In 1879, Thomas Edison patented the incandescent light bulb. For more than a century, the incandescent bulb and its upscale offspring, the halogen bulb, have reigned supreme.
Huntoon
The reign is ending. Light-emitting diode (LED) lighting is replacing Edison lighting.
Here’s a question: How much more impact is rooftop solar having on retail electric sales than LED lighting?
It’s a trick question. Rooftop solar has had less impact on retail electric sales. LED lighting already has reduced annual retail electric sales by 30 billion kWh. Rooftop solar has reduced annual retail electric sales by 14 billion kWh.
But it’s the future that’s really interesting. The U.S. Energy Information Administration’s latest study forecasts LED lighting over the next 20 years to reduce annual retail electric sales by 300 billion kWh under a “current path” and by 435 billion kWh under a more aggressive path.[1] Rooftop solar over the next 20 years is expected to reach 100 billion kWh annually.
Let’s think about that. For all the attention given rooftop solar as environmental boon, new age investment and regulatory flashpoint, the LED bulb is three times more significant.
And three times more significant for electric utilities. Lighting represents 15% of retail electric sales. Over the next 20 years, half of those lighting sales will disappear, perhaps three quarters under a more aggressive path. Those electric vehicles better show up soon.
And what if Haitz’s Law — the LED parallel to Moore’s Law — continues, such that the cost per lumen keeps falling by a factor of 10 every 10 years? The LED is just another form of semiconductor. The substitution could be even more rapid.
Even at today’s cost per lumen, Edison lighting is much more expensive on a life-cycle basis than LED lighting. Much, much more expensive.
A General Electric soft white 60-W Edison bulb can be had in quantity purchase for $1.30, and rated to last for 1.4 years based on an average use of three hours per day. A GE soft white 60-W equivalent LED bulb can be had in quantity purchase for $3, use 10 W and last for 13 years based on the same average. So over 13 years, Edison lighting would cost an extra $9 for the bulbs and an extra $78 for the electricity (at 11 cents/kWh).[2]
Bottom line: Rooftop solar may be all the rage, but just changing light bulbs makes a bigger dent in emissions from combusting fossil fuels. And saves money to boot. Doing good and doing well.
Watt’s in your socket?
Steve Huntoon is a former president of the Energy Bar Association, with more than 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 of Energy Counsel LLP.
[1] You won’t find these forecasts in EIA’s “Annual Energy Outlook 2016,” which forecasts a lighting consumption decline of only 28% from 2015 to 2040 (Figure IF3-3). Instead the forecasts are derived from EIA’s specialty study “Energy Savings Forecast of Solid-State Lighting in General Illumination Applications” (September 2016) and require interpolating from Tables 4.2 and Figure 4.2, and converting from British thermal units to kilowatt-hours and from source to sink.
[2] Edison lighting also costs more for the incremental air conditioning in the summer to combat the heat from the bulb. (Generally, this extra cost is more than the incremental heating savings in the winter.)
CARMEL, Ind. — MISO will conduct three new separate, but related, studies this year that could identify a transmission solution for the RTO’s constrained interface between its North and South regions.
The efforts include a market congestion planning study, which is part of MISO’s 2017 Transmission Expansion Plan (MTEP 17), as well as a footprint diversity study and regional transmission overlay study.
Any of the reports could produce a replacement for, or supplement to, the seven-year transmission use settlement between MISO and SPP that limits flows between MISO North and South.
While the trio of studies share modeling and assumptions, each has a different scope, Arash Ghodsian, MISO manager of economic studies, said at a Jan. 18 Planning Advisory Committee meeting. He added that he didn’t know which study might produce a feasible project.
MISO’s Eric Thoms said the congestion and footprint studies would identify project candidates in the third quarter. However, the lengthier regional transmission overlay study, which is expected to determine long-term transmission needs at the end of this year, will not identify prospective projects until the study is concluded in 2019.
The footprint study is the only effort specifically designed to “identify potential mitigation plans to increase the interface capability” between MISO North and South, Ghodsian said. That study will be completed at the end of this year in concert with the MTEP 17 market congestion planning study, which will focus on MISO South.
Project candidates emerging from the congestion planning study will be selected at the September PAC meeting, Ghodsian said. “If we have a good enough solution for transmission needs, we’ll stand by it,” regardless of what study produces it, he said.
None of the studies would result in a revised settlement with another RTO, he noted.
MTEP 19 Will Probe Demand Response, Efficiency Programs
MISO is already putting together pieces for MTEP 19 in the form of a demand response and energy efficiency study.
The RTO said the third-party study is a “refresh” of a similar 2014-15 report and will provide a 20-year forecast for DR, energy efficiency and distributed generation and “their associated costs to install in MISO and the Eastern Interconnection.” Work on the study should run through December, and the RTO said it will conduct quarterly stakeholder workshops related to the subject, with the first scheduled for Feb. 24.
