WILMINGTON, Del. — PJM again deferred a vote on the grid operator’s proposed pseudo-tie pro formaagreement last week after stakeholders complained that revisions were not made public until the night before the Markets and Reliability Committee meeting.
“While I agree you’ve read the documents [during presentations at previous meetings], I don’t agree that you’ve read the same documents … so, in a sense, they’re multiple first reads,” American Municipal Power’s Steve Lieberman said. “People are trying to keep up with the speed at which you’re making changes, but it’s difficult.”
CFO Suzanne Daugherty, who chairs the MRC, agreed to the delay. She said the late changes reflected language PJM and MISO had agreed to just two days prior to the meeting.
PJM had postponed a vote on the agreement at the May MRC meeting, citing ongoing negotiations with MISO, which had been reluctant to sign PJM’s proposal. (See “Pseudo-Tie Discussion Postponed to Continue Negotiations with MISO,” PJM Markets and Reliability Committee Briefs.)
PJM’s Jacqui Hugee said the RTO resolved its issues with MISO by incorporating language into their Joint Operating Agreement obviating the need for the grid operators to agree to each other’s pseudo-tie rules. MISO has filed its own agreement at FERC and isn’t requesting approval from other grid operators or balancing authorities, she said. Other balancing authorities, including Duke Energy, the Tennessee Valley Authority and SPP, have been willing to sign PJM’s agreement.
“Whether [the unit is being tied] into PJM or into MISO, the same rules are going to apply,” she said.
Some stakeholders, including Independent Market Monitor Joe Bowring, remained concerned about language that suggested that the native balancing authority (BA) would control redispatch of pseudo-tied resources in certain situations, including non-emergencies.
Hugee said the language complied with NERC standards. Mike Bryson, PJM’s vice president of operations, explained that the RTO would maintain control during performance assessment hours and resources would be rewarded or penalized like any other resource under Capacity Performance requirements. In other situations, the native BA would set certain operating limits, scenarios that are also addressed in PJM’s existing market-to-market flowgate procedures, he said.
“If PJM is experiencing an emergency and MISO is experiencing an emergency at the same time, MISO — according to NERC standards — has the authority to dispatch that resource because it’s in their balancing authority. So what will happen is that resource will probably be penalized because they’re not available to PJM during that performance assessment hour, assuming PJM would have called on them,” Hugee said. “Everybody knows that’s a risk they take before they pseudo-tie.”
“That means that a pseudo-tied unit is not really equivalent to an internal unit, which is what the issue has been all along,” Bowring responded. “I could certainly imagine someone arguing that they shouldn’t have to pay a penalty because they were following NERC procedures and following dispatch instructions.”
“They can argue it, but we have a provision that says if you are a Capacity Performance resource and you’re not there when we call on you, you’re going to get a penalty,” Hugee said. “The same Capacity Performance rules apply to everybody, whether you’re physically internal or you’re tying into PJM from another balancing authority.”
PJM also incorporated in the agreement a provision allowing it to suspend a resource. If the RTO intends to cancel an agreement, it likely won’t want the tied unit operating during the 60-day notice period for cancellation, Hugee said. She also introduced an accompanying agreement for dynamic scheduling but said that will be brought for vote at a later meeting.
AMP’s Lisa McAlister asked how the agreement will affect collecting congestion charges from the resource to the RTO border and if it resolves the double-charge issue. Hugee said that topic isn’t being addressed in the current agreement and that it will be filed in concert with MISO as JOA revisions in a separate docket at FERC. PJM believes the congestion charge filing is likely to be challenged as there are already five pending complaints on the issue, Hugee said. The RTO hopes the filing on agreements will not be challenged and may win commission approval even without a quorum.
Hugee said that, while the Tariff and JOA revisions for the agreement will require separate dockets, PJM wants to file all of them contemporaneously and have them reference each other.
“The plan is to file one big packet because I’d like to resolve everything at once, and it makes sense to do it that way,” she said. “We [would] … explain to FERC that it’s very important that all of these things get approved [together] … so that we can alleviate that concern about getting out of sync of one getting approved and the other not getting approved.”
Hugee said that if the agreement needs to be “tweaked” for individual units, she would ensure it remains in accordance with the JOA.
Carl Johnson, representing the PJM Public Power Coalition, was the first to suggest deferring the vote. He said he couldn’t vote in favor of the package at the meeting because some of his members hadn’t yet reviewed the current version of some of the documents, but that he “probably could get to a point where we could support it” by the MRC’s July meeting. Lieberman said AMP also couldn’t vote in favor of the changes at the meeting. He said it is still attempting to figure out how PJM handled the revisions it had recommended, which it couldn’t find in the current versions.
Hugee said PJM and MISO have committed to filing the agreement with FERC by July 27, the same day as the next MRC meeting.
“Maybe we’ll have to ask them for a couple of days,” Daugherty said, then announced that PJM would be deferring the vote until the July MRC and Members Committee meetings.
WILMINGTON, Del. — An informational update on PJM’s Transmission Replacement Processes Senior Task Force at the end of the Markets and Reliability Committee meeting last week turned into a hotly contested debate and impromptu vote.
The result was that the task force is still on target to resume on July 28. It has been on hiatus since an MRC vote in September, about a month after PJM and Transmission Owners received an order to show cause from FERC to determine whether the TOs are complying with their local transmission planning obligations for supplemental projects under Order 890. The hiatus, requested to focus on responding to the show cause order, was extended until July at the February MRC. (See FERC Orders PJM TOs to Change Rules on Supplemental Projects.)
In his presentation, PJM’s Fran Barrett noted the “predominate desire” of TOs to continue the suspension of the task force and transmission customers’ “uniform desire” to lift resume task force meetings.
The TOs filed their initial response to the show cause order on Oct. 25 and followed up with responses to comments on its filing a month later. The TOs insisted their Operating Agreement already complies with Order 890 but proposed a Tariff amendment providing additional detail regarding the process for planning supplemental projects (EL16-71).
FERC assured the order would be finalized by January, according to Barrett. But the commission didn’t rule on the TOs’ response before losing its quorum in February.
