MISO is seeking stakeholder guidance on how to forecast the probable locations of future renewable, energy storage and distributed energy resources in order to better inform its transmission planning.
To prepare for MISO’s 2019 Transmission Expansion Plan modeling, stakeholders had asked the RTO to update probable utility-scale renewable zones, map out future storage placement based on likely economic benefits, create an electric vehicle siting methodology and gather more information on DER through forecasts of customer-driven adoption and surveys of load-serving entities.
“Some of these categories are relatively new to our MTEP process,” MISO Senior Policy Studies Engineer Jordan Bakke said.
James Okullo with MISO’s policy studies group said MTEP 19’s utility-scale renewable study, prepared by Vibrant Clean Energy and used to predict future renewable siting, may include areas outside of the RTO’s territory.
“We cannot ignore the impact of our neighbors and what’s happening outside of our footprint,” Okullo said during a Sept. 29 MTEP 19 workshop.
The RTO’s current MTEP siting methodology allows for siting of about 50 GW of new wind projects and 9 GW of utility-scale solar expansion in the footprint over the next 15 years.
Okullo said MISO would also examine which states have opened state-owned land to renewable project siting.
ITC Holdings’ Cynthia Crane asked if the RTO would want utilities and states to supply information on county efforts to stifle renewable siting, pointing to residents in Michigan’s Thumb region that are actively campaigning against new wind farms.
Okullo said such information would be useful to MISO planners.
After stakeholders suggested the RTO rank its states in order of receptivity to renewable development, Indiana Utility Regulatory Commission adviser Dave Johnston cautioned against such a political exercise.
“In a state like mine, you wouldn’t think we’d be very open to renewable development, but we’re very into economic development and manufacturing, so we welcome those plants. So it’s hard to paint states in certain boxes. It’s hard to predict,” he said.
In MTEP 18, MISO projected the siting of 2 GW of future energy storage in its future with the most aggressive growth of DER. It also placed no more than 100 MW of energy storage at any single load bus in the next 15 years. In MTEP 19, MISO could predict greater penetration by studying the full range of storage benefits, engineer Kunjal Yagnik said.
Wind on the Wires’ Natalie McIntire asked why MISO would include energy storage in MTEP resource assumptions when storage could very well solve transmission needs and become a project recommendation itself.
“It seems like it could serve both functions,” she said. MISO officials agreed.
Bakke said MISO will have to sort through the several nuanced benefits of storage when predicting future locations. For example, storage could be placed near a proliferation of renewable resources or situated in areas where frequency response could use improvement, he said. Customized Energy Solutions’ David Sapper said he agreed with MISO’s view of storage as a “composite resource.”
Ann Benson, a MISO policy adviser, said the RTO is looking for better ways to increase DER visibility in MTEP siting. She asked stakeholders for ideas about how MISO could prepare a more complete database of existing and anticipated DER locations.
Marcus Hawkins, director of member services for the Organization of MISO States, advised MISO against using footprint-wide assumptions for DER trends, noting that in listening to recent discussion from stakeholders and regulators, he’s heard a clear preference for a state-by-state differentiation of DER assumptions.
If appropriate, MISO could also forecast use of other emerging technologies, MISO policy studies staffer Temujin Roach said. Those could include small hydropower resources near rivers and lakes, small modular nuclear reactors and compressed air energy storage.
MISO will hold two more workshops before moving forward with final MTEP modeling in early 2018. For now, the RTO is asking stakeholders by Nov. 1 to provide suggestions on how to incorporate forecasts for renewable and new technologies into MTEP modeling and resource siting.
RENSSELAER, N.Y. — NYISO will soon announce the formation of a carbon pricing task force, CEO Brad Jones told the Management Committee on Wednesday.
The task force will “provide guidance on implementation, to explore how fast we can move forward on these issues,” Jones said.
NYISO in August released a Brattle Group report on pricing carbon into its wholesale energy market to support New York’s decarbonization goals. At a Sept. 6 public hearing held by the ISO and the New York Department of Public Service, stakeholders offered broad support for incorporating a $40/ton carbon charge into the market. (See NYISO Stakeholders Talk Details of Carbon Charge.)
Stakeholders are still concerned about how the costs for decarbonization will be allocated, and committee participants wondered who would be running the task force. Jones said the group will report to the grid operator’s Market Issues Working Group.
Hot September Causes Historic First in Flow Limits
Unseasonably warm weather in the second half of September led NYISO to secure the West Central interface to limit flows toward western New York, the first time the ISO had to secure flows in the reverse direction because of high levels of Lake Erie loop flows, COO Rick Gonzales said.
Western New York transmission | NYISO
“This shoulder period is usually the time for generators and transmission owners to schedule their off-peak maintenance outages, so unusually warm weather during this period can present reliability challenges,” Gonzales said. “We did reschedule a number of major transmission maintenance outages to later in the week and bring on one additional generator to make sure that NYISO was meeting its reliability commitments.”
In his regular operations report, Gonzales highlighted that “peak load in August was even less than the peak load in July, so we didn’t even reach 30,000 MW of peak load this summer.” The balance of the operations report was delivered at the Business Issues Committee earlier in September. (See NYISO Business Issues Committee Briefs: Sept. 12, 2017.)
Mild Summer Poses Few Challenges
This summer was the fourth consecutive summer in which the ISO’s peak load fell short of the 50/50 forecast, Vice President for Operations Wes Yeomans said.
The Summer 2017 Hot Weather Operations report showed that actual ambient temperatures, total summer loads and peaks were all below 50/50 projections. New York did experience two instances of hot weather, but only for short durations.
| NYISO
A warm front crossed Upstate New York and New York City during June 11-13, with Albany registering temperatures of 95 F and LaGuardia Airport hitting 100 F. June 13 peak load was 29,126 MW.
