As I walk the halls of National Association of Utility Regulatory Commissioners meetings, I hear a lot about the “grid of the future” or “grid modernization.”
Thomas
According to the North Carolina Clean Energy Technology Center’s “The 50 States of Grid Modernization” report, more than 30 states are exploring “grid modernization” to various degrees. New York is knee-deep in Reforming the Energy Vision, Ohio is doing “Power Forward” and Illinois is pursuing “NextGrid.” These are all terrific initiatives, and these state’s utility commissions should be applauded for their efforts to proactively realize that the traditional electric utility service business model is changing and unless utilities and regulators get in front of certain issues, consumers will ultimately pay the price later.
These grid modernization efforts are driven by several factors that stem from technological innovations changing consumer needs for electricity in the face of aging infrastructure. While different states have different dynamics and different solutions, they are fundamentally addressing the same challenge. Fortunately, these challenging circumstances are leading to creative thinking and solutions that are more than just throwing money at the problem.
Changing Dynamics
Similar to these state-led efforts that focus on the retail electric delivery system, a parallel re-examination of our wholesale energy markets is long overdue. For a variety of reasons, the dynamics in our wholesale markets are changing. Flat peak consumer demand year over year, low-cost natural gas-fired generation, the proliferation of subsidized intermittent resources (with no fuel costs) and an increasingly flat supply stack, combined with market rules that have not kept pace, have all contributed to a wholesale power market in which units that produce relatively inexpensive power and are needed for reliability are in significant financial stress and at risk for closure.
Just last month, Energy Secretary Rick Perry recognized that the power industry “has experienced massive change in recent years, and government has failed to keep pace.” The much anticipated Department of Energy “Staff Report to the Secretary on Electricity Markets and Reliability” called for FERC and RTOs to reform market rules in order to promote grid resilience and proper energy price formation. In many respects, the DOE report recognizes that if certain low-cost plants do not receive proper price support in the current market, those plants will likely retire, leading to higher costs to consumers over the long term.
Energy price formation is not a new issue, and FERC has taken positive steps to improve it over the last several years. FERC, through Order 825, has made significant changes to the settlement of energy transactions and the triggers for scarcity pricing. PJM and the other RTOs are in the middle of implementing these reforms. While their impacts have yet to be realized, they nonetheless offer great promise.
Energy Price Formation 2.0
While the reforms to date have been important, it is time for the next step — Energy Price Formation 2.0, if you will. As a result of technological advances and current market conditions, PJM has a glut of units that participate in the market at roughly the same low price. LMP was developed based on a supply stack and a sloped supply curve, but today’s supply “stack” looks more like a flat piece of glass. In today’s market, new natural gas combined cycle plants, baseload coal plants and most nuclear plants can produce power at prices that by historical standards would be considered a bargain.
The fact that there is a bounty of low-cost resources available to meet demand means that prices will be less volatile and costs to consumers of electricity will be lower over time. The last two summers in PJM bear witness to the fact that high temperatures and higher-than-normal demand did not lead to significant upward pressure on electricity prices in PJM (see chart below).
| PJM
As a result of these current market conditions, it takes longer for those higher-cost peaking plants to be dispatched and set the energy price. While good for consumers at the present moment, if market rules are not altered, consumers will lose the benefits associated with the plethora of low-cost resources, as those resources will be forced out of the market because of insufficient revenues. In such a scenario, higher-cost resources will move closer to the front of the supply stack, run more often, set the clearing price at a higher level and cost consumers more over time.
Clock is Ticking
PJM has suggested a series of energy market reforms to allow consumers to continue to benefit from this abundance of low-cost resources. PJM has proposed that energy prices should be set by the units that are running to serve consumer needs and unit flexibility should be rewarded, not punished. The current rules do not do this and instead rely on out-of- market payments to specific operationally constrained, low-cost units that must run for reliability purposes. Ultimately, such a regulatory paradigm does not send the appropriate price signal to either the flexible or inflexible unit. While such a market design may have worked against an actual supply stack with material differences in price among resources, it falls short in the current “flat” market.
