The grid operator also clarified that the additional cost recovery must only cover the cost of purchasing additional allowances.

The Monitor and RTO added a final condition: that cost recovery would only be appropriate to the extent that energy market revenues earned for operation during the period covered by the purchased allowances are insufficient to cover the cost of those allowances, and only to the extent the revenue deficiency resulted from mitigation.

Legal Challenge

GenOn last week also joined with the New England Power Generators Association to file suit in Suffolk County Superior Court against the state for “regulating emissions from the electric generation sector in the same manner as all other sectors of the Massachusetts economy.”

The suit alleges that the state’s GHG rules “are arbitrary and capricious because they will increase statewide greenhouse gas emissions in direct contravention of the express purposes of the Global Warming Solutions Act.”

GenOn cited ISO-NE modeling of the impact of the rules on statewide GHG emissions demonstrating that generators in the region would maintain reliability by shifting electricity production from power plants in Massachusetts to other states. Relatively efficient clean-burning facilities in Massachusetts would therefore operate less, while inefficient and less clean resources in other states would run more.

Finally, the suit alleged that the state agencies exceeded their statutory authority in promulgating mass-based emissions regulations that remain in effect 30 years beyond the sunset date for any such regulations.