Page 1228 – RTO Insider

June 24, 2019

Ohio Nuke Bill — A Worthwhile Tradeoff?

By Christen Smith

Ohio lawmakers are being asked to trade ratepayer-funded renewable energy mandates for the jobs and carbon-free energy that would come from the continued operation of FirstEnergy Solutions’ Davis-Besse and Perry nuclear plants.

House Bill 6, titled the Clean Air Act, has confounded fossil fuel proponents and environmental groups alike, while state Republicans and labor unions insist the cost of losing the facilities overrides the need to invest in renewable resources and energy efficiency programs.

Under current law, the state’s electric distribution utilities (EDUs) must obtain 12.5% of their power from renewable sources by 2027, including 0.5% from solar. HB 6 would repeal those requirements and provide subsidies to “clean air resources” including nuclear power and some solar resources that had obtained siting certificates before June 1.

The Davis-Besse nuclear plant in northern Ohio | *NRC*

“Ohioans deserve so much better,” said Miranda Leppla, vice president of energy policy at the Ohio Environmental Council Action Fund. “HB 6 is nothing more than a ploy to bail out corporate utilities that want to continue to run old, dirty energy sources, under the guise of ‘clean air.’”

FirstEnergy argues its plants deserve the help. Davis-Besse and Perry produce 2,100 MW of electricity around the clock — 90% of Ohio’s carbon-free power — but the company says it can’t afford to keep the plants running based on its revenues from PJM’s wholesale market, which has seen prices fall because of renewables and cheap natural gas.

The bill, approved 53-43 by the House of Representatives on May 29, also has the support of Gov. Mike DeWine. “As I have previously stated, Ohio needs to maintain carbon-free nuclear energy generation as part of our energy portfolio,” DeWine said. “In addition, these energy jobs are vital to Ohio’s economy.”

The bill is now being considered by the state Senate.

Critics say FES doesn’t need help to keep the plants afloat and are playing a “shell game” in PJM’s capacity market auctions to convince lawmakers otherwise.

“The bottom line is that Ohio nuclear resources are in no danger of retiring anytime soon and to do so would not only be economically irrational but would financially harm the equity shareholders of these nuclear assets,” Paul Sotkiewicz, president of E-Cubed Policy Associates and PJM’s former lead economist, told the Ohio Senate Energy and Public Utilities Commission on June 4. He came to share the results of an American Petroleum Institute-funded study that accused the company of misleading lawmakers and the public about their intentions to deactivate the plants over the next two years.

“I must say, I was surprised with this result,” Sotkiewicz said. “Of all the nuclear assets in PJM, I viewed single-unit facilities such as Three Mile Island, Davis-Besse and Perry to be very much at risk for retirement given the Nuclear Energy Institute’s reported costs for single-unit sites.”

FES’ supporters say Sotkiewicz’s math is wrong.

“The natural gas industry is doing what all rivalrous generation resources do in these instances,” said Ray Gifford, former chairman of the Colorado Public Utilities Commission, who was brought to Columbus by FES to convince the Senate Energy and Public Utilities Committee to approve the bill. “It is protecting its turf and trying to handicap its rivals.”

FirstEnergy spokesperson Tom Becker said that Sotkiewicz’s profitability calculations are “deeply flawed” and correcting his “obvious” errors would show a loss in excess of $125 million for both plants over the next decade.

“After weeks of testimony in committee inaccurately criticizing the health, longevity and maintenance of our two nuclear plants in Ohio as unworthy of future investment, suddenly this last-minute report — funded by out-of-state oil and gas interests — proclaims that Davis-Besse and Perry are in excellent position to continue providing clean energy in Ohio,” he said. “Clearly the opponents of HB 6 cannot make the argument on both sides.”

Emissions and Reliability

FES says its nuclear plants’ contribution to the grid’s reliability and the state’s carbon-free electricity can’t be ignored.

“I see no good alternative, and these plants are too vital to Ohio to sacrifice because of the failures of a distorted regional wholesale market,” Gifford said.

He said it’s unrealistic to expect renewables and battery storage will replace the lost capacity if the plants close. Just ask Germany and Japan, where carbon emissions and energy prices increased after they severely curtailed their nuclear output, he said.

“You end up with a collective action problem where states that do not subsidize their failing units end up being chumps who forego the power, the resilience characteristics, the jobs and tax revenue,” he said, urging Ohio not to give up its plants and let natural gas fill the void. “I don’t know a good way to cut this Gordian Knot, but I do know that losing these plants would be bad for Ohio and bad for consumers.”

A PJM analysis released earlier this month concluded emissions will drop regardless of whether Perry, Davis-Besse and FirstEnergy’s Beaver Valley plant in Pennsylvania close or stay open — though the reduction would be significantly greater if the plants stay online. (See PJM: Nukes Keep Energy Costs Down, in Theory.)

The problem, according to PJM Independent Market Monitor Joe Bowring, is that the number of gas plants slated to come online in 2023 will likely decrease by more than half of what is currently in the RTO’s pipeline of approved projects, and less enthusiasm for nuclear subsidies in Pennsylvania means a scenario that saves all three plants is far from realistic. A combination of nuclear plant retirements and canceled gas projects would increase energy costs and push emissions in both states higher because of the reliance on less efficient coal-fired generation, PJM’s analysis concluded.