“We’re locked in the horns of an MRC-directed process versus a FERC-directed process, and we’re looking for guidance for how to take that forward,” he said.
Chris O’Hara, PJM deputy general counsel, stressed that the RTO doesn’t have approval authority over TO supplemental projects. “PJM is ready to engage on these topics. However, that engagement might be more productive after FERC takes action on” the situation, he said.
Representatives of several TOs — including Public Service Enterprise Group’s Alex Stern, PPL’s Frank “Chip” Richardson, Exelon’s Gloria Godson and Duquesne Light’s Tonja Wicks — all advised that they would attend task force meetings once the hiatus has ended, but they likely will not be able to make many decisions until the FERC action is resolved. The circumstances that precipitated suspending the task force in the first place haven’t changed, they said.
Godson motioned to continue the hiatus, and Stern offered a friendly amendment to extend it until FERC rules on the issue and reconsider options if nothing has changed by December. “I don’t think our attorneys would sanction our involvement under a show cause order,” Stern said.
Carl Johnson of the PJM Public Power Coalition said he appreciated the “intellectual honesty,” but that he would oppose the motion because there are other issues on which the task force could be productive. Susan Bruce, representing the PJM Industrial Customer Coalition, and American Municipal Power’s Lisa McAlister also opposed the proposal.
“AMP thinks there’s valuable work to be done [before] a FERC order,” McAlister said. “We’re getting a piecemeal change process that’s the result of, frankly, AMP being a very squeaky wheel. … We don’t think that’s the best procedural way for making these changes.”
American Electric Power’s Dana Horton said there are plenty of other issues to focus on at PJM that aren’t under the auspices of a show-cause order. He supported extending the hiatus so stakeholders don’t have to waste time on unproductive discussions. “We don’t want to expend resources to just look at each other,” he said.
The motion to extend the hiatus failed with 1.79 in favor in a sector-weighted vote that had a 3.335 threshold for passage.
WILMINGTON, Del. — The PJM Markets and Reliability Committee on Thursday endorsed a plan to change compensation in the RTO’s regulation market, despite howls from some market participants that units would be shouldered with more work while receiving less pay.
PJM’s Eric Hsia said the changes resulted from staff observation that the RegD, fast-responding signal would sometimes move in the opposite direction of the area control error, exacerbating the frequency regulation problem.
Additionally, many resources were self-scheduling into the market, which amplified the response to the signal, he said. Howard Haas, the Independent Market Monitor’s chief economist, later added that the current market design incentivizes self-scheduling to receive surplus payments.
PJM and the Monitor developed a package of revisions to the market that received 75% approval from the Regulation Market Issues Senior Task Force. The package would, among other revisions, replace the “mileage ratio” portion of the regulation performance credit, which proponents say doesn’t correctly compensate RegD and causes load to overpay for the service. Hsia noted that discrepancy also contributed to the oversupply issue.
In connection with the task force, PJM produced a new regulation signal and requirements that were implemented on Jan. 9. (See “New Regulation Rules Improving ACE Control,” PJM Operating Committee Briefs.)
Transitioning to the revised signals could drive the value of RegD compensation to zero, Hsia said, so the package includes a minimum “regulation rate of technical substitution” (RRTS) value of 0.65 for the first 12 months of implementation and 0.5 for the following 12 months. The RRTS terminology would replace the previous “benefit factor.”
“Really, what we’re trying to do there is ensure that there is going to be compensation even though there will be oversupply,” he said.
Tom Rutigliano, representing the Energy Storage Association, argued that PJM’s plan omits necessary changes. He urged stakeholders to defer voting on the package until it includes greater detail on regulation providers’ obligations, how resources’ physical limitations will be incorporated into the signals and how the metric that replaces the mileage ratio will be calculated.
“We feel the Tariff language seeking endorsement today is unacceptably vague on several key market features,” he said.
The revised regulation signal changed a longstanding, material market rule that the RegD product energy neutral, Rutigliano said. Making the change without revising the Tariff bypasses FERC review in violation of the Federal Power Act, he said. Ten unaffiliated organizations built about 285 MW of storage designed to charge and discharge equally in a 15-minute time frame, he said, but the new signal implemented on Jan. 9 has no firm energy limit and substantially changes performance requirements. Analysts at ICF say the neutrality requirement means that during steep ramp-up or ramp-down hours, RegD resources alone will not be adequate; thus RegA resources will set the market clearing price.
“This is an entire industry that received clear guidance [on] their performance obligations, invested hundreds of millions of dollars in single-purpose machines to meet those obligations and, frankly, had the rug pulled out from under them,” he said. “We are asking that no participant in this market should have that happen to them without getting their day at FERC.”
Hsia had noted earlier that PJM has been working with market participants to address some issues created by the new signal. He said instances of resources being asked to follow a signal for more than 15 minutes dropped to just two in the first half of June. No resources were asked to follow a signal for more than 30 minutes.
The package of revisions will also change how regulation payments are calculated, all without being codified in the Tariff. Rutigliano called this an “unprecedented” situation “where you have what is essentially an administrative pricing curve, and that curve is left entirely to the RTO’s discretion.”
Speaking on behalf of client Beacon Power, Gabel Associates’ Gabbi Hudis said the revisions “have those resources performing additional work while receiving significantly less compensation than the RegA resources.”
“I can appreciate the desire to get this right,” said Gabel Associates’ Mike Borgatti, representing client NextEra Energy. The rule changes are “significant” for some market participants, he said, and neglecting to include them in the Tariff set “an unhealthy precedent.” Additionally, FERC’s lack of quorum means it’s unlikely that delaying the vote a few months will significantly impact how soon the commission will consider the issue, he said.
Haas said all of Rutigliano’ s concerns were discussed by the RMISTF and that FERC orders established the RTO’s authority to make changes to the regulation signal and the rate-of-substitution curve.
“What we’re seeing here in terms of the PJM/IMM proposal is the result of all of those discussions, and those discussions led to ‘we need to fix this issue,’” he said. “We can hold off and continue to talk about this forever, or we can take this proposal to the commission. ESA wants this issue to be in front of the commission. Allowing the PJM/IMM proposal to go forward will allow [that] to happen. … I think that’s the appropriate place to take this.”