The wholesale power market of today is not that same as the wholesale power market of 10 years ago. To date, wholesale markets have delivered enormous value to consumers. In order for the value to continue for the next 10 years, regulators, consumers and other stakeholders need to recognize and respond to the changes that are already here. The clock is ticking. We all need to get to work.
Glen Thomas is president of PJM Power Providers Group (P3), which represents independent power producers.
AUSTIN, Texas — Renewable energy developers, energy providers, end users, renewable manufacturers and others gathered last week for the Infocast Texas Renewable Energy Summit, where attendees heard discussions on the challenges ERCOT faces in building transmission, adding renewable resources and ensuring grid reliability. Here’s some of the highlights.
No CREZ in Sight for Permian Basin’s Energy Production
A rebound in oil and gas production in West Texas’ Permian Basin has prompted a call for more transmission, but Texas is unlikely to repeat the $7 billion Competitive Renewable Energy Zone (CREZ) transmission investment, speakers said.
Midstream load has “come alive again” in the Permian, said Brad Schwarz, Hunt Power’s director of system planning. He said that has led to producers wanting to access the grid with “a significant amount of load” — 15 to 20 MW — within about a year.
“In an area that is typically not meant to serve that amount of load, just getting through ERCOT’s approval process will take that 12 to 18 months,” Schwarz said.
“Let’s say it does take 18 months [to plan a transmission line]. Those … companies can’t wait, so they’ll self-generate just to” be able to process and ship their output, said GridLiance’s Brian Gedrich, vice president for the independent transmission company’s South Central Region. “Once they’re self-sufficient, what’s the justification for building transmission? Building transmission may be the best answer, but is it the best answer for consumers when they’re already generating?”
Cratylus Advisors’ Mark Bruce, who is working with Pattern Development on its Southern Cross Transmission Project, noted the inconsistency between the legislative push behind the CREZ initiative and a similar effort to address the Permian Basin. The years-long CREZ effort resulted in the construction of 3,600 miles of transmission with capacity to deliver 18.5 GW of wind power across the state.
“The thing about CREZ that made it so special is the government said, ‘We will build it, and you will come.’ It provided a mechanism for parties that all had risk but couldn’t solve for that risk,” Bruce said.
“I find it interesting in Texas, where policymakers are allowed to make market judgements, the [Public Utility Commission] is tying its own hands to say we’re done with this CREZ stuff. There are mechanisms in place to address those timeline issues. If there were to be a planning process to serve this future generation in an economically viable way, to maximize [solar] generation and also benefit the oil and gas industry in the process, why wouldn’t you build it all?”
Bruce and Jeff Billo, ERCOT’s senior manager of transmission planning, agreed that with or without another CREZ-like development, ERCOT will continue to see growth in its solar power. The ISO currently has almost 1 GW of solar capacity, and the interconnection queue has more than 200 MW of planned capacity with signed agreements.
“The economics [for] solar transmission additions are much better than for wind,” Billo said. “There are a couple of reasons for that. Every day the sun is shining, it’ll be at its nameplate capacity. The dollars for congestion … add up quickly [for solar]. If you have a solar plant that’s constrained, it’s constrained every single day during peak demand. From a planning perspective, it’s easier to justify transmission for solar than wind.”
“Solar is going to start finding its way, as the economics are there,” Bruce said. “The real challenge is the market fundamentals aren’t moving, unless the gas price moves. If the fundamentals of the [generation] stack doesn’t shift, you’re going to see policymakers putting their thumbs on the market over the next six to eight months.”
Bruce said he was referring to efforts by NRG Energy and Calpine to persuade Texas regulators to “ratchet up” the effect of the operating reserve demand curve to push prices higher. Regulators could also adjust marginal loss calculations to harm remote wind and solar generation and help generation in load pockets, such as gas plants in the Houston area, he said.
Genscape’s Hudson Gilmer said RTOs are making a mistake by continuing to address new intermittent generation with traditional transmission solutions.