Applied Energy Group, the consulting firm responsible for the 2014-15 study, has been retained to perform the analysis.
Rao Konidena, MISO adviser of energy efficiency, said the RTO recognizes that energy efficiency and DR programs are administered by states and will respect state jurisdiction by simply collecting data on savings from programs while refraining from analyzing any specific program.
MISO has admitted that there is a “gap” the DR and energy efficiency data it requires of load-serving entities and what gets reported, leading to a modeling disadvantage.
MISO will file with FERC to remove transmission service request (TSR) redispatch study options from its Tariff, citing market-based dispatch as the more efficient option.
A TSR reserves transmission capacity in the market and the redispatch option is added if a transmission customer has also purchased redispatch service. The transmission provider attempts to relieve system constraints by redispatching its resources, and the option requires MISO to identify which nearby generators — even ones external to MISO — can be redispatched to mitigate transmission constraints.
According to MISO’s Tariff, a TSR with a redispatch option is not eligible for financial transmission rights or auction revenue rights, unlike regular TSRs, making the option unappealing.
Paul Muncy, of MISO’s transmission access planning division, said market-based dispatch would take the place of TSR redispatches. Although TSR dispatches are still offered, MISO currently has no confirmed TSRs that use a redispatch option, and the study option should have been eliminated long ago, he added.
According to MISO, the current TSR redispatch option is burdensome, requiring customers to sign a contractual financial agreement with generation owners in order to use a subset of units and agree on an operating procedures guide between generation owners, impacted transmission operators and MISO.
The RTO said that when it dispatches around congestion, implementing the TSR-related operating guides “would take away from normal market-driven dispatch implementation and reduce market transparency, adding burden to [the] market system and settlement system.”
“It’s not only cumbersome, but it detracts from market efficiency,” Muncy said.
Some stakeholders have wondered if there is any harm in just retaining the language in the Tariff, but MISO compliance staff responded that keeping dead language in the Tariff is not a zero-cost option because the RTO must work to update the procedures in place behind the language.
Improvements Sought for Competitive Transmission Process
MISO will convene a Competitive Transmission Task Team to improve its competitive transmission selection process, aiming to complete a FERC filing on the matter sometime after October.
Brian Pedersen, MISO senior manager of competitive transmission administration, asked for stakeholder feedback on every aspect of the competitive process — from qualification to MISO’s communication — to begin the effort.
“We want to pop our heads up and ask how well we’ve done,” he said.
Stakeholders should also think about how to streamline the process in cases where MISO is dealing with multiple competitive transmission projects at the same time, Pedersen said.
“This is definitely a substantial undertaking,” he said. “We need to think about how to stagger that, scale it.”
MISO also reflected on the breadth of proposed projects stemming from its first request for proposals. The RTO said the process resulted in a “variety of innovative and novel cost caps, concessions and commitments … taking advantage of the freedom to develop new ways to compete on cost” and the annual transmission revenue requirement within the developer selection process.
Pedersen said an “extraordinary amount” of resources and innovation went into project proposals.
“It definitely was an instruction in innovative thinking and competitive spirit,” Pedersen said.
The RTO is moving ahead on voluntary meetings with developers that were not chosen.
MISO has also opened its 2017 prequalification window for organizations seeking to become a qualified transmission developer. Interested parties must be a MISO member and submit a transmission developer application — along with a $20,000 application fee — before Feb. 6.
In December, LS Power subsidiary Republic Transmission was awarded the Duff-Coleman 345-kV transmission project, the RTO’s first competitive project under FERC Order 1000. The company will construct two substations and a 28.5-mile line in Southern Indiana and Western Kentucky. Republic will deliver quarterly updates to MISO throughout 2017 on the progress of the $49.8 million project. (See LS Power Unit Wins MISO’s First Competitive Project.)
Minimum Design Requirements Task Team Retired
MISO has retired the Minimum Design Requirements Task Team upon conclusion of the group’s work, PAC Chair Cynthia Crane said.
A first version of Business Practices Manual 029, which governs minimum design requirements for competitive projects, was implemented last January. A second version of the manual, detailing a set of ratings that transmission projects will be required to meet, is slated to be released this spring.
Crane said future improvements to BPM 029 will be funneled through the upcoming Competitive Transmission Task Team.
DALLAS — SPP stakeholders last week spent the remains of a meeting cut short by weather-related travel problems discussing staff and member solutions to the RTO’s Z2 crediting process.
In the end, the Z2 Task Force came no closer to a solution to the albatross and decided to schedule monthly meetings in an effort to reach an April deadline for recommending improvements.
The task force was established last August and had hoped to present its findings to the Board of Directors and Markets and Operations Policy Committee in January or April of this year.
“We knew six months was aggressive,” said Bruce Rew, SPP’s vice president of operations and the group’s staff secretary.
Stakeholders drilled down into two of the six options first presented by SPP staff in November: “reverse engineering” of the Z2 process and using incremental long-term congestion rights (ILTCRs). (See Z2 Task Force Looks at Incremental Congestion Rights.)