Susan Bruce, representing the PJM Industrial Customer Coalition, agreed that the decision should now be in FERC’s hands. “These issues are now before FERC, and we would like to move the PJM/IMM package to allow that to occur because, in our view, currently customers are overpaying relative to the benefit that they’re receiving, so we want to make sure that that doesn’t continue,” she said.
“Something isn’t right about what we’re paying for regulation right now,” the PJM Public Power Coalition’s Carl Johnson said in agreement. “If we do defer [a vote], we risk just taking even longer before we get to a solution on the market side.”
Calpine’s David “Scarp” Scarpignato added that the current processes also harm resources that provide the traditional, slower RegA service. Exelon’s Jason Barker also voiced support for the revisions package.
Proponents of the deferral attempted to negotiate for a specific deadline for making a FERC filing, but Bruce and Johnson were skeptical that additional, more-focused debate — “this time, for reals,” as Bruce put it, invoking youth slang — would produce any better results.
“It’s hard to know whether or not there’s the prospect of consensus,” she said. “It seems like that conversation’s happened, and there’s not consensus. I’m not sure what more could be done to get there in the next two months.”
Many other provisions that affect resources aren’t included in the Tariff to that level of detail, Scarp said, but that’s a separate conversation that goes beyond regulation rules.
“I don’t think all stakeholders are in agreement that all of this should even go in the Tariff,” Scarp said. “If we put every similar provision in the Tariff, instead of being 6-inches-thick, it would be 6-feet-thick.”
Bob O’Connell of Panda Power Funds warned that moving the language into the Tariff instead of the Operating Agreement would shift control away from stakeholders to PJM. He later proposed developing a manual specific to the regulation market that aggregates in one place the market rules currently embedded in multiple manuals.
“If that is what the stakeholders want, I encourage you to move forward with the motion to defer,” he said. “If you don’t want that, if you want to continue to retain some voice in the process other than just an advisory voice, I recommend that you move forward with the RMISTF package and figure out a different way to address how to get the changes you’d like to see changed worked into the Tariff.”
Borgatti made the motion to defer the vote, but it failed, receiving 1.61 in favor in a sector-weighted vote that had a threshold of 3.335 for passage.
John Horstmann of Dayton Power & Light reiterated disapproval with the revisions package that he’s expressed previously, calling it “the final nail in the coffin” for anyone who built to the 15-minute standard.
“It’s very disappointing that this can occur basically unilaterally,” he said. “If we build you [PJM] a one-hour battery today, could the same thing happen a year or two down the road that you want a two-hour battery? Unfortunately, the signal it sends … is that PJM’s a pretty risky place to do business because you really don’t have a lot of rights when it comes to rule changes. … I’ve heard an awful lot of reasons why this is such a wonderful process that got us to this point, but largely, the small number [of] owners that are hugely impacted have been pretty much stonewalled through the process.”
Stakeholders approved the revisions package with a 3.89 sector-weighted vote.
CHICAGO — The Mid-America Regulatory Conference last week drew an above-capacity assembly of public utility regulators, legal counsel and other industry insiders to the shores of Lake Michigan. Registration was initially capped at 550, but 62 more attendees signed up for a conference that featured panel discussions on cybersecurity, energy storage, artificial intelligence and other challenges facing regulators.
Acting FERC Chairman Cheryl LaFleur addressed the commission’s lack of a quorum during her keynote, saying there’s been a “little bit of a plot twist” in D.C.
LaFleur sits in the chairman’s seat for the third time in seven years following Norman Bay’s departure in February, which also left FERC without a quorum. LaFleur is one of only two remaining on the five-person commission. Commissioner Colette Honorable has announced she will not seek a second term when her current one expires June 30. (See Honorable: Leaving FERC, but not Sure When.)
While Honorable has not said how long she might stay on, LaFleur made clear she intends to finish her term, which expires in June 2019. In the meantime, LaFleur and Honorable await the arrival of recent appointees Robert Powelson and Neil Chatterjee, who still await Senate confirmation.
“This will add a line to my obituary and hasten its appearance,” said LaFleur, noting that one of her staffers has grown a “quorum beard” similar to hockey playoff beards.
“And it’s really quite shaggy.”
Orders awaiting a final ruling are piling up. FERC’s regular monthly open meeting is still on the calendar for July 20, but it is expected to be canceled. The commission doesn’t meet in August, meaning FERC might not conduct its second open meeting of the year until late September.
“We’re trying to triage [the orders],” LaFleur said. “We’re assessing the comments, and we’ll frame the issues for the new commissioners. Since we’ll [eventually] have four new commissioners, it’s not for me or Colette to say which way we’ll go.”
In the meantime, the commission is keeping an eye on price formation (“It’s important to send clear and concise signals.”), energy storage (“We’ve gotten a pretty strong signal there’s a lot of work on that.”) and the “issue du jour” — the interplay between wholesale markets and state policies.
“We’ve seen a decoupling of what resources are being built and invested in, driven by federal tax policies and state policies,” she said, citing as examples CAISO’s curtailment of solar and hydro energy, and efforts by SPP and MISO to integrate more than 20 GW of wind energy.
“The states are not satisfied with the resources markets are choosing for them,” she said. “They are subsidizing some resources [nuclear units in New York and Illinois] and requiring utilities to buy resources. Are we going to let the markets choose, or the states choose?
“I always say there are three basic values: what is the cost, the reliability and the environmental impacts? The markets weren’t set up to take the environmental impact into account. They would have to be redesigned,” LaFleur said.
She offered three solutions to the problem: 1) redesign the markets to allow the states to become the “resource payer and selector,” but set a market for nonsubsidized resources and allow the markets to price in carbon; 2) litigation, as is taking place in Illinois and New York; and 3) changing how states handle resource adequacy.
“I’m fine with that,” LaFleur said, “as long as we do it on purpose, and don’t tumble into anything by accident.”