“It’s not an accident we continue to build transmission the way we have for the last 75 years. The planning process and the stakeholder process are designed to build more transmission,” he said. “The transmission planning hasn’t evolved [along with generation]. We’ve got to get smarter in planning for system growth. Other solutions, like dynamic line rates or convertors, are so much more effective than building CREZ like we did years ago.”
Billo said things are better than 2011 and 2012, when the fracking boom “sort of took everyone by surprise.”
“There are fundamental differences now in the time frame it takes to build transmission,” Billo said. “I give a lot of credit to the [transmission and distribution providers] out there. What we see today that we didn’t see five years ago is they have a lot better relationship with their customers that fosters communications that helps the planners and utilities … we’re a lot better off than we were.”
Texas PUC Commissioner Brandy Marty Marquez recalled when wind generation was limited to barren West Texas and the state legislature set a wind capacity goal of 2 GW.
“Looking back at the original goal … you might call it adorable,” Marquez said in her keynote address.
However, thanks to the CREZ and Texas’ insatiable demand for energy, ERCOT has almost 20 GW of wind energy at its disposal, some of which can now be found along the Gulf Coast.
“We’ve exceeded the capacity found in any other state, and almost every other country,” Marquez said. “It was a labor of love for our state.”
Marquez noted the transmission buildout has led to other benefits as well, pointing to more than 24,000 jobs the Department of Energy says the wind industry has created and $85 million in annual revenue to ranchers and farmers for turbine leases.
She said the PUC, like ERCOT, will remain fuel-neutral, however. “The market will drive the agenda and be the ultimate arbiter of fuel use,” Marquez said.
Garza: No ‘Price Collapse’ in ERCOT’s Market
Although ERCOT averaged real-time prices of only $24.62/MWh in 2016 — an 8% drop from the year before and the lowest since the nodal market’s implementation in 2010 — it’s incorrect to call it a “price collapse,” said Potomac Economics’ Beth Garza, who leads the ISO’s Independent Market Monitor. (See “IMM Offers Additional Suggestions to Improve Markets,” ERCOT Briefs.)
“I don’t believe [price collapse] is a fair and accurate assessment,” Garza said. “Prices are lower, but price collapse says they were unsupported at high levels somehow. It’s more a reflection of the conditions we have, [with] very low natural gas prices and the changing composition of the energy being produced.”
Garza noted wind energy accounted for 15% of ERCOT’s generation mix last year, a number that has jumped to 21% in the first half of 2017. The extra capacity and low prices masked the fact that ERCOT set a record for peak demand last summer. That was unlike 2011, when record heat led to large price spikes.
“Since 2011, we’ve seen over 17 GW [of new energy] come into the market, and with very few [fossil fuel] retirements,” said Filsinger Energy Partners’ Tim Wang said. “Last year, we had record heat and record peak demand, but prices stayed flat. That’s the state of the market right now. There’s plenty of capacity.”
That has caused problems for owners of uneconomic units, such as Dynegy. Though Tudor, Pickering, Holt & Co. analyst Neel Mitra has told investors he regards the company as one of the country’s top independent power producers, Dynegy has had problems selling its assets.
“Everything in ERCOT is up for sale right now,” Dynegy’s Bob Helton said.
“What’s your price, Bob?” Garza asked Helton.
“Apparently, it’s pretty high,” he responded with a laugh.
Helton said those economics are pushing owners of some aging plants to save money by reducing maintenance expenses. “You’re going to run it until it fails,” he said. “Do you announce a retirement before that happens, or do you have a major tube leak or something that requires a high-dollar investment?”
“A large amount of that [recent plant] construction took place at the turn of the century,” Garza said. “A lot of those units are about 15 years old. That’s half their expected life.”
“How do you get more money to the market?” Wang asked. “After 2011, there was a lot of conversation around resource adequacy and a capacity market. As the new capacity has come on, the market has responded with those low prices, and all that conversation has died down. To a certain extent, you have to be proactive. If it gets to the point where you have retirements, demand spikes and prices go up again, will the market respond to a one-year price cycle? Or will it return to its senses and say, ‘We did this before. We’re not going to do it again.’”