‘Rise Like Lazarus’

Sotkiewicz insists the new law would just increase the profitability of the plants by as much as 240%, with no true reduction in carbon emissions on account of the bill’s last-minute carveout for two of Ohio Valley Electric Corp.’s coal plants.

Citing data compiled from publicly available sources, Sotkiewicz said the single reactors at Perry and Davis-Besse incur costs nearly 25% below the industry average. He estimated annual net operating profits over the next decade for Perry will reach $28 million, while Davis-Besse will collect almost $44 million.

As a result of FES’ bankruptcy proceedings, Sotkiewicz says the reorganized company will soon rid itself of crippling debt service and be poised “to emerge as a fully independent power producer.”

He also pointed out that the entirety of FirstEnergy’s generation portfolio, except for its 545-MW West Lorain fuel-oil and natural gas-fired plant, has submitted retirement notices. “That seems highly implausible … why would [bond holders] agree to become equity holders in a single peaking plant? Other resources slated for retirement are likely to ‘rise like Lazarus,’ but only those with the most to offer competitively. Perry and Davis-Besse are good candidates given their profitability.”

He further suggests that PJM auction data indicate that FirstEnergy plays “a shell game” by “hiding cleared capacity in units slated for retirement (or already retired) to eventually be transferred over to nuclear plants when they remain in service” — another sign that the Ohio nukes “are not going away anytime soon.”

Gifford says Sotkiewicz gets its all wrong.

“The API study does what all wish-fulfillment utility planning models do,” Gifford said. “It cherry-picks its numbers to overstate revenues and understate costs. By doing so, plants operating at a loss suddenly turn profitable.”

Specifically, Gifford accused the API study of using inaccurate price nodes and assuming plants receive capacity payments when they have not cleared auctions in several years. He also said the study underestimates operating costs for nuclear plants, including overlooking refueling years, equipment maintenance and the differences between cost structures at single- and multiunit facilities.

He also cited another API study that determined TMI would lose $466 million over the next decade.

“Three Mile Island and Davis-Besse are virtually twin facilities, and both are operated at the highest level of performance within the same PJM market construct,” he told the committee. “Yet, a study completed 60 days prior to the one submitted to you today reflects nearly a $750 million difference in profitability between the two units over the next 10 years. How can that be?”

Over-compliance on EE

HB 6 also would make major changes to Ohio’s energy efficiency incentives.

Under current law, EDUs assess a monthly $4.10 fee on customers. The Ohio Environmental Council Action Fund says about 74 cents support distributors meeting renewable resource standards and the remaining $3.36 is used for energy efficiency and peak demand reduction.

Over the last five years, Ohio’s EDUs have collected more than $1.3 billion from residential customers to meet the mandates, Public Utilities Commission of Ohio Chairman Sam Randazzo said. Utilities boost their take by reducing energy efficiency and peak demand response over and above the state requirement for the year.

“The EDUs have been over-complying with the statutory demand-side compliance requirements,” Randazzo told the committee on June 4. “Based on past experience and the incentives that each EDU presently is receiving, it is reasonable to expect that this over-compliance trend will continue into the future.”

PUCO spokesperson Matt Schilling said the primary driver for this behavior boils down to the millions in shared profits that utilities split for each megawatt-hour saved. Between 2014 and 2017, companies shared $233 million in savings, he said.

In fact, all the state’s EDUs will hit the statutory compliance peak of a 22.2% reduction in demand a full four years before the 2027 deadline, according to PUCO’s analysis.

“The escalating annual supply-side and demand-side compliance requirements were not based on any studies or analysis,” Randazzo said. “They were and are arbitrary. But more importantly, the compliance obligations were proposed and considered based on some assumptions about the future — assumptions that sharply conflict with our current reality.”

Randazzo said the compliance obligations incentivize entry of renewable generation sources while simultaneously encouraging EDUs to reduce the size of the overall electricity market — disproportionately impacting “non-preferred” technologies on both the supply and demand side. Because it’s unlikely they’ll stop collecting these fees, Randazzo said, it’s no wonder these older technologies, nuclear generation included, want financial assistance “to stay in the game.”

Rob Kelter, senior attorney with the Environmental Law & Policy Center, said existing efficiency mandates help keep costs lower for consumers.

“Because the efficiency programs reduce energy consumption across the state, energy prices are lower for all Ohioans,” he said, noting a Resource Insight report that determined ratepayers save an additional $2/month because of the fees. “Our Energy Efficiency Resource Standards are vitally important, not only for the environmental benefits that result from reducing our energy consumption, but because they keep energy prices low for all Ohioans.”

Sweetener for EDUs?

EDU Duke Energy Ohio testified in April that any elimination of the energy efficiency standard should be gradual, with “a reasonable period of time to allow affected stakeholders to adjust to the change.”

Two other companies, AES’ Dayton Power & Light and American Electric Power, indicated their support for HB 6 last month.

Duke, AEP, FirstEnergy and AES are the parent companies for all six of Ohio’s EDUs.

The companies also own almost two-thirds of OVEC, which would benefit from a provision in the bill that codifies a state Supreme Court ruling allowing it to charge customers up to $2.50/month to subsidize its Kyger Creek and Clifty Creek coal-fired plants.

On top of the nuclear subsidy fee, which sunsets in 2026, electricity companies can also recoup costs lost on long-term contracts to meet Ohio’s renewable portfolio standard mandates until 2030. AEP, the Columbus-based utility that owns more than 40% of the state’s coal and natural gas plants, urged lawmakers to allow rate recovery for these existing contracts when moving the bill forward.