Southern Diversifies
With 46 GW of generating capacity and vast natural gas assets, Southern Co. bills itself as “America’s premier energy company.” But like others in the industry, the utility is weaning itself off coal.
“Carbon is a big issue around the world,” Southern CEO Tom Fanning said during a “fireside chat” with Ellen Nowak, chair of the Wisconsin Public Service Commission. “We have to think about ways to transition our fleet in a responsible way, while balancing the issues of clean, safe, reliable and affordable energy. The transition to that is a big, big deal.”
The company plans to add 1,900 MW of renewable resources, along with 1,000 MW of nuclear capacity and 500 MW of “21st century clean coal.” Its wholesale subsidiary, Southern Power, has added or announced more than 2,400 MW of new capacity from renewable resources and more than 1,400 MW of natural gas capacity since 2010.
Before Fanning arrived at Southern in 1980, the company’s generation was 70% reliant on coal. Coal still made up 67% of the resource mix in 2002, but that number dropped to 31% last year. Natural gas meanwhile increased from 11% to 47%, while renewables now account for 5% of the portfolio.
“It’s all part of our long-term strategy. We really wanted to be long on gas,” Fanning said. “It was clear to us the transition of the fleet had to occur.”
To that end, Southern in recent years acquired a 50% equity interest in Kinder Morgan’s Southern Natural Gas pipeline and created the nation’s largest natural gas-only distribution company by merging with AGL Resources.
“One of the keys to success in building this portfolio of the future is the notion of infrastructure creating options,” Fanning said. “It gives you the scale to withstand stormy seas. Who would have predicted Westinghouse [Electric] would have gone bankrupt?”
Southern and Westinghouse recently reached an agreement to complete two units as part of the troubled Vogtle nuclear plant expansion. Whether the construction is ever completed remains to be seen, but Southern will continue to diversify its portfolio.
“[The U.S.] has the ability to set policy based on the notion of abundance,” said Fanning, who co-chairs the Electricity Subsector Coordinating Council, an advisory board to the federal government. “One of the challenges we saw in the last presidential election was that so many people are viscerally losing faith in the institutions of government and the people running them. We in the industry have to step into the middle and get rid of the red and blue.
“I’m one of the optimists. At the end of this decade, we can easily be net energy exporters, creating wealth, creating a better experience for everybody. We have the public-private partnerships to grow the finances of the states we serve. I believe we can make a difference.”
A panel of Midwest commission chairs agreed that state legislators and regulators will continue to set energy policy direction regardless of what happens in D.C.
Nancy Lange, chair of the Minnesota Public Utilities Commission, said the state’s long-time fuel mix of coal, natural gas, nuclear, Canadian hydro and wind energy is changing in the face of modest load growth (less than 1%). Each of Minnesota’s three investor-owned utilities are adding more wind generation to the mix, driving out coal in the process.
“It’s not because of policy but because of price,” Lange said. “Minnesota utilities are still offering coal as a must-run resource, but they’re on the margin in some cases, and that’s led to some of the retirements we’ve seen. The interesting thing about coal is some of the coal units are not operating as baseload units in the market, largely because they’re not clearing the market price.”
The Illinois Commerce Commission’s Brien Sheahan said renewable energy and energy efficiency will earn 70% of the economic benefits flowing from the Future Energy Jobs Bill, approved in December, which includes zero-emission credits for nuclear plants.
“Some have estimated that at $12 [billion] to $15 billion,” he said. “It’s not just about supply. … It’s really about energy policy and getting the state to lower carbon in the future. Whether we continue to have [a] leadership position depends on what the courts do and what FERC does. There was a lot of discussion at the FERC technical conference about accommodation, harmonization or mitigation. Some of [FERC’s] proposals lean to mitigation too strong.
“Markets exist to serve state purpose. They don’t exist in and of themselves,” Sheahan said.
DTE Energy announced recently that it would phase out coal by 2030, accelerating what the Michigan Public Service Commission’s Sally Talberg called a “fundamental transition in [the state’s] energy supplies.” She said the slow pace of energy policy decisions at the federal level makes it difficult for state regulators and planners to find certainty.
“Often, by the time an investment is made, you get a court ruling,” Talberg said. “Regardless of what we see at the federal level, states are taking the initiative. Naturally, they’re looking at cleaner suppliers. It does provide us the opportunity to move to cleaner and more efficient resources, such as natural gas.”
Nowak pointed to the difficulty of assessing a social value for various fuel resources, asking, “Why are we pricing just wind and solar?
“I’ve always struggled with choosing just one resource to apply that to,” she said. “We don’t do it for nuclear, and we don’t do it for gas. What’s the social benefit for coal? It provides jobs. Nuclear is carbon-free. … Are we going to put social value on that?”
“The [legislative] directive to look at externalities and the social cost … is a very difficult thing for our commission to grapple with,” Lange said. “As these [distributed energy resource] valuations and methodologies move along … we think of them as supply resources and not social resources. Not having to add on that externality piece, which some legislators added on because of some imperative they want to take … will have the carbon fee showing up as costing less in [integrated resource planning] scenarios.”
The staid, hidebound grid operator, with its granular focus on engineering models and studies, has seldom been an attractive landing place for America’s brightest young students. Acronyms like PJM and MISO don’t carry the same cachet as Apple, Google or Microsoft.
However, that is changing quickly, agreed a panel of RTO leaders.
“When I first joined SPP, I kept hearing about this guy, Doug,” said Paul Suskie, an Arkansas commissioner before joining the RTO in 2011. Eventually, Suskie, SPP’s executive vice president of regulatory policy and general counsel, came to learn that “Doug” actually stood for Dumb Old Utility Guy.
No more.
“One of the benefits we have … in the industry is we are kind of cool now,” ERCOT CEO Bill Magness said. “That’s hard to get used to. They see how we integrate wind and solar on the system and how we’re developing markets for the future. They’re introducing us to other students as, ‘They’re doing cool stuff.’ Our mission, to a lot of younger employees, is a very critical thing. We’re doing something that’s important and needs to be done.”
Asked how MISO markets to the younger generation when it can take 10 years to build a transmission line, CEO John Bear said, “Once we bring them into the control room and show them what we’re up against and where we’re headed in the future, that’s very exciting for them.”
