SPP said last week it is accepting applications for industry experts to serve on a fourth independent panel to review Order 1000 transmission proposals in 2019.
The RTO forms the pool each year to manage competitive projects. A panel composed of experts from the pool will review, rank and score proposals for competitive projects approved for construction by the Board of Directors.
Interested candidates must have expertise in at least one of the following transmission-related areas:
Engineering design
Project management and construction
Operations
Rate design and analysis
Finance
Applications will be accepted through Aug. 31. Panelists will be selected based on a recommendation by SPP’s Oversight Committee and approved by the board later this year. Those serving on the panel will be considered contractors and will be compensated through a monthly retainer and hourly rate.
More information can be found on SPP’s website. Interested parties may also contact regulatory analyst Aaron Shipley.
For the ninth straight month and 17th of the last 19, SPP amassed market-to-market (M2M) payments in its favor from MISO during April.
| SPP
SPP staff said during its Seams Steering Committee meeting last week that MISO incurred $1.97 million in charges, increasing its total payments to SPP to $53.3 million since the two neighbors began the process in March 2015.
The main cause of charges in April was the Nebraska City temporary flowgate in Omaha Public Power District’s control zone. The constraint was binding for only 30 hours during April but racked up more than $717,000 in charges because of area outages, combined with lower wind generation and high south-to-north flows.
SPP’s Nashua-Hawthorn permanent flowgate in Kansas was binding for 142 hours and accumulated more than $427,000 in M2M charges.
The committee met June 6 at Southwestern Public Service’s offices in Amarillo, Texas.
Solar Inverter Problem Leads CAISO to Boost Reserves
By Jason Fordney
CAISO will make permanent a once-temporary practice of boosting its power reserves to account for utility-scale solar tripping offline because of an inverters problem, something NERC has identified as a major reliability issue.
When solar generation is at its peak, CAISO will set the operating reserve target at either 15% of the total solar production forecast or the maximum NERC/Western Electricity Coordination Council requirement, whichever is greater.
The ISO has worked with solar operators to reprogram inverters since last year, CAISO Shift Supervisor John Phipps said Monday at a Market Performance and Planning Forum. Some of the inverters began working properly after reprogramming, but others are hard-wired and still subject to tripping. Phipps said that 2,700-2,800 MW of generation across the whole ISO system cannot be reprogrammed.
“They are not in any one regional area;, they are spread out across all the plants in California,” Phipps said during a presentation, adding that the issue is not affecting behind-the-meter or storage resources.
The inverters, which convert photovoltaic DC output to utility frequency AC, sometimes trip offline to protect the systems during voltage fluctuations. CAISO began procuring additional reserves a year ago, after the problem occurred in August 2016 because the Blue Cut fire in Cajon Pass caused transmission line faults and disconnected 1,200 MW of solar. (See CAISO Boosts Reserves After August Event Report.)
CAISO CEO Steve Berberich last month cautioned the ISO’s Board of Governors about the seriousness of the problem, which caused the loss of 860 MW of solar resources on April 20. (See CAISO Board Approves Forecast Error Measures.)
The inverter problems have so far triggered two NERC alerts, one on June20, 2017, and the other on May 1 of this year. NERC said the problem could also affect non-bulk power systems and recommended all operators follow certain recommendations spelled out in the more recent alert.
“While this NERC alert focuses on solar PV, we encourage similar activities for other inverter-based resources such as, but not limited to, battery energy storage and wind resources,” the agency said in the May 1 alert.
Ancillary Service Scarcity Increases
CAISO has seen an increase in ancillary service scarcity events in the real-time market, Director of Market Analysis and Forecasting Guillermo Bautista Alderete told the forum. He said that while the number of incidents has increased, the magnitudes are small, with about 75% of the scarcities at fewer than 10 MW. The increased incidents stem from a confluence of factors and changes in the market, he said, including the solar operating reserve requirement.
Most recently, CAISO issued three notices of ancillary service scarcity events for May 3-6, May 15, and May 23-28, nearly all of which were associated with regulation up service and mostly in the SP26_EXP region in Southern California. In 2018, 46% of the scarcities happened in SP26_EXP, 35% in NP26_EXP and 19% in CAISO_EXP.
CAISO pays an ancillary services scarcity price when it is unable to procure the target quantity of one or more ancillary services in the integrated forward market or real-time market runs. About 52% of the scarcities are due to limits in generator telemetry, which is the process whereby a generator supplies the ISO with real-time data. Mismatches between telemetry and real-time needs require the ISO to procure additional capacity in the real-time market. About 33% are due to generator outages and re-rates, and 15% categorized are as “other.”
CAISO’s Market Monitor in its 2017 State of the Market report noted that scarcity events in the real-time market “increased significantly” from 26 in 2016 to 54 in 2017.
BOISE, Idaho — With the prospects for large nuclear plants becoming increasingly difficult in the U.S., nuclear proponents last week expressed excitement about the future of small modular reactors, touting their flexibility and lower capital cost.
Small modular units offer the clean benefits of nuclear while being more easily tailored to varying usage and sites, and the technology is seeing significant federal investment and partnership, industry experts told the annual meeting of Western Conference of Public Service Commissioners. During a panel discussion, they noted that other countries such as China and Russia are pursuing nuclear while it is being driven out of markets in the U.S.
Moderator Stan Wise, former chairman of the Georgia Public Service Commission, noted that the panel didn’t include any opposing viewpoints as is often the case at similar events. He said the discussion was “informational” and not about whether nuclear should — or should not — be pursued.
Wise stepped down as chairman of the state commission in February, maintaining his support for the continuing expansion of the controversial Vogtle nuclear plant — a stance for which he was “unapologetic,” he told the audience. (See Georgia PSC Votes to Complete Vogtle Units.)
“I think we need to be aware of opportunities for changes, for enhancements and for a new paradigm,” Wise said.