Tom Froehle, AEP’s vice president of external affairs, testified on June 12 that the bill allows the company to further invest in renewable resources, while simultaneously addressing Ohio’s increasing reliance on out-of-state generation and its legacy resource issues dating back more than a decade.

“HB 6 provides ongoing certainty for an important and longstanding baseload generating asset,” he said. “The bill also includes rate caps for customers while allowing for the continued operation of OVEC generating units, which will provide certainty for AEP Ohio’s customers and Ohio jobs.”

Critics said this OVEC carveout serves one purpose alone: bolstering support among EDUs.

“The only reason these plants are in HB 6 was to enlist support for HB 6 from the other Ohio utilities, because the bailout for the nuclear plants would only benefit FirstEnergy,” said John Finnigan, lead counsel for the Environmental Defense Fund.

Ratepayer Impact

HB 6 would eliminate the $4.10 fee and charge residential customers $1/month, starting in 2021, to support the nuclear plants through 2026. Commercial customers will pay $15/month, industrial customers will pay $250 and large-scale users consuming more than 45 million kWh at one site annually will pay $2,500 monthly. The anticipated $198 million in revenue will be collected by the state treasury and distributed back to the defined “clean air resources” at a rate of $9/MWh. The subsidy would be reduced if the “market price index” — based on energy futures contracts for the PJM AEP-Dayton hub and projected capacity prices using PJM’s Rest of RTO market clearing price — exceeds $46/MWh. Wind and new solar generators are ineligible for the credit.

Ohio Sen. Steve Wilson (R), chairman of the Energy and Public Utilities Committee, told RTO Insider the issue is certainly “complicated” for lawmakers.

“I’ve been working hard to be the guy in the striped shirt blowing the whistle and giving everyone a chance to explain their position,” he said. “But we are working hard to get FirstEnergy an answer by their June 30 deadline.”

The committee completed its fourth hearing on the bill June 19 and has scheduled a fifth for Tuesday.

June 24, 2019

FERC Reverses Course — Again — in PJM Line-loss Case

By Rich Heidorn Jr.

FERC last week reversed its position in a more than decadelong dispute over line-loss refunds, ordering PJM to surcharge load to recover overpayments resulting from earlier commission rulings.

Acting on a voluntary remand of a case before the D.C. Circuit Court of Appeals, the commission’s ruling Thursday reversed orders it issued in 2011, 2012, 2015 and 2016. It ordered PJM to pay refunds of misallocated line-loss overcollections to some financial marketers and to surcharge load to recover refunds from parties that previously had received overpayments (EL08-14-012).

Last week’s ruling, which could require PJM to collect millions from load, was actually the third reversal by FERC in the complicated dispute.

PJM — Transmission line crossing the Pennsylvania Turnpike near Bowmansville, Pa. | © *RTO Insider*

The case originated from a complaint by financial marketers — including Black Oak Energy, EPIC Merchant Energy and SESCO Enterprises — who argued they weren’t getting their fair share of line-loss refunds for up-to-congestion (UTC) transactions. PJM includes line losses in its LMP calculations to ensure correct pricing signals and efficient dispatch, a procedure that results in the RTO collecting more in line losses than it pays to generators.

After initially ruling that the marketers were not entitled to line-loss refunds, the commission reversed itself, leading PJM to pay the marketers $37 million in 2010. FERC reversed itself again in orders in 2011 and 2012, leading PJM to issue invoices in 2012 requiring the marketers to repay the refunds. As of 2014, PJM told FERC, only $9 million of the $37 million had been returned.

The commission’s latest reversal came in response to a challenge by financial marketer Energy Endeavors to commission rulings in 2015 and 2016. During briefings before the D.C. Circuit, the commission submitted an unopposed motion for voluntary remand, citing court rulings finding that the Federal Power Act gives the commission “broad remedial authority, including the ability to act retroactively to correct unjust situations and to ensure that what ‘should have been done’ is done,” FERC explained.

“The commission in the past has referenced a general policy of not ordering refunds in cost allocation and rate design cases. However … we find that the commission has greater discretion with respect to this refund-related issue under sections 309 and 206b of the FPA than was indicated by those statements.

“In light of these precedents, the commission will consider whether to require refunds in cost allocation and rate design cases based on the specific facts and equities of each case, even where such refunds must be funded through surcharges on certain parties.”

In addition to directing PJM to pay line-loss overcollections to financial marketers for UTC transactions, FERC also ruled that the RTO should treat customers that export energy from it to MISO “on an equal basis to PJM load.”

It said PJM has authority to impose surcharges if needed to implement the refunds but should not surcharge the MISO exporters because the exporters had made business decisions based on “a reasonable expectation of receiving at least some credit for line losses.”

“Certain exporters pointed out that they would not have engaged in significant numbers of export transactions had they had notice that they would no longer be eligible for a pro rata share of marginal line-loss allocations,” the commission noted. “DC Energy, for example, calculated that it would not have engaged in 350,000 MWh of transactions.”

The commission directed PJM to calculate the refunds, with interest, owed to the financial marketers; the amounts of refunds previously paid, and not returned, that may be retained by the financial marketers; and the surcharges owed by PJM load and the exporters based on their proportionate share of the marginal line-loss allocations taking into account the payment of refunds.

