Page 1423 – RTO Insider

January 25, 2018

EIM Body Tables Nominating Process Changes

By Jason Fordney

FOLSOM, Calif. — The Energy Imbalance Market (EIM) Governing Body on Tuesday rejected CAISO’s move to change how members of the panel are nominated, saying the idea “appeared to come out of nowhere.”

EIM Governing Body CAISO Nominating Committee — Howe | © *RTO Insider*

Chairman Doug Howe made the “out of nowhere” comment as the board unanimously tabled any decision on the ISO’s proposed revisions to the nomination process.

“What problem are we trying to solve here?” Howe said after a CAISO briefing on the proposal during a Jan. 23 meeting of the panel. “For me, it’s ‘I really don’t know.’” He said the changes could create confusion in the market. “It doesn’t strike me as sending the right message out.”

The rejected proposal would have eliminated the EIM Nominating Committee’s obligation to use an executive search firm to help fill Governing Body vacancies, instead encouraging committee members to rely more on their own contacts. The plan would also have altered a current policy that allows the committee to re-nominate sitting body members without considering other candidates.

Governing Body member Kristine Schmidt said the proposal would saddle the Nominating Committee with the “heavy lifting” normally performed by a search firm. This would include tasks such as defining the scope of the work, evaluating qualifications and accreditations, narrowing the list, and conducting interviews.

“In my opinion, that is the work of the executive search firm,” Schmidt said, adding that the proposal should be vetted by the committee and the EIM Body of State Regulators.

“The changes that are being proposed trouble me greatly,” she said, contending that they appeared to be the product of a few individuals, and “there is no sunshine on that decision.” She added that “the process is working just fine to date.”

Looming Term Expirations

Created in 2016 to oversee the rapidly expanding regional market, the five-member Governing Body has decisional authority over EIM matters. The current members were all among the first to be seated on the body, and the terms of Howe and Carl Linvill are set to expire on June 30, while Vice Chair Valerie Fong and John Prescott’s terms expire June 30, 2019.

Schmidt, whose term expires in 2020, was the only member to be reappointed to the body after her inaugural, one-year term ended last year. (See EIM Governing Body OKs Charter Expansion; Retains Schmidt.) A former executive at ITC Holdings and Xcel Energy, Schmidt served as chair during her first term, which was truncated to stagger the normally three-year terms for members.

CAISO’s proposal would have altered the policy around reappointing a member that has expressed a wish to be re-nominated. Current practice dictates that the Nominating Committee “should determine whether it wants to re-nominate the departing member without interviewing other candidates.” If the committee decides against re-nomination, it is required to use the outside firm to find at least two other candidates.

The proposed change would have obligated the Nominating Committee to consider the current member but “also normally consider additional qualified candidates.” It also would have specified that the committee interview and consider at least two candidates for each position when a sitting member is not seeking re-nomination.

CAISO has cited the expense of hiring an outside consultant as a reason for the proposed changes. (See CAISO Proposes EIM Governance Changes.)

The ISO also proposed to change the process for determining whether the Governing Body — rather than its Board of Governors — has decisional authority over an ISO proposal. CAISO currently makes that determination, but a dispute resolution process is triggered if the chair of either the ISO board or EIM body challenge the decision and cannot conclude an agreement on the issue.

CAISO’s proposal would have allowed ISO management to directly consult with the objecting chair. Any change resulting from that consultation would then be subject to a vote by both chairs, a process the ISO thinks would avoid further meetings and delays.

Fong said that CAISO must take “a more holistic approach” to EIM governance changes, calling the proposal “confusing for the market and confusing for us.”

Body Briefed on ISO Roadmap

During the Jan. 23 meeting, CAISO staff told the Governing Body that the EIM could expand as a result of the ISO’s proposal to extend its day-ahead energy market into what is now a regional balancing market. (See CAISO Plan Extends Day-Ahead Market to EIM.) The ISO is focused on the day-ahead market to better manage the load curve and is working on a package of other changes. The ISO is also pursuing efforts to support reliability-must-run payments for needed gas generators and to lower market barriers for distributed energy resources.

The EIM Governing Body met on Tuesday at CAISO headquarters in Folsom | © *RTO Insider*

CAISO Director of Market and Infrastructure Policy Greg Cook briefed the Governing Body on the final roadmap posted Jan. 12. Out of the 16 initiatives CAISO is undertaking this year, 12 are related to the EIM, he said.

“You have a busy year coming up in front of you,” Cook told body members.