Conventional Generation Playing ‘Chicken,’ Trying to Hang on
With economic headwinds making it difficult to build conventional generation, Chad Blevins, a senior consultant for The Butler Firm, said owners of existing plants are holding on as long as they can. He pointed out that unless one works for the generation owners, it’s difficult to determine what their cash positions are.
“There’s a lot of games of chicken going on here between these utilities,” he said. “‘As long as we lose money while the other guys lose money, we’re good. If he goes under first, that will help lift up the market just enough so I’ll be good.’ They want to hang on as long as they can, so they have that physical option until the other guy pulls out of the market and they’re clearing at a better price.”
NRG’s Mark Walker, speaking on the same panel discussing investments in traditional generation, said there’s still a need in ERCOT for flexible resources that can supplement intermittent renewables. “Several projects are being delayed, but if we’re going to make some [market design] changes, now is a good time before we get to a crisis situation,” he said.
Walker also said that if ERCOT had a local reserve product, expensive efforts like the $590 million Houston Import Project might be avoidable.
“Right now, ERCOT only has one tool in its toolbox [to address local reliability], and that is building transmission,” he said. “Had we had a local reserve requirement in the Houston area, we might have had enough to avoid a project the size of that one.”
Technological Improvements Leading to more Efficient Renewables
A panel of wind energy developers discussing the forces driving their market agreed that the recent influx of wind has been driven by larger and more efficient turbines. Technological advances will continue their influence going forward, they said.
“Technology has definitely played a big role, and it’s going to play a larger role in opening up new areas,” said Phil Moore, vice president of development for Lincoln Clean Energy. “We’ve had a huge amount of transmission buildout in the last decade, but it’s going to be tougher going forward. Technology is going to have to bridge that gap in opening up less-than optimal areas.”
“The projects I’m seeing starting construction are in areas I never would have dreamed as being economical in ERCOT,” said Ward Marshall, Pattern Development’s senior director of business development. “Texas has been an unbelievable dumping ground of [federal tax credits]. A lot of projects have been built from that standpoint, but now we’re flooded with immense amounts of low-cost, cheap power.”
Marshall took the opportunity to plug Pattern’s Southern Cross project, saying it “will have some effect on draining the swamp.”
ERCOT’s Paul Wattles and the Sierra Club’s Cyrus Reed looked at demand growth in Texas through different lens colors during a discussion on behind-the-meter energy resources.
“Per capita load growth is flat, like it is everywhere,” said Wattles, the ISO’s senior analyst of market design. “Our growth is coming from the industrial sector and oil and gas growth in West Texas and the Gulf Coast. We’re going to continue to see load growth in ERCOT, but not necessarily [per capita growth] because — like the rest of world — we’re becoming more efficient.”
“We continue to get people moving in here, we continue to have housing starts of 100,000/year,” Reed said. “Sierra Club is pushing that building codes be solar friendly at the local level, so even if rate cases go the wrong way, there will be opportunity for growth.”
Of course, distributed energy resources present their own challenges. Wattles reminded attendees that ERCOT is continuing to map DER on the distribution system, so it can gain a better understanding of where they are.
“When you start seeing solar and storage together, you’re seeing a DER that can be dispatched,” he said. “We’re still a way away from that. The critical mass just isn’t there yet, but I think we have to be ready for it.”
“We’re in the early stages in Texas … of allowing distributed resources to get on the grid and grow, so we can have them available and start using them,” Sunrun’s Amy Heart said. “We’ve certainly seen Texas is not out of the ordinary. Let’s not stop a market in its tracks just when it’s getting its feet under it.”
Look no further than Ontario’s Independent Electricity System Operator (IESO), which has about 35 MW of DER connected to its grid. The ISO’s manager of generation procurement operations, Rob Sinclair, said because much of those DER are the result of power purchase agreements, it gives the Canadian grid operator more insight than its brethren.