“This resolution provides the most equitable result, as it permits those engaging in up-to-congestion transactions to participate equally in the distribution of line-loss credits while not unduly upsetting settled expectations,” the commission said.

Pierce Atwood attorney Randall S. Rich, who represents several of the financial marketers, declined to comment on the ruling and said he did not know how much money is at stake.

PJM spokesman Jeff Shields said the RTO will implement the order but does “not have an estimate of a dollar figure at this point.”

“There will be challenges associated with how many years have elapsed, during which time participants now deemed by FERC to owe money have left the market,” Shields said. “PJM is disappointed by the order for a number of reasons, not the least of which is the financial burden it will place on consumers who actually use the grid to buy and sell energy.”

June 24, 2019

NW Price Spike a ‘Wake-up Call,’ Ex-BPA Chief Says

By Hudson Sangree

The Pacific Northwest’s March 1 price spike “should serve as a wake-up call” of the region’s coming capacity shortage, power industry consultant and former Bonneville Power Administration chief Randy Hardy warned in April.

Hardy reported that bilateral March 1 day-ahead peak prices at the Mid-Columbia trading hub broke $900/MWh, driven by natural gas prices of $160/MMBtu. By comparison, CAISO day-ahead prices that day ranged from about $38 to $82/MWh, holding that high for only one evening interval. (See Cold Forces NW to Dip More Deeply into EIM as Avista Joins.)

On Wednesday, the Western Electricity Coordinating Council Board of Directors received a briefing from Operating Committee Chair Richard Hydzik on preliminary findings of the OC and the Market Interface Committee regarding the event. “The question was, was there a capacity issue related to this?” asked Hydzik, principal transmission operations engineer with Avista.

The answer is still up in the air. Hydzik noted the region had adequate reserves during the event, and his presentation focused on the temporary supply constraints.

The event occurred during the first week of March, with unusually low temperatures that were closer to those in a typical January. The cold snap led to high demand for natural gas and electricity. At the same time, utilities were doing maintenance or had taken assets out of service during a time that normally sees lower demand.

Hardy’s report noted that the high prices “and the capacity shortage that they reflected, occurred despite all the soon-to-be retired PNW coal plants operating at maximum capacity.”

Hardy cited research by analysts E3 that predicts load growth and announced coal plant retirements could leave the PNW with an 8-GW capacity deficit by 2030 without new dispatchable capacity. That would increase the region’s loss-of-load probability (LOLP) to 48%, he said, noting that WECC utilities’ normal reliability standard is a 5% LOLP.

Hardy said the situation is complicated by moves by Oregon and Washington lawmakers to prevent the building of new gas-fired generation. Hardy said the region could be limited to wind and solar for new energy resources and batteries and pumped storage for new capacity.

Shoulder Month Surprise

Hydzik told the WECC board the March 1 price spike was attributable in part to a lack of south-to-north transfers on the DC Pacific Intertie, which was down for maintenance. A major gas pipeline moving fuel from British Columbia into Washington was running at 80% capacity because of an explosion last fall, and one 730-MW unit at the coal-fired Centralia (Wa.) plant had been taken offline. Balancing authorities were serving native demand and limiting exports.

“So, this is March. Typically, it’s a shoulder month,” Hydzik said. “Six months earlier you plan all of your maintenance to be out of this stuff [before summer demand hits]. Once you take some of these facilities down, you cannot quickly restore them, and you’re simply out of service.”

But the BAs and the Northwest Power Pool Reserve Sharing Group had ample reserves. No emergency alerts were called, and transfers were flowing into the region. BC Hydro “saw this coming,” Hydzik said, and sent an additional 2,000 MW into the U.S. from Canada, reversing the predominant flows on the BC Intertie as the utility’s Powerex marketing arm reduced purchases and boosted exports to take advantage of the surging market.

“Good for them,” he said. “Maybe not so good if you’re south of the border. …

“So, what did we find so far?” he said. “Everyone in the Northwest had more than adequate reserves. … Just because something was expensive doesn’t mean it wasn’t available.”

Gas supplies were constrained, and coal plants and other resources have been retired. Additional findings will be presented at a future meeting, he said.

Director Jim Avery said the situation had raised concern at WECC and may be a sign of things to come.

“Here we are in the shoulder months experiencing some of the bigger problems,” Avery said. “These are going to become the new norms.

“We’re going to have different resources that perform differently in different seasons,” he said. “And yet we’ve been operating the system the same, and that is, ‘Well, shoulder months, that’s when we do our maintenance.’ We’re going to have to rethink that because during peak load conditions in the middle of the day, we may have an abundance of resources [such as solar] that we’ve never had before. And that’s just the new norm.”

Hydzik said he agreed with Avery’s comments.

Hardy offered several potential actions to respond to the capacity shortage, including adding transmission to access Montana or Wyoming wind power; an overhaul of “fossil fuel era” planning and operating metrics; and incentives for ramping resources.

A lack of action would leave the region praying “for rain and mild weather,” Hardy said.

“Murphy’s law predicts that the next low water year in the PNW will arrive in 2025 as peak coal plant retirement occurs and the PNW [integrated resource plans] defer decisions on construction of new resources waiting for the next cost reduction in carbon-free capacity.”