January 25, 2018

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, 2018

SPP Working to Respond to FERC’s Quick-Start Directive

By Tom Kleckner

OKLAHOMA CITY — SPP told members last week it and its Market Monitoring Unit will file separate reply briefs in response to FERC’s December order that found the RTO was suppressing investment signals by not allowing quick-start resources (QSRs) to set LMPs.

The commission issued a Section 206 order requiring SPP to change its Tariff to address quick-start pricing (RM17-3). FERC said it found the RTO’s approach to the resources’ pricing to be “inconsistent with minimizing production costs” and suggested several changes it could implement. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)

SPP quicks-start resources FERC — Richard Dillon explains SPP’s position | © *RTO Insider*

Under a 206 filing — “fairly new to SPP,” said Market Design Director Richard Dillon — FERC can unilaterally make changes to an RTO’s or ISO’s rates, terms or conditions. The reply briefs are due by Feb. 12, with a final order expected within six months of that. The MMU will file its brief after the RTO. Neither Dillon nor MMU Executive Director Keith Collins revealed what they will say in their briefs.

“A quick-start unit provides a product other [resources] can’t,” Dillon said. FERC “wants the value of the product to be reflected in the LMP itself.”

In the meantime, SPP staff said it will continue its work on three open revision requests addressing QSRs. Securing the Markets and Operations Policy Committee’s unanimous approval last week of a revision request that corrected and clarified a previous revision was a first step.

Staff developed RR 256 as it began working on the previous revision request’s implementation details. It said the revision addresses a market inefficiency “inadvertently” created in RR 116 and eliminates a potential gaming opportunity. RR 116 was approved in October 2015 but has yet to be filed with FERC. Two other quick-start related Tariff changes, RR 137 and RR 142, have also been approved by SPP stakeholders but not yet filed.

Dillon said the revision requests are built on top of each other and reflect stakeholders’ “desires and corrections,” but they will not be filed with FERC until the commission rules on the Section 206 docket.

RR 116: Provides the primary language for the new QSR logic and replaces “quick-start resource” with “offline supplemental reserve resource” for those resources supplying offline supplemental reserve.
RR 137: Updates previously removed enhanced combined cycle language referencing QSR limits and the Tariff’s Appendix G for QSR changes.
RR 142: Clarifies that QSRs are ineligible to register as multiconfiguration combined cycle resources.

In its order, FERC said SPP should:

Commit and dispatch QSRs in real time consistent with minimizing production costs, subject to operational and reliability constraints;
Remove the option for enhanced energy offers for QSRs that incorporate commitment costs in the incremental energy curve; and
Consider both registered and unregistered QSRs in quick-start pricing to ensure prices reflect the cost of the marginal resource.

Golden Spread Electric Cooperative’s Mike Wise said the revision requests are unresponsive to the FERC order and “come very short of the mark.” Dillon admitted the changes do not cover everything in the 206 order, “but they’re moving in the same direction.”

Dillon said addressing all of FERC’s directives in the 206 filing would result in significant market changes for SPP. He pointed out SPP’s pricing is ex ante (planned), and that an ex post market (actual outcomes) would require major software changes.

“We don’t know what the final order will look like,” he said. “When we get an actual order from FERC, we’ll have another RR incorporating additional direction from FERC.”

Oklahoma Gas & Electric’s Greg McAuley said his company would prefer SPP file the revision requests, rather than wait on FERC. “The concern is stakeholders have already indicated a willingness to do this. As an entity with brand new quick-start resources coming online and available, what we’ve been working on is very important to us.”

“A bigger issue is credibility,” Dillon countered. “We used to have a reputation of knowing what we were doing and being really sharp. If we make some filings inconsistent with the very 206 filing FERC gave us, that calls into question we know what we’re doing. We don’t want to dig that hole any deeper.”

Complicating matters is SPP does not yet have a definition for QSRs in its Tariff, as do the other RTOs. Stakeholders have suggested a minimum run time of one hour or less to qualify as a QSR.

January 23, 2018October 21, 2025

Counterflow: The Devil Went Down to Georgia

Counterflow

By Steve Huntoon

Georgia Public Service Commission Vogtle — Huntoon

“Johnny, rosin up your bow and play your fiddle hard,
’Cause hell’s broke loose in Georgia and the Devil deals the cards.”

There’s a process problem with the Georgia Public Service Commission’s Vogtle decision, and there’s a substance problem.

Process Problem

Georgia commissioners publicly and vehemently stated that Vogtle should be completed.^[1] And then they had a hearing on whether Vogtle should be completed. See the problem?

Regulators are supposed to make reasoned decisions based on records. It’s hard to do that before you have a record.

