CAISO’s real-time market experienced an uptick in volatility during the fourth quarter of 2016, as five-minute prices at times spiked to well above day-ahead and 15-minute levels on unexpected variability in output from solar resources.
On the flip side: Solar generation increasingly sent mid-day prices into negative territory during the quarter, a trend that the ISO’s internal Market Monitor says is continuing into this year.
CAISO’s Q4 negative prices occurred most frequently during mid-day, the period of highest solar output. | CAISO
“November did see a fairly high frequency of prices above the $250 level in the five-minute market,” Gabe Murtaugh, a senior analyst with the ISO’s Department of Market Monitoring, said during a March 22 call to discuss his group’s quarterly market issues report. “You’d have to go back to the beginning of 2015 to see this frequency.”
In November, real-time prices surged to $250 or higher during nearly 1.5% of intervals, compared with fewer than 0.4% of intervals during the same period in 2015. Prices hit $750 or more during 0.6% of intervals, up from 0.3% a year earlier.
Murtaugh attributed the prices spikes to more cloud cover than was forecast by CAISO, translating into lower solar output than was accounted for in the day-ahead market during specific intervals. The ISO was forced to move up the bid stack to secure higher-priced resources in real-time to cover the shortfall — especially during the afternoon ramp as solar resources began to reduce output.
“This outcome resulted in part from a combination of solar deviations and tight supply conditions during intervals when system ramping needs were greatest,” the department said in its report.
Contributing to the price discrepancies between the five- and 15-minute markets were differences in the solar forecasting methodologies used for each, an issue the ISO addressed through changes to its forecasting software in December.
Still, instances of high prices during the fourth quarter were “fairly irregular,” according to Murtaugh. More frequent were intervals of negative prices, the Monitor noted.
The department observed negative prices during 4.7% of intervals during the five-minute market and 1.8% of those in the 15-minute market. By comparison, during the same period a year earlier, negative prices occurred in 2% and 1% of five- and 15-minute market intervals, respectively.
The last quarter of 2016 also saw five-minute prices go negative nearly 20% of the time during the 10 a.m. interval — the beginning of the mid-day period most subject to solar-drive price dips.
Graph shows that CAISO Q4 real-time prices consistently outpaced those for the day-ahead and 15-minute markets during the afternoon ramp. | CAISO
Nearly all of the negative prices were the result of the ISO’s market mechanisms — and not the result of out-of-market operations to curtail output.
“These are conditions where an economic downward dispatch is issued to a unit with a negative marginal cost, so negative marginal cost units are setting the marginal price in the system,” Murtaugh said. “This is a solution that is arrived at from the market optimization and it’s similar to any other solution that we would see in the market during other times of the day when marginal costs are set at a marginal level.”
The Monitor’s data showed that most of the negative prices held to a range between $0 and -$50/MWh.
Carrie Bentley of Resero Consulting wondered where most of the negative prices clustered — closer to $0 or $50?
“Off the cuff, it tends to be more clustered between the $0 and $25 range,” Murtaugh responded. “That typically tends to be the amount of tax incentives that are given out on a per-megawatt-hour basis to solar facilities and wind facilities — and those tend to be the ones we see setting the price more frequently.”
Murtaugh also offered call listeners a “teaser” regarding the first quarter: “For the data that we’ve already looked at in 2017, the [negative price] numbers are fairly high for the first quarter as well.”
Wei Zhou, a senior project manager with Southern California Edison, probed Monitor staff about an observed increase in negative prices in the ISO’s day-ahead market this year.
“What’s the expectation for the frequency of negative pricing in the day-ahead market?” Zhou asked.
Keith Collins, CAISO manager of monitoring and reporting, called the development an “improvement” that would allow the ISO to better align resource commitments in the day-ahead market with actual conditions in real-time, decreasing the potential for oversupply.
“So shifting [negative prices] to the day-ahead is not necessarily in and of itself a bad thing, but it’s not a trend that was observed prior to the last few weeks,” Collins said, adding that it was a topic that could be covered in a future Market Performance Planning Forum.
WESTBOROUGH, Mass. — Transmission developers will have to wait a bit longer for ISO-NE’s first competitive project.
The RTO told stakeholders Wednesday that it will not issue a request for proposals for the Keene Road market efficiency transmission upgrade because the cost would be greater than the production savings. The grid operator had explored the project as a way to release pent-up wind resources in Maine.
Rollins Wind Farm in Maine | Reed & Reed, Inc.
Director of Transmission Planning Brent Oberlin presented his staff’s analysis to the Planning Advisory Committee on March 22, confirming preliminary results released in December. (See ISO-NE Study Sees Little Savings from Keene Road Tx Upgrade.)