June 24, 2019

ERCOT Briefs: Week of June 17, 2019

HOUSTON — Beth Garza’s annual visit to the Gulf Coast Power Association’s Houston chapter Thursday once again drew a roomful of electric industry insiders and observers hoping to glean insights into the state of the ERCOT market.

But first, Garza, director of ERCOT’s Independent Market Monitor, had to remind her luncheon audience what her role is. Asked about her expectations of the market’s performance during the summer, Garza responded, “The cool thing about my job is that it’s the Market Monitor, not the market predictor.”

Garza did allow that forward prices do show a “moderation of expectations” for the summer. She shared a slide that showed ERCOT’s North Hub futures for August at around $120/MWh and the July futures at around $70/MWh.

A year ago, August futures briefly eclipsed $250/MWh in May, when the reserve margin was 11%. It is now down to 8.6%.

“It’s been a wet spring, and wet springs tend to portend not-that-hot summers. I think we will see similar outcomes in the summer of 2019,” she said, echoing ERCOT’s weather forecast. (See “Staff Prep Directors for Summer Expectations” and “IMM Market Report: Load Continues to Climb,” ERCOT Board of Directors Briefs: June 11, 2019.)

ERCOT says it expects to use emergency measures this summer to meet a record forecasted peak demand of 74.9 GW, more than last summer’s all-time system peak of 73.5 GW. The grid operator has an available capacity of 78.9 GW.

The Monitor’s State of the Market report notes ERCOT’s load grew at a 5.3% clip last year. ERCOT expects the growth to continue at a 2.5 to 3% rate through 2022, when peak demand is projected to hit 84.1 GW.

“This continued growth puts us on a path of being short,” Garza said. “If you look at installed capacity … the resources we have today will be insufficient to serve projected load in 2021.”

One luncheon guest asked Garza whether batteries and other forms of energy storage could play a major role in the market.

“The difficulties and challenges around batteries are numerous and hard,” she said. “ERCOT is not alone in the RTO world in wrestling with those questions and trying to figure out what the right answers are. I don’t have easy answers, because there are no easy answers.”

74-MW Wind Farm to Retire in November

ERCOT on Thursday approved West Texas Wind Energy Partners’ request to shut down a 74-MW wind farm in Southwest Texas. The grid operator said its reliability analysis indicated the facility was no longer needed to support system reliability.

The Southwest Mesa Wind Energy Center will be decommissioned and retired permanently in November.

Southwest Mesa began commercial operation in 1999. With nearly 22.1 GW of installed wind in ERCOT’s footprint as of April, the facility’s retirement will represent a 0.33% cut in wind capacity.

— Tom Kleckner

June 24, 2019

SPP Proposes to Drop Exit Fee to $100K

By Tom Kleckner

SPP may ask FERC to lower its exit fee in response to the commission’s April order that the RTO eliminate the fee for members who are not transmission owners or load-serving entities.

Staff told the Corporate Governance Committee on June 17 that they believe FERC’s order (EL19-11) suggested the commission may approve a lower amount. SPP faces an Aug. 1 deadline to make a compliance filing and has already submitted a rehearing request to clarify the definitions of TOs and non-TOs. (See FERC Tells SPP to End Exit Fee for Non-TOs.)

The committee agreed in executive session to recommend a fixed $100,000 exit fee to the Board of Directors when it meets on July 30. The current exit fee is estimated at $631,915, nearly twice the $327,191 fee that FERC approved in 2006, when it last required the RTO to impose an exit fee on all members.

Load-serving members would be subject to an additional share of SPP’s financial obligations and future interest based on their net energy for load percentage. LSEs would be defined as distribution or electric utilities that have a service obligation and/or secures energy and transmission service to serve its end-use customers’ demand and energy requirements.

Staff noted the commission’s order said “some level of exit fee that does not act as a barrier to membership and is not excessive could be appropriate in SPP.”

By making the fee a fixed amount, SPP said it would be addressing the commission’s concern that the exit fee can move up or down.

FERC’s order came in response to a complaint filed by the American Wind Energy Association and Advanced Power Alliance, formerly the Wind Coalition. The groups charged that SPP’s exit fee results in unjust and unreasonable rates and creates “a barrier to membership” for non-TOs and non-LSEs.

“What’s being proposed here does not seem to track with cost-causation principles. Such an exit fee that’s not based on any … principles would likely be opposed,” APA’s Steve Gaw said. “We would like to see something that is more in line with what other RTOs have found to be appropriate for membership and stakeholder participation.”

SPP — Denise Buffington | © *RTO Insider*

CGC member Denise Buffington, director of federal regulatory affairs with Evergy companies Kansas City Power & Light and Westar, cautioned against the move considering the pending rehearing request.

“If FERC gets this as an alternative … it’s an easy pass for them not to deal with this issue. My preference would be to wait until we get an order on the rehearing request,” she said. “If I were giving legal advice on behalf of the client, I would stick close to what FERC has ordered.”

SPP CEO Nick Brown said staff debated the timing of the alternative proposal but said the recommendation was “to help FERC get the right answer.”

“We’ve continued to debate this [issue] at the request of non-members or members who wished to withdraw but couldn’t afford the exit fee,” he said. “In putting this proposal on the table, we specifically wanted to influence FERC’s thinking and help them to make a decision. We consider this just and reasonable.”

Other committee members favored the lower exit fee. Dogwood Energy’s Rob Janssen said the reduced fee would solve the problem of “zombie members”: those who stayed members “because it was easier than paying the exit fee.”