NYISO’s summer peak of 29,699 MW occurred July 19, coming in far below the 50/50 peak forecast of 33,178 MW, Yeomans said. NYISO met all reliability operating criteria during the peak and required no statewide out-of-market commitments or demand response activations, he said.
Yeomans noted that New York State Electric and Gas this summer completed its Auburn Transmission Project, which included construction of a new 115-kV Elbridge-State Street line and re-conductoring of the existing line linking those points. The upgrades provide higher thermal ratings and alleviate the need for the coal-fired Cayuga plant to maintain local reliability.
A new 345-kV Dolson Avenue substation interconnection for the CPV Valley Energy Center was completed in early September and the second Ramapo phase angle regulator returned to service Sept. 14, Yeomans said.
2018 Budget up 5% on Security Enhancements
NYISO’s draft 2018 budget calls for $155.7 million in spending allocated across a forecast of 157.8 million MWh of usage, representing a Rate Schedule 1 charge of 98.7 cents/MWh, according to an overview presented by Alan Ackerman, chair of the Budget and Priorities Working Group.
The draft budget represents a 5% increase in revenue requirement from this year and a 0.3% decrease in projected megawatt-hours, translating into a 5.45% increase in transmission charges.
Among the ISO’s key priorities for next year are physical and cybersecurity enhancements to secure operations and meet audit and compliance needs. System and resource planning will focus on reliability and the support of studies requested by the Public Service Commission, including assessing potential public policy transmission needs such as offshore wind integration, Clean Energy Standard implementation and congestion in the North Country (the state’s extreme northern frontier, bordering Lake Ontario, Lake Champlain, the Saint Lawrence River, Vermont, Ontario and Quebec).
Busy NYISO Agenda Drives Consumer Impact Analysis
The ISO will conduct consumer impact analyses on five major projects for 2018, NYISO Senior Manager for Consumer Interest Liaison Tariq N. Niazi told the committee. The ISO conducts such analyses for projects with anticipated net production cost impacts of at least $5 million or changes in energy or capacity market prices of at least $50 million per year.
Also to be analyzed are projects incorporating new technology into ISO markets for the first time, those that allow or encourage a new market product and those that create mechanisms for out-of-market reliability payments. The grid operator leaves room in the process for unanticipated analyses, such as FERC directives where NYISO has implementation flexibility or emergent stakeholder issues.
For 2018 the projects being analyzed are:
Integrating Public Policy: This project is attempting to accommodate state’s decarbonization goals with the wholesale energy and capacity markets and align the process with the Reforming the Energy Vision initiative.
Buyer-Side Mitigation (BSM) of Repowering Projects: To encourage private investment, the ISO will seek to develop a specially tailored BSM evaluation process that reduces the potential for over-mitigation of repowering projects.
Constraint Specific Transmission Demand Curves: The ISO will would study replacing its current transmission constraint pricing methodology with multiple transmission demand curves that can vary according to the importance, severity and/or duration of the transmission constraint violation. It would replace the current procedures, in which some transmission shortages are resolved by relaxation instead of by setting prices through use of a transmission demand curve. The goal is more efficient pricing of transmission constraints, reduced price volatility and more efficient resource scheduling.
DER Participation Model: The ISO is evaluating potential modifications to its existing demand response programs as part of the Distributed Energy Resource (DER) Roadmap it announced in February. (See NYISO ‘Roadmap’ Sees Dispatchable DER by 2021.) The project will include the design of DER performance obligations, metering and telemetry requirements, baseline and performance measurement and verification rules, and resource modeling. It also will seek to develop ways to balance the simultaneous participation of DER in the wholesale markets and retail-level programs.
Energy Storage Integration and Optimization: The ISO will continue to develop its model for the participation of energy storage in the wholesale markets, including improving the optimization of storage on a least-cost basis through more sophisticated energy constraint modeling. The goal is to improve modeling of resources that can inject and withdraw energy from the grid in response to ISO dispatch signals.
MC Approves Western New York Tx Proposal
The Management Committee voted unanimously to advise the Board of Directors to approve NextEra Energy’s proposed Empire State Line in western New York, as recommended by an ISO public policy transmission planning report. The ISO’s Business Issues Committee endorsed the same report earlier in September. (See Public Policy Tx Project Wins Key NYISO Endorsement.)
Dawei Fan, NYISO supervisor of public policy and interregional planning, presented the report, which represents NYISO’s first-ever evaluation of transmission needs stemming from public policy requirements.
NYISO received comments on the report from the New York Power Authority, NYSEG, New York State Energy Research and Development Authority, NextEra and LS Power’s North America Transmission, the last of which intends to pitch its own transmission project to the board on Oct. 16, before the board’s October meeting.
Several meeting participants sought more information about what topics would be discussed at the upcoming board meeting and whether their absence would “dilute” the impact of their already submitted comments. Howard Fromer of PSEG Power wanted to know if participants seeking to speak to the board planned to address legal arguments as opposed to more technical points.
NYISO Vice President for System and Resource Planning Zachary Smith responded that the comments would not focus on legal matters and asked that all supplementary comments be delivered to the RTO by Sept. 29. Stakeholders who want to speak directly to the board were asked to notify the RTO by Oct. 3.
Remember the Cash for Clunkers program? Inefficient cars paid to go away.
The Energy Department’s directive to FERC last week is Cash for Clunkers with a twist: inefficient generators paid to stay.