The current nuclear fleet is a “24/7” baseload resource that provides about 60% of non-greenhouse gas-emitting generation in the U.S., said Doug Little, who left the Arizona Corporation Commission last year to join the Department of Energy as deputy assistant secretary for intergovernmental and external affairs. Portions of Little’s comments echoed the Trump administration’s conclusion that nuclear units, along with coal plants, contribute to national security, the subject of a controversial order issued by the president last week. (See More Questions than Answers for FERC, RTOs on Bailout.)
“The department has been very supportive of this technology,” Little said. “We don’t want to see the industry move offshore in terms of the technology and the knowledge base.” He pointed to the benefits of small nuclear because of its modular nature and flexibility in siting.
Little used the analogy of a Ford F-150 pickup truck and a Prius hybrid electric vehicle. While the large utility vehicle might have a high operating cost and be less environmentally efficient than a compact EV, “I can do things with that F-150 that I can’t do with a Prius,” such as hauling a large load of hay on a farm. There are national security benefits of baseload plants, he argued, as 98% of military facilities get power from utilities and gas supply disruptions and price spikes can occur.
“How do we properly value these assets?” Instead of focusing strictly on price, the reliability value of nuclear should be considered, Little said. “I think the conversation needs to be broadened a bit, and that is what we’re trying to do at the department.”
Economic factors have shut down six reactors in the U.S. since 2013, with 12 more planned to go offline by 2025, said Rita Baranwal, director of the Idaho National Laboratory’s Gateway for Accelerated Innovation in Nuclear (GAIN) program. There are only two reactors under construction in the U.S., but there are 18 being built in China with another 31 planned, and five under construction in Russia with 22 more planned, she noted in a presentation. There are currently 440 operating reactors in 30 countries and 50 under construction in 13 countries around the world, she said.
“We want to ensure we have the continuing operation of the existing [U.S.] fleet,” Baranwal said.
Jose Reyes, chief technology officer of Oregon-based NuScale Power, described the giddy growth arc of the company founded in 2007. The Nuclear Regulatory Commission accepted the design application for its small modular reactor for review in March 2017, seen as a breakthrough regulatory hurdle for the technology. About $720 million has been invested in the technology, including $226 million from DOE in a competitive funding opportunity and a $40 million DOE matching fund award this month.
The NuScale Power Module can be stacked in up to 12 units for 600 MW in gross output. Its first deployment, a 12-module plant at a Utah Associated Municipal Power Systems site, is due for 2026 commercial operation.
“It’s exciting for me to see how this small dream has gotten this far,” Reyes said. “I wake up in the mornings and I pinch myself.”
KANSAS CITY, Mo. — Midwestern regulators must not overlook the transformative effects of renewable energy and the pace of advancing grid technologies in their decisions — all while ensuring that electricity rates stay affordable, panelists speaking at a regional regulatory conference advised last week.
Those themes cropped up during several panel discussions at the June 4-6 Mid-America Regulatory Conference. Here’s some of what we heard.
Build Large Tx Projects for Wind
Industry experts agreed that new, large-scale transmission is necessary to facilitate a growing influx of wind power, and many said RTOs’ current seams processes pose an obstacle.
Nicole Luckey, Invenergy director of regulatory and government affairs, stressed that transmission must be built to unlock the benefits of low-cost wind energy.
RTOs must fix their interregional project processes, Luckey said, pointing out that no major interregional lines have ever been approved between SPP, MISO and PJM.
“Something is clearly going wrong,” Luckey said. “Today’s transmission planning is reactive rather than proactive.”
She added that it’s imperative for RTOs to focus on aging and degraded transmission, citing the American Society of Civil Engineers’ 2017 Infrastructure Report Card that gave U.S. energy infrastructure an overall grade of D+.
“My company’s biggest challenge is not siting interstate transmission lines. Siting is laborious … but it’s not the biggest challenge,” said ITC Great Plains President Brett Leopold. Instead, the RTOs’ differing interregional planning processes can hamper “higher-voltage backbone projects” and leave companies with only “piecemeal lower-voltage reliability projects.”
Steve Gaw, consultant for the Wind Coalition and the American Wind Energy Association, agreed that RTO seams represent a stumbling block for building large transmission. “To me, the big hurdle we have today is seams. … We have all this wind generation in the Midwest, but we have these artificial barriers,” he said.
Gaw would like to see FERC intervene on the “intensifying” problem of interregional transmission planning. FERC’s “interregional piece is so weak that it really hasn’t produced anything. I’d like to see FERC weigh back in,” he said. “If we don’t have somebody applying pressure on this, it’s going to continue as it has.” He added that he’d like to see a cost study performed on the inefficiencies in deploying resources along the seams.
“I don’t think the seams involve a mountain range or an ocean. It’s worse — they’re political in nature,” said ITC Transmission Director of Public Affairs Tom Petersen.
Energy consultant Will Kaul, also chair of the Great Plains Institute, said RTOs have done well in transmission planning. “I think they have a lot to show for it,” he said.
But even Kaul wasn’t sure if planned transmission buildout by 2030 would be enough to facilitate the renewable energy goals of municipalities and companies. He said insufficient transmission can constrain the full capability of renewable sources.
Nick Wagner, incoming National Association of Regulatory Utility Commissioners president, and co-vice chair of the Iowa Utilities Board, said commissioners in RTO states may “finally be at point where they’re tired of” ongoing seams issues. He suggested that regulators may begin initiating meetings with RTO officials and ask for solutions.
Gaw also pointed out that while energy prices continue to decline, the costs to upgrade transmission and distribution are on the rise and need to be properly recovered.
“There is story here that needs to be told. We’re moving to a new system,” Gaw said.
Russell Feingold, vice president of management consulting at Black & Veatch, said it’s time to rethink traditional ratemaking, especially considering low energy demand.