The task force also reviewed a proposal from Westar Energy that suggested modifying SPP’s generator interconnection process and transmission service requests and incorporating financial hedging instruments. Westar also proposed revising the Tariff so that any proposed sponsored projects would be studied for inclusion in the planning process and possible selection for Tariff funding.
That suggestion did not seem to gain much traction with stakeholders.
Grant pointed out that Westar’s plan would result in a separate process to secure annual revenue rights or transmission congestion rights. “I want to get back to being simple and not doing anything more than we need to do, because that’s what got us into trouble,” he said.
Under the SPP Tariff’s Attachment Z2, staff is responsible for assigning members financial credits and obligations for sponsored upgrades. However, staff had not applied the credits for years dating back to 2008, complicating the task of trying to accurately compensate project sponsors and claw back money from members who owed debts for the upgrades.
Kansas City Power & Light’s Denise Buffington, who chairs the task force, noted that each discussion on Z2 unearths new information previously unknown to the group.
“We’re still trying to figure out what the universe looks like, and how to rate it,” she said last week.
Staff’s reverse-engineering proposal would remove short-term TCRs (less than one year) from the crediting process, although short-term revenues have declined substantially since the start of SPP’s Integrated Marketplace. A second proposal over the long term would implement a standard credit payment rate for all creditable impacts, including both network and point-to-point reservations, should the Z2 process be terminated.
SPP also suggested using its current ILTCR process as a cost-recovery mechanism for upgrades with directly assigned upgrade costs (DAUC). To be eligible for the ILTCRs and megawatt capacities, upgrades would have to be sponsored with DAUC, create additional available transfer capability on a specific path and be the outcome of a study request.
“With Z2 credits, there’s no question whether or not they’re given,” said NextEra Energy Resources’ Aundrea Williams. “With ILTCRs, there’s no certainty they’ll be awarded. Z2 is the byproduct of a formula. There’s still a possibility of not getting them as part of the auction. You would have to look at the overall pool of who gets what and what’s eligible for a” generator interconnection.
Oklahoma Gas and Electric’s Greg McAuley suggested another option: not completely disregarding the “do-nothing option.”
“I don’t like Z2 either, but if there’s enough confusion with these [proposals], I still think there’s a problem,” he said. “It’s like the devil you know. We know this devil, and until we’re sure that we have a viable option that isn’t just as complex, or more so, we shouldn’t dismiss the do-nothing option out of hand.”
FERC last week rejected Vote Solar’s request that the commission reconsider its decision not to enforce the Public Utility Regulatory Policies Act against Montana regulators (EL16-117-001).
Vote Solar petitioned FERC in early December after the dismissal of its first complaint, which alleged that the Montana Public Service Commission violated the federal law when it allowed NorthWestern Energy to suspend its tariff for solar qualifying facilities pending an updated rate review. (See FERC Rejects Complaint on Montana Solar; 2nd Case Pending.)
FLS Solar’s Fairmont Solar Farm in Fairmont, NC | FLS Solar
The Montana PSC issued the suspension last June after the utility argued that QF rates for solar producers were 35% above avoided costs and that the 130 MW of planned solar projects in the utility’s service area would place an undue burden on ratepayers.
The solar advocacy nonprofit said that NorthWestern was seeking to “undermine” PURPA and renewable generation.
The commission reiterated that it cannot direct the Montana PSC to take any action because state regulators are not FERC-jurisdictional public utilities subject to the Federal Power Act. The commission also said Vote Solar did not have standing to petition for enforcement because it was neither an electric utility nor a QF.
The commission rejected Vote Solar’s contentions that FERC has the authority to issue a declaratory order against the Montana PSC through the Administrative Procedure Act and that the commission can bring an enforcement action pursuant to Section 210 of PURPA based on the nonprofit’s complaint.
By granting Vote Solar’s request, the commission said it would be acting ultra vires — beyond its authority.
Furthermore, the commission maintained that its choice not to act against the PSC is backed by the Supreme Court, which “has established the general rule that an agency’s decision not to exercise its enforcement authority, or to exercise it in a particular way, is committed to its absolute discretion” under circumstances when their enforcement is not legally mandated.
“Because there is no legal requirement here to commence an enforcement action, there is thus no decision subject to legal error,” the commission said. “Although Rule 206 of our Rules of Practice and Procedure permits ‘any person’ to file a complaint with the commission, our regulations cannot grant us more authority than the statute grants us.”
Vote Solar said that FERC’s original dismissal created a “framework wherein the commission can only take action against a state regulatory authority when asked to do so by a regulated party … [and] leaves the public without a path to seek relief from the commission when state regulatory authorities fail to implement PURPA properly and places the burden on electric utilities, qualifying cogenerators and qualifying small power producers as the only entities that can seek enforcement action.”
The commission countered that Vote Solar is already an intervenor in a similar, separate complaint against the Montana PSC by North Carolina-based solar developer FLS Energy (EL17-5).