The original Cash for Clunkers was an economic stimulus for new stuff to replace the old stuff. The DOE’s Notice of Proposed Rulemaking subsidizes the old stuff to stop the new stuff: a sort of stimulus in reverse. (See related story, Perry Orders FERC Rescue of Nukes, Coal.)
So we might say the DOE version is a Twisted Sister sort of twist on the original.
Bailing out the Retiring, Retired and Canceled Clunkers, and then Everyone Else
We know with certainty that the DOE proposal subsidizes the inefficient because those are the plants that will opt for the federal rate guarantee instead of market-based rates. How will this play out?
DOE says there are 34 GW in projected retirements over the next five years. Under the DOE proposal, none of that would retire and instead would go on the federal dole.
And then there’s the 71 GW that already retired over the last six years but will likely return, like “Night of the Living Dead,” for that federal rate guarantee.[1]
And how about all those canceled nuclear projects?
So we’ll have around 100+ GW of uneconomic clunkers crashing the markets, and of course crashing market prices. This will force all the economic plants that depend on legitimate market prices to join the federal dole.
Natural gas plants will do this by simply adding 90 days’ worth of oil tanks.[2]
What will all this cost consumers? DOE doesn’t even try to answer that question, but here’s one way of looking at it. First, we can assume that FERC won’t want thousands of individual rate cases for all the power plants in all the RTOs.[3]
So FERC would need some sort of standard compensation. Let’s say it adopts a cost of new generation, maybe $400/MW-day.[4] Generation in the RTOs is around 530 GW; add the roughly 70 GW of retired clunkers that will return from the dead for about 600 GW on the federal dole. That’s about $88 billion annually.
So we are talking about tens of billions of dollars a year squandered first on what are, by definition, uneconomic resources, and then by paying economic resources that are rendered uneconomic by the clunkers and forced onto the same federal dole.
I can’t help noting how Republicans blasted the original Cash for Clunkers,[5] which had a one-time cost of $3 billion. The DOE version is tens of billions of dollars every year, forever.
Resiliency
DOE says that its proposal is about “resiliency” (the new buzzword for reliability). But the retiring plants really are clunkers, as this PJM slide excerpt illustrates (I’ll translate the jargon after the slide):[6]
| PJM
The deactivating (retiring) stuff has an outage rate — equivalent forced outage rate-demand (EFORd) — that is three times the new stuff (14.56% versus 4.42%). Yet DOE wants to subsidize these clunkers so they won’t retire.
And that somehow is going to improve resiliency, again in a Twisted Sister sort of way.
90 Days of Fuel Supply on Site
A few words about the fuel supply requirement. DOE relies heavily on PJM’s experience in the polar vortex of 2014 and claims that natural gas supply was the major problem. It was not. As this PJM chart plainly shows, natural gas interruptions affected 9,300 MW, accounting for less than 25% of total forced outages of 40,200 MW:[7]
| PJM
The FERC testimony of Mike Kormos, PJM’s executive vice president at the time, directly contradicts DOE’s main claim: “Natural gas interruptions removed less than 5% of the total capacity required to meet demand on Jan. 7, [2014], while equipment issues associated with both coal and natural gas units made up the far greater proportion of forced outages.”[8] (Emphasis added.)
Beyond equipment issues, another basic flaw in a metric like fuel supply on site is that coal piles freeze, as some did in the polar vortex. Years of coal supply on site would be worthless if frozen. And of course, nuclear plants can’t run during refueling and other outages. Years of nuclear fuel on site would be worthless during those outages.
Here’s a fun fact you won’t find in the DOE NOPR: Baseload (combined cycle) natural gas plants average lower forced outage rates (4.29%) than baseload coal plants (7.71%), and have about the same as nuclear plants (3.51%).[9] It’s these overall forced outage rates that matter — not a single metric like fuel supply on site.
As for 90 days specifically, DOE provides zero rationale for that. In the polar vortex, the generation emergencies in PJM aggregated 20 hours.[10] What is magic about 90 days (other than being tailored to the average coal plant stockpile)?
FERC and RTOs like PJM have learned from the polar vortex to reward performance and penalize nonperformance, instead of using a meaningless metric like days of fuel supply on site.
PJM hasn’t had a single system generation emergency in more than three years — that’s more than 26,280 hours of reliable operation. And PJM locks down adequate, reliable generation resources years in advance.
Bottom line: DOE proposes to take a system that is incredibly reliable and squander tens of billions of dollars on uneconomic resources to make it less reliable.
J&R Gone Missing
Absent from the DOE NOPR is an explanation of how its proposal would satisfy the lodestar requirement of the Federal Power Act that all rates be just and reasonable.[11]
Subsidizing uneconomic clunkers in organized markets is the antithesis of just and reasonable rates. It would be a repudiation of everything that FERC has sought to accomplish over the last 25 years.
Maybe Rick Perry was right all along: DOE should be abolished.
If you’re one of those owners, you might want to hold the wrecking ball. Or come to think of it, maybe you wouldn’t: more rate base if you wreck and rebuild. ↑
The Wall Street Journal cites unidentified experts for the notion that only nuclear and coal plants will qualify under the DOE proposal. That is wrong. Installing oil storage at natural gas plants is routinely done. Of course, if rate base becomes the game, LNG tanks would be used instead. ↑
There’s a straight-faced argument for that: If new generation investment costs that much, existing generation should be compensated at the same level. Otherwise we would be incenting existing generation to retire that would cost less to keep around than paying for replacement new generation. ↑
DOE gives lip service to the statutory requirement by using the term “just and reasonable” twice in its proposed regulation. It’s like saying “bring me a blue rock that is red.” ↑
Western utility PacifiCorp is seeking bids for up to 1,270 MW of wind power to integrate into its system by the end of 2020.