“The problem is that the old regulatory compact does not work in the 21st century,” Feingold said. “The traditional volumetric structure, while it served its purpose in the past, perhaps it’s not the best practice for recovering utilities’ costs.”
Feingold said riders like infrastructure trackers can help utilities recover their total cost of service, but he added that it’s difficult to arrive at numbers everyone can agree on.
“I often say that if you get five analysts in a room, you’ll get five different answers on what costs should be for residential customers,” Feingold said.
Trump’s Bailout
A few panelists said if President Trump’s recent order directing Energy Secretary Rick Perry to prevent further nuclear and coal plant retirements takes effect, it will muddy market signals and infrastructure investment. (See More Questions than Answers for FERC, RTOs on Bailout.)
“The wind industry will not like this,” Gaw said of the order.
The fact that coal and nuclear generation are on the brink of retirement demonstrates that the “marketplace is working,” Gaw said.
“Cars get old, they get replaced with more efficient models — that’s what happening today on the grid,” he said. “This approach is going backward and ignoring consumers and market signals.”
“The good news is it’s easier to keep the status quo than change,” Petersen offered grimly, adding a disclaimer that ITC is “agnostic to what the generation source is.” Nevertheless, Petersen predicted that the order, if realized, will create “uncertainty and mixed signals” in transmission planning.
“It makes it hard to plan for the future,” he said.
Renewables in Demand
General Motors Global Manager of Renewable Energy Rob Threlkeld said his company will achieve 100% renewable energy usage by implementing more energy efficiency measures, addressing erratic renewable generation times through battery storage and influencing public policy.
But Iowa Consumer Advocate Mark Schuling said he had concerns with renewable power purchase agreements when large industrial customers go outside utilities to obtain them, which may leave other customers with higher bills.
“We need to make sure we’re not impacting the utility model,” he said.
Schuling said utilities should offer environmentally conscious, reliable and affordable energy, appealing to a broad class of customers. He said he often hears residential customers explaining that they can’t afford rate hikes because they’ve been on the “same Social Security income for 20 years.”
“There’s not a customer comment period where we don’t get those type of comments,” Schuling said.
He said pilot projects are a good method for testing the effectiveness of new ideas, especially when considering how new energy programs will affect low-income ratepayers.
“I think storage is the change that’s coming that’s going to impact generation,” Schuling predicted. “We have a lot of wind in Iowa, and when storage comes online, it’s going to change” how energy is delivered, he said.
Andy Zellers, Brightergy’s vice president of development and general counsel, said the company’s current 5-MW solar pilot project with Entergy New Orleans could become a 50-MW project if it tests well. The project still requires approval and is under a non-disclosure agreement, he said.
“I can’t say much about [the project], but it’s literally on an island. Transmission is bottlenecked getting it in and out of the parish,” Zellers said.
Zellers facilitates solar projects for utilities when commercial customers approach them for renewable sources. He said at some point, utilities will have to change their business plans to factor in the green desires of commercial customers.
“Customers with means are coming to the utilities saying, ‘We need this,’” Zellers said. “If the utilities are not providing this, they’ll go somewhere else.”
Zellers said distributed energy-friendly policies can be sold to conservative regulators and politicians if they’re marketed using their reliability-enhancing potential and entrepreneurial opportunities.
“These arguments will win eventually,” he said, adding it will take “patience and pressure.”
David O’Brien, Navigant director of strategy and operations, said the market becomes more contested in nature as distributed energy resources multiply in regulated utilities’ territories.
“Increasingly, you can see utilities and third parties competing with one another,” O’Brien said.
Sunrun Director of Public Policy Amy Heart, whose company focuses exclusively on residential rooftop solar, said she discourages the notion among customers that they’ll become independent of the grid after installing solar. Rather, she wants to introduce more diversity into the grid.
But SPP Vice President of Engineering Lanny Nickell said his RTO’s 84-GW queue currently contains more renewables than its load can consume. “[SPP] has been called the Saudi Arabia of wind,” Nickell said.
Nickell said during one interval in April, approximately 64% of SPP load was served by wind generation.
“If you would have told me 10 years ago that this was doable, I wouldn’t have believed it,” Nickell said.
If SPP “had the right transmission and the right resources,” he said, it could reliably use a generation mix that includes 75% wind generation.
Electric vehicles could snap up excess wind generation, other panelists pointed out.
“There’s a lovely relationship between charging your electric vehicle at night and the surplus of wind energy at night,” Luckey agreed.
“We need more EVs. We need more load to be able to absorb all of these renewables,” Petersen said.
MISO President and Chief Operating Officer Clair Moeller said his staff talk “about the possibility of a post-capacity world,” considering the influx of new non-firm resources.
He noted that MISO is also managing a renewables-heavy queue that — if all projects are realized — will add 93 GW to the its portfolio.
“If we don’t solve the queue problem, the solar is going to move to rooftops because the demand is there,” Moeller said.
But Luckey said that study delays plague both MISO’s and SPP’s interconnection queues and can leave new wind projects in a holding pattern.
“Timelines have to be tightened up, studies have to make sense, and studies have to be completed on time,” Luckey said.
Samantha Williams, Midwest director of the National Resources Defense Council’s Climate and Clean Energy Program, said utilities and regulators should look for ways to encourage DER use in rate design.
“There’s an opportunity here to use rate design as an enabler … to get utilities to open opportunities for clean energy for customers,” she said.
But she added that rate design should protect low-income vulnerable customers, especially those on fixed incomes.
“Novel and untested rate design should be tested and vetted by credible data,” Williams said.
She warned against utilities seeking high fixed charges on utility bills, saying most increase requests are rejected outright or scaled back by state regulators. “Most of the bill should be volumetric.”
Williams said she prefers time-of-use rates over mandatory demand charges, adding that residential customers would have to be educated to understand their energy use and pinpoint which household actions cause a high demand charge.
“We’re going to have a whole community of people that need education on what triggered the charge. The fact that it’s all backward-looking is very challenging as well. I think demand charges are the least understood,” Williams said.