“Our dismissal of Vote Solar’s complaint here did not foreclose Vote Solar’s public participation in our proceedings,” FERC said.
DALLAS — SPP’s Mike Ross told the Strategic Planning Committee last week the industry can expect a future with less federal intervention under President Trump’s administration.
Ross, SPP’s senior vice president of government affairs and public relations, and a former six-term Democratic congressman from Arkansas, said he expects Trump to quickly issue an executive order withdrawing from the Paris Agreement on climate change.
“I believe the Clean Power Plan will be rolled back through whatever kind of legal thing they need, from executive order to rescinding the rule to simply not funding the [EPA]. Overall, I think you’ll see less regulation,” Ross said. “Everything in our industry will be regulated a lot less and pushed back to the states.”
Ross said he expects Trump’s opposition to the CPP to result in the delay of some coal plant retirements but not in new generator construction. “Quite frankly, I don’t think many companies are going to be spending millions of dollars to build a new power plant based on who the new president is,” he said.
He said he expects Congress to pursue legislation on cybersecurity and to review the Federal Power Act and RTO capacity markets. He also said there is some talk of FERC revisiting Order 1000.
Bloomberg reported last week that Trump will tap Commissioner Cheryl LaFleur as chairman of the commission, replacing Norman Bay.
FERC currently has three Democrats and two vacancies, but it will shift to a 3-2 Republican majority under Trump, so LaFleur’s appointment could be temporary.
Although Ross didn’t name names, he said potential appointees include those “who knew SPP very well and have been involved with SPP.”
“She’s pro-coal,” he said of Honorable, who previously chaired Arkansas’ Public Service Commission. “The last coal plant in America [AEP subsidiary Southwestern Electric Power Co.’s John W. Turk Jr.] was built in Arkansas, and she voted for it.”
Audrey Zibelman, chair of the New York Public Service Commission since 2013, is headed to Australia to lead the operator of that country’s largest gas and electricity markets.
In a press release late Sunday — Monday morning in Australia — the Australian Energy Market Operator said Zibelman will become its CEO on March 20. Zibelman’s last meeting heading the NYPSC is scheduled to be on March 16 in New York City.
Then living in the Philadelphia area, Zibelman was appointed by Gov. Andrew Cuomo as PSC chair in 2013. She was tasked with shepherding the state’s Reforming the Energy Vision initiative, which was unveiled in 2014.
Prior to joining the NYPSC and founding Viridity Energy, a demand response and demand management provider, she was the chief operating officer of PJM from 2004 to 2007 and held various utility and regulatory positions before that. She is the wife of former PJM CEO Phil Harris.
“Audrey’s vast experience in creating and managing new wholesale electricity markets, and transforming existing energy markets and large power systems will further strengthen the work that AEMO has undertaken to support Australia’s energy industry transformation,” Anthony Marxsen, AEMO board chair, said in a statement.
“Audrey has the vision to lead, guide and support our organization and the broader Australian energy industry as we transition our energy markets and reform power systems planning and management.”
Melbourne-based AEMO is responsible for operating Australia’s largest gas and electricity markets and power systems, including the National Electricity Market and interconnected power system in Australia’s eastern and south-eastern seaboard, and the Wholesale Electricity Market and power system in Western Australia.
Zibelman succeeds acting CEO Karen Olesnicky, who has held that title since the death of AEMO’s founding CEO, Matt Zema, in July 2016.
“I am forever grateful to have played a part in bringing the governor’s highly lauded vision of a clean-energy economy to fruition,” Zibelman said in a statement. “Thanks to the governor’s leadership, New York state is on a pathway to achieve 50% renewable electricity by 2030 and create an affordable, clean and resilient power system for all New Yorkers. It has been an immense privilege to work with my colleagues in the governor’s office, on the commission and the dedicated, capable Department of Public Service staff.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, was dismayed by the news.
“PSC Chair Audrey Zibelman and New York’s energy team have made our state a national and global model for the 21st century energy grid. Her leadership in reforming utility regulation, the promotion of distributed generation and public participation testify to her lasting contribution. Her departure will be a real loss for New York state,” Reynolds said. “But Gov. Cuomo has a very strong energy team and vision, and we assume the administration’s sharp focus on modernizing and decarbonizing the grid will continue with Audrey’s replacement.”
Her departure leaves the PSC even more short-handed than it already is.
Former Chair Garry Brown left the commission in February 2015 and was not replaced. Last month, longtime commissioner and former chair Patricia Acampora said she would retire after the Feb. 16 commission meeting.
That would leave only two current members, Gregg Sayre and Diane Burman on the five-member panel. Their terms expire Feb. 1, 2018.
Sayre, a former telecommunications assistant general counsel from the Rochester area, was appointed in 2012.
Burman, chief counsel to the New York State Senate Republican Conference before her appointment to the PSC in 2013, is often the lone dissenting vote in commission meetings.
