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.
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.
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 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.
“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.”
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.
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.
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.
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.
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.”
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 McIntyre: Won’t Commit to Probe Leak to ‘GoodFriend’.)
“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.)
“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.”
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.”
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.”
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.
Lighthizer
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.
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.
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 New 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
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.
CAISO is in the midst of phase 3 of its Energy Storage and Distributed Energy Systems (ESDER) proceeding | STEM
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 proposed award of $22 million in grants to deploy microgrids, the first batch in its latest $44-million competitive microgrid solicitation. (See California Awarding $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.
OKLAHOMA CITY — SPP’s Strategic Planning Committee last week decided it will respond to FERC’s request for a definition of “resilience,” rather than losing valuable time turning the effort over to a newly created task force.
The commission on Jan. 8 rejected Energy Secretary Rick Perry’s call for cost-of-service payments to coal and nuclear generators, instead creating a new docket (AD18-7) requiring RTOs and ISOs to answer two dozen questions about how they define and assess resilience. FERC said it will use the response to determine whether additional action is necessary. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
Grid operators must respond by March 9.
American Electric Power’s Richard Ross, stressing the importance of stakeholder feedback, asked, “Will the creation of a task force end up consuming two-thirds of the time needed to get feedback?”
During the SPC’s Jan. 18 meeting, SPP staff initially suggested creating a forum in which they could solicit member concerns and input on resiliency issues, but they eventually yielded to the SPC’s management role to save time.
“Let’s start the discussion and see what happens,” SPP CEO Nick Brown said. “Using the whole Strategic Planning Committee is the best approach. Let’s let our team of experts put straw comments together, and see where they fly.”
Brown assured the committee he is, and will be, in “constant contact” with his counterparts to track progress at other RTOs, and said there was little appetite for asking FERC for an extension.
“I suggest we move ahead as best we can, using our existing stakeholder process,” he said.
Asked whether this was the commission’s effort to end up with resiliency standards, Brown said he didn’t know. “I think FERC is just looking for guidance on this. It’s a new commission, and there’s a lot of different thoughts on that commission.”
FERC has started the dialogue by inviting feedback on its suggested definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
SPC Chair Mike Wise, with Golden Spread Electric Cooperative, said he would work with the committee’s staff secretary Michael Desselle and SPP General Counsel Paul Suskie to create a timeline and process for gathering input.
Energy-only Resources Report Leads to Discussion, not Results
A staff report on including energy-only resources in SPP’s transmission planning process generated significant debate but did not result in an action item.
Staff reminded the committee several times that it was only presenting a status report, and that it would provide more information in the future.
“It’s pretty clear from the discussion we have some concerns,” Wise said. He and Desselle “want to spend some time looking at this before we get back to you.”
Staff said they are attempting to develop and adopt policies that better align SPP’s generation interconnection, transmission service and integrated transmission planning processes to “provide value proportional to cost when considering capacity and energy-only resources.”
Jay Caspary, SPP’s director of research, development and special studies, said this will address a perception that there is an “inequity of costs associated with market access and transmission expansion” allocated to load-serving entities when compared to non-LSE interconnection customers.
As the discussion dug deeper into the weeds, it was evident that stakeholder concerns ranged in many different directions, from the meaning of firm and non-firm transmission service to the length of time it takes proposed projects to get through the interconnection queue.
Caspary highlighted one equity issue as the “big one”: LSEs or merchants with energy resources compete equally in the market with those that have capacity resources and typically incur lower costs with associated market access.
“We could determine all network load in the footprint is firm,” Wise said. “That’s one way to eliminate much of this issue.”
“That may be very well where we end up,” said Lanny Nickell, SPP vice president of engineering. “We were trying to limit our creative thinking to what we felt we could accomplish. These are just ideas, not the end-all, be-all solutions to all the concerns we’ve been hearing.”
Staff said they would narrow a list of “modification considerations” — and “not proposals,” Nickell clarified — and incorporate the SPC’s feedback into a whitepaper, to be presented to the committee in the future.
Until then, much of the project’s burden could fall onto the Generator Interconnection Improvement Task Force (GIITF), which has been asked to address the overloaded interconnection queue and new requirements from FERC’s proposed rulemaking initiatives.
The GIITF in April intends to share with the Markets and Operations Policy Committee details on its three-stage process to clear the queue’s backlog. The group expects its next major issue to be rules accommodating battery storage, following a “dozen or so” requests for storage in the latest queue.
“That’s a bigger and bigger item for us to deal with,” said SPP’s Steve Purdy, the GIITF’s staff secretary. “We have a lot to accomplish by October.”
The MOPC recently granted the task force a one-year extension to develop a replacement for SPP’s current interconnection process. (See “Generator-Interconnection Task Force Extended for 1 Year,” SPP Markets and Operations Policy Committee Briefs.)
Brown told the SPC that the Corporate Governance Committee is reviewing SPP’s governance structure to ensure it still matches where the RTO is today — and will be soon with the possible integration of the Mountain West Transmission Group.
SPP’s footprint touches 14 states, stretching from East Texas to the Canadian border, having added Nebraska utilities and the Integrated System since 2009.
“We need to put some thought into the governance structure as we continue to grow,” Brown said. “Is a committee structure we put in place in 2003, and changed incrementally, appropriate for where we are today? It’s time. We just haven’t sat down and taken a detailed look.”
The Finance Committee is also moving forward with changes to increase transparency into SPP’s budget, which Brown said raises questions about the RTO’s withdrawal fee.
“All those things fit together,” he said, promising the SPC and Board of Directors will stay informed of the progress.