“What you can’t do is address a demand charge after the fact,” Heart said.
Lon Huber, a head of consulting with Strategen, said utilities and regulators should not shake up rates simply to accommodate DERs.
“Rates should avoid rocking the boat for 98% of customers for the sake of 2%,” he said. One of the rate designers on Xcel Energy Minnesota’s new residential time-of-use program, Huber said he worked to assign an energy cost for every hour of the year. The utility last month won approval from the Minnesota Public Utilities Commission to test a two-year time-of-use pilot program that charges residential customers more for energy consumed during the 3-8 p.m. peak, with the most inexpensive rates occurring at night. The program is set to begin in 2020 for about 10,000 customers.
Huber said utilities developing their own time-of-use programs must make several decisions, including deciding on peak time rebates or a critical baseline rates.
“You’re basing a rate design on calling a certain number of critical events per year. If a utility plans for 10, but calls two, does there need to be a rebate?” Huber asked. “It gets really tricky really fast.”
Ryan Prescott, Tradewind Energy director of market analysis, said that customers choosing not to participate in new energy programs should be shielded from the costs of implementing them.
Prescott pointed to Dominion Energy’s recently rejected 100% renewable energy program intended for its large customers as an example of the need for utilities to carefully vet programs.
“Costs weren’t very well known,” Prescott said of Dominion’s program.
“Low-income customers are customers first. They’re low-income second,” Ameren Vice President of Corporate Planning Steve Kidwell said in a later panel.
Kidwell predicted that Ameren’s steady coal retirements will not raise rates, in large part because of inexpensive wind energy coming online. He said it’s a “huge opportunity” to be able to keep customer bills low while gradually increasing Ameren’s renewable component.
WASHINGTON — The headlines at the Energy Information Administration’s 2018 Energy Conference were generated backstage, as FERC Chairman Kevin McIntyre and Department of Energy Undersecretary Mark Menezes were questioned by reporters about President Trump’s coal and nuclear bailout after their speeches. (See FERC Blindsided by Half-Baked Trump Order.)
But an earlier panel featuring officials from PJM, ERCOT and GE Power also provided some highlights. Stan Kaplan, director of EIA’s Office of Electricity, Renewables and Uranium Statistics, moderated questions from the audience.
No, said Eric Gebhardt, chief innovation officer for GE Power.
“In many cases, the microgrids are being installed [for industrial uses] because of higher-cost electricity. … A 10-MW natural gas [reciprocating generator] can produce a [levelized cost of energy] of around 6 cents/kWh, which is extremely competitive.”
Adding cogeneration, “a [combined heat and power] application where you take the heat off that to create steam for your process or you use it for HVAC purposes, it drives the value even further. … With a combined heat and power [application], you could be pushing 90% efficiency in the overall cycle, which is great efficiency.
“The second thing is many customers are looking to decarbonize by putting in solar in conjunction with this. And then you start using energy storage as part of that for peak demand clipping, because many times these microgrids don’t [supply] 100% of the load. They might be 80% of the load, might be 70% of the load … so, there’s many ways it can be economic.”
In contrast, he said, microgrids “trying to be completely off-grid … that’s not always an economic way to operate today, or not necessarily the most economic way to operate today.”
Does a more intelligent, distributed grid increase resilience or make us more vulnerable to cyberattacks?
“Arguably, spreading things out, having distributed resources, microgrids, are in one way maybe increasing the cyber grid [attack surface],” said Craig Glazer, vice president of federal government policy for PJM. “You’re also enabling [resilience]. It’s not like you can attack one substation and take out metropolitan areas. So, I think on balance [there’s] probably more benefit to that.”
The bigger challenge, Glazer said, is that there are no mandatory cybersecurity standards for the natural gas pipeline industry, unlike the electric grid.
“You know who regulates the cybersecurity of the natural gas pipeline industry? The TSA [Transportation Security Administration], the people that check your bags at the airport. …
“There is a very small staff. They’re dedicated people. But it’s a very small staff totally underwater, frankly, in this area.
“If you hit the fuel supply, you’re going to have an impact on the electric grid, yet we somehow have just accepted a vastly different structure: voluntary, suggested standards for the pipelines versus mandatory standards for the electric grid.”
Are the industry’s capabilities keeping pace with the increasingly intelligent, complex grid and the growth of behind-the-meter generation?
“It’s a great question that I don’t know the answer to,” said Beth Garza, director of the ERCOT Independent Market Monitor.
“The interaction of more and more data [with] finer granularity, and then having the systems and tools to process this … to turn it into actionable information, I think is a challenge. I tend to be optimistic on all of that … but I do see it as a challenge.”
Gebhardt agreed. “How do you deal with going from a thousand centralized power plants to hundreds of thousands and hundreds of millions of end nodes that are going to be producing power, as well as being able to curtail power, simultaneously? How does all of that get managed? That’s going to be something that many utilities and technology companies have to deal with.”
Glazer recalled the April 2015 power outage that darkened the White House and much of downtown D.C. NERC said it began with the failure of a 230-kV lightning arrester 40 miles south of the capital. (See Failed Lightning Arrester Caused April Outage.)
“The outage was not that big a deal, but the restoration was much more complicated because [PJM], as well as the local utility [Pepco], didn’t have any visibility into which buildings had backup generation and were running them and which ones didn’t.
“So, the [National] Air and Space Museum had backup generation; the Hirshhorn Museum didn’t. But nobody knew that. This happened on a patchwork all through Washington. It made the restoration that much more difficult.”
California’s solar generation has produced the late afternoon duck curve. Why don’t we hear about ramping challenges in ERCOT?
“Part of the challenge in California is that customers don’t use as much electricity as they do in Texas,” Garza said. “It is very much driven by [Texas’] air conditioning load in the summertime. That is supported by solar [generation] but any kind of projection I’ve done that’s grossed up the solar curve on our load curve, I can’t get Texas to look like the California duck curve.”