The study showed increasing the Keene Road export limit from 165 MW to 195 MW would save $1.37 million in production costs annually over a 10-year period. Raising the interface export capacity beyond 195 MW would result in very small additional savings. ISO-NE estimated a total project cost of $7 million to $10.4 million.
Detail of Keene Road Constrained Area | ISO-NE
The upgrade would have been eligible for competitive bidding under FERC Order 1000. ISO-NE has yet to implement a request for proposals under the order.
The New England States Committee on Electricity (NESCOE) said the upgrade isn’t worth the cost to consumers.
“First, consumers would fund ISO-NE’s first-time work to implement an RFP and evaluation process,” NESCOE said in comments filed with the RTO last month. “Second, as required by the Tariff, consumers would also have to pay for the incumbent transmission owner to develop a backstop solution. Those unavoidable costs have to be considered in the context of a very small project for which there is no present indication that an economic solution exists.”
Aleks Mitreski of Brookfield Renewable filed comments saying his company “strongly supports” the project. “In addition to production savings, there would be significant added benefits in the added production of non-emitting [megawatt-hours] that would contribute toward meeting state policy goals and GWSA (Global Warming Solutions Act) targets,” he wrote.
Jeff Fenn of SGC Engineering, representing Emera Maine, also questioned Oberlin. “It’s not entirely true that no one has come forward with a solution” for the Keane Road bottleneck, he said.
The Keene Road interface is the 115-kV system that is left after the loss of the Keene Road 345/115-kV autotransformer, Fenn told RTO Insider after the meeting. The interface can be overloaded by the locally connected 115-kV generation, causing a voltage violation upon loss of the autotransformer.
Fenn said the problem could be solved by eliminating some of the generation post-contingency.
One method would be relocating one of the generator leads such that it was lost with the loss of the autotransformer. An alternative would be a generation rejection special protection scheme.
Fenn said either solution would cost less than $500,000, “therefore well within the payback as defined by the ISO economic study. In addition to this, it is probable that one of the generators in the area would be willing to fund the change as the benefit to them would provide a rapid payback.”
However, Fenn said the RTO “determined that the line relocation smelled too much like an SPS, and as such was not allowed to be considered. They also refused to consider the SPS alone as a solution.”
NEW ORLEANS — MISO expects a 19.2% planning reserve margin this summer, well above its 15.8% requirement, and a percentage point above its projection last year, despite predictions of higher-than-normal temperatures.
The figure is also higher than the prediction of 17.4% in the RTO’s resource adequacy survey with the Organization of MISO States. The RTO said the difference was the result of negative load growth and more demand response resources.
| MISO
“We’re seeing a decline in load forecasts and an increase in demand response,” explained MISO Vice President of System Operations Todd Ramey at the March 21 Markets Committee of the Board of Directors meeting.
Independent Market Monitor David Patton said his monitoring staff has calculated a similar percentage.
The RTO relied on data from the National Oceanic and Atmospheric Administration to calculate summer readiness; the agency forecasts higher-than-average summer temperatures in the footprint, with MISO South experiencing the most significant temperature spikes.
| NOAA
Based on the forecast, the RTO expects a 125.1-GW peak demand with 149.1 GW of supply on hand to meet it. Last year, the RTO anticipated a 125.9-GW peak demand and said it had 148.8 GW at the ready for an 18.2% reserve margin. The RTO’s 24 GW worth of reserves are higher than last year’s 23 GW, and beats the requirement by 4.2 GW.
MISO will reveal final reserve margin numbers at a summer readiness workshop sometime in May.
FERC staff have greenlit — perhaps temporarily — PJM’s proposed Tariff revisions to allow increased participation from seasonal resources just in time for the RTO’s Base Residual Auction in May (ER17-367). The order remains subject to refund and further FERC action.
The proposals had been on a 60-day clock that would have allowed them to go into effect on March 24, but staff’s order keeps the door open for additional commission review once it regains a quorum of commissioners. (See “Loss of Quorum Means Filings to Become Effective Unless FERC Staff Acts,” PJM Market Implementation Committee Briefs.)
Mehoopany Wind Farm | Old Dominion Electric Cooperative
The changes relax current rules prohibiting seasonal resources from aggregating across locational deliverability areas. The proposal also provides for additional winter capacity interconnection rights (CIRs) and modifies rules for measuring demand response performance in the winter.