Rocco LaDuca, spokesman for Senate Energy and Telecommunications Committee Chair Joseph Griffo, said the senator is aware of the pending vacancies. “The [Republican caucus] will be having discussions in the days and weeks ahead to determine how to move forward. They are mindful of the commission’s responsibility to conduct its business, but there’s still time until March to address this issue,” he said.
Commissioners are appointed to six-year terms and are paid $109,800 annually. The chair has a $127,000 salary.
WASHINGTON — FERC last week proposed regulations intended to reduce uplift, allocate it more accurately and increase transparency (RM17-2).
The Notice of Proposed Rulemaking — the fourth issued by the commission in its ongoing price formation initiative — is premised on a preliminary finding that current RTO and ISO practices regarding reporting of uplift payments and operator-initiated commitments are unjust and unreasonable.
“The allocation of uplift costs should, to the extent possible, encourage behavior that will reduce the need for uplift-creating actions and avoid discouraging market participant behavior that lowers total production costs (i.e., enhances efficiency),” the commission said.
Lack of Transparency
“The lack of transparency regarding uplift and operator-initiated commitments, which can cause uplift, hinders market participants’ ability to plan and efficiently respond to system needs,” the commission said. “Market participants may lack the information necessary to evaluate the need for and value of additional investment, such as transmission upgrades or new generation. Also, without sufficient transparency, market participants may not be able to assess each RTO’s/ISO’s operator-initiated commitment practices and raise any issues of concern through the stakeholder process.”
Generators receive uplift payments when their production costs exceed their energy and ancillary services revenues. Last week’s order focuses on one of the main causes of uplift: deviations between the day-ahead and real-time market that can force operators to commit additional units. This can result from generators delivering less energy in real time than their day-ahead offers or real-time loads exceeding expectations.
Balancing charges (canceled resources, generators, imports, load response, local constraints control and lost opportunity cost) were responsible for 59% of all uplift in the first nine months of 2016 in PJM. The top 10 generators received 35.4% of all uplift and the top 10 organizations received 77% during the period. PJM’s Independent Market Monitor has long advocated disclosing the recipients of uplift payments, something that FERC’s recent NOPR would require monthly.
Although all RTOs and ISOs use some form of beneficiary pays or cost-causation principles to allocate uplift, their methods “vary significantly, both in terms of granularity and the exemption of certain types of transactions,” the commission said. “The definition of what precisely constitutes a deviation also varies across RTOs/ISOs.”
Some RTOs also fail to consider how deviations affect uplift costs. “Deviations from day-ahead market schedules that create the need for additional resource commitments in real-time tend to increase real-time uplift costs. On the other hand, deviations can also contribute to the convergence of the day-ahead and real-time markets,” the commission said.
“Allocating costs to deviations that did not cause the costs to be incurred may inappropriately penalize certain types of transactions that are beneficial to price formation,” the Office of Energy Policy and Innovation’s Stanley Wolf said in a presentation at Thursday’s commission meeting, which was closed to the public because of concerns about disruptions by anti-pipeline activists.
‘Helping’ and ‘Harming’ Deviations
The NOPR requires RTOs and ISOs to separate uplift costs assigned to deviations into at least two categories based on their causes: congestion management or systemwide capacity, a catch-all for any other deviations made to meet the system’s energy needs. The commission said categorization would ensure the costs are allocated more precisely to the participants that caused the uplift. The NOPR gives RTOs flexibility to create additional categories.
Grid operators would also be required to distinguish between deviations that help or harm their systems. Generators would be assigned uplift costs based on the net of their “harming” deviations — the total amount of deviations minus their “helping” deviations.
FERC said that any actions generators take in response to dispatch instructions should not be considered deviations. Also excluded would be transactions economically evaluated by RTOs in real time, such as the coordinated transaction scheduling between PJM and its neighbors NYISO and MISO.
The commissioners said they were inclined to exclude instructed deviations from the “help” category but asked for stakeholders’ comments on the issue.
RTO Requirements
The commission also proposed several requirements to increase transparency into uplift cost allocation and the decision-making of grid operators, noting that while all RTOs and ISOs release some information, “there is significant variation in the timing, granularity and types of data released.”
RTOs and ISOs would be required to:
Report total uplift payments for each transmission zone, separated by day and uplift category;
Report total uplift payments for each resource monthly;
Report megawatts of operator-initiated commitments in or near real time and after the close of the day-ahead market, broken out by transmission zone and the reason for the commitment; and
Define in their tariffs the transmission constraint penalty factors, how those factors can set LMPs and the process by which they can be changed. Transmission constraint penalty factors are the values at which an RTO will relax the flow-based limit on a transmission element to relieve a constraint rather than re-dispatch resources.
“The proposed transparency reforms will help market participants understand the operational constraints on the system, plan and efficiently respond to system needs, and evaluate the need for and value of additional investment,” FERC said.