Will energy storage replace combustion turbine peaking plants?
“That question comes up a lot,” Gebhardt said. “I look at it more as an ‘and’ versus an ‘or’ question, because there’s so many existing peaking plants that are out there right now. Combining them in a hybrid application with energy storage brings tremendous value. … The batteries handle the really fast ramp rates and allow the gas turbine to come on at a slower ramp rate going from a dead stop. … And if you have it there, it also serves other purposes — voltage support, frequency response…
“Certain parts of the U.S. are testing markets, saying we would take either a combined cycle gas turbine or some sort of gas turbine or energy storage. … But for the vast majority, the ‘and’ solution is probably the better one.”
CARMEL, Ind. — Over the next month, MISO stakeholders will rank 14 market improvements the RTO might undertake in 2019.
Stakeholders have until July 12 to take MISO’s Market Roadmap candidate ranking survey and organize eight new and six existing improvements by priority. The survey was announced during a June 7 workshop.
In addition to ranking the eight new submissions approved this spring for consideration by the Steering Committee, stakeholders will also consider six currently active initiatives that have already been discussed in stakeholder meetings. (See Steering Committee Advances MISO Market Improvement Ideas.)
The active items under consideration include:
Improving generator modeling so it can depict more combinations of combined cycle units;
Creating a short-term capacity reserve product available to solve capacity shortages within 30 minutes;
Developing a multiday market forecast;
Improving energy storage resource integration beyond what is required for FERC compliance;
Automating dynamic ratings for transmission lines that offer temperature-adjusted and short-term emergency ratings; and
MISO will review survey results at the August Market Subcommittee meeting, and then reconcile its preferred ranking with stakeholders’ prioritization to update a work plan for 2019 to 2023, said Lakisha Johnson, the RTO’s market strategy adviser.
The RTO has already issued a first draft of the roadmap based on internal rankings of the 14 proposals, designating its resource availability and need (RAN) effort, and plan to create a short-term capacity product as top priorities, followed by better modeling of combined cycle generators. Next on the list: creating a look-ahead dispatch tool, improved modeling of all generators and more comprehensive storage resource integration. The RTO ranked all other candidates as low importance.
This year’s ranking features only a partial list of roadmap ideas and doesn’t include improvements relegated to the “parking lot,” the lowest-ranked candidates that MISO and stakeholders predict will be useful sometime in the future. Parking lot items are reintroduced in the ranking for refreshed status every other year.
“Each year, we alternate between doing a fully exhaustive ranking of the parking lot versus only focusing on active and new candidates,” explained MISO Senior Manager of Market Strategy Mia Adams.
However, this year, MISO moved the suggestion for financial incentives for primary frequency response from the parking lot into the Market Roadmap because Indianapolis Power & Light submitted a new version of the suggestion.
Some stakeholders wondered if some improvements should be combined with others.
“There’s some concern if you make something of a Frankenstein roadmap product,” Adams said, adding that MISO may be open to bundling market improvements into portfolios when it makes sense.
Customized Energy Solutions’ Ted Kuhn said he thought the roadmap was meant for more in-depth market improvements than some of the new ones submitted this year, singling out Independent Market Monitor David Patton’s new recommendation to remove transmission charges from coordinated transmission service with PJM.
Patton said the coordinated transactions with PJM are rarely used, and the product has “failed” because MISO levies charges when an offer is made in addition to when an offer is struck.
But Kuhn said the Monitor’s suggestion could be completed “in a weekend” and questioned its consideration in the roadmap.
MISO Executive Director of Market Operations Jeff Bladen said Market Roadmap items represent “a variety of dimensions” and said stakeholders should come with suggestions on which products could be fast-tracked.
Northern Indiana Public Service Co.’s Bill SeDoris said one parking lot item should be considered sooner than next year — creating a compensation process for energy delivered during a system restoration event, an idea currently on hold. The item is timely and fits well into current discussions around resilience, SeDoris said. He added that the issue had been discussed recently in closed session discussions of the Reliable Operations Working Group.
Patton cautioned against focusing too much on the resilience “buzz word” when deciding which improvements to undertake.
SeDoris responded that MISO might appear remiss for not having discussed restoration energy compensation the next time it goes before FERC to discuss resilience. He said he would bring the issue to the Steering Committee’s next meeting in the hopes of reigniting interest in creating a compensation mechanism.
MEXICO CITY — Bob Smith has enjoyed a long career in transmission planning and development, much of it in the American West where he said federal lands can create “unique problems” for building electric infrastructure.
As vice president of transmission, planning and development for TransCanyon, Smith is responsible for conceptualizing and planning transmission projects for the joint venture between Berkshire Hathaway Energy and Pinnacle West Capital.
BHE is Warren Buffett’s energy holding company that includes PacifiCorp and NV Energy. Pinnacle West’s assets include Arizona Public Service. Together, they offer $90 billion worth of “leverage” to TransCanyon.
| Shutterstock
Smith told a Gulf Coast Power Association breakfast audience last week that “there’s a clear need for transmission infrastructure” in Mexico, and that the country is “fertile ground for these opportunities.”
So why is TransCanyon going to “watch the process and see what happens” for the time being?
Two words, say veterans of the emerging Mexican market: land rights.
“I’ve gotten the sense it’s every bit as difficult here as it is in the United States,” Smith said during the June 6 breakfast, the seventh in a series. “I get the sense there’s a real value of the long-term commitment to the land and cultural identity.”
Stations of the Cross
Just ask Energia Veleta’s Mannti Cummins, who is working to develop a 50-MW wind farm in Baja California Sur. He filed a social impact study, one of several necessary requirements before construction can begin, with Mexico’s Ministry of Energy (SENER) in July 2016. He received a response back last week.