Successful proposals for new or repowered wind projects must demonstrate that they qualify for the federal production tax credit and can achieve commercial operation by Dec. 31, 2020, according to the company’s request for proposals.
The RFP is for “new or repowered wind energy interconnecting with or delivering to PacifiCorp’s Wyoming system with the use of third-party firm transmission service and any additional wind energy located outside of Wyoming capable of delivering energy to PacifiCorp’s transmission system that will reduce system costs and provide net benefits for customers.” The minimum project size is 10 MW.
Benchmark bids for PacifiCorp’s RPF are due on October 10. | PacifiCorp
Portland, Ore.-based PacifiCorp said it would consider a “build-transfer” agreement where the developer assumes responsibility for construction and transfers the facility to PacifiCorp, or a power purchase agreement for up to a 30-year term.
“These new wind resources are a key part of the company’s plan to both meet customer energy needs and continue our cost-conscious transition to less carbon-intensive energy,” said Stefan Bird, CEO of PacifiCorp’s Pacific Power unit.
PacifiCorp will hold a bidder conference on Oct. 2, with notices of intent to bid due Oct. 9 and benchmark bids due by Oct. 10. RFPs for Wyoming-based projects are due on Oct. 17 and non-Wyoming projects on Oct. 24. Agreements will be executed by April 16, 2018, according to PacifiCorp’s schedule. The RFP requires approval from Utah and Oregon regulators.
PacifiCorp included in its 2017 integrated resource plan a proposal to add new wind resources. (See PacifiCorp IRP Sees More Renewables, Less Coal.) The wind energy will be procured in association with the new 500-kV Aeolus-Bridger/Anticline transmission line, a segment of PacifiCorp’s Energy Gateway, a 2,000-mile transmission project that has been developed over the past 10 years. The wind solicitation is part of the IRP’s “Energy Vision 2020” initiative, which also includes plans to repower and improve the utility’s current wind portfolio.
PacifiCorp is a subsidiary of Berkshire Hathaway Energy and serves 1.8 million customers in six states through its Pacific Power and Rocky Mountain Power subsidiaries. PacifiCorp operates 72 generating units with nearly 11,000 MW of capacity, which is currently 62% coal, 15% natural gas, 7% wind and 5% hydro, and the rest coming from biomass, solar, nuclear and geothermal.
Entergy on Thursday said it will continue to operate the Palisades nuclear plant until early 2022 under the terms of its original agreement with Consumers Energy, representing an about-face for the companies after they announced last winter they planned to terminate the arrangement.
The two companies now say they will honor the terms of their 15-year power purchase agreement, which will keep the Michigan nuclear unit running until April 2022. The companies signed the deal in 2007 after Entergy paid Consumers parent CMS Energy $380 million for the plant.
Palisades plant | Entergy
Charlie Arnone, Entergy’s top official at Palisades, said last week’s ruling from the Michigan Public Service Commission factored heavily into the decision to terminate the buyout of the PPA. The Sept. 22 order (U-18250) permitted Consumers to issue securitization bonds for just $142 million of the $184.6 million in qualified costs needed to buy out the PPA. Consumers planned to make a one-time, $172 million payment to Entergy.
The PSC said Consumers’ substitute capacity plan was not solid enough to grant the requested funds, and customer savings as a result of exiting the PPA wouldn’t be as significant as the company had estimated.
“Having certainty around the replacement portfolio is integral to the commission’s determination on whether a regulatory asset should be granted because it will ultimately affect electric reliability and whether savings will be achieved,” the PSC wrote in its decision. “Accordingly, the replacement portfolio is the underpinning of the commission’s evaluation and approach to the regulatory asset determination.”
The PSC pointed out that major components of Consumers’ plan — which included the purchase of a gas-fired plant and the expansion of the 60-MW Filer City coal plant in Michigan — “are either not near the conclusion of the regulatory process or, in the case of the gas plant purchase, have not yet been filed,” even at the “tail-end” of a seven-month proceeding.
Consumers spokeswoman Katelyn Carey said the decision not to pursue a 2018 Palisades shutdown was made after careful review by both parties.
“Moving ahead under the terms of our current Palisades’ power purchase agreement through 2022 is the best path forward. We appreciate the thoughtful, deliberate approach by all parties during the process and remain committed to delivering affordable, reliable, safe and clean energy to our customers across Michigan,” Carey said in a statement.
Entergy last December announced it would close Palisades on Oct. 1, 2018, citing unfavorable market conditions for nuclear generation and more economic alternatives. (See Entergy, Consumers Announce Closure of Palisades Nuke.)
In a press release Thursday, the company said that it “remains committed to its strategy of exiting the merchant nuclear power business.”
“We greatly appreciate the continued patience of our employees and the local community in Southwest Michigan throughout this regulatory process, and we will continue to focus on the plant’s safe and reliable operations,” Arnone said. “Entergy will continue to make all necessary investments and maintain appropriate staffing, in accordance with strict licensing standards.”
Local media outlet MLive reported that some of Palisades’ 600 employees celebrated the news.
Entergy said it expects to free up $100 million to $150 million in cash flow through keeping the PPA in place. Revoking the termination also enables the company to amortize and depreciate refueling outage costs and capital expenditures, with those cost to be included in operational results, rather than incurred as expenses.
As recently as late July, officials from the Nuclear Regulatory Commission were attending citizen meetings on Palisades’ decommissioning process, with some nearby residents concerned about on-site storage of radioactive materials. NRC said that a reserve account for Palisades contained $425 million to cover the potentially 60-year decommissioning process.