PJM sparked controversy about a highly debated issue among stakeholders when it unilaterally filed the revisions with FERC in October under Section 205 of the Federal Power Act. The commission issued a deficiency notice in December, which PJM replied to in January. (See FERC Wants More Detail on PJM’s Seasonal Capacity Plan.)
While the order notes that protesters argued that PJM’s proposal was “an insufficient solution to the larger problem of the costly and inefficient nature of eliminating stand-alone sub-annual resources,” it nonetheless granted the effective dates PJM proposed: Jan. 19 for winter CIRs and June 1 for DR revisions. Requests for rehearing must be filed within 30 days.
The PJM Board of Managers responded on Monday to accusations leveled by XO Energy in February, defending the grid operator’s practices and denying the up-to-congestion trader’s request that the board disregard rule changes on uplift recently endorsed by stakeholders.
In a long and strongly worded letter to the board, XO President Shawn Sheehan accused PJM staff of having bias against financial-sector stakeholders and actively working to undermine their interests. He was specifically concerned with how the process played out in the Energy Market Uplift Senior Task Force, which recently proposed a phased response to uplift issues. Those proposals were eventually endorsed at both the Markets and Reliability and Members committees. XO had asked that the board not act on the endorsements pending the outcome of FERC’s recent Notice of Proposed Rulemaking on uplift issues. (See UTC Trader Displeased with PJM’s Handling of Uplift Rule Changes.)
PJM CEO and board member Andy Ott responded to Sheehan’s claims in a much more reserved tone March 20, suggesting that Sheehan could meet with Dave Anders, the RTO’s director of stakeholder affairs, to discuss his concerns further. Ott defended the RTO’s stakeholder procedures, noting that it provided technical experts that offered “a significant amount of objective technical analysis” throughout the yearslong development of proposals from the task force.
“PJM’s role is to ensure the market remains efficient and competitive, and to provide analysis and justification if they believe certain market inefficiencies should be addressed,” Ott wrote. “I appreciate that some PJM stakeholders disagree with PJM’s conclusions in this regard, but such disagreements do not make PJM biased or negative toward any particular stakeholder group.”
Sheehan had suggested that PJM staff pushed stakeholders into approving the proposals and didn’t provide enough opportunity for engagement, but Ott noted that the process had been going on for more than three years.
“Clearly, abundant opportunity has been afforded to all stakeholders, including the financial community, to express views, persuade others and offer alternatives,” he wrote. “I can find no basis to adopt the extraordinary remedy you have suggested, which would table and disregard the expressed preferences of a very sizeable majority of the PJM members.”
The MRC and MC endorsed proposals for phases 1 and 2 of the uplift response. Proposals for a third phase are still being discussed at the task force level and haven’t been brought for discussion at any of the standing committees.
CAISO staff expect to submit a proposed black start procurement proposal to the Board of Governors in May, officials said Tuesday.
The ISO launched an accelerated procurement effort in January after identifying the need for additional black start resources in the transmission-constrained San Francisco Bay Area. (See CAISO Kicks Off Effort to Procure Black Start Resources.)
CAISO kicked off the black start procurement initiative to obtain resources equipped to restore the transmission system in the San Francisco area in the event of a blackout. | SF Travel
“I’m not expecting [that] we’re going to have significant Tariff changes for purposes of this initiative,” Andrew Ulmer, CAISO director of federal regulatory affairs, said during a March 21 call to discuss a draft final proposal that deviated little from the approach laid out in the initial proposal. (See CAISO Proposes TO-focused Black Start Procurement.)
Ulmer added that the ISO hoped to make draft Tariff language changes available to stakeholders ahead of the board vote.
The black start initiative represents the second phase of a 2013 undertaking to address NERC reliability standard EOP-005-2, which required transmission operators to draw up plans for system restoration in the event of widespread blackouts.
The ISO’s plan envisions the significant involvement of an affected transmission owner in selecting a black start resource, both in drawing up technical specifications and vetting proposals from those resources that bid into the solicitation.
Based on stakeholder feedback, CAISO settled on a cost-of-service approach to compensating the resource, rather than providing a capacity-type payment sufficient to support the operation of an otherwise unprofitable generator.
The payment would allow for recovery of capital and fixed operations and maintenance costs plus a “reasonable margin” for the resource owner, according to Scott Vaughan, lead grid assets manager at the ISO.
The proposal calls a resource to be contracted under a three-party agreement between the ISO, the local TO and the resource’s owner.
Paul Nelson, electricity market design manager at Southern California Edison, sought more details about the nature of the agreement — specifically the extent of the TO’s responsibility.
Ulmer explained that CAISO expects that any black start resource procured under the process would not only become part of the ISO’s system restoration plan but that of the TO as well.