“The advantage we have, because we contracted with a vast majority of these facilities, we know where they are and how they’re operating,” Sinclair said. “That gives us a bunch of insight, but there are still things we’re not fully aware of. We’re trying to understand how to modernize our tools to integrate those resources. We’re moving from a PPA framework to a net metering framework, so we’re just about to learn how net metering will work in our market.”
California’s scorching heat and soaring load pushed CAISO day-ahead energy prices to record highs in the second quarter after the ISO’s market mitigation measures unexpectedly failed.
CAISO’s Department of Market Monitoring (DMM) said it will investigate some of last quarter’s day-ahead market outcomes that may be rooted in a misalignment between software systems.
The Monitor raised concerns in its second-quarter report because energy prices increased even after undergoing mitigation. At one point in the midst of the heat wave, day-ahead prices exceeded $200/MWh during a five-hour period and pushed past $600/MWh in one hour.
“DMM expects that prices should generally not be significantly higher in the final market run than in the market power mitigation run,” the report says. “Both DMM and the ISO will continue to investigate this issue.”
On June 21, “the total bid in cost of energy in the binding pricing interval run was about $1 million higher than the as-bid cost before market power mitigation,” the Monitor said. “However, energy revenues were almost $25 million greater in the binding integrated forward market than in the market power mitigation run due to the magnified impact that higher prices have on the total market.”
One possible cause, which has been raised previously in stakeholder discussions: software differences between the market mitigation and the integrated forward market (IFM) runs, the latter of which is a fundamental CAISO market process that establishes exactly what generators will be needed to meet demand forecasts.
The two processes run independently of each other and produce separate results, or solutions, based on differing inputs, specifically because the mitigation run relies on mitigated bids that can produce a different dispatch order from the IFM.
“If it is determined that a software error resulted in erroneously high prices, DMM requests that the software error be resolved and that the ISO consider the possibility of price corrections,” the Monitor said in the report.
According to the report, CAISO has proposed two explanations for the deviation between the mitigation and IFM runs: differences in unit commitment due to the reduction in available bids (due to lower prices) in the market power mitigation run; and differences in the solution stemming from the independence of the market runs and solution error tolerance.
In the report, the Monitor recommends that the ISO study revisions to solution time and tolerances in the day-ahead market “given the substantial settlement impacts of this case.”
“DMM’s analysis indicates it is unlikely the differences are due to the impact of bid mitigation,” CAISO spokesman Steven Greenlee told RTO Insider. “DMM is asking the ISO to continue investigating the cause further in the event it is caused by a software or other issue that may have a significant impact on market results in the future.”
Greenlee also said that CAISO currently has no plans to issue price corrections until there is “conclusive” evidence of an error, noting that the ISO is “significantly beyond” the price corrections window.
As for the $25 million discrepancy, “DMM has not concluded this is an overpayment but believes the magnitude of this impact highlights the need to further investigate the cause of significantly higher prices in the market run compared to the market power mitigation run,” Greenlee said.
Hot Weather Drives Up Prices
Average day-ahead and 15-minute prices increased during every month in the second quarter, the report showed. Monthly average day-ahead prices rose from less than $23/MWh in March to about $34/MWh in June, caused by high temperatures and loads.
Aside from weather and load, congestion was high on the Path 26 transmission line, which links the Southern California Edison and Pacific Gas and Electric service areas. Price spikes — as high as $250/MWh in the five-minute market and a $750/MWh in the 15-minute market — also increased as a result of weather and the line restrictions. North-south congestion on Path 26 drove real-time congestion to its highest level since the 15-minute market became binding in 2014.
Solar output hit a new record in the second quarter, but higher system loads reduced the instances of negative pricing that accompanied solar surpluses in the first quarter. Real-time prices went negative during 15% of intervals during April, falling to under 6% in June, compared with about 22% of intervals in March.
| CAISO
Solar generation continued to grow on the system, reaching a record peak output of 9,914 MW on June 17. There were reduced curtailments in the second quarter despite a reduction in the power balance constraint tool for oversupply from 300 MW to 30 MW, effective April 11.