“Sentence first! Verdict afterwards,” as the Queen said in “Alice in Wonderland.”

Substance Problem

Last September, my column showed that the original “need” for Vogtle, in the form of a projected increase in customer demand, had basically disappeared.^[2] And with simplifying assumptions favorable to Vogtle, and using Lazard cost estimates, completing Vogtle would impose excess costs of $23.6 billion on Georgia consumers over the next 40 years.

Here’s a quick quiz: After eight years of construction, what percent of Vogtle is constructed? Answer in footnote below.^[3]

So there was a hearing. Or more like Kabuki theater. The Public Interest Advocacy Staff (PIA Staff) of the Georgia commission showed:^[4]

Because of multiple flaws in Southern Co.’s case, “the project is uneconomic on a going forward basis by $1.6 billion.” The commission’s Advisory Staff agreed with PIA Staff that completing Vogtle is uneconomic at the cost estimated by Southern.^[5]
“Certain costs [$1.5 billion, excluding Toshiba’s parental guarantee] for which the company is seeking recovery from ratepayers resulted from project mismanagement.”
“Had the commission been more accurately informed by the company as to the depth of the problems facing the project, the commission would have had the opportunity to assess the project status and make different decisions earlier on in the construction, when sunk costs were not so daunting an issue.”
Giving Vogtle co-owners “the right to abandon the project if any company costs are disallowed for any reason, including fraud, failure to disclose a material fact or criminal misconduct” was a “threat” and “unconscionable.”

Southern, of course, disputed all this.

Given the enormity of these issues and the long-term consequences of a decision to complete or not complete Vogtle, one would have expected a deliberate, careful analysis of the record and a reasoned decision.

Instead, the last day of hearings was Dec. 14, briefs were required five days later and the commission made its decision two days after that. Speed readers, I guess.

Are you ready for the decision itself? The Georgia commission without any explanation at all simply proclaims:^[6]

“Based upon careful consideration of all the evidence in the record, the commission finds as a matter of fact and concludes as a matter of law that it is appropriate to continue construction of Vogtle Units 3 & 4 under the terms set forth in this order.”

Georgia, that’s all the explanation you get. C’est la vie.^[7]

But what should consumers expect from regulators who had announced their decision before the hearing? Why waste ink?^[8]

More Project Delays Rewarded

Going forward, Georgia consumers have no protection against continuing project delays and overruns.^[9] The Georgia commission order claims that it incents performance by reducing return on equity if target dates aren’t met.

Unfortunately that is just wrong. Reduced ROE during delays is only for the periods of delay. After the project is in commercial operation, that ROE becomes part of the rate base, upon which Southern gets a generous return for at least 40 years. That is why Southern already will make an extra $5.2 billion over the life of the project from the delays to date.^[10] Nice work if you can get it.

The longer Vogtle takes to complete, the more Southern makes.

And every electric consumer in Georgia is on the hook for whatever Vogtle ends up costing.

What site selection advisor for a large consumer of electricity will recommend locating a new facility in Georgia? Because there is no competition in Georgia,^[11] any new business would have unlimited exposure to the Vogtle plant. Moody’s Investor Service already downgraded JEA because it owns 206 MW of Vogtle.^[12]

Customer Refund Gimmick

One last note on the Georgia commission decision: It directed that Southern refund part of the Toshiba/Westinghouse Electric settlement payment to consumers, $25 per customer per month for three months, with a bill line item saying “Vogtle Settlement Refund.” Great PR, but this refund money isn’t coming from Southern. It’s money that otherwise would have been credited against the cost of Vogtle.

So consumers effectively will be paying Southern a generous return on their refunds for decades. Sort of like your credit card company sending you a $75 gift card, but then that $75 shows up on your next bill as a cash advance. Which you can’t pay off for the next 40 years.

Oh, sorry, one more thing: The Georgia commission authorized a token 5-MW solar project to be located at, you guessed it, Vogtle. No consideration of whether that project size or location made any sense. But even more rate base for Southern.

The Sad Reality

The sad reality is that Vogtle never made sense, and this became obvious years ago. The Vogtle owners failed to oversee the failures of Toshiba and Westinghouse, failed to report the failures to the Georgia commission, and failed to provide realistic project costs and schedules. The hole became billions deeper as a result, and Southern’s past and future profits grew as a result.

Instead of holding the Vogtle owners accountable for their failings, the Georgia commission is more concerned with not appearing to have made consumers pay something for nothing. So the Georgia commission approves continuing an uneconomic project, gives Southern and the new project contractor an even bigger blank check than before, and maintains the incentive of higher profitability from greater delays.