“It makes sense to us to have a three-party agreement with ISO, the black start resource and the participating transmission owner … ensuring we have evidence that we secured the capability for the [NERC] reliability standards.”
“So … there’s three roles — the ISO, the black start resource and the transmission — and all three in conjunction need to provide certain services and responsibilities, and the contract will lay out what those are and who’s responsible for the roles and responsibilities and the costs,” Nelson offered.
“Yes, that’s correct,” responded Ulmer, adding that in April, CAISO intends to release a sample contract for stakeholder review.
CAISO also plans next month to publish draft technical specifications for black start resources, followed by a stakeholder meeting on the subject during the second half of May. During the first half of June, the ISO expects to issue a request for proposals for resources in the San Francisco area.
Stakeholders should submit comments on the black start draft final proposal to the ISO by April 4.
CARY, N.C. — SPP cannot absorb much more wind power within its footprint, CEO Nick Brown told the RTO Insider/SAS ISO Summit last week.
“I believe we’re at a saturation point in terms of the appetite of load within our footprint to want more wind,” said Brown. “How much is too much? I think we’re nearing that, although the [generator interconnection] queue is still full and we are seeing more and more and more wind interconnected. So what happens when we can’t accommodate anymore? We’ll curtail it for reliability reasons.”
On March 14, the day of the panel discussion, SPP was getting 55% of its electricity from coal, with about 18% each from wind and natural gas and 7% from nuclear.
On March 19, the RTO announced it had set a new wind-penetration record of 54.22% early that morning, with 12,078 MW produced.
“How can it keep growing? … There is going to have to be a demand for wind outside our footprint. And so far, we’re not seeing requests for that. We’re not seeing people come in to our transmission queue and say ‘I want transmission service to move wind from the western part of SPP footprint the east or to the west,’” Brown said. “[Wind] is incredibly efficient in how its produced, but if we don’t see that demand to the eastern load centers, it will saturate.”
The variability of wind has provided its own challenges.
On some days, SPP has seen 10,000 MW of wind disappear and reappear. “That’s the equivalent of 10 nuclear units,” Brown noted. “We are becoming so much more dependent on big data. Tons and tons and tons of granular information from all the wind in the footprint across 14 states.”
Update on Expansion
That footprint may be expanding with the potential addition of the Mountain West Transmission Group, a partnership of seven transmission-owning entities within the Western Interconnection, including the Western Area Power Administration’s Loveland Area Projects and Colorado River Storage Project. (See Mountain West to Explore Joining SPP.)
“As we continue to work through the details of integrating them into our wholesale markets, it will create new technical challenges operating a market across two interconnections tied together by four DC ties,” Brown said.
Brown said SPP has considered both operating two separate markets and solving a single market across the two interconnections. “We’re mostly leaning towards a single [market] across the entire footprint constrained by the DC ties,” Brown said.
CARY, N.C. — Thanks to smart meters, phasor measurement units (PMUs) and the forecasting challenges of renewable generation, utilities and RTOs are becoming increasingly voracious consumers of data.
“Instead of getting SCADA data every four seconds,” notes Stephen Rourke, vice president of system planning at ISO-NE, “we’re getting PMU data every two cycles.”
But some are not using the information as well as they could, speakers said at the RTO Insider/SAS ISO Summit at SAS headquarters last week.
“The amount of operations data that’s being created is just incredible,” said Bill McEvoy, industry principal for OSIsoft. “And a lot of it is still being created in silos.”
That’s a mistake, said Jill Dyché, vice president of best practices at SAS. While many companies perform only “random acts of analytics,” forward-thinking organizations have created analytics “Centers of Excellence,” she said.
“Analysis is a collection of very distinguished skill sets that may not exist elsewhere in the organization, so there’s an argument for leveraging those in a sustained way through some kind of COE or marketplace,” she said. “For energy companies, the potential is not just in optimizing our business but also becoming data businesses. There’s a huge potential in using our data in fresh new ways.”
Data Quality
Most companies fail to measure the cost of poor, missing or inaccurate data. “Typically when I get a ‘yes’ on that question, it’s after the fact,” Dyché said. “We realize that a business initiative failed because we didn’t have the data, or the data was wrong,” she said. “Data quality can make or break some pretty serious decisions these days.”
“I think it’s wise to watch where your numbers come from,” said Brad Lawson, a SAS industry consultant. “Working in the utility industry, we could never get customer numbers to match. You went to one group and there was a customer count of whatever. The next group may be 10,000, 15,000 more. So we finally got a group together to talk about, what is a customer? What we found within this utility was that we had about seven different definitions of ‘customer.’”