During a February earnings call, Consumers CEO Patti Poppe said CMS would improve its financial position by terminating the Palisades nuclear plant PPA in favor of employing more energy efficiency, demand response, renewable power and coal-to-gas switching. She added that Consumers’ substitute capacity plan for the “above-market” PPA would have replaced a single, big-bet capital project with many smaller options carrying less risk, and that CMS could replace other PPAs by building its own plants.
MISO’s proposed multiyear evaluation on the future impact of integrating renewable energy will consist of 10 separate studies, with each focused on projected grid conditions at steadily increasing levels of renewable penetration.
But the RTO’s sweeping approach is drawing mixed reactions from stakeholders.
MISO policy studies engineer Jordan Bakke said the evaluation will first model current renewable penetration — about 8% of the resource mix. It will then examine growing system complexity in increments of 10% renewable resource penetration, concluding with an RTO system powered 100% by renewable sources.
Existing renewables in MISO footprint | MISO
At each 10% checkpoint, MISO will assess systemwide ramping capability, operating reserves, transmission congestion, voltage and frequency stability, and loss-of-load expectation, among other data.
“Between some milestones, the system complexity might not increase much, but at other points, it could increase a lot — and those are our inflection points,” Bakke said during a Sept. 27 Planning Advisory Committee meeting. “We currently don’t know where these inflection points lie.”
The evaluation will attempt to identify when the growth of renewables and the retirement of baseload units require changes in the structure or operation of the system, something MISO has not attempted to answer until now, Bakke said. (See MISO to Conduct Long-Term Renewable Integration Study.) It also aims to predict:
How and when system reliability will be impacted by heavy renewable output;
Whether there are limits to the amount of wind and solar generation MISO can support;
How long until energy storage becomes a requirement;
What parts of the grid will be stressed first; and
How much renewable energy can be deployed before substantial system changes are needed.
The study will also explore what solutions will best mitigate system stressors, Bakke said, whether they be new transmission lines or buses, energy storage, better dispatch availability, demand response measures or better coordination efforts.
Bakke said he would return to later PAC meetings to discuss what MISO has discovered at each study milestone. The study doesn’t have a definitive end date, but Bakke said MISO would likely examine the effectiveness of continuing the study after a year.
Wind on the Wires’ Natalie McIntire said the study may not be “helpful or accurate” given that MISO has not yet reached a 10% renewable penetration and will take several years to achieve a 50%. Transmission could look very different by then, she noted.
“We’ve seen a lot come on in a relatively short amount of time,” countered Bakke, adding that MISO is especially interested in studying the system at a 30-60% renewable penetration, which may become a reality.
Other stakeholders pointed to the high number of renewable projects lined up in MISO’s interconnection queue, which could quadruple wind capacity in some parts of the footprint.
“We started out calling this a breakpoint study,” said MISO Director of Planning Jeff Webb. “If the systems breaks here, what do you do to fix it? And if it breaks here, what do you do to fix it?”
Some stakeholders said the study seems like a high-risk, low-reward endeavor, considering that advances in renewable technologies could solve their own shortcomings by then. Others suggested that generation and transmission owners might question the relevance of study results going out to 2050.
“We’re asking what things do we need to care about in 10 years, and what things do we have to care about in 30 years,” Bakke explained.
Xcel Energy’s Drew Siebenaler said that the study could yield a “holistic look” at renewables and system capability. “We fully support this effort as long as it takes,” he added.
NEW YORK — New York’s Reforming the Energy Vision initiative aims to fulfill a twofold objective, according to the state’s top energy official: attract the capital needed to integrate renewable energy into the grid while simultaneously motivating utilities to work with clean energy startups instead of treating them like enemies.
“Everything has to change,” New York State Chairman of Energy and Finance Richard L. Kauffman said Tuesday at Greentech Media’s New York REV Future 2017 conference in Brooklyn.
Government is changing too, the state’s first “energy czar” said. While state agencies “used to just do one-time grants,” they are now working to develop sustainable business models for the electricity sector.
REV Changing the Role of the Utility
Kauffman said he sees “green shoots of change” as evidence of New York’s evolving energy framework, such as Consolidated Edison’s Brooklyn-Queens Demand Management program (BQDM), a $200 million effort designed to defer infrastructure spending through energy efficiency, distributed energy resources and demand response. (See NYPSC Extends Con Ed Demand Program.)
“Its non-wires requirement — that was a big deal and that has spread to Central Hudson … and we’re close to National Grid — thousands of rate cases,” he said.
And while the solar industry has shown a profound change in its willingness to engage with state agencies, utilities have “a real struggle to figure out how to be partners [with DER providers] instead of competitors.”
But integration of DER will be key to the evolution of the grid, he said.
“There’s no question that storage has to be a critical part of the system, which is getting peakier and peakier. Yet the value of storage is not adequately captured yet,” Kauffman said. “Utilities procure power, but up to now have not had any financial incentive to reduce peak power purchases.”
Moderating a panel on REV policy, Greentech’s Katherine Tweed asked where to draw the line to mark the right mix of energy resources: “BQDM is the greatest experiment in the world … but people say Con Edison’s going to build that substation when they need it.”
Con Ed Vice President for Distributed Resource Integration Matt Ketschke said, “Most DER doesn’t line up with Con Edison because most of it is not in the business of power generation. … Our real goal is ultimately to eliminate the need for those substations.”
Theatrical Disruption
Three protesters from the New York Energy Democracy Alliance disrupted Kauffman’s talk with a bit of guerrilla theater to highlight the difficulty they say some 800,000 low-income people in the state have paying their energy bills under REV.
The skit began when a man several rows from the stage stood up and identified himself as a renter having trouble paying his utility bills.