The flogging will continue until morale improves.

Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.

“I do want to see this project completed,” said PSC Commissioner Lauren “Bubba” McDonald. “I do not like to see failure.” http://www.ajc.com/business/georgia-power-told-its-homework-vogtle-nuke-options/mnHqeJ7BdDza0U25xAxfbP/. “As an unabashed supporter of nuclear power,” [PSC Chairman Stan] Wise wrote, “I intend to be present for that vote and will resign shortly thereafter so that you may appoint my successor prior to the (candidate) qualifying period for the 2018 elections.” http://politics.myajc.com/news/state–regional-govt–politics/psc-wise-quit-after-vogtle-vote-governor-can-appoint-successor/Dv6bJbPTpNupmLUUe83f8J/. Commissioner Tim Echols said: “The last thing I want to do to my ratepayers is to say, ‘Look, I spent $4.5 billion of your money, and you have nothing to show for it.’ That’s a formula for getting unelected, as far as I’m concerned.” https://www.greentechmedia.com/articles/read/the-nuclear-power-war-isnt-over-yet#gs.1G0g8AQ. Echols went on to write an op-ed for The Wall Street Journal and an article for Public Utilities Fortnightly in full-throated advocacy for completing Vogtle, all before the hearing on whether to complete Vogtle. ↑
http://energy-counsel.com/docs/Vogtle-the-Law-of-Holes-and-Two-Modest-Proposals.pdf. The column also showed that the fuel diversity argument for Vogtle was vacuous. ↑
Reportedly, 40%. A shocking audit report on Vogtle’s sister nuclear units in South Carolina was prepared by Bechtel in 2016. It was never meant to see the light of day, but the link to it is in the news story here: https://www.postandcourier.com/news/audit-highlighted-problems-with-south-carolina-nuclear-project-a-year/article_9ac96112-9185-11e7-9979-977331ac2233.html. ↑
http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=170562. In this proposed order, the PIA Staff provides a damning “just the facts” recitation of everything wrong about Vogtle. ↑
https://www.youtube.com/watch?v=JtycWKqQVk8 ↑
http://www.psc.state.ga.us/factsv2/Document.aspx?documentNumber=170765. ↑
Adding to the incredulity is that terms of the commission decision were reviewed with Southern in advance of the commission meeting. “Although Echols said he did not want to get into details about his interaction with Georgia Power over the new conditions, he added, ‘Ultimately, they were read in and gave feedback’ on those restrictions.” http://chronicle.augusta.com/news/2017-12-21/georgia-public-service-commission-vote-allows-plant-vogtle-proceed. ↑
Not part of the decision is a motion by one of the commissioners on what the decision should be. This motion refers to the uncertainty of future natural gas prices, and how Vogtle can be a hedge against high gas prices.Of course future energy prices can’t be known. But the salient fact is that a forecast of future natural gas prices is effectively a mean. Lower gas prices would mean Vogtle is even more uneconomic. Higher gas prices would mean Vogtle is less uneconomic and might even be economic. But decisions need to be based on the mean, not on one extreme or another. And here’s another important point: If the gas price hedging value is significant the right thing to do is suspend Vogtle at a relatively trivial cost of $112 million for up to 10 years, which cost comes from Southern’s own consultant. http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=169459 (Black & Veatch Deferral Study). The Georgia Commission decision makes no mention of this option. ↑
The original project completion date was in 2017. In December 2016, Southern promised completion by 2020. Then nine months later, the completion date was pushed back almost two more years. And that date is likely more fantasy than reality. As of late 2016, two AP1000 plants in China were supposed to go into commercial operation in early 2017. https://www.reuters.com/article/us-westinghouse-nuclear/westinghouse-to-start-first-china-reactor-in-2017-sees-tens-more-idUSKCN11M1Q7. Somehow that didn’t happen, and last month the China state agency said they “will hopefully begin commercial operation next year.” http://www.nicobargroup.com/news-views-1/. “Hopefully”? ↑
“As a result of the delays experienced by the project, the company will make considerably more profit over the lifecycle of the units than it would have had the project been completed on time. The company’s profit will increase from approximately $7.4 billion to approximately $12.6 billion over the unit’s entire lifecycle.” http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=170562 (page 8). ↑
As I’ve pointed out before, Vogtle and the lack of competition are joined at the hip. ↑
https://www.moodys.com/research/Moodys-assigns-Aa2-and-Aa3-to-JEA-FL-sr-and–PR_904363490 ↑