Similar disparities exist in data on solar capacity and generation, he said, complicating utilities’ forecasting challenges.
Forecasting EV Charging
Electric vehicles are a growing concern for utility forecasters, particularly in California, which has more than 40% of the EVs in the U.S.
“The utilities would like to be able to manage that charging,” said Ralph Masiello, senior vice president of Quanta Technology. “In other words, if everyone comes home from work [and] plugs the car in at 6 p.m., that’s right when that duck curve is ramping the worst. So it’s the last time that you want another 1,000 MW of EV charging.
“The big data need for the utilities is how do they know when those customers are going to plug in? And the answer is they’ve got to monitor [the California Department of Transportation] for traffic conditions. Because a traffic accident on Interstate 405 can mean 1,000 Teslas plugging in a half-hour later than they normally would.”
Data Volumes Taxing Hardware
As one of the biggest users of data analytics at ERCOT, Manager of Demand Response Carl Raish is looking forward to a refresh of the ISO’s hardware platform. “I’m hopeful that this hardware change is going to make my life better. I’ve done what I could with software in terms of trying to leverage capabilities that are in SAS to make code run better. But it’s really the volumes of data [that are challenging] at this point.”
Helping to provide answers to RTOs’ challenges is the Electric Power Research Institute. EPRI’s Market Design research group has created webcasts and an ISO/RTO Market Design Tech Forum, in which technical market designers discuss the challenges of changing markets. Its Market Design and Operations Research Program provides analytical support for research projects.
Erik Ela, senior technical leader of EPRI, said the organization is tackling the industry’s biggest research and development challenges, including providing adequate compensation to prevent retirement of resources that are not used often; incentives to encourage system flexibility; pricing schemes; and incorporating policies that favor technologies for reasons other than cost.
ISO markets currently dispatch resources based on reliability and cost, Ela noted.
“But there are a lot of other things that we don’t do at the ISO. We don’t have an environmental [input in market clearing engines]. We don’t care about job preservation. … Fuel diversity is very hard to quantify. So there’s a lot of these other aspects out there that a lot of the states have a lot of incentive to try to keep … [But] that’s not built into the way we clear our markets.
“So how do we interact with these policies in the way that we are running the markets? That’s a big area and [one] I think that we’ll see more and more questions about.” (See related story, Ott Seeks ‘Resilience’; Clark Handicaps ZECs.)
CARY, N.C. — Despite a late spring Nor’easter that closed airports and forced some speakers to participate via phone, dozens of RTO and ISO officials journeyed to SAS’ snow-free campus in North Carolina last week for a discussion on data and technology challenges. Here’s some of what we heard at the RTO Insider/SAS ISO Summit.
Duck Curve, Meet Armadillo Shell
The duck curve — which came out of California to describe the ramping challenge provided by solar resources — has since been adopted as a term by other regions, including ISO-NE. (See “New England’s Duck Curve,” Overheard at NECA Renewable Energy Conference.)
But not in Texas, if Kenan Ögelman, vice president of commercial operations for ERCOT, has his way. Texas, which has led the nation in wind development, is starting to make strides with solar as well.
So Ögelman is pitching an alternative description: an armadillo on its back. “The belly of the duck is the shell of the armadillo,” he explained.
As in California, solar generation stops just as demand is rising to its daily peak. But Texas’ width may make it a bit easier to manage the ramp. “Because most of our load centers are in the center and the east … of Texas, and most of the highest potential solar is in the west, we might be able to buy ourselves … an extra hour there potentially because Texas is so big.”
When solar is wanting to dispatch and use the grid, that isn’t necessarily overlapping with wind as much so there might be some … complementary ability to use the grid.”
California, meanwhile, will be releasing a new version of the duck curve soon, said Lorenzo Kristov, principal for market and infrastructure policy for CAISO.
The new curve is necessary, Kristov said, because solar has grown so fast that the duck curve is playing out four years ahead of projections.
“We actually hit 11,000 [MW] net load last year — that’s just below what we forecasted for 2020,” he said. “And we actually hit this very steep ramp — the 13,000 [MW] that was … the projection for 2020 — we hit it in December 2016.”
The California Energy Commission’s 20-year forecast for rooftop solar adoption is updated every two years. “And invariably the forecast they did two years ago is way lower than the forecast when they revise it two years later,” Kristov said.
One other development: Peak demand is coming later in the day. “The solar starts to reduce the magnitude of the normal peak hours, leaving a residual peak that happens a little bit later because the air conditioning is still running, but the sun has now gone down,” he said.