“I think this change will make them come out of the woodwork and make a decision one way or the other,” Janssen said.

The CGC will also recommend approving the compliance filing, which would change SPP’s governing documents in response to FERC’s order. Staff said it will include what it believes are errors in FERC’s order, for which they are seeking rehearing.

If the board approves the committee’s recommendations in July, they will be promptly filed at FERC to meet the Aug. 1 deadline.

June 24, 2019February 12, 2025

NYISO Business Issues Committee Briefs: June 20, 2019

RENSSELAER, N.Y. — NYISO presented the Business Issues Committee the final market design for pricing carbon emissions into its wholesale electricity markets on Thursday, the same day the New York State Assembly passed a bill that will put many of Gov. Andrew Cuomo’s environmental targets into statute.

The Climate Leadership and Community Protection Act (A842 9) will require 70% of the state’s electricity be generated by renewable resources by 2030, nearly quadruple its offshore wind energy goal to 9 GW by 2035 and require the economy to be carbon-neutral by 2040. The law also doubles the distributed solar generation goal to 6 GW by 2025 and targets deploying 3 GW of energy storage by 2030. (See New York Boosts Zero-carbon, Renewable Goals.)

| NYISO

Stakeholders were divided on whether the bill — expected to be signed into law by Cuomo — necessitates increased skepticism on carbon pricing or urgency on the effort.

“It will take time to digest the new information, but having carbon pricing helps reach these goals, said Rana Mukerji, NYISO senior vice president for market structures. “If [load-serving entities] are required to buy renewables, the procurement prices will reflect the benefit renewables derive from having carbon priced into the energy market.”

Representing the Independent Power Producers of New York, Matt Schwall said, “IPPNY continues to be very supportive. … Carbon pricing is now more important than ever. There’s been a lot of time spent developing the idea, and this will help us reach the targets.”

Luthin Associates’ Aaron Breidenbaugh, representing Consumer Power Advocates, an unincorporated group of nonprofit institutional customers, said he was “skeptical” of how consumers could benefit from carbon pricing under the new law.

Couch White attorney Kevin Lang, speaking for New York City, said he shared Breidenbaugh’s concerns: “Carbon pricing isn’t going to get us incrementally more generation … and I agree that NYISO needs to look at the new law before moving forward.”

Mark Younger of Hudson Energy Economics said, “You can put targets, but that doesn’t mean they’re effective. You can put 7,000 MW of wind in the North Country and meet a target of 7,000 MW of additions, but not get much benefit of zero-carbon megawatt-hours in the state.”

“Action needs to start happening immediately, and we need to be sending price signals that reflect the value, or the damage, of carbon emissions,” said Howard Fromer, director of market policy for PSEG Power New York. “How? The closest thing is the mechanism we’ve come up with here, and carbon pricing is even more important now than it was a year ago.”

Robert Pike, NYISO director for market design and product management, said, “We’re here today just to recognize the culmination of the work that’s taken place over a considerable amount of time.”

Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), said, “A long time ago, we said that a market without a carbon component is inconsistent with our environmental goals. Carbon pricing can help the state reach its goals.”

On Monday, third-party consultant Analysis Group presented to the Installed Capacity/Market Issues Working Group preliminary results of a supplemental analysis examining the impacts of pricing carbon. The study is intended to augment the Brattle Group report process that concluded in December. (See More Details Divulged on New NYISO Carbon Pricing Study.)

Broader Regional Markets Update

Pike presented the monthly Broader Regional Markets report and highlighted item No. 26, noting that the Management Committee in May approved a new external supplemental resource evaluation (SRE) penalty regime.

Approved by the BIC in April, the SRE penalty provisions will boost the ISO’s ability to call on external resources that have sold capacity to New York. Pending FERC approval, the proposal is anticipated to become effective in August.

Pike also highlighted BIC and MC approval last month of revisions to the NYISO-PJM joint operating agreement to address coordination on flowgates similar to the East Towanda-Hillside Tie Line.

Manual Revisions

The BIC approved revisions to several manuals, with most of the changes required by implementation of the Zone J (New York City) reserve region.

Following Board of Directors and stakeholder approval, the ISO in April filed a proposal with FERC to establish the new reserve region. (See NYISO Business Issues Committee Briefs: March 13, 2019.)

Ashley Ferrer, NYISO energy market design specialist, reported that the changes would affect the Ancillary Services, Day-Ahead Scheduling and Transmission & Dispatch Operations manuals.

ISO staff engineer Harris Miller detailed additional revisions unrelated to the Zone J reserve requirements being proposed within the affected manuals.

Ferrer said the proposed New York City reserves would go into effect Wednesday, assuming approval by FERC.

LBMPs, Gas Prices Drop

NYISO locational-based marginal prices averaged $23.10/MWh in May, down about 17.5% from April and about 19.7% from the same month a year ago, Pike said in delivering the monthly operations re p ort. Year-to-date monthly energy prices averaged $37.57/MWh, a 25% decrease from a year ago.

Day-ahead and real-time load-weighted LBMPs came in lower compared to April. Average daily sendout was 373 GWh/day in May, higher than 371 GWh/day in April and lower than 397 GWh/day in the same month a year ago.

Transco Z6 hub natural gas prices averaged $2.27/MMBtu for the month, off slightly from April and down 11% from a year ago.