“During nearly all of the intervals in the second quarter when prices were negative, there were sufficient dispatchable market bids to resolve oversupply and the software did not have to relax the power balance constraint or curtail self-scheduled generation,” the report said.
EIM Members Fail Sufficiency Tests
In the Energy Imbalance Market (EIM) region comprising PacifiCorp East, NV Energy and Arizona Public Service, prices were often similar because of large transfer capacity and little congestion. There was some price separation in these balancing authority areas because one or more failed the flexible ramping sufficiency test, which limited transfers among them. EIM balancing areas continued to fail the upward and downward sufficiency tests “regularly” in the second quarter, the report said. “In particular, Puget Sound Energy failed the downward sufficiency test more frequently, during about 13% of hours, up from about 3% of hours in the previous quarter.”
EIM participants have discussed what they see as problems with the market’s resource sufficiency test stemming from shifting CAISO load forecasts. (See EIM Participants Seek Resource Test Tweaks.)
The ISO and PacifiCorp were exporters in the EIM during the quarter, while the other areas were mostly net importers, with the ISO’s largest exports occurring during solar-heavy hours.
The quarter also saw relatively high “bid cost recovery payments,” which ensure that resources scheduled in the market recover costs when the market does not provide sufficient revenues. Excessively high bid cost recovery payments can indicate that unit commitment or dispatch is inefficient, and the costs of the payments are allocated to market participants through uplift costs.
Those payments were estimated at about $28 million during the quarter, the highest since 2013, with much of that covering during several days in May. On May 3, the ISO declared a system emergency for the first time in nearly 10 years, and many committed units received payments higher than $50,000, the report said.
MISO will release results from its regional transmission overlay study by December — nearly two years ahead of schedule.
The RTO finished the overlay analysis earlier than the slated 2019 finish, citing the collapse of the Clean Power Plan as a factor in speeding up the process.
“Originally, we set aside three years,” said Lynn Hecker, MISO manager of expansion planning.
Hecker said MISO “no longer has the urgency of the Clean Power Plan,” so the more specific planning work of the study would become more protracted, broken up over MISO’s usual annual planning Transmission Expansion Plan studies. Furthermore, transmission issues gleaned from the overlays could inform specialized, targeted studies in the MTEP 18 planning cycle, she said.
MISO will generally “shift away” from studies that run three years to focus on one-year studies in order to provide detailed transmission needs instead of a “macro look,” Hecker said. However, the RTO learned “valuable” economic and reliability lessons from the overlay study, which was originally meant to inform long-term transmission planning as the resource mix shifts. The study created a possible transmission map — or overlay — for each of the three future scenarios in MTEP 17. (See MISO Planners Looking at 3 La. Projects, Overlay ‘Skeleton’.)
A second round of preliminary overlay results using an existing fleet projection shows several 345-kV line additions in MISO Midwest, as well as a handful of 500-KV lines in — and one leading into — MISO South. The “policy regulations” future shows a bigger network of 345-kV lines in the Midwest region and multiple 500-kV lines in MISO South. One DC line would link South and Midwest while another would stretch from Arkansas to Iowa.
The “accelerated alternative technologies” future depicts a large network of 765-kV lines in the Central region, including two 765-kV paths connecting with South, and a DC line across North Dakota and Minnesota, in addition to the proliferation of lines in Midwest and South.
“Now that we’ve closed the books on the regional transmission overlay process, it’s time to take a closer look … to address targeted studies further and answer stakeholder questions,” Hecker said.
She said future targeted studies could be themed, focusing on transmission issues across seams, generation retirement impacts, increased distributed energy resources, grid stability in Minnesota and Wisconsin, renewable integration impacts and potential transmission to support “resilient” resources — a concept handed down by the recent Energy Department grid study and yet to be explored by MISO.