RTOs, Retail Choice Help Walmart Meet Renewable Goals, Cut Costs
As Walmart’s director of markets and compliance, Chris Hendrix is charged with controlling energy costs while meeting the retail giant’s goal of obtaining half of its electricity needs from renewable power by 2025.
That has led the company to set up its own energy supply company to power its 4,500 Walmart and Sam’s Clubs locations in the U.S. It also has invested in more than 400 renewable generation projects, including wind in Texas and solar in California, Arizona, Massachusetts and Connecticut. “In ERCOT, about 30% of our load is [served by] wind. It’s going to grow over time,” Hendrix said, citing two projects under construction.
“Not only are we buying power, we’re also a market participant in all the ISOs. … We have a retail supply license in 11 states, plus the U.K. We just act like everybody else, your Direct Energy, your Constellations of the world. The only difference is … I don’t have a sales force and I don’t have customer parallel on the backside.” His customers are the store managers.
“Every single market, every single co-op, every single utility, we’re there. So we have a good cross-section of the U.S. markets,” he said. But only ISO/RTO markets and states with retail choice give him all the tools he needs to do his job, he said.
“The only way that we’re able to buy large-scale renewables is through an ISO,” he said. And ISOs and RTOs with retail choice provide transparent LMPs that allow price hedging.
“Where we run into problems is in parts of California, where we don’t have choice, [and] SPP [and] MISO, where we’re exposed to an average price. It may not even be a time-of-use price. … So that’s not really setting the right price signal for us to implement renewables or energy efficiency or demand response, because all I have is a flat price of 7 cents/kWh.”
Alberta Capacity Market to Create New Forecasting Challenge
There will soon be one less energy-only market in North America. The Alberta Electric System Operator is planning to introduce a capacity market to ensure it has sufficient firm generation supply as the province seeks to add renewables and eliminate coal generation by 2030.
That means new challenges for Steven Everett, forecasting manager for AESO.
“Whether it’s two or three or five [years] — or however many years out our capacity market is — our load forecast will determine what will be the size of that market,” he said. “So there’s going to be new layers of scrutiny on that forecast.”
NYISO Teaching QA Staff Hacking Skills
No electricity conference is complete without a discussion of cybersecurity. Top technology officials from PJM and NYISO took part in a conversation with moderator Stu Bradley, vice president of SAS’ cyber business unit.
Jonathon Monken, senior director of system resiliency and strategic coordination for PJM, noted that an RTO’s challenge is different from that of utilities.
“We are very, very [information technology] heavy. We have a very small amount of physical infrastructure at PJM and a massive IT infrastructure. What that means … is that the attack surface area is significant. It’s huge.”
NYISO Executive Vice President Rich Dewey, who oversees operations, markets and information technology, said the ISO is spending more on training to enhance its defenses and address the shortage of IT security experts.
“Typically in the energy space, 5% of your IT budget is kind of the norm [for training]. … We actually spend probably a higher percentage of our budget on training in the security space. We look at it from two areas: One is trying to close that skill gap of trying to find qualified individuals on the market. There’s not a lot of them.”
The ISO also is training some of its quality assurance team, which tests software before it is put into production, “how to hack,” Dewey said.
“Every time we’re getting ready to put a new piece of software into production, they try to break into it. They try to go through the standard list of the most well-known vulnerabilities and try to see if they can actually get into the system and compromise the security of the system.
“It’s been kind of eye-opening. … We’ve taken delivery of production-ready software. We set it up in our QA environment, we let our QA guys loose on it and before you know it we’ve discovered five or six vulnerabilities — pretty common vulnerabilities — that they didn’t even realize that their own software had. And we work with them to patch those [holes].”
Monken said the electric industry is working with the Defense Advanced Research Projects Agency (DARPA) on a “rapid attack detection and characterization system” for industrial control systems. “That’s something that [the Defense Department] has the money and time to invest in because they see it as a threat factor for national defense. It might not be a tool that we use with great frequency, but being able to provide some tactical expertise from the industry side to the development side tool is something that has significant benefits to us later on as that moves past the prototype stage and into something that can be utilized in the industry.”
North Carolina Utilities Commissioner ToNola Brown-Bland said those seeking regulatory changes to accommodate new technologies should consult with regulators to seek tailored solutions.
“The lawyers in the room and the regulators don’t want to be ‘No.’ We want to help get to ‘Yes.’ But … the current regulatory regime [has] served us very well. … You don’t necessarily want to throw it [all] out.”