They’ve “significantly changed our working environment,” Bear said. “Our offices look more like Starbucks than they did before. That, and the issues we are trying to solve are very intriguing to millennials. They love the mission of the RTOs. They’re not looking to go to Wall Street, but helping people who can’t look out for themselves.”
MISO’s internship program currently brings in 30 to 50 students each cycle. Of course, not all students wind up with a job, Bear said, “but they all go back and talk about what we’re doing. It’s word of mouth. We’re not a big brand, but the compounding effect is very high.”
PJM CEO Andy Ott extolled the virtues of his RTO’s Arc Program, an engineering development initiative designed to provide talent with “career-broadening opportunities.” Participants in the 36-month rotational program spend nine months apiece focused on core learning sessions for markets, system operations and planning.
“It not only gets people excited to work for PJM but improves our diversity,” Ott said.
A diverse team of PJM employees interviews roughly 60 college students a year, hiring only the top three, he said.
“It’s highly competitive. Over the past six years, nearly two-thirds of the candidates we’ve hired are diverse candidates. There’s no mandate. It just happened organizationally.”
Suskie said SPP has also “beefed up” its internship program and has reached out to historically black colleges. “The demographics of the industry are changing,” he said.
Energy storage proponents said battery technology and cost improvements make storage more commercially viable, but regulatory and policy actions still pose challenges.
“Energy storage and distributed generation all offer something we’ve never had in the utility industry before. It gives the customers the ability to choose,” said Betty Watson, senior manager of energy policy for Tesla. “Energy storage … is the ultimate streamlined technology. We now have the ability to react to what’s going on the grid. If you look at ways utilities are incentivized, they need to invest in infrastructure.
We’re talking about a technology that reduces the amount of money you invest [in infrastructure]. There are a lot of current opportunities under current existing regulations, but this technology will drive change in the industry,” she said.
“A market means an opportunity to earn a return on the work we do,” said John Fernandes, Invenergy’s director of regulatory affairs. “Developers are frequently told, ‘Well, show us something. We’d like to take a look at it.’ We need reassurance not that we will get selected, but assurance it’s not an exercise in regulation. It’s an opportunity to compete.”
“By the time someone publishes a cost for energy storage, it’s already improved by the time the ink dries. That’s how fast this market is moving,” pointed out Brent Bergland, general manager with Mortenson Construction. “By the time a report gets to the commissions, it’s old news. It took six months to create, but over six months, you might have a significant drop in the cost of services.”
“It’s up to us to keep the momentum going to understand the technology,” said Kiran Kumaraswamy, AES Energy Storage’s market development director. “Pilots waste years. If we’re making a decision on a study, we ought to be planning now.”
“My frustration with pilots is that they’re too narrow. It’s one location, one set of conditions,” Watson said. “We learned from renewables that when you expand the scope, expand regions and aggregate things, these conditions change. We need to get storage on the system and see how it interacts at multiple uses, so we can integrate it.”
As SPP and ERCOT continue to see periods when wind accounts for at least 50% of energy production — a share SPP predicts could reach as high as 60% — Beth Soholt, executive director of Wind on the Wires, sees no reason renewables couldn’t account for 35 to 40% of energy production at any time.
“I think that’s very doable,” said the Midwestern renewables advocacy group’s leader. “One of the greatest shifts we’ve seen is learning how to operate the system with much more wind. It’s not just technical issue, but a mind-changing issue that you can have a reliable system with a lot more variable generation. We’re seeing coal plants being ramped to the market [like intermittent resources]. I think utilities will get smart about their new role in the integrated market.”
Melissa Seymour, MISO’s executive director of customer and state affairs in the Central Region, said the RTO, which is dominated by vertically integrated utilities, could see between 23 and 41 GW of wind on its system by 2025, creating a greater need for transmission. Most MISO states are on track to meet or exceed their renewable portfolio standards, she said.
“Markets need to really incent the types of products the market needs,” Seymour said. “We have the same issues as we do with storage. Conversations with stakeholders are very important as we continue to grow. We have a lot of resources on the system that want to come offline. MISO is trying to ensure they can do this in a safe way. Enabling effective retirements is something we can do going forward.”
“Now is the time for states and the RTOs … to figure out ways to better coordinate the retail planning of the markets with the wholesale design of the market, optimizing clean-energy resources on the system, to ensure just and reasonable rates and prudently occurred costs, for the assets,” said John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council.
A panel focused on artificial intelligence and machine learning assured its audience there is nothing to fear as today’s smart grid gets even smarter. AI, which uses complicated algorithms to detect unseen patters, and machine learning, the ability of computers to learn without being explicitly programmed, simply enable utilities to use predictive analytics to forecast consumption, monitor assets to reduce outages and improve efficiencies across the grid.
“Artificial intelligence allows you to use a scalpel, rather than a sledgehammer, to make effective use of your dollars,” explained Anna Lising, senior manager of regulatory affairs for Oracle Utilities.
Jeff Gleeson, a product manager with Nest Energy Services, provided a real-life example with the Nest Learning Thermostat. Owned by Alphabet (parent company of Google), the Nest uses AI and machine learning hidden from the customer to yield more efficient results from their energy usage.
“The grid is getting more complicated. People’s usage needs to match the complexity of the grid,” Gleeson said. “We believe you don’t need to know the complexity. We want you to be comfortable. We’re working in the background … using artificial intelligence and machine learning behind the [thermostat]. The thermostat knows what your [time-of-use] rate is. It nicely corresponds to the grid’s challenges … the solutions are also getting more complex, but the good thing is, we can do it in certain ways that make it very easy.”
“The neat thing about artificial intelligence and machine learning is that it’s been used in the utility industry for over a decade,” said Sean Gregerson, a global director with Schneider Electric Software. “We’re ahead of the curve. Ultimately, machine learning is going to be used for self-healing grids … automatically healing grids that are under stress or failing in unforeseen ways.”