Controversy is swelling over the February 2017 spillway collapse at the Oroville Dam in Northern California, after local officials last week filed a scathing lawsuit alleging corruption at the state’s main water agency and lawmakers called for FERC to delay the facility’s relicensing.
“Decades of mismanagement and intentional lack of maintenance” by the California Department of Water Resources led to the federally declared disaster, according to allegations in the Jan. 17 lawsuit filed by the City of Oroville against the department. Filed with the California superior court in Butte County, the suit describes maintenance issues and a culture of poor supervision, fabricated inspection reports and corruption at the agency.
“For years, DWR supervisors were more interested in lining their own pockets than ensuring the safety of the facility and its workers. Important maintenance projects were delayed or never completed, and substandard supplies were used to address vulnerabilities in the dam’s armored spillway,” the lawsuit alleges.
Oroville is home to the Hyatt and Thermalito power plants totaling 933 MW of capacity, which had to be shut down during the incident. During the dam’s 2005 FERC relicensing proceeding, three environmental groups requested that the state pave the hillside below the emergency spillway to avoid erosion. The spillway failure generated criticism of both the DWR and FERC for ignoring the previous warnings. (See Local Officials Appeal to FERC as Oroville Water Levels Recede.)
The court filing alleges a “toxic culture” at the department, describing incidents of racist and sexist behavior, employee theft and other corruption. It describes how events around the incident unfolded, including the interaction of local law enforcement with DWR officials prior to and during the evacuation, which caused chaotic and dangerous road conditions and massive traffic jams. A complaint filed through the state Government Claims Program over the Oroville situation was rejected last July because it was determined it would be better resolved by the courts, the lawsuit says.
The lawsuit does not specify financial damages but does cite physical damage to city infrastructure, equipment and personal property as well as costs related to the evacuation, loss of tax and tourism revenue, and emergency and law enforcement services.
DWR spokesperson Erin Mellon said the department does not comment on pending litigation.
On Friday, U.S. Rep. John Garamendi (D), whose district is near Oroville, petitioned FERC to postpone the pending relicensing of the dam, citing the incident and saying “a failure by FERC to delay relicensing of the Oroville Dam would be a serious abdication of its regulatory responsibility.” A week earlier, nearly two dozen California state legislators filed in support of delaying the license.
Blowback over New DWR Director
The DWR has had four directors since the beginning of 2017, when Bill Croyle took over as acting director after Mark Cowin’s nearly seven-year stint. Cindy Messer briefly took over from Croyle in July 2017 until Gov. Jerry Brown appointed Grant Davis to the role.
Davis only led the department until this month, resigning after an independent forensics team released its report on the dam failure. (See Report: Regulatory Failure Caused Oroville Incident.) He was the signatory to the department’s Dec. 20 relicensing application to FERC, and he noted that the spillway incident followed California’s wettest January and February in more than a century.
Brown appointed Karla Nemeth to replace Davis on Jan. 10. That decision has stirred controversy, as TheSacramento Bee reported last week, because Nemeth is married to Tom Philp, executive strategist of the Metropolitan Water District of Southern California, a key member of a group of public agencies known as the State Water Contractors, which are the main recipients of water stored behind the Oroville Dam.
The City of Oroville’s lawsuit alleges the State Water Contractors “lobbied DWR to defer maintenance at [State Water Project] facilities, in order to reduce their own costs” and used their influence to defer needed maintenance at the facility.
Metropolitan Water District is also involved with negotiations around Brown’s $17.1 billion water tunnels proposal, a large-scale project opposed by many Northern California officials and environmentalists.
Real-time price data from 2018 indicate the ISO-NE grid is nearly free of congestion, stakeholders learned during a Planning Advisory Committee teleconference last week.
ISO-NE System Planning Engineer Victoria Rojo presented the PAC with an analysis of historical market and operational data, saying “the small congestion component of the locational marginal prices suggests there is little congestion on these interfaces.”
| ISO-NE
The analysis showed that interface flows typically operate closer to the limit during on-peak hours and that portions of the system far from load centers — especially northern Maine — have high negative loss components. Rojo attributed the Maine negative line losses to new wind energy resources.
“We are effectively close to a congestion-free system,” said Michael Henderson, the RTO’s director of regional planning and coordination.
West Central Mass 2027 Tx Needs Assessment
ISO-NE will conduct a 2027 needs assessment for the Western and Central Massachusetts (WCMA) study area to examine any potential transmission needs 10 years out and determine their time sensitivity.
West Central Mass Study Area | ISO-NE
The study will consider future load distribution; resource changes in the area based on Forward Capacity Auction 11 results; 2017 solar and energy-efficiency forecasts; reliability over a range of generation patterns and transfer levels; and all applicable NERC, Northeast Power Coordinating Council and ISO-NE transmission planning reliability standards.
Comments on the preliminary draft study are due by Feb. 4 and the study should be complete in the second quarter.
Critical Load Level and Need-by Date Determination
Senior transmission planning engineer Pradip Vijayan presented staff analysis to determine the critical load level (CLL) and a need-by date (NBD) for steady-state, peak-load needs on short circuits.
The study noted that in past needs assessments, a “year of need” was used to denote summer peak load needs likely to be required within three years. However, for time-sensitive needs, the Tariff requires a specific NBD.
New England Subarea Model | ISO-NE
The RTO performs a CLL analysis for each identified need, and the results inform market participants about the quantity and general location of resources that would either satisfy the need or defer it for regulated transmission solutions.
For a time-sensitive need, the calculated CLL signals at what load level an identified need would be eliminated — which may call for additional reduction in New England load.
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.)
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.
“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.
Vogtle Nuclear Power Plant
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.
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. ↑
“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. ↑