Solar for All: San Antonio’s Strategy
Tim Fairchild, director of SAS’ Global Energy Practice, asked CAISO’s Kristov how to make solar more than what Microsoft founder Bill Gates has termed “a toy for rich people.”
“There are a lot of things that don’t make sense from a societal perspective, one of them being the incentive to size your solar installation to the needs of your house,” responded Kristov. “Many houses have shade trees. We don’t want you to cut down shade trees to put on solar panels. But if you have sunny rooftops, why not make those a resource for the entire community, sized to the maximum size you want, and sell the excess?”
That’s the approach San Antonio’s municipal utility has taken. “Essentially, they viewed all sunny rooftops as an asset and they paid for the solar panels — paid rent in the form of a per-kilowatt-hour [fee] to the residents of the house. And then all the energy generated just became part of the supply resource portfolio of the utility.”
Storage
Although California was the first state to mandate utilities obtain energy storage, the “value stack” compensation method for DER is still a “work in progress” at the state Public Utilities Commission, according to Kristov. New York regulators this month introduced the “value stack” concept to replace net metering for distributed energy resources. (See NYPSC Adopts ‘Value Stack’ Rate Structure for DER.)
“If [storage is used] for peak shaving and capacity deferral on a distribution feeder — to put off the day when you upgrade the conductors — you need to be able to use it off-peak on something else to get a little extra funding for it,” said Ralph Masiello, senior vice president of Quanta Technology. “You see that in study after study. One or 2 or 3% of the feeders can be justified on capacity deferral alone. But if you can do the capacity deferral plus time arbitrage year-round — even when you’re not overloaded — then the economics improve to 10% of the feeders or more.
Meanwhile, “storage is on a declining cost curve, as PV was, and it will become more and more attractive for more applications. Today we’re adding storage to the market models in an incremental fashion — not changing the paradigms; making it look like a generator. But if we thought more broadly and towards the future when it was cheaper and more plentiful, this needs to be part of a capacity planning exercise. Ask the question: How much storage is good, is right, for a given market?”
Kiran Kumaraswamy, market development director for AES, foresees storage displacing peaking plants with 4 to 5% capacity factors. “Based on what we’re seeing in the solar space, I think there’s going to be utility-scale storage and there’s going to be consumer storage as well,” he said. “Exactly to what level it’s going to happen in the future is anybody’s guess.”
Plug for EIA
The Trump administration’s proposed federal budget announced last week would cut the Department of Energy’s spending by 6%. Chuck Newton, president of Newton-Evans Research, said it is essential that the department protect its Energy Information Administration. “It’s very important that we give good data to Congress,” he said. EIA “has to continue in place.”
CAISO’s Board of Governors last week approved an ISO request to designate two Calpine natural gas-fired plants in Northern California as reliability-must-run despite criticism from several stakeholders. Acknowledging concerns, ISO officials pledged to avoid “case-by-case” designations in the future.
At the board’s March 15 meeting, Carrie Bentley, a consultant speaking on behalf of the Western Power Trading Forum (WPTF), said the organization “does not at all oppose” designating the units as RMR.
“Obviously, though, after years of the ISO saying they’re not going to use the RMR Tariff authority anymore — and that they’re going to rely on the capacity procurement mechanism — we were really surprised,” Bentley said.
CAISO sought RMR designations for Calpine’s Yuba City and Feather River plants after determining that both 47-MW peaking facilities would be needed to support local grid reliability after they fall off their current contracts with Pacific Gas and Electric at the end of the year. (See CAISO Seeks Reliability Designations for Calpine Peakers.)
CAISO’s Board of Governors approved reliability must-run designations for Calpine’s Yuba City and Feather River peaking plants after the December 2017 expiration of their contracts with Pacific Gas and Electric. | Calpine
Calpine had informed CAISO in November that capital planning requirements required that it be apprised of any reliability need for the plants before this fall, when the ISO releases its 2018 resource adequacy (RA) assessment. The assessment will determine what plants would be eligible for longer-term resource adequacy payments under CAISO’s capacity procurement mechanism (CPM).
‘Purgatory’
“When a unit is facing retirement, or a continued need for operation, we’re in a state of purgatory,” Mark Smith, Calpine vice president of government of regulatory affairs, told the board. “We’re in a position where we can’t make investments that we know that we will never recover and we may not be able to take actions to redeploy those assets elsewhere where they might be more valuable.”
Neil Millar, CAISO executive director of infrastructure development, emphasized that the ISO would seek to implement the RMR contract for Yuba City only if it is not shifted into the CPM program following the assessment.
