By Michael Kuser and Rich Heidorn Jr.

WASHINGTON — If the economists who testified at FERC’s technical conference last week agreed on nothing else, it is that a carbon adder is the simplest way for the power markets to value emission-free generation.

New York is going to try and translate the theory into practice as a way of addressing the impact of the state’s zero-emission credits (ZECs) for its upstate nuclear plants, officials told FERC.

On the first day of the two-day conference (AD17-11), state and NYISO officials asked FERC for time to develop their plan even as merchant generators called for immediate action to block the subsidies or respond to their effects on the wholesale markets.

The ZECs are part of New York’s Clean Energy Standard, which mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. The CES also calls for renewables to meet 50% of the state’s energy needs by 2030.

The subsidies will support Exelon’s two-unit Nine Mile Point, and the single-unit R.E. Ginna and James A. FitzPatrick plants for more than 12 years at a cost estimated as high as $7.6 billion. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.) At a legislative hearing into the ZEC program in Albany on May 1, however, New York Public Service Commission interim Chair Gregg Sayre said he expects the actual cost may be much less, perhaps as low as $2.86 billion.

NYISO CEO Brad Jones told FERC that while the ISO supports the ZEC program, it wants to find a way to incorporate the payments into the wholesale market.

The ISO has hired the Brattle Group to develop a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. Generating units that emit carbon would incur a penalty based on their level of carbon emissions; the penalties collected by the ISO would be “returned to customers in some equitable manner.”

PJM also is considering a similar mechanism, while New England has rejected it as impractical and overly expensive. (See related story, ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)

Urgency vs. Patience

Jones said the project was in its “initial stages” and that implementation could take three years.

That is too long for other stakeholders.

“I was shocked to hear [Jones] say yesterday that he doesn’t think the rates are just and reasonable but we have three years to work out a solution,” said Abe Silverman, vice president and deputy general counsel for NRG Energy. “No, this is something that needs to happen almost immediately.”

John Reese, senior vice president of Eastern Generation, said the issue is particularly acute in New York, which has a one-year forward capacity auction, unlike the three-year auctions in PJM and ISO-NE. Eastern Generation operates almost 5,000 MW of generation in NYISO and PJM, including 18% of New York City’s capacity.

“I can’t wait for seven years or eight years for this to work out,” he said. “Regardless of which model we end up with, we need to be sending investment signals now!”

The Independent Power Producers of New York argued that the state’s goals and its energy markets have reached a crossroads, saying that out-of-market solutions threaten the ability of the wholesale market to meet system needs at the least cost.

“Retail electricity customers are required to pay for renewable energy credits to support new large-scale renewable resources, as well as zero-emissions credits to support nuclear facilities which might otherwise retire from the market — both of which are out-of-market valuations for environmental attributes,” IPPNY CEO Gavin J. Donohue said. “The implementation strategies used to meet those [CES] goals conflict with the competitive market principles that have produced unparalleled reliability and record-low electricity prices.”

The NYISO discussion focused on several questions, some of which will also be central to challenges to the ZECs in court and before FERC: state vs. federal jurisdiction; the price suppressive impact of ZECs; and the efficacy of saving at-risk nuclear plants versus replacing them with renewables.

Dynegy, Eastern Generation, NRG and the Electric Power Supply Association filed a federal court suit in October claiming the ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The suit asks the court to find the ZECs invalid and order them withdrawn from the CES. (See Federal Suit Challenges NY Nuclear Subsidies.)

The same companies filed suit in February challenging Illinois’ ZECs for Exelon’s Quad Cities and Clinton nuclear plants and have also asked FERC to reject the subsidies (EL16-49). (See IPPs File Challenge to Illinois Nuclear Subsidies.)

 Do ZECs Interfere with the Wholesale Markets?

The Supreme Court has attempted to draw the lines between state and federal jurisdiction over the power industry in a series of rulings, most recently the January 2016 ruling in EPSA v. FERC, in which the court upheld FERC’s jurisdiction over demand response, and the April 2016 order in Hughes v. Talen, which rejected Maryland’s subsidy of a generator that could have undermined PJM’s capacity auction.

New York regulators took pains to ensure the ZEC program complied with the court’s advice in the latter case. “Nothing in this opinion should be read to foreclose Maryland and other states from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation,’” the court said.

Scott A. Weiner, deputy for markets and innovation at the New York State Department of Public Service, made an impassioned defense of the ZEC program, saying it was permitted by states’ “settled jurisdiction over environmental policy, resource adequacy, fuel diversity and reliability.”

“Rather than opening this discussion with the question of how state policies can be implemented through federally regulated wholesale markets, we should ask, ‘should they?’ An attempt to select resources through the federally regulated wholesale markets to achieve individual state policies may undermine, even if unintentionally, those very state programs,” he said. “By incorporating state policy into the wholesale markets, the state would have to seek a tariff change to reform its own policy.

“This changing role of the state’s utilities must be harmonized by federal and state regulators acting in respectful collaboration without one seeking to subsume the other.”

Rather than attempting to “absorb” state policies into the federal wholesale markets, Weiner said, FERC should consider removing barriers to new entry by state-supported resources by eliminating buyer-side mitigation.

“It is essential to recognize that policies addressing legitimate state interests may have incidental impacts on wholesale market prices without raising the specter of price suppression or undermining markets.”