“While uplift is not constituting a large proportion of total costs and is unavoidable to some extent, I think RTO/ISO stakeholders and the commission should strive to minimize uplift when and where possible because uplift is unhedgeable, lacks transparency and, if not allocated properly, can encourage inefficient behavior,” Chairman Norman Bay said.
The NOPR only addresses uplift costs incurred because of deviations. RTOs may also pay uplift for reliability reasons, such as stand-by costs, or inaccurate load forecasting.
“We note that the commission is not proposing to require RTOs/ISOs to allocate any amount of uplift costs to deviations; rather we are simply proposing reforms to uplift cost allocation to deviations to the extent an RTO/ISO chooses to allocate some uplift costs to deviations,” FERC said.
Comments on the NOPR are due no later than 60 days after its publication in the Federal Register.
Previous orders in the commission’s price formation initiative concerned fast-start resources, shortage pricing and the alignment of settlement and dispatch intervals and a doubling of the “hard” energy offer cap. (See FERC: Let Fast-Start Resources Set Prices.)
WASHINGTON — Energy storage facilities should be permitted to provide multiple services and earn both cost- and market-based revenue streams, FERC said last week in a policy statement clarifying its prior rulings on the issue.
AES Laurel Mountain in Elkins, WV | AES
“Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers,” the commission said in the statement, which was approved on a 2-1 vote (PL17-2).
The commission said that storage resources, which can switch from providing one service to another almost instantaneously, may not be cost competitive without multiple revenue streams.
Chairman Norman Bay and Commissioner Colette Honorable said their position is supported by most of those who testified at the commission’s technical conference Nov. 9 or provided comments afterward. “Commenters believe that the key question is not whether to allow multiple-use applications for electric storage resources but how to allow and enable such applications,” they said. (See FERC Panelists Debate Storage Uses, Compensation.)
Bay and Honorable said the statement was needed to address “potential confusion” over FERC precedent in two previous rulings.
Commissioner Cheryl LaFleur dissented. LaFleur wrote that she agreed that the “commission should be flexible and open to proposals that go beyond the model contemplated” in the prior orders but said the issue should have been considered as part of the Notice of Proposed Rulemaking the commission issued Nov. 14. (See FERC Rule Would Boost Energy Storage, DER.)
Precedents
In the 2008 Nevada Hydro case, the commission rejected a request by the owner of the Lake Elsinore Advanced Pumped Storage project that its resource be classified as a transmission facility under CAISO’s control, with its costs recovered through the ISO’s transmission access charge (ER06-278, et al.).
The commission sided with the ISO, which said that its independence would be compromised because it would have to decide when the facility would operate, how much energy it would produce and when it would operate the pumps to store water.
In the 2010 Western Grid ruling, the commission allowed storage facilities to be classified as transmission assets receiving cost-based rates for providing CAISO voltage support and thermal overload protection. The ruling was conditioned on the operator’s promise to forego any sales into the ISO’s wholesale electric markets (EL10-19).
The commission noted in its ruling that Western Grid would be responsible for maintaining the state-of-charge on the projects. CAISO’s independence would be maintained because it would not be responsible for buying power to energize the projects or for operating the charge and discharge of the batteries, the commission ruled.
“That order was limited to the facts that Western Grid presented to the commission,” FERC said last week. “Thus, that order should not be read to require other entities to forgo market sales as Western Grid proposed. We clarify that there may be approaches different from Western Grid’s approach under which an electric storage resource may receive cost-based rate recovery and, if technically capable, provide market-based services that may address these concerns.”
Implementation Issues
This commission said the policy statement “is not intended to resolve the detailed implementation issues surrounding how an electric storage resource may concurrently provide services at cost- and market-based rates. Rather, it is intended to clarify that providing services at both cost- and market-based rates is permissible as a matter of policy, provide guidance on some of the details and allow entities to address these issues through stakeholder processes and in filings before the commission.”
It said future requests by storage operators must ensure that:
Storage resources receiving cost- and market-based rates do not over-recover their costs at the expense of ratepayers;
Storage resources earning cost-based rates do not suppress competitive prices in the wholesale markets, which could harm competitors without cost-based revenues; and
The RTO/ISO’s level of control of the storage resource does not jeopardize its independence from market participants.
Double Recovery
The commission said concerns over double recovery can be addressed by crediting cost-based ratepayers for market-based revenues. It said the commission’s accounting rule in Order 784 and the requirement to submit Electric Quarterly Reports “provide sufficient transparency to allow effective oversight for any needed revenue crediting.”
As an alternative, the commission said, a resource’s market-based revenues could reduce the revenue requirement used in its cost-based rate.
Protecting Competition
Bay and Honorable said they did not share the concern of commenters who fear that allowing storage to receive multiple revenue streams could suppress market prices and undermine competition. They noted that some generators with market-based rates also receive cost-based rates for providing reactive service.