However, first Cummins had to meet with a SENER representative housed in the ministry’s training facility, a dated, one-story, cement building located in a working-class part of Mexico City. Cummins was told his study was in order, but that he would a receive an electronic copy of SENER’s “opinion letter” later. The document, indicating the Office of Social Impact Studies had the “necessary and sufficient information” to do its own evaluation, arrived in Cummins’ email at 1:10 a.m. He then had to return to the SENER office later that morning to sign a document acknowledging he had received the PDF.
Electronic signatures are not considered official in Mexico, Cummins said.
“They want original, wet signatures. The most mundane business in the U.S. becomes an administrative stations of the cross here in Mexico,” said Cummins, a practicing Catholic.
Fortunately for Cummins, the proposed wind farm is in a desolate area of the state, near the oil-fired generators “that keep the beer cold in Cabo.” He only had two landowners to deal with, and none of the federal lands, social property, conservation areas and indigenous territory that other developers will face. Still, it took a team of six students working 24/7 for six weeks under their former professor to produce baseline studies, conduct interviews and draft the report.
“It would take anyone else six months,” said Cummins, who was facing an investor’s deadline. “And this was for 50,000 acres and two landowners.”
Sebastian Robinson, director general of Punto Focal, a surveying firm that specializes in setting real estate boundaries, says 51% of the country now consists of social property called ejidos, a result of the Mexican Revolution that dragged on from 1910 to 1940. When you discount the urban areas, he said, that percentage jumps into the 60s.
“The problem is, ownership has become muddled,” Robinson said.
Land ownership became an issue in the 1890s, when 20% of the country was owned by foreign interests and rich landowners. By 1910, half the country’s rural population worked on huge estates essentially as slaves, and the pent-up frustration was one of the primary causes of the revolution.
It wasn’t until socialist Lazaro Cardenas was elected president in 1934 that much of the ensuing violence subsided. Cardenas instituted the practice of ejidos, in which peasants within a community were given sub-parcels of former estates or national land — some as large as 120,000 acres — but the land was not necessarily registered, Robinson said. President Carlos Salinas eventually ended the practice in 1992.
Many of the ejidos’ original owners have long since died without transferring the titles, or they have moved into the cities to escape rural poverty. “With maybe 90% of the ejidos, there’s no chain of title,” Robinson said.
And while the government maintains a public registry of social land, Robinson said there’s no legal inventory of land ownership. The problem is magnified by the lack of accurate surveys.
Robinson and Cummins bring all this up in pointing to the potential difficulties facing the first two competitive transmission projects currently out for bids by Mexico’s state-run utility, the Federal Electricity Commission (CFE). Mexico’s energy reform of 2014 opened up the transmission system to private contractors, partly because CFE keeps its retail rates artificially low for political purposes, and it can afford to do little more than keep the lights on, Cummins said.
One of the projects is a $1.2 billion, 870-mile, 500-kV connection between Mexicali in Baja California and Hermosillo, Sonora, in northwestern Mexico. The second is the $1.7 billion Oaxaca project, more than 1,000 miles of 500-kV line between Mexico City and Veracruz, home to the country’s only nuclear plant. Technical bids on the first line are due June 15, and the Oaxaca bids are due in July, but a requirement of HVDC experience will likely limit the field.
Laguna Verde Nuclear Plant | Nuclear Energy .NET
Robinson said CFE already owns 89% of the Oaxaca project’s right of way, but that still leaves about 100 miles of line where ownership will have to be determined and dealt with. “That’s a lot of problems,” he said.
Both projects will be built under a build-operate-transfer (BOT) model, in which private companies will build the infrastructure, operate and maintain the system while recovering rates, and then transfer all the rights, licenses, permits, authorizations and property to CFE.
“CFE used to own it all,” Cummins said. “Now, it just administers the network.”
Watch and Wait
Still, developers say Mexico is too big of a market to ignore. SENER says the country’s generating capacity has doubled to more than 73 GW since 2000, and load growth and the retirement of aging, inefficient plants will require another estimated 50 GW of generation over the next 15 years. Mexico hopes to add $10 billion worth of transmission infrastructure in the coming years, including the two competitive projects.
Smith pointed to Mexico’s load growth, broad support for renewable energy and “mature and competent” planning processes as reasons to get involved in the market.
To be fair, Smith said TransCanyon was too late to bid on the Oaxaca project. The company did look at the Hermosillo-Mexicali project, he said, but decided to “monitor progress” of the initial offers “to learn the best way to engage.”
“We decided at this point, between the risk and lack of experience [in Mexico], we decided it wasn’t a wise thing to do,” he said. “We’ll try to learn lessons on best way going forward. There are some tremendous opportunities here. It’s early, very early in the process, but it’ll be interesting to see how it goes.”
FERC last week gave final approval to NERC reliability standards on training requirements and the coordination of protection systems to detect and isolate faults (Order 847, RM16-22).
Standard PER-006-1 (Specific Training for Personnel) sets training requirements for real-time operations personnel to ensure they understand the purpose and limitations of protection systems schemes. It also adds more precise and auditable requirements, FERC said.
PRC-027-1 (Coordination of Protection Systems for Performance During Faults) seeks to ensure protection systems operate in the intended sequence. It requires applicable entities to perform a protection system coordination study to determine whether the systems are operating in the proper sequence during faults or compare present fault current values to an established fault current baseline. In the latter case, a coordination study would be required only if there is a 15% or greater deviation in fault current values. The reviews are required every six years.
The commission’s June 7 order also approved new and revised definitions for three terms: protection system coordination study, operational planning analysis and real-time assessment.
FERC, however, rejected a proposal in its Notice of Proposed Rulemaking to modify PRC-027-1 to require an initial protection system coordination study as a baseline, bowing to complaints by NERC and others.
NERC said that although the requirement could help reduce misoperations caused by a lack of coordination, it would be costly and burdensome. The reliability organization said it “expects that many entities will choose to do a full protection system coordination study … for their more impactful [bulk electric system] elements” and that “it is highly likely that the overwhelming majority of entities have already conducted coordination studies for their protection systems.”