After he had asked Kauffman how REV would address the concerns of “low-income communities of color,” two women on either side of the man stood up, pretending to be Kauffman’s security guards.
“Silence!” shouted the women, who wore capes reading “REV = Not Your Business” and “REV = Not a Democracy.”
“This is not the place for the complaints of the working class.”
They went on to bow at Kauffman, a former Goldman Sachs banker, mocking him as the “all-powerful energy czar.”
They finished their skit within a couple minutes — escorting the man out of the conference room before the real security could arrive — and exited to scattered audience applause.
Kauffman took the disruption with humor, saying he was “well aware that accountability is key and that well more than 800,000 New Yorkers have trouble paying their electric bills.”
The electric power system “is financially inefficient as well as energy-inefficient,” Kauffman said.
“So, guilty as charged — I do have a financial background,” he said. But Kauffman said that background only motivates people inside the industry to make the system more efficient.
‘Where Policy Meets Reality’
Nilda Mesa, director of urban sustainability and equity planning at Columbia University’s Urban Design Lab, opened the conference by saying that energy efficiency should be treated like a renewable resource “because the greenest electron is the one that’s not used.” Eventually, “financing people can start to understand the engineering language,” she said.
Scott Weiner, deputy for markets and innovation at the New York Department of Public Service, pointed to the challenge of shifting “from a paradigm of net metering to more market-based uncertainty that exists through the value of DER methodology,” particularly for the solar sector.
“But the industry has stepped up,” he said.
Financing is key to the transformation of the grid, Weiner said: “If I could take out my magic REV wand, I’d like to see the investment community, the people who provide project financing, more directly engaged.”
Todd Glass, energy lawyer with Wilson Sonsini Goodrich & Rosati, asked how project financiers could judge utilities, considering the wide spread between various utilities’ cost of service estimates. Weiner said, “Figuring out the marginal cost of service can be hard to do; that’s where policy meets reality.”
Energy Secretary Rick Perry on Friday ordered FERC to rescue at-risk nuclear and coal generation in deregulated states by ensuring they receive “full recovery” of their costs.
Perry’s extraordinary Notice of Proposed Rulemaking, invoked under Section 403 of the Department of Energy Organization Act, requires FERC to complete a final rule within 60 days after publication of the NOPR in the Federal Register.
Separately, DOE announced it had conditionally approved a $3.7 billion increase in the federal loan guarantees for the over-budget and behind-schedule Vogtle nuclear project. Georgia Power and its partners, Oglethorpe Power and the Municipal Electric Authority of Georgia, had previously received guarantees of $8.3 billion to support construction of Vogtle Units 3 and 4.
Spent nuclear fuel pool | Simone Ramella via Wikimedia Commons
In a letter to FERC, Perry cited coal and nuclear retirement statistics and DOE staff’s recommendations in the grid study it released in August. The study said FERC “should expedite its efforts with states, RTO/ISOs and other stakeholders to improve energy price formation in centrally organized wholesale electricity markets” to ensure “baseload” coal and nuclear generators receive compensation for their “resilience” to fuel supply disruptions. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Coal generators typically keep 60 to 90 days of fuel at plant sites; operators of nuclear plants refuel every 18 to 24 months.
60 Days to Act
“Now that a quorum has been restored at the commission, I am confident that the commission will act in an expeditious manner to address this urgent issue,” Perry said his letter. “To that end, in the enclosed NOPR, I direct the commission to consider and complete final action on the rule proposed therein within 60 days from the date of the publication of the NOPR in the Federal Register. As an alternative, I urge the commission to issue the proposed rule as an interim final rule, effective immediately, with provision for later modifications after consideration of public comments.”
Perry said the final rule should take effect within 30 days of publication in the Federal Register and that each RTO and ISO submit a compliance filing within 15 days of the effective date of the rule.
Perry began his letter by invoking President Trump’s campaign slogan, saying “America’s greatness depends on a reliable, resilient electric grid powered by an ‘all of the above’ mix of generation resources.”
The secretary went on to cite the 2014 polar vortex, Superstorm Sandy and Hurricanes Harvey, Irma and Maria as evidence that “much more work needs to be done to preserve these fuel-secure generation resources” to ensure sufficient power, “voltage support, frequency services, operating reserves and reactive power.”
“Distorted price signals in the commission-approved organized markets have resulted in under-valuation of grid reliability and resiliency benefits provided by traditional baseload resources, such as coal and nuclear,” he said. “The rule will ensure that each eligible reliability and resiliency resource will recover its fully allocated costs and thereby continue to provide the energy security on which our nation relies.”
Polar Vortex
When PJM lost as much as 22% of its generating capacity to forced outages during the polar vortex, Perry noted, the RTO needed generation from coal plants scheduled for retirement to prevent rolling blackouts, with American Electric Power reporting that it deployed 89% of its coal units scheduled for retirement. Nuclear plants, he noted, had an average capacity factor of 95% during the crisis. He did not mention that some coal plants also were unable to operate because of frozen coal piles and other problems.
Lignite coal conveyor at plant | FEECO International
Perry cited DOE’s January 2017 Quadrennial Energy Review, which reported that 37 GW of coal capacity retired between 2010 and 2015, more than half of all generation retirements during the period. The report predicted coal would also represent half of the 34.4 GW of retirements projected between 2016 and 2020, with natural gas plants (30%) and nuclear (15%) making up most of the remainder.
The secretary quoted NERC’s warning that “premature retirements of fuel-secure baseload generating stations reduces resilience to fuel supply disruptions.” Unmentioned was that NERC’s most recent State of Reliability report concluded “bulk power system reliability remained … adequate” in 2016, repeating the group’s findings from 2013–2015.