“Similarly, some vertically integrated public utilities make cost-based rate sales to captive wholesale requirements customers such as transmission-dependent utilities while also making off-system market-based rate sales to others,” the commission said. “If we were to deny electric storage resources the possibility of earning cost-based and market-based revenues on the theory that having dual revenue streams undermines competition, we would need to revisit years of precedent allowing such concurrent cost-based and market-based sales to occur.”
In her dissent, LaFleur said she disagreed with Bay and Honorable’s “sweeping conclusions.”
“The policy statement summarily dismisses concerns regarding the impact of such arrangements on market competition and leaves far more than just ‘implementation details’ to be worked out,” she wrote. “Indeed, the policy statement provides no guidance on how the commission could evaluate whether a particular filing under Section 205 of the Federal Power Act successfully avoids adverse market impacts.”
RTO Independence
The commissioners acknowledged that storage resources must maintain the necessary state of charge to provide their cost-based services when called on by the RTO.
“But, assuming this priority need is reasonably predictable as to size and the time it will arise each day, the electric storage resource should be permitted to deviate from this state of charge at other times of the day in order to provide other, market-based rate services,” the statement said. “In situations where this premise does not hold … the cost-based rate service may be the only service that the electric storage resource could provide.”
The statement also said that RTO dispatch of storage resources to provide cost-based service should take priority over the resource’s provision of market-based services. Performance penalties could be imposed on resources that fail to deliver when called on, it said.
“We further provide guidance that the provision of market-based rate services should be under the control of the electric storage resource owner or operator, rather than the RTO/ISO, to ensure RTO/ISO independence. In other words, while the RTO/ISO always performs the actual optimization of resources participating in the organized wholesale electric markets, during periods when the electric storage resource is not needed for the separate service compensated at cost-based rates, the RTO/ISO would rely on offer parameters provided by the electric storage resource owner or operator for such operation, just as the RTO/ISO does with other market participants.”
LaFleur’s Concerns
In addition to her procedural concerns, LaFleur said she worried that the policy statement “could be read to reflect the commission’s views about the impact of multiple payment streams on market pricing more generally, thus implicating broader regional discussions on state policy initiatives and their interaction with competitive markets.”
“These issues, which are currently being discussed by several RTO/ISOs and their stakeholders, will require careful and holistic consideration to ensure that policy advancements can be achieved while the benefits of competition are preserved for customers,” she said.
“Storage is an important and promising resource that warrants commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions. However, efforts to accommodate these resources should not come at the expense of careful market design after full public participation.”
FERC on Thursday approved a final rule on recovering from balancing contingency events and proposed a second rule to ensure that remedial action schemes do not compromise reliability.
Recovery from a Balancing Event
The final rule approves NERC reliability standard BAL-002-2, which seeks to ensure that balancing authorities and reserve sharing groups can use reserves to balance resources and demand to recover from system contingencies and restore their area control error (ACE) to pre-contingency levels (RM16-7).
| MISO
In response to opposition from NERC, the Edison Electric Institute and most RTOs and ISOs, the commission backed off from a proposal that would have required reliability coordinators to authorize extensions of the 15-minute ACE recovery period.
In its Notice of Proposed Rulemaking in May, the commission said it was unclear how an entity would prepare for a second contingency during the extension under NERC’s proposal. A balancing authority operating out-of-balance for an extended period of time is “leaning on the system” by relying on external resources, which could affect other entities within an interconnection, the commission said.
EEI and the RTOs said that the requirement “would result in unnecessary duplication of requirements adding no tangible benefit to reliability while needlessly increasing the compliance burden.”
Instead, the commission’s final rule adopts a proposal by Arizona Public Service requiring only that an entity that is unable to recover ACE because of a second disturbance inform the reliability coordinator and provide it with a recovery plan.
The commission also approved NERC’s proposal that demand-side resources that are technically capable be included as contingency reserves.
Remedial Action Schemes NOPR
The commission also approved a NOPR backing NERC reliability standard PRC-012-2, which is designed to ensure that remedial action schemes (RAS) do not introduce “unintentional or unacceptable” reliability risks (RM16-20).
The standard defines an RAS as a plan to detect abnormal system conditions and automatically take corrective actions — such as tripping generation or load, or reconfiguring a system — to maintain stability and limit the impact of cascading events.
The NOPR also would withdraw pending standards PRC-012-1, PRC-013-1 and PRC-014-1 and retire standards PRC-015-1 and PRC-016-1.
The commission solicited comment on a proposed clarification that the new standard will not supersede system performance obligations under reliability standard TPL-001-4, which limits “non-consequential load loss” to 75 MW for certain contingencies.
Rehearing Denied on GMD Rule
FERC also rejected rehearing requests by EEI and others on its September order requiring grid operators to assess and protect against the threat of geomagnetic disturbances (RM15-11-001). (See FERC Approves GMD Reliability Standard.)
EEI had challenged the standard’s (TPL-007-1) implementation plan, saying it failed to account for the impacts of changes to the definition of a benchmark GMD event.