FERC said it agreed that applicable entities will conduct studies on their significant facilities even without the requirement.
“We recognize the concern that were the NOPR directive adopted, applicable entities could be required to rerun protection system coordination studies for the sole purpose of generating compliance documentation, even if such entities already performed protection system coordination studies that remain valid but lack documentation to substantiate compliance,” the commission said.
The D.C. Circuit Court of Appeals on Friday backed FERC in its revised interpretation of a PJM Tariff provision governing responsibility for transmission upgrades, turning aside a challenge by the owner of a power plant in Marcus Hook, Pa. (ESI Energy v. FERC,16-1342).
At issue was whether LS Power Associates, the parent of West Deptford Energy, should be liable for transmission upgrades ordered before the developer entered PJM’s interconnection queue. In 2014, the court vacated FERC’s order ruling the company was liable, calling the commission’s decision “the very essence of unreasoned and arbitrary decision-making.” (See Appeals Court Scolds FERC over West Deptford Interconnection Dispute.)
West Deptford (N.J.) energy plant under construction| MJ Electric
West Deptford submitted its interconnection request on July 31, 2006, and was later informed it would be assessed $10 million for improvements PJM ordered as a result of two previous projects, FPL Energy Marcus Hook and Liberty Electric.
Tariff Change
Under section 37.7 of the PJM Tariff then in effect, the RTO could seek reimbursement for a previously constructed network upgrade if the new proposed project used the added capacity created by the project or would have required it itself. The reimbursement request only applied if the cost of the upgrade was at least $10 million and it was placed in service no more than five years before the interconnection customer’s queue closing date.
If section 37.7 controlled, West Deptford would have been required to reimburse Marcus Hook and Liberty Electric for the upgrade. (Ninety percent of the upgrade’s cost had initially been assigned to Marcus Hook.)
In 2008, however, while West Deptford’s interconnection request was pending, PJM won approval for an amendment changing the assignment of responsibility for prior upgrades. Section 219 of the revised Tariff allowed PJM to seek reimbursement for previously constructed upgrades for only five years “from the execution date of the interconnection service agreement for the project that initially necessitated” the upgrade.
FERC initially ruled that West Deptford must pay, concluding that the 2006 rules applied. But the court said FERC’s ruling “provided no reasoned explanation for how its decision comports with statutory direction, prior agency practice or the purposes of the filed rate doctrine.”
FERC Reversal
In response to the remand, FERC in August 2016 reversed its ruling, relieving West Deptford of the reimbursement obligation (ER11-4073). FERC said it based its decision on the “significant skepticism” the D.C. Circuit expressed in the remand order and the “numerous shortcomings” the court identified in the commission’s analysis.
Marcus Hook appealed, saying the old rules should apply to West Deptford and challenging FERC’s interpretation of the five-year trigger under the new rules. (Florida Power & Light subsidiary ESI Energy was later substituted for Marcus Hook as petitioner.)
In siding with FERC, the court said the commission “directly and adequately addressed” Marcus Hook’s challenges to the determination that section 219 applied.
FERC was required to provide a “reasoned explanation” of how applying section 219 comported with the Federal Power Act and commission precedent, the court noted. “Unlike its prior decision, the commission’s decision on remand did both,” it said.
5-Year Trigger
Although section 219 did not specify what action was required within the five-year window to trigger cost responsibility, FERC said the most reasonable interpretation was that the “end date” was that on which West Deptford signed its interconnection agreement.
Marcus Hook argued that section 219 made an interconnection customer liable for an upgrade that entered service during the five years preceding the customer’s queue entry. It said the dispositive date should be either when West Deptford submitted its interconnection request (July 31, 2006) or when PJM determined that the upgrade was required for its interconnection (November 2006).
“Although Marcus Hook’s suggested interpretation is a possible reading of the Tariff provision, it is no more reasonable than the one the commission put forward,” the court ruled. “Accordingly, we find that the commission did not err in its interpretation of section 219 of the revised Tariff.”
FALMOUTH, Mass. — New England is up to the task of managing the tough challenges facing its wholesale market and grid — even if there is no grid in the future, regional energy experts said last week.
“The feds are less important now, and New England used to live by its wits — we never had oil or gas — but now we’ve got offshore wind,” Douglas Foy, president of energy consultancy Serrafix, said Monday at the 25th annual New England Energy Conference and Exposition. The event is hosted jointly by the Northeast Energy and Commerce Association and the Connecticut Power and Energy Society.
Looking back on the era of restructuring electricity markets in the 1980s and 90s, “the most significant feature of those times was a collaboration between government, private industry and environmentalists,” said Foy, formerly both a secretary of commonwealth development in Massachusetts and president of the Conservation Law Foundation. “There were a bunch of very smart players all trying to get to a common goal.”
“That’s a remarkable thing and quite a contrast to what we see today,” said David O’Connor, senior vice president for energy and clean technology at ML Strategies. “The way our country is polarized now, it’s harder to imagine collaboration.”
Fletcher School professor Barbara Kates-Garnick, a former Massachusetts undersecretary of energy, said the challenge today is to recreate that collaborative dynamic: “I think it was both trust, collaboration and a recognition of the need to address looming issues that contributed to our willingness to tackle different problems in a collaborative rather than adversarial fashion, as is the mode today.”
“Energy efficiency created an environment where now it’s so successful, so prevalent, we’ve levelized the demand that used to be growing inexorably every year,” O’Connor said.
Paul McCary, of law firm Murtha Cullina, said the financial incentives of wholesale markets helped form the consensus to try something different, which brought lower-cost power.
“But restructuring the electricity market was not done to face the problems we have today,” McCary said, adding that deregulation didn’t address the resource mix.