At a 2013 technical conference, FERC stopped short of NERC’s warning, saying that the shift in generation from coal toward gas and renewables “may result in future reliability and operational needs that are different than those of the past.” (See Capacity Market Attracts Praise, Criticism at FERC.)
“The fundamental challenge of maintaining a resilient electric grid has not been sufficiently addressed by the commission or the commission-approved ISOs and RTOs, and the lack of a quorum at the commission has undoubtedly thwarted the issuance of rules,” Perry continued in his letter. “But the continued loss of baseload generation with on-site fuel supplies, such as coal and nuclear, must be stopped. These generation resources are necessary to maintain the resiliency of the electric grid. Failure to act expeditiously would be unjust, unreasonable and contrary to the public interest.”
Asked for comment, FERC spokeswoman Mary O’Driscoll said only, “We have received the proposal and are reviewing it.”
DOE’s proposed rule would require RTOs and ISOs to implement market rules that allow the generators with a minimum 90-day fuel supply on site “full recovery of costs.”
“These resources must be compliant with all applicable environmental regulations and are not subject to cost-of-service rate regulation by any state or local authority,” Perry said. “The rule requires the organized markets to establish just and reasonable rate tariffs for the full recovery of costs and a fair rate of return.”
Analysts at ClearView Energy Partners said Perry’s action makes it likely that some method of compensating “essential reliability services” (ERS) could be in place in RTO markets by next spring, “although we caution that it may differ from the NOPR and reflect substantive variations across regions.” NERC has described ERS as including frequency and voltage support, and ramping capability.
“In our view, DOE has placed the essential reliability services issue at the top of FERC’s near-term electric agenda (even though we thought FERC might be leaning that way anyway). We also believe this rulemaking pushes consideration of the non-peak pricing proposal sketched out by PJM and other general price formation rulemakings aside between now and December, at least, should FERC hit DOE’s aggressive timeline.”
Industry Reaction
Predictably, Perry’s order sparked widely divergent reactions.
Maria Korsnick, CEO of the Nuclear Energy Institute, praised what she called Perry’s “decisive … remarkable action,” which she said addresses two “fundamental problems” in the electric sector.
“One is markets that fail to value everything that is important to our electricity system. … Our pricing system is badly broken and … is based almost entirely on short-term price. As a result, nuclear reactors, which provide benefits that everyone agrees we need, find themselves struggling to survive when the nation needs them most,” she said.
“The other problem is that electricity is essential to modern life but only gets noticed if the electricity fails to flow, as has happened most recently in Texas, Florida and Puerto Rico. It is taken for granted, and it does not command the attention it needs from policymakers all across the nation. This course needs to change.”
“We commend Secretary Perry for initiating a rulemaking by FERC that will finally value the on-site fuel security provided by the coal fleet,” said Paul Bailey, CEO of the American Coalition for Clean Coal Electricity. “The coal fleet has large stockpiles of coal that help to ensure grid resilience and reliability. We look forward to working with FERC and grid operators to quickly adopt long overdue market reforms that value the coal fleet.”
The American Wind Energy Association said Perry’s proposal “would upend competitive markets that save consumers billions of dollars a year.”
“The best way to guarantee a resilient and reliable electric grid is through market-based compensation for performance, not guaranteed payments for some, based on a government-prescribed definition,” said Amy Farrell, AWEA’s senior vice president for government and public affairs.
“This looks like federal cost-of-service regulation, and a major retreat from competition in electricity,” said Rob Gramlich, a consultant who worked for AWEA for several years after serving as an aide for former FERC Chairman Pat Wood III.
Mary Anne Hitt, director of the Sierra Club’s Beyond Coal campaign, said the NOPR ignores FERC’s role as an independent agency.
“The Federal Power Act clearly states that FERC cannot favor one energy source over others in its rulemakings, and Perry’s ask — without evidence or common sense — seeks to prop up dangerous coal and nuclear plants that can no longer compete in the wholesale market,” she said. “We are prepared to take to court any illegal rule that props up dirty fossil fuel plants or weakens clean energy’s market access.”
Graham Richard, CEO of Advanced Energy Economy, said FERC should reject what he called a “Perry Energy Tax” on consumers.
“Simply put, this proposed rule has something for everyone to dislike. If you’re a believer in competition and free markets, this rule would insert the federal government squarely into the middle of market decisions. If you are driven by keeping energy costs low, this rule would impose higher energy costs on consumers for no tangible benefit by forcing electricity customers to pay to keep uneconomic power plants in operation,” Richard said. “Finally, if you are driven by innovation and technology, this rule purposefully puts a thumb on the scale for existing, century-old technology at the expense of modern advanced energy that is currently winning based on price and performance.”
RTO Response
ISO-NE spokesman Matthew Kakley said the RTO was reviewing the NOPR while it completes work on a fuel security study. “New England’s wholesale markets have been competitive and brought forward the resources necessary for reliable operations. With the region’s resource mix evolving, ISO New England is conducting an operational analysis of fuel security risks under a range of potential resource scenarios, and we plan to release the study results next month.”
SPP spokesman Derek Wingfield said the RTO was awaiting FERC’s response to the NOPR. “As always, we remain committed to partnering with DOE, FERC and others in our industry to ensure our markets and other services are designed to protect our nation’s electricity infrastructure,” he said.
CAISO is aware of the NOPR and will continue working “with state and federal energy regulators and stakeholders to maintain and strengthen grid resiliency and reliability,” said spokesman Steven Greenlee.
PJM, NYISO and MISO all said they were reviewing the directive.
“As you can imagine, with this just out, we’ll need time to review, analyze and understand,” said PJM spokesman Ray Dotter.