“It’s important for everyone to understand, this is not necessarily as complicated as it sounds. It’s heavily stats-based,” Gleeson said. “If you’re wondering whether the machines are coming for us, know machines have a hard time telling the difference between a plate of fried chicken or a picture of a poodle. If you see the pictures next to each other, you feel bad for the machine, because they look the same.”
There are also unforeseen drawbacks. Gregerson related a story about his children playing with Alexa, Amazon’s voice-responsive “intelligent personal assistant.” After his kids mistakenly signed up for a product agreement, Gregerson said he tried to undo the damage.
Alexa responded: “I’m sorry. I don’t understand that.”
ERCOT’s Technical Advisory Committee has canceled its June meeting because of a lack of voting items.
The TAC’s next scheduled meeting is July 27. The Board of Directors does not meet again until Aug. 8.
TAC Chair Adrianne Brandt, of San Antonio’s CPS Energy, asked committee members to vote by email on a pair of revision requests, setting a 5 p.m. deadline Wednesday for responses:
NOGRR170: Revises the Nodal Operating Guide to be consistent with NPRR824 language related to NERC Reliability Standards EOP-011-1 (Emergency Operations) and BAL-001-2 (Real Power Balancing Control Performance).
RRGRR014: Conforms the Resource Registration glossary to the as-built release, which captured baseline updates before the approvals of RRGRR006 and RRGRR007. The RRGRR adds solar resource registration inputs omitted from the greybox tab for RRGRR009.
New Hampshire regulators on Friday took the first step toward an overhaul of their net metering rules, reducing compensation for rooftop solar owners while ordering a study of the value of distributed generation that will inform long-term changes.
Solar Panels at Exeter High School
The Public Utilities Commission ordered utilities to implement a new alternative net metering tariff that retains monthly netting for small distributed generation system owners while moving to instantaneous netting for non-bypassable charges. The rules, “to be in effect for a period of several years,” will begin Sept. 1 (Order 26,029).
The commission chose a quasi-adjudicative process to reconcile two settlement proposals on how to develop and implement a new alternative net metering tariff, as directed by the state legislature last year in House Bill 1116.
Two Proposals
One settlement proposal came from a coalition of utilities and consumer parties (UCC), including Eversource Energy, Liberty Utilities, Unitil Energy Systems, the state Office of Consumer Advocate, the New England Ratepayers Association, Consumer Energy Alliance and Standard Power of America.
The other proposal was filed the same day by a coalition of distributed generation industry advocates and environmental organizations known as the Energy Future Coalition (EFC), which included the Acadia Center, The Alliance for Solar Choice, the Conservation Law Foundation and eight other organizations and companies (docket DE 16-576).
In its unanimous 74-page order, the commission ruled that:
Small customer-generators with renewable energy systems of 100 kW or less will continue to net meter their DG resources monthly. Those customer-generators will receive monthly net export credits equal to the monetary value of kilowatt-hour charges for energy service and transmission service at 100% and distribution service at 25% — a 75% reduction — while paying the full amount of non-bypassable charges, such as the system benefits charge, stranded cost recovery charge, other similar surcharges and the state electricity consumption tax. Previously, they received kilowatt-hour credits.
Large customer-generators will continue to be net-metered as they are currently but will also receive monetary credits rather than kilowatt-hour credits on a monthly basis. To qualify for alternative net metering, large customers must consume at least 20% of their actual or estimated annual distributed generation system electric production behind the meter.
DG systems installed or queued during the period the new net metering tariff is in effect will have their net metering rate structure grandfathered until Dec. 31, 2040.
Pilot projects will be proposed and a value of DER study will be designed and completed to “inform the development of the next version of net metering or another alternative regulatory mechanism.”
“As the penetration level of DG in the state is quite low in both absolute and relative terms, there is little evidence of significant cost-shifting from DG customers to customers without DG,” the commission said. “Payment of non-bypassable charges by all net-metered customers and a reduction in the distribution credit for net exports should serve to mitigate the potential for such cost-shifting, even if DG penetration levels increase significantly above their low levels.”
The commission said it accepted common elements in the two settlement proposals and resolved differences between them based on the legislative purposes of HB 1116. The bill called for “the continuance of reasonable opportunities for electric customers to invest in and interconnect customer-generator facilities and receive fair compensation for such locally produced power while ensuring costs and benefits are fairly and transparently allocated among all customers.”
The order requires Eversource, Liberty (Granite State Electric) and Unitil to file revised tariffs within 30 days. The commission also approved an automatic rate adjustment mechanism for the companies to recover lost revenue, under the process approved for Unitil in February (Order No. 25,991).
Value of DER Study
The order provides that the alternative net metering tariff take effect while the utilities and stakeholders collect further data, implement pilot programs and conduct a study on the value of DERs.
It directs stakeholders to convene working groups within 60 days to develop proposals on the commission’s mandates. It also requires them to file quarterly progress reports with the PUC. The order also gives concerned parties 30 days to submit written briefs or comments on grandfathering issues, such as the clause that “customer-generators that receive a net metering capacity allocation while the new alternative net metering tariff is in effect to be ‘grandfathered’ at the applicable net metering design and structure then in effect through Dec. 31, 2040.”
Reaction
“The ruling is a mixed bag,” CLF attorney Melissa E. Birchard said.
While the order is an overall win for the state because it sets a path forward to value the broad benefits of clean energy resources and accelerates grid modernization, Birchard said she was dismayed by the cut in the distribution credit.
“It is disturbing to see cuts to an important program like net metering at the same time that New Hampshire is lagging behind the rest of the region on solar penetration and energy efficiency,” Birchard said. “If we’re not careful, other states in the region are going to reap the financial benefits of strong solar and energy efficiency programs while Granite Staters pay more on their electric bill for a disproportionate share of the costs.”
Nashua, New Hampshire Dam
While the distribution portion of the credit is only one piece of the overall credit, “this cut is arbitrary in the sense that there was no real data in the docket to support it, and it will affect the pace of clean energy investments,” Birchard said.
Gradual Change
The commission said that an abrupt change from monthly netting to instantaneous netting would likely confuse customers and send potentially inefficient price signals.