Distillate prices were down 8.5% year over year and mixed from the previous month, with Jet Kerosene Gulf Coast averaging $14.64/MMBtu, up a penny from April, while Ultra Low Sulfur No. 2 Diesel NY Harbor dropped to $14.54/MMBtu from $14.72/MMBtu in April.

May uplift increased to 13 cents/MWh from -15 cents in April, while total uplift costs, including NYISO’s cost of operations, came in higher than the previous month.

The ISO’s 23 cents/MWh local reliability share in May was up from 20 cents the previous month, while the statewide share climbed to -11 cents/MWh from -35 cents in April.

The Thunderstorm Alert cost was 19 cents/MWh, up from the usual zero to 1 cent.

— Michael Kuser

June 24, 2019

SER Phase 2 Targets Data Retention, Consolidation

By Rich Heidorn Jr.

Phase 2 of NERC’s Standards Efficiency Review has narrowed its focus to four tasks, tabling two others for potential work by other committees, members of the Phase 2 team said last week.

In a June 17 conference call, the team said it would focus its work on the four initiatives that received the highest response from stakeholders in polling that concluded March 22. (See “Team Reviewing Feedback on SER Phase 2,” NERC Standards News Briefs: May 8-9, 2019.)

The team’s decision followed a June 11 meeting with the SER Advisory Group and FERC staff.

“There was a discussion with the Advisory Group on how [SER] Phase 2 is much different than Phase 1. We’re looking more holistically and long-term at ideas that can streamline things going forward, not necessarily individually at the requirement level,” said SER Phase 2 Chair John Allen, manager of reliability compliance for the City Utilities of Springfield (Mo.). “I thought there was good support from the Advisory Group and at least no indication from FERC staff that we were heading down a road that was not viable.”

The top two priorities — changes to the evidence-retention rules and consolidating information/data exchange requirements — are expected to be completed this year.

The team also will tackle a proposal to move “competency-based” requirements from standards to guidance documents and developing a risk-based standards template; those efforts are likely to extend into 2020, team members said.

“There’s a lot of work that was already done on … evidence retention, so there was a good baseline to start on that. On the data and information consolidation, it’s pretty cut and dried, straightforward,” Allen said.

“These other two are shifts. We’re putting these ideas out there to say, ‘Here’s how we do it today. How can we do it more efficiently going forward?’ To make that successful, we’ve got to get all the right stakeholders together.”

The SER team declined to work on relocating competency-based requirements to the certification program/controls review process, which will be transitioned to the Compliance Certification Committee or the Organization Registration and Certification Programs (ORCP).

It also is dropping an initiative on consolidating and simplifying training requirements. A subgroup of the Phase 2 team “is talking about potentially drafting a [standards authorization request] for the training concept,” said Chris Larson, NERC manager of standards information.

Reducing the Scope of Work

In working on the prototype standards, Allen said, the SER team should “find some way to try to reduce the need or the scope of the work for a future Standards Efficiency Review or Paragraph 81 or whatever you want to call it — a cleaning up of the standards.”

Paragraph 81 is a reference to FERC’s March 2012 order on NERC’s Find, Fix and Track process, in which the commission told NERC it would welcome proposals to revise or remove reliability standards or requirements that are redundant or add little protection to system reliability (RC11-6, et al.).

“If we can put ourselves on a better path going forward where we don’t have to do this every five years, we’ve done some good work,” Allen continued. “That’s really what we’re going to look to in the prototype standard — is how to put some tools out there going forward to help have a more efficient product where we don’t have to go and clean them up every few years.”

“I’ll second that concern,” said John Pespisa, an Advisory Group member from Southern California Edison. “[The] key to not doing this again in the near future is bringing that key concept into this process.”

Randy Crissman, senior reliability and resilience specialist for utility operations at the New York Power Authority, said there is a need for a “communications strategy.”

“How do we help facilitate the adoption and implementation of that type of an approach? It’s going to be a pretty big lift, but if we don’t try it, it will never happen.”

June 24, 2019

NW Price Spike a ‘Wake-up Call,’ Says Ex-BPA Chief

By Hudson Sangree

The answer is still up in the air. Hydzik noted the region had adequate reserves during the event, and his presentation focused on the temporary supply constraints.

Hardy’s report noted that the high prices “and the capacity shortage that they reflected, occurred despite all the soon-to-be retired PNW coal plants operating at maximum capacity.”

Shoulder Month Surprise

“Good for them,” he said. “Maybe not so good if you’re south of the border. …

“So, what did we find so far?” he said. “Everyone in the Northwest had more than adequate reserves. … Just because something was expensive doesn’t mean it wasn’t available.”

Gas supplies were constrained, and coal plants and other resources have been retired. Additional findings will be presented at a future meeting, he said.

Director Jim Avery said the situation had raised concern at WECC and may be a sign of things to come.

“Here we are in the shoulder months experiencing some of the bigger problems,” Avery said. “These are going to become the new norms.

Hydzik said he agreed with Avery’s comments.

A lack of action would leave the region praying “for rain and mild weather,” Hardy said.

June 23, 2019

FERC Rejects PJM TMEP Rehearing Requests

By Christen Smith

FERC last week rejected a set of rehearing requests by PJM merchant transmission owners, New Jersey regulators and the New York Power Authority contesting the cost allocations for several cross-seams projects.