Vogtle Guarantees
While Perry’s NOPR is intended to preserve the current nuclear fleet, his approval of additional loan guarantees is intended to ensure that hopes for a new generation of units are not crushed under the weight of Vogtle’s delays and cost overruns. Vogtle Units 3 and 4 are the first nuclear plants to be licensed and begin construction in the U.S. in more than three decades.
“I believe the future of nuclear energy in the United States is bright and look forward to expanding American leadership in innovative nuclear technologies,” Perry said. “Advanced nuclear energy projects like Vogtle are the kind of important energy infrastructure projects that support a reliable and resilient grid, promote economic growth, and strengthen our energy and national security.”
Rory D. Sweeney, Jason Fordney, Peter Key, Amanda Durish Cook, Tom Kleckner and Michael Kuser contributed to this story.
AUSTIN, Texas — DeAnn Walker will chair her first open meeting of the Public Utility Commission of Texas on Thursday after her recent appointment, which couldn’t come at a busier time for the commission.
Walker | Courtesy DeAnn Walker
The Sept. 28 agenda includes an update on Hurricane Harvey restoration efforts, consolidated dockets related to a proposed swap of transmission assets between Oncor and Sharyland Utilities, and Lubbock Power & Light’s request to move its load from SPP to ERCOT.
The PUC is also in the midst of rulemaking projects to improve price formation in ERCOT’s energy-only market, reliability-must-run service and determining rate case procedures for transmission and distribution providers.
And then there’s Sempra Energy’s $9.45 billion bid to acquire Oncor, the state’s largest utility. A federal bankruptcy court has already approved Sempra Energy’s purchase of Oncor and its bankrupt parent, Energy Future Holdings, but the California company must still gain the PUC’s approval. (See Bankruptcy Court Advances Sempra Bid for Oncor.)
The commission has rejected two previous acquisition attempts by Hunt Consolidated and NextEra Energy.
Texas Gov. Greg Abbott last week announced Walker’s appointment as PUC chair to replace Donna Nelson, who stepped down in May. Walker, who served as a senior policy adviser to Abbott on regulated industries, will fill out the remainder of Nelson’s term, which expires in September 2021. (See Texas PUC Chair Nelson Stepping Down.)
Commissioners Ken Anderson and Brandy Marty Marquez have kept the three-seat PUC running while waiting on a new chair. Anderson has served on the commission since September 2008 — a record tenure — though his term expired Aug. 31. Marquez’ six-year term expires in September 2019.
Walker returned to the PUC on Sept. 21, after previously working at the commission from 1988 to 1997 as an assistant general counsel and then as an administrative law judge. She spent 15 years at CenterPoint Energy as director of regulatory affairs and as an associate general counsel, before joining Abbott’s staff.
Walker is a member of the State Bar of Texas. She received her bachelor’s degree from Southern Methodist University and her law degree from the South Texas College of Law.
CAISO and Pacific Gas and Electric have asked FERC to reconsider its decision last month to approve only some of the utility’s requested transmission rate incentives related to more than $1 billion in planned grid improvements.
The ISO and the utility on Sept. 25 filed separate requests for FERC to rehear a determination that PG&E had not justified all of its proposed “abandoned cost” recovery, which allows it to recover from its customers the costs of abandoning construction for reasons beyond its control. (See FERC Approves PG&E Transmission Cost Recovery.)
Timeline and cost of PG&E’s proposed projects | PG&E
PG&E in its rehearing request called the incentive request “narrowly tailored” and said it faces significant challenges in developing the greenfield projects that are not in an existing right of way (EL16-47). The utility had requested 100% recovery of costs for any of the eight projects if they are abandoned, but FERC approved incentives for only three of them. The utility said it has already invested $68 million in construction and that the projects face risks, including environmental permitting, siting authority and potential impacts of from California’s renewable energy goals.
“Consequently, under a rigid application of the effective-date limitation imposed in the orders under review, PG&E now faces an unexpected risk of loss equal to 50% of that initial $68 million investment,” the company said, adding that “if allowed to stand, this outcome will create a disincentive for PG&E to make similar investments in the future.”
PG&E said that while the requested incentives would allocate to ratepayers 100% of the risk of abandonment for reasons beyond a utility’s control, “FERC’s orders here shift 50% of that risk for a defined period (before the issuance of a project specific declaratory order) to the utility and its shareholders. This reallocation makes investment in new transmission projects riskier and less attractive.”
CAISO’s filing contended that each project meets FERC’s standard because it was approved by the ISO as part of a regional planning process and that “CAISO approved these specific projects to meet identified reliability needs on the CAISO system.” Project sponsors such as PG&E have an obligation to obtain approvals and rights if the projects are approved as part of the ISO’s annual transmission planning process.
CAISO said it has canceled other projects approved in annual plans and that it is currently assessing whether to cancel other previously approved projects, so “the risk of abandonment is not hypothetical.” When developing its 2015-2016 plan, the ISO canceled 13 PG&E low-voltage transmission projects it had previously approved.
Southern California Edison on April 7 filed a similar request for abandoned cost recovery upon which the commission has yet to rule (EL17-63). The petition requested approval of incentives for a package of transmission improvements totaling about $1.3 billion, approximately $903 million of which are recoverable in transmission rates.
While the California Public Utilities Commission had objected to PG&E’s incentive rate request, FERC rejected the state regulators’ arguments about PG&E’s transparency and cost control.
Earlier this month, FERC in a different proceeding also rejected a protest from the PUC over incentive rate adders the commission had approved for PG&E in 2016. (See FERC Upholds PG&E ISO Incentive Adder, Rebuffs CPUC.)