“For example, instantaneous netting may be confusing to customers who lack real-time data about their electricity usage,” said the order. “It may also provide financial incentives for maximum on-site electric consumption during periods when the benefits of DG exports to the system may be greatest, such as at the time of late afternoon system peaks, thereby decreasing the potential system-wide benefits of those energy exports.”
Birchard believes the cuts in net metering will be temporary.
“There should be a new rate established after the commission carries out a value of distributed energy resources study, particularly distributed solar and hydro, and after that study it’s going to open a proceeding to revalue it,” said Birchard. “So the credits that those resources receive will be based on the broad benefits, potentially including climate change and health benefits. That kind of value-based rate can make clean energy innovation more competitive in an open market way so that different kinds of resources can compete with each other based on their value.”
California regulators last week advanced on a plan to study the potential for eliminating the Aliso Canyon natural gas storage facility.
The move came as Southern California Gas reiterated warnings about the impact of gas shortages on grid reliability this summer.
The state’s Public Utilities Commission issued a draft request for proposals to develop an “Aliso Canyon Reliability and Economic Analyses.” The central question to be answered, according to the draft: “should the commission reduce or eliminate the use of the Aliso Canyon storage facility, and if so, under what conditions and parameters, and in what time frame?”
The commission seeks public comment on the draft by June 29 and expects to issue the RFP on July 6. It is considering what elements of the proposal work or could be improved, if any important questions are missing and whether instructions are clear.
Location of Gas Leak at Aliso Canyon Natural Gas Storage Facility | SoCalGas
Injections into the 86 Bcf facility near Los Angeles have been halted since the leak was discovered in October 2015. The restriction was kept in place even after the leaking well was finally plugged in February 2016.
State Senate Bill 380 prohibited reinjection of gas into Aliso until completion of a safety review and required the PUC to determine whether use of the facility can be reduced or eliminated while still maintaining electric and gas reliability.
Winning bidders on the RFP will be required to hold stakeholder workshops and public hearings, as well as perform hydraulic model analysis of the reliability of the Aliso system under a variety of scenarios, using forecasted electricity demand and contribution of renewables to the generation mix.
The PUC is looking for bidders experienced with Synergi Gas software — or an equivalent — and working on gas-electric coordination. Also desired is a background running community forums and “developing models to assess the market, consumer and economic impact of significant changes to the natural gas or related markets.”
Bidders’ proposals are due on Aug. 24, and the contract award date is tentatively set for Sept. 29.
“From our perspective, we are cautiously optimistic that, based upon the CAISO forecast, we will be able to meet the demands on our system. Of course, this is dependent on there being no unplanned outages on either the electric or gas systems,” SoCalGas CEO Bret Lane said in a June 16 letter.
Lane’s letter was accompanied by another June 13 letter from a group of municipal utilities to State Sen. Henry Stern, saying that they have serious concerns with the continuing moratorium on injections that the legislature required until a root cause of the leak is identified. The analysis is not needed because the wells have been retrofitted and gas no longer flows into outer casings, the practice that led to the gas leak, the utilities said.
“We are concerned that the bill constrains the transmission of natural gas, which could limit local electric supply, resulting in electric outages,” says the letter from Burbank Water and Power, Pasadena Water and Power, and Vernon Public Utilities.
The utilities also said that the legislation failed to define a process for emergency gas injections, “suggesting that a response to a blackout might come too late.” They backed SoCalGas’ recommendation that the current gas inventory at Aliso Canyon be increased to prevent blackouts.
The utilities caution that temperatures were moderate last year, which has so far not been the case this year. A heat wave last week swept areas of California, cutting electricity to about 190,000 Pacific Gas and Electric customers and prompting CAISO to issue a conservation alert. (See California Heat Wave Prompts CAISO Flex Alert.)
BRANSON, Mo. — Energy industry veterans mused on the state of energy innovation and the future of the sector during a panel discussion at MISO’s annual stakeholders’ meeting last week.
Thomas Voss, retired chairman of Ameren and a self-proclaimed devotee of innovation, said microgrids and rooftop solar are gaining traction.
“In California, it’s completely changed the planning process. Lines that they thought would be overloaded were fine because of rooftop solar,” Voss said during the June 21 panel. “Now there’s winner and losers, and it might not be as fair as it should be, but hopefully we can come together and solve that.”
William Mohl, a former Entergy executive, said MISO has the luxury of studying what the RTOs on the coasts are doing with renewables and storage and waiting until it becomes economic to implement the results.
James Jura, former CEO of Associated Electric Cooperative Inc., recounted how he used to ask industry participants if they had heard of Elon Musk before he was a household name: “I said, ‘You have to look him up because he’s going to get between you and your member-owners.’”
Libby Jacobs, former chair of the Iowa Utilities Board and former Organization of MISO States president, said FERC will need to address the public appetite for renewables with orders or possible rulemaking.
“I do see energy storage as one of the coming-together points of what regional, state and national entities can do,” she said. MISO has tentatively scheduled a July 24 common issue meeting to discuss how storage might fit into its market and could convene a task team to craft new rules. (See MISO’s Next Step on Storage: ‘Common Issues’; Task Team?)
Voss said with load growth flat nearly nationwide, it’s time for state regulators to determine whether current energy policies will still make sense when demand eventually rises again.
Mohl agreed. “Slow load growth hides a lot of sins,” he said, adding that baseload resources are no longer being tested regularly for reliability.
Capacity is still not properly priced for merchant generation, Voss said, maintaining that suppliers have no incentive to build any new generation — especially in Southern Illinois. “I don’t think the capacity problem has been solved anywhere in the country. There’s no drive to build anything new,” he said.
Mohl added that low margins and low gas prices are pricing some longtime generators out of the market.
“There are some that say, ‘Well, they should just leave the market,’ but we don’t want all of them to leave the market,” he said, adding that capacity needs to be priced properly.
As the industry moves away from coal — and even nuclear — generation, RTO leaders, regulators and utilities will require more defined plans for upgrading natural gas infrastructure and pipelines, Mohl said.