NY, Exelon: ZECs not Intended to Suppress Prices

“New York, like other states, does not seek to suppress wholesale market prices. Ending application of this false assumption eliminates the need for market rules based on that presumption,” Weiner said.

Exelon also insisted that ZECs are not vehicles for price suppression, comparing them to the renewable energy credits (RECs) issued in support of state renewable portfolio standards.

“Buyer-side mitigation rules are aimed at large buyers seeking to suppress market prices by introducing new, uneconomic supply. But environmental programs like ZEC programs do not fit that description,” Exelon said. “First, in ZEC and REC programs, the state is purchasing a separate environmental attribute, so ZECs and RECs are not tied to energy or capacity sales.”

Impact, not Intent, is What Matters

Others counter, however, that it is the impact of state policies on prices — not policymakers’ intent — that is at issue.

David Patton, president of Potomac Economics, which provides market monitoring in NYISO and ISO-NE, said nuclear subsidies can be much more damaging to wholesale price formation than renewable subsidies because solar and land-based wind have low capacity values.

Former FERC Commissioner Tony Clark, now a senior adviser at Wilkinson Barker Knauer, said at a conference in March that while FERC hasn’t seen harm to the markets from state REC programs, the scale of the nuclear generation covered by subsidies — 20% or more of the market in some regions — may make them more vulnerable. (See Ott Seeks ‘Resilience’; Clark Handicaps ZECs.)

And even renewables are having a significant impact on prices, Lawrence Makovich, chief power strategist for IHS Markit, told FERC.

He presented analysis that he said demonstrated that wind output suppressed PJM prices by about 24% during the top net load hours in 2015, when peaking units were setting the price. Wind suppressed prices by 4% when net loads were average and by about 9% during minimum load, he said.

“On the cost side, compensating for the impact of wind … [caused] load-following generators to increase output ramping and starts and stops, causing less production efficiency and higher [operating and maintenance] costs,” he said.

Is Preserving Nukes the Best Policy Choice?

Exelon says ZECs are justified because it would take too long and be too costly to replace the zero-emission capacity of at-risk nuclear plants versus renewables. “When a nuclear facility retires, it cannot feasibly be replaced by renewable generation in the time necessary to avoid a spike in emissions. Instead, it will be replaced predominantly by fossil fuel-fired plants emitting significant carbon and other air pollution,” Exelon said.

The company cited Germany’s retirement of its nuclear fleet following the 2011 Fukushima nuclear accident, which resulted in “a massive increase in emissions despite investing in new renewable generation to such a degree that its electricity rates are now among the world’s highest.”

Similarly, the closure of the San Onofre nuclear plant in early 2012 “resulted in an increase in emissions that more than offset all of California’s investment to date in wind, solar and biomass generation,” Exelon said.

New York concluded replacing its nuclear fleet would require that it triple its energy-efficiency targets or construct 9,000 MW of onshore wind or 22,000 MW of solar.

NRG’s Silverman, however, said New York chose an expensive path.

“For $3.5 billion — or approximately half the price of the bailout in New York — the state could have purchased enough renewables to replace the output of all of its at-risk nuclear fleet with 100% new renewable power. Additionally, New York’s Independent Market Monitor found that a new combined cycle on Long Island is a far cheaper means of reducing carbon in New York than the nuclear bailout.”

Impact on LSEs

The impact of state mandates on load-serving entities was the key concern of James Holodak Jr., vice president of regulatory strategy and integrated analytics for National Grid, which owns LSEs in New York and New England.

Holodak said National Grid’s Niagara Mohawk Power subsidiary was forced to absorb $2 billion in stranded costs as a result of New York legislation that required utilities to buy electricity from independent power producers for at least 6 cents/kWh, a price higher than utilities’ production cost.

Holodak said the law forced Niagara Mohawk to sign contracts for output in excess of its actual demand and helped increase the utility’s rates by 25% between 1990 and 1995, causing many industrial and commercial customers to seek alternative suppliers or lower-cost locations.

Holodak said New England states with mandates should adopt a structure similar to that in New York in which each LSE is required to purchase the ZECs from the New York State Energy Research and Development Authority while recovering the costs from its customers. “In this instance, NYSERDA acts as the middleman, which advances the state’s policy goals and presents less risk for utilities than under a mandatory contracting model between the generator and the utility,” Holodak said.

He also made a case for allowing utilities to own renewables rather than being required to purchase them.

“Long-term bilateral [power purchase agreements] with developers equate to ‘virtual ownership’ with utilities and their customers absorbing project risks without the benefits of ownership,” he said, acknowledging that support for utility ownership will depend on utilities’ ability to “produce demonstrable customer savings.”

“We further recognize that this position may seem inconsistent with our broader support for market-based solutions where circumstances permit. However, today’s RTO/ISO markets do not adequately incentivize new entry from zero-emitting resources and it is not clear how or when they will evolve to do so.”

FERC’s agenda said the technical conference “may address matters at issue” in the following pending dockets:

• ER16-1404 Power Producers of N.Y. v. NYISO re. buyer-side capacity market power mitigation
• EL16-92-001 (See ‘Special Case’ DR Exempted from MOPR in NYISO.)
• ER17-386-002 (See FERC OKs NYISO Demand Curve Reset.)
• ER16-120 and EL15-37-002 (See FERC Orders Further Changes to NYISO RMR Rules.)