“There are a couple layers to the challenge — the state/federal split, for example,” McCary said. “Can you tweak and tweak the market until you get there? I question how many ornaments you can hang on the FERC market-structure tree. The 90s were more simple politically — today is a bigger challenge.”
“Screw the feds,” Foy said. “I’ll always bet on New England.”
Speaking on the second day of the conference, Peter Kelly-Detwiler of Northbridge Energy Partners said the industry can thank the Trump administration for bringing resilience to the fore, both with last fall’s Notice of Proposed Rulemaking and the president’s June 1 order directing the Department of Energy to maintain uneconomic coal and nuclear plants. (See FERC Blindsided by Half-Baked Trump Order.)
“On climate change, irrespective of one’s political beliefs, science is science, and it ain’t going away,” Kelly-Detwiler said. “I used to think that if I put my hands over my eyes, nobody could see me, but I was 3 when I thought that.”
Kelly-Detwiler looked to the future, imagining what the energy space will be in 2050, and said experts are not good at forecasting, as evidenced by looking back to 2001 at anticipated electricity sales, solar penetration or natural gas production.
“Why? Because all our forecasts are based on what we know, not on what we don’t know, and on what trends are accelerating and why they’re accelerating,” he said. “We have to start thinking about what that new dynamic looks like and have that inform our future forecasting.”
NASA for several years has been delivering power to an experimental aircraft via laser. “Let’s fast-forward to a grid in 2050,” he said. “We can send energy to a plane with a laser right now, and we have 32 more years of high-performance computing that’s going to accelerate its ability to solve problems for us. One question that would be worth asking is: Do we have a grid at all?”
“Even if we transition the electric power sector to zero-carbon electricity today, we still would still not be able to meet even the 2030 goals [40% greenhouse gas reduction],” said Courtney Eichhorst, lead analyst for regulatory strategy at National Grid. “Clearly the challenge is in two sectors: transportation and heating.”
Michael Sloan, managing director of natural gas for energy services company ICF, said public policy should be set with an eye to the future, especially regarding electrification of the residential sector.
“First of all, would residential electrification reduce carbon emissions? It’s not clear. What are the impacts on the grid? What are the impacts on consumers, on voters? We’ve seen policy changes that hurt consumers lead to a change in government in Ontario,” he said.
“Policy-driven residential electrification would be a very expensive approach to reducing greenhouse gas emissions,” Sloan said. “We should look at the most efficient ways to reduce emissions first, and let the market decide how best to meet residential heating load, at least until the less expensive approaches to reducing GHG emissions have been exhausted.”
On the issue of eliminating the internal combustion engine and turning to electric vehicles, Matt Solomon, transportation program manager for the Northeast States for Coordinated Air Use Management, said “there are so many advantages, so many ways that driving electric is a better experience for the consumer,” and people “get it” in one drive.
“States aren’t the best communicators … but Massachusetts is the first state to have actually put money into putting on test-drive events,” Solomon said. After an event targeted at high-earning, tech-savvy people, 68% of participants say they are more likely to buy an EV, he said.
On residential distributed energy resources, Ian Schneider, a Ph.D. candidate at the Massachusetts Institute of Technology, said that tariff design has to match the grid reality.
“If we don’t design the markets correctly, then outdated tariffs will leave this energy revolution to not necessarily benefit all customers,” Schneider said.
DERs are disrupting an already outdated rate design, he said. MIT’s Energy Initiative identified four obvious inefficiencies with current rate designs: They’re neither time-based nor location-based, and “they tend to recover fixed costs volumetrically, so the utility is recovering fixed costs for previous expenses” on a per-kilowatt-hour basis.
As those who can afford solar panels consume less of the utility’s power, lower-income people are forced to pay a higher percentage of those fixed costs, which is inherently unfair, he said.
The fourth inefficiency: that the rates don’t account for capital investments going forward, “so in a world where the marginal cost of producing electricity is very low, but capacity costs, both for the distribution system and for generation, can be very high, it becomes more important to think about coincident peaks and how consumers are driving peak costs on the system,” Schneider said.
Daniel Allegretti, Exelon vice president for state government affairs in the East, said there is a continuing tension between the utility and competitive paradigms.
Philip O’Connor, president of energy consultancy PROactive Strategies, said flat load, disruption of traditional generation economics and digital deployment are driving the electricity industry toward a second wave of competitive restructuring.
“We’ve had a decade in this country in which overall electricity consumption, served by the grid, has not increased,” O’Connor said. “The entire business model and the regulatory scheme for the traditional, vertically integrated utility, and for the wires-only company, is predicated on the idea of growth and expansion.”
Digital deployment leads to one big thing — customer sovereignty, he said. “Unfortunately, the structure of the industry, especially the vertically integrated part, stymies that development. So what are we left with? We have rising fixed costs, particularly in the monopoly environment, but flat sales, so you’ve got to keep raising the price.”
Brian Conroy, Avangrid director of network projects, said, “We see ourselves as a platform provider, and our collection of projects will deliver the platform and functionality envisioned for a future marketplace and a future grid operating environment.”
Public policy for reducing greenhouse gases or increasing the use of renewables usually means starting demonstration projects, he said.
“As we plan the future, everything we do … for least-cost planning, we have to look at what are the non-traditional alternatives,” Conroy said. “We see ourselves as a smart integrator, pulling all these diverse things together with a very smart or intelligent platform … to squeeze the value out of the distributed energy resources to get the most for our customers.”
The smart grid might outsmart the customer, according to Harrison Grubbs, director of strategic partnerships at marketing firm KSV. The firm surveyed people on their attitudes on renewable energy and found that utility customers don’t think much about their energy use.
“We wanted to drill down and get an understanding, what exactly customers do know and where those opportunities are,” Grubbs said. “We asked customers where does the majority of their electricity come from. Thirty percent said they don’t know. We also found that 27% of customers in New England believe that the majority of their electricity comes from coal and oil.”