“I think a lot of times people hope and pray that it’s there when they need it, but what I don’t see is a more intentional plan. … If you get down to renewables and natural gas and remove baseload generators, there’s inadequate infrastructure,” he said.
“There’s a big disconnect there,” Voss agreed. “There hasn’t been enough attention on, ‘Is the firm supply of gas really firm?’”
“Right now, it really doesn’t matter. But it will,” Mohl added.
Jacobs predicted increased difficulty in siting new pipelines and transmission alike because of a surge in environmental activism. “I think 10 years ago, regulators would have asked, ‘Why are there police, bomb-sniffing dogs at your meetings?’” she said.
VALLEY FORGE, Pa. — The plethora of data PJM provides is only useful if the grid operator also explains what it all means, stakeholders told RTO staff last week at a special session of the Market Implementation Committee on providing transparency in how market prices are developed.
John Horstmann of Dayton Power and Light said that stakeholders are not always as informed as staff about what is significant in the numbers and what is not.
“I think we’re looking for more than just raw data,” Calpine’s David “Scarp” Scarpignato said. “We’re looking for some kind of meaning.”
Staff acknowledged the need for explanation. The meeting adjourned early, with Rami Dirani, PJM’s facilitator of sessions on the topic, agreeing to develop a presentation on what data the RTO can provide and some ideas regarding the best way to provide them. The presentation, scheduled for the committee’s next meeting July 11, will also address confidentiality and critical energy infrastructure information (CEII) considerations, he said.
Gary Greiner of Public Service Electric and Gas said that he wants to go beyond price spikes and trends and “get a seat alongside of the dispatcher as they’re making their reliability decisions” to know why units are dispatched out of market, why those units weren’t economic and why that isn’t anticipated. PJM’s current practice of reviewing the past month’s results loses the advantages of instantaneous feedback, he said.
“I don’t know that that’s a good model for price formation,” he said.
Acknowledging confidentiality and competitive concerns, Greiner urged PJM to provide the most granularity possible to help market participants understand system dynamics, such as where circumstances are changing and what’s causing it. And while he also acknowledged the importance of not making dispatchers so preoccupied with how their actions will be perceived that they hesitate to make the right decisions, he cautioned against relying on a dispatcher’s “experience and intuition” to dictate a “significant portion” of dispatch.
“As much of that as we can push into the algorithms embedded in the models, the better we are — and we won’t know that unless we can see it,” he said.
The goal for PSE&G, he said, is to make decisions as predictable as possible so market participants can anticipate situations and act on them as quickly as possible.
“I don’t have a sense of what’s going on there,” he said. “When dispatchers are taking out-of-market actions, I’d like to know what they are and why they’re taking them … to get closer to a more transparent dispatch that we all understand.”
Joe Ciabattoni, who manages PJM’s market coordination, said MISO’s forecast reports offer more granularity, which PJM is studying and plans to include in its reporting. PJM’s security-constrained economic dispatch engine provides forecasts of various intervals, including “very short-term,” “short-term,” “intermediate-term” and “real-time,” he said, adding that staff will consider what data from each category could provide meaningful information for stakeholders.
“Historically, we’ve always reported on the overall forecast because years ago, before we had sophisticated applications, that’s all that really mattered,” he said.
Dirani said he would begin compiling information in response to the group’s interests. He asked stakeholders to provide, as soon as possible, any additional issues PJM should examine and be prepared to fully evaluate all of them for the next meeting.
BRANSON, Mo. — MISO will have adequate generation over the next five years to address its changing resource mix and the adoption of new technologies, planning staff told RTO leaders last week.
Low electricity demand plays a big part in the brighter forecasts and more optimistic tone adopted by MISO when discussing future resource adequacy, staff say.
“Energy efficiency has made our load essentially flat since 2008,” Clair Moeller, MISO executive vice president of operations, said during a June 20 meeting of the Board of Directors’ System Planning Committee.
The RTO’s annual resource adequacy survey published jointly with the Organization of MISO States earlier this month found that low demand will leave its footprint flush with capacity through at least 2022. The survey showed a 2.7- to 4.8-GW regional surplus over the next five years, while last year’s survey predicted a 0.4-GW shortfall by 2018 if no new generation came online. (See Capacity Survey Shows MISO in the Black.) MISO expects peak loads of more than 130 GW by 2032. Current summer peak is expected to hit about 125 GW.
Director Phyllis Currie asked what MISO is receiving from states in terms of resource planning.
Jennifer Curran, MISO vice president of system planning, pointed to a new level of fuel diversity in states’ integrated resource plans, which typically chart a resource mix that is one-third each coal, natural gas and either wind or nuclear generation.
“The old days were a preponderance of coal; the new days are a preponderance of gas,” Moeller said.
Wind projects still occupy about a 67% share of the current 32 GW of new generation in the RTO’s interconnection queue. Moeller expects fewer wind projects to enter the queue as federal production tax credits are phased out.
Planners think batteries do not yet make financial sense in the MISO footprint. “We think we have some time to work through how to do the math to optimize storage,” Moeller said.
However, MISO is hedging bets this year by introducing a fourth 2018 Transmission Expansion Plan 15-year future scenario that envisions a surge in rooftop solar, localized storage devices and electric vehicle use. (See “MISO Tweaks 4th and Newest MTEP Future,” MISO Planning Advisory Committee Briefs.)
“Now the electric vehicle folks are sure this is going to happen, and the solar collector folks are sure this is going to happen,” Moeller joked. “We’ll see. What we need to ensure is that we have the grid for the future when the future gets here.”
| MISO
MISO still expects emerging technology like solar to increase the complexity of transmission planning and noted that demand-side programs have the potential to “fundamentally change load levels and shapes.”
Moeller noted that the Department of Energy forecasts even higher future solar penetration than MISO’s highest predictions.
“We’re not quite sure where their optimism comes from, but that’s where it is,” Moeller said.
An Energy Information Administration report released early this year projects that the U.S. will add nearly 70 GW of new wind and solar photovoltaic capacity from 2017 to 2021. Solar will be one of the “most competitive sources of new generation” by 2022 and will represent more than 50% of new capacity additions between 2030 and 2040, according to the agency.