The commission’s ruling Thursday reaffirmed a July 2018 order that directed PJM and its TOs to submit compliance filings revising Tariff provisions regarding cost responsibility assignments for four targeted market efficiency projects (TMEPs) with MISO included in PJM’s Regional Transmission Expansion Plan (ER18 –614).

FERC had approved 41 PJM transmission projects but rejected the allocations for TMEPs b2971, b2973, b2974 and b2975, instituting a Section 206 proceeding to resolve the matter and ensure the Tariff contained clear language regarding allocations for the future. (See FERC OKs PJM RTEP Allocations, Sets TMEP 206 Proceeding.) The PJM TOs had argued that the RTO erred in not allocating project costs to Hudson Transmission Partners and Linden VFT, which operate merchant lines into New York City and had recently converted their firm transmission withdrawal rights to non-firm. Those lines would benefit from the TMEPs, the other TOs contended.

On July 31, 2018, PJM submitted a compliance filing updating the cost responsibility assignments to reflect Hudson and Linden, while the PJM TOs the next day submitted a separate filing clarifying that TMEP allocations would be assigned to merchant facilities.

Hudson, Linden and NYPA contested FERC’s rejection of the original cost allocations excluding merchant owners from the TMEP assignments. They argued that the commission misinterpreted PJM Tariff language that “limits all cost allocations … based on their actual firm transmission withdrawal rights.”

FERC rejected that argument, noting that the basis for cost allocation under the TMEP provision “is the net congestion incurred in PJM zones” regardless of merchant transmission facility contracts for firm or non-firm withdrawals rights.

“Customers of merchant transmission facilities without firm transmission withdrawal rights still receive benefits from TMEPs in the form of lower congestion costs,” the commission said. “PJM transmission owners make clear that the intent of the TMEP provision was to assign costs to merchant transmission facilities based on the net congestion relieved by the project.”

BPU Rebuffed

The commission also rejected the New Jersey Board of Public Utilities’ contention that FERC erred in accepting TMEPs b2955 and b2956 because the projects were no longer necessary after Hudson and Linden relinquished their firm withdrawal rights. The BPU argued that PJM should have therefore withdrawn the projects from the RTEP.

But FERC pointed out that PJM re-evaluated the projects after the merchant owners relinquished their firm withdrawal rights, citing an affidavit from Aaron Berner, the RTO’s manager of transmission planning, that explained why that move did not change the results of the RTO’s reliability studies that determined the rejected projects to still be “necessary.”

“Mr. Berner explained … that the analysis showed that injections of electricity by the merchant transmission facilities, not withdrawal from these facilities, contributed to the need for the projects. Because firm transmission withdrawal rights relate only to withdrawals from PJM, the relinquishments of the firm transmission withdrawal rights have no bearing on the need for projects b2955 and b2956,” FERC said.

The commission further accepted the cost allocation revisions submitted in PJM’s July 31, 2018, compliance filing that reflected Hudson and Linden’s pro rata share of the sum of the net transmission congestion charges paid by market buyers, as identified in the TMEP study. It also approved the PJM TOs’ Aug. 1, 2018, compliance filing clarifying the language regarding TMEP cost allocations.

June 23, 2019

FERC Stands Firm on Michigan Dam Closure

By Amanda Durish Cook

FERC last week denied a request to reconsider its decision to revoke the license for a small Michigan hydroelectric project over significant safety concerns.

The commission also rejected Boyce Hydro’s motion to transfer the license for its 4.8-MW Edenville Dam to another operator, Wolverine Hydro, calling the request moot in light of the revocation (P –10808).

FERC ordered Edenville closed in February 2018, then revoked the dam’s license the following month after finding it had insufficient spillway capacity and that Boyce had a longstanding history of noncompliance with other safety measures. The commission denied Boyce’s request for rehearing on the closure early this year. (See Closed Michigan Dam Loses Rehearing Bid.)

In the order issued Thursday, FERC said it only entertains motions for reconsideration when a party can assert the commission “may have erred by overlooking or misunderstanding facts or arguments set forth in the party’s rehearing request.” Boyce didn’t pose that argument in its request for rehearing over the license, and its other arguments were “unconvincing,” the commission wrote.

“Here, Boyce Hydro does not claim that the commission misunderstood or misinterpreted its prior arguments. Thus, its pleading is not a proper request for reconsideration and we will not consider it as such. … To the extent that Boyce Hydro seeks to introduce new facts and arguments into the record, it is making an untimely, collateral attack on the now final revocation order.”

FERC made clear that revocation of the license was not up for negotiation and that Boyce’s only recourse now is to seek a new license.

“In any event, we have no ability to grant the relief that Boyce Hydro seeks. We have revoked the license for the Edenville Project, in orders that are now final. Accordingly, we currently have no jurisdiction over the Edenville project works. Should Boyce Hydro or any other entity wish to operate the project to generate electricity, they would need to seek a license to do so,” FERC said.

And because it could not reinstate the Edenville license, FERC said it also could not grant the request to transfer the license to Wolverine.

Boyce had claimed that it could secure a new power purchase agreement with Consumers Energy at a higher rate that would have allowed it to obtain a loan to “fund construction of auxiliary spillway capacity sufficient to pass the entire [probable maximum flood]” requirement, then pass the license to Wolverine.

But FERC said Boyce brought no “firm proof” that such a situation will play out.