The commission said EEI’s concern was “premature.”
“At this time, the commission has no way of knowing what impacts the modified benchmark GMD event definition may have on the approved implementation plan because NERC has not yet developed or proposed a revised” definition, FERC said. It added that NERC may propose a longer implementation plan if needed as a result of a revised definition.
In FCA 10 last year, ISO-NE used two zones: Rest of Pool, which comprises Connecticut, Vermont, New Hampshire, Maine, and western and central Massachusetts; and Southeastern New England (SENE), which includes Northeast Massachusetts/Greater Boston and Southeast Massachusetts/Rhode Island.
FCA 11 (2020/21) and FCA 12 (2021/21) will be conducted in four zones: Southeast Massachusetts/Rhode Island, which includes Greater Boston; Northern New England, which includes Maine, New Hampshire and Vermont; Connecticut; and Rest of Pool, generally central and western Massachusetts.
“Most major transmission projects are already certified,” Al McBride, director of transmission strategies and services, told the Planning Advisory Committee last week, meaning the RTO has determined they will be operational in time for the capacity commitment period.
As they go into service, additional portions of the Greater Hartford/Central Connecticut and Southwest Connecticut transmission project will be included in the Connecticut zone. The project is expected to be completed in 2019.
Likewise, resource retirements are unlikely to have significant impact on the zones. “Our modeling show that even if they occur, it is not likely to change the boundaries,” he said.
New Study Looks at Less Maine Wind, More Offshore
Integrating renewable resources close to load centers in the Southeast Massachusetts/Rhode Island area could be more cost effective than tapping large volumes of wind in Maine, according to a new high-level transmission cost analysis presented to PAC members last week.
Renewable energy advocacy group RENEW requested an additional analysis in which large amounts of renewable resources, primarily onshore wind in Maine as outlined in scenario 2, were changed to incorporate a more diverse mix of renewable resources spread over wider geographic areas.
Under scenario 2, Maine wind injections were assumed to be 12,872 MW in 2030, with 1,219 MW of offshore wind in Southeast Massachusetts and Rhode Island. In scenario 6, the Maine wind has been cut by more than half to 5,959 MW, with offshore wind boosted to 5,370 MW.
Even that smaller amount of Maine wind could require a complete overhaul of the AC power system, system planner Marianne Perben said.
Instead, renewable resources would be tied directly into several HVDC connectors connecting the wind integrator system to a hub in Millbury, Mass. Scenario 2 assumes a need for 9,043 MW of congestion relief, while scenario 6 envisions a need for 3,596 MW.
Splitting offshore wind resources between Connecticut, Rhode Island and Southeast Massachusetts could alleviate the need for a congestion relief system for those resources, planners said.
The analysis found that offshore wind could be imported without the need for congestion relief if it were sited off of Connecticut, Rhode Island and Southeast Massachusetts. That would allow the resources to take advantage of interconnections vacated by about 4,400 MW of resources close to the coastline that are expected to be retired by 2030: the Pilgrim nuclear plan, Millstone Unit 1, Montville Units 5 and 6, Brayton Point Units 1 through 4, and Canal Units 1 and 2.
“Under this … assumption, the cost to integrate renewable resources (excluding plant collector and interconnection system costs) in scenario 6 would be driven exclusively by the cost of integrating Maine onshore wind resources and would be significantly reduced, as compared to scenario 2,” the RTO said.
Renewable collector and interconnection system (left) and approximate path of HVDC congestion relief system (right). | ISO-NE
In scenario 2, the total Maine congestion relief system would cost an estimated $20 billion; in scenario 6, the price tag is estimated at $8 billion.
The estimates do not account for individual plants’ interconnection costs or potential costs from the challenge of managing large volumes of renewables during off-peak periods, the RTO said.
ISO-NE Recommends Against Keene Road Project
Staff told the PAC it is recommending the RTO not move forward on the Keene Road transmission project.
In December, staff told the committee that increasing export limits from the current 165 MW to 195 MW would save only $1.35 million to $1.38 million (2015 $) in energy production costs. (See ISO-NE Study Sees Little Savings from Keene Road Tx Upgrade.)
Written comments are due to PACmatters@iso-ne.com by Feb. 17. The RTO will report its final decision at the March or April PAC meetings.
Streamlined Regional System Plan due this Summer
ISO-NE staff is preparing a streamlined regional system plan for unveiling in the summer.
The document, which had become an unwieldy 200 pages, will come in at about 50 pages, said Michael Henderson, director of regional planning and coordination. Instead of duplicating sections of other RTO documents, links will be provided.
In response to stakeholder feedback, the plan will be produced every other year. It had formerly been produced annually.
It will include forecasts of gross load, energy efficiency and behind-the-meter photovoltaics and projections of systemwide need for capacity and reserves, along with transmission system needs.
A draft will be posted for PAC review on July 7, with comments and reviews scheduled throughout the summer. The final document will be presented at a public meeting on Sept. 14.