Feather River will not be eligible for a CPM designation because it is not needed for capacity but to provide voltage support for its local area by absorbing reactive power from the system. Millar said the ISO is working with PG&E to develop “longer-term mitigations” on both the transmission and distribution to come up with a way to reduce reliance on gas-fired generation for voltage control in the area.
“We do need a better process moving forward than bringing these [RMR proposals] forward on a case-by-case, one-off basis,” Millar said.
Bentley recounted recent steps taken by CAISO that should support RA prices, including submitting comments to the California Public Utilities Commission supporting a reduction in the amount of wind and solar that can count as RA and a 2018 local capacity requirements study showing increased capacity needs in some local areas.
“WPTF therefore encourages the board and ISO leadership to take this as an opportunity to step back and ask if there’s anything else the ISO already has Tariff authority to do to help orderly economic retirement and support the RA bilateral market prices,” Bentley said. “A turnaround in prices can only occur in a functioning bilateral RA market.”
‘Sufficiently Visible’
For “sufficient prices” to materialize, Bentley contended, market signals must be “sufficiently visible” to both suppliers and load-serving entities.
Eric Eisenman, director of ISO relations and FERC policy at PG&E, agreed that there was a reliability need for the two plants and that the ISO was the “appropriate venue” for addressing the matter.
“With that said, PG&E encourages the ISO to work with stakeholders [and] PG&E to enhance and improve the process for analyzing and reviewing risk-of-retirement issues for generation,” Eisenman said. “The expedited process of the last two weeks was, quite frankly, not ideal. We all need to do a better job at that.”
Eisenman said his company wants to more closely examine the trade-offs between the CPM and RMR processes.
“I’m actually encouraged by what I’ve heard here today — to some extent,” said Jan Strack, transmission planning manager at San Diego Gas and Electric, adding that the RMR matter was something warranting a deeper look.
Strack noted that the ISO has a lot of aging gas-fired generation. “We’ve got to figure out a way to let that stuff go,” he said, adding that RMR contracts should be “a measure of last resort.”
“In the current instance, I think we feel there has not been enough light shined on all the various alternatives that could be looked at, rather than just going into an RMR contract,” Strack said.
Millar called the Feather River decision “strictly a matter of timing,” with the RMR providing CAISO time to determine the best solution for local voltage support.
“Putting it bluntly, three months with no opportunity for any stakeholder process doesn’t give us that time,” Millar said, referring to the “compressed timeline” in which the ISO needed to notify Calpine about the RMR decisions. The company had requested a decision by the end of March in order to have adequate time to draw up a cost-of-service proposal and perform the required capital maintenance.
Signs of Market Failure
| CAISO
Governor Ashutosh Bhagwat wondered if there were any other ISO mechanisms available to ensure the plants’ availability other than RMR.
Keith Casey, CAISO vice president of market and infrastructure development, said the RMR option provided CAISO more flexibility in dealing with Calpine’s near-term need to make capital investments than the CPM, which functions as the ISO’s standard “backstop” for needed plants at risk of retirement. Still, Casey said it would be “unfortunate” for the ISO to find itself facing a “proliferation” of RMR agreements.
“If we now find ourselves ramping up in that, that’s a sign we have a market failure,” Casey said.
CAISO CEO Steve Berberich said the RMR issue was “symptomatic” of the fact that the RA processes that both the ISO and PUC have in place “are starting to fray at the edges a little bit.”
“Of course, the ISO has advocated for a longer-term resource adequacy program so that we don’t have this year-by-year emergency situation that we always have to go through,” Berberich said.
Berberich pointed out that the current RMR issue is part of an “evolving grid.”
“Take a step back — why is voltage high at Feather River?” Berberich asked rhetorically. “The voltage is high because of light-load conditions. We have substantial distributed generation on the system.”
He suggested that the voltage issue — rooted in distribution-level changes that are affecting the low-voltage network — could possibly be better managed by a distribution-level solution rather than a transmission-connected resource such as the Feather River unit.
“This is a very complicated issue,” Berberich said. “I’d like to tell you that this is the last time we’re going to talk about RMR, but I don’t think that’s going to be the case.”
In a long and strongly worded letter to the board, XO President Shawn Sheehan accused PJM staff of having bias against financial-sector stakeholders and actively working to undermine their interests. He was specifically concerned with how the process played out in the Energy Market Uplift Senior Task Force, which recently proposed a phased response to uplift issues. Those proposals were eventually endorsed at both the Markets and Reliability and Members committees. XO had asked that the board not act on the endorsements pending the outcome of FERC’s recent Notice of Proposed Rulemaking on uplift issues. (See 