Several stakeholders balked at MISO’s mention of studies based on “resiliency,” but MISO Director of Policy Studies J.T. Smith assured attendees that the RTO and its stakeholders would together set out to define the concept in later public meetings.
“In the meantime, MISO will continue on the complicated process to improve the alignment of the project costs and benefits,” Hecker promised stakeholders during a Sept. 25 special conference call of MISO’s Economic Planning Users Group.
Some stakeholders asked why MISO did not consult its own generator interconnection queue to inform the overlays.
| MISO
Hecker said the RTO took “a much more forward-looking” approach, examining congestion 20 years out amid MISO’s shifting resource mix.
“We did a best guess of where generators will be sited in the future,” she said.
The study will not be used to justify projects in future MTEP cycles, which will still require the usual rigorous MTEP studies.
The overlays “will help us look at if what is needed in the short-term will be compatible with long-term needs,” Hecker said. “They’re multiple, long-term views of what transmission may be needed.”
Wind on the Wires’ Natalie McIntire noted that there are “several” lines that appear in all three preliminary overlays. She asked if MISO planned to use the recurring lines as part of a “no regrets” lineup of projects.
Hecker acknowledged the “commonalities” between overlays, but she said that MISO would not guarantee it would include the lines in a future list of recommended projects, despite their possible recurrence in future MTEP planning cycles.
CEO Andy Ott set the tone from the outset, promising stakeholders that the initiative would not result in unbridled spending.
“Some worry when we say the word ‘resilience,’ we need to gold-plate the system. And that’s not really anybody’s intention,” Ott said. “Does that mean we need to spend infinite amount of dollars? Of course not.”
He said staff will focus on three issues: deducing the criticality of grid assets, fuel security and quicker recovery from system failures.
“Twenty years ago, we didn’t talk about people attacking the grid. Today it’s a common discussion,” he said.
Paul Stockton, managing director at consulting firm Sonecon and former assistant secretary of defense, used his keynote address to warn that cyberattacks are coming and that the government will be involved in the response.
“Attackers are preparing the battlefield today. … They are trying to establish a persistent presence so they can attack you at a time of their own choosing,” he said. “We need to be prepared to raise the cyber walls.”
Stockton said triggers should be developed now to establish when and how conservative operations are implemented, praising PJM for having “by far the most detailed” plan among RTOs and ISOs.
He said the industry also should plan for external reactions, such as a potential “panic in the financial markets” when media reports reveal that conservative operations have been implemented. Inaccurate news reports could spread fear and chaos, he warned.
“It doesn’t matter if it’s true. If it gets out on media enough, you’ve got a serious challenge,” he said. “Get ready for information warfare.”
He agreed with a point Ott had made earlier to “make critical facilities less critical” by building redundancies.
Attendees acknowledged the issues but challenged PJM to let its actions do the talking.
“What is your plan to engage critical stakeholders to get from where we are today to where we need to be?” Exelon’s Gloria Godson asked.
Ott responded that PJM staff will work through the stakeholder processes and engage states through existing channels, such as the Organization of PJM States Inc. “There’s no specific one item that’s going to cover anything,” he said.
“In terms of accountability, it’s great if PJM is going to say they’re going to do everything, but that kind of takes the states off the hook,” Stockton said. “The states have to know if there are areas in cybersecurity or addressing critical facilities within their localities, that there are things that they should be doing to make sure that their utilities are in a proper state of resilience.”
Other panelists agreed with Stockton that a major hurdle is defining the cost-benefit payback of resilience upgrades.
“We don’t know the probability of the storm coming and we don’t know the probability of what kind of damage is going to result,” said Stephanie Brand, director of New Jersey’s Division of the Rate Counsel. “It is very difficult to figure out what are the measures that will bring the most bang for the buck.”
Ralph LaRossa, the president and CEO of PSEG Power, recalled his years running Public Service Electric and Gas. Customers never wanted the lights to go out, and if they did, they had to be back on within 20 minutes, he said.
Brand questioned that characterization, saying customers are more informed and understanding than that.
“There will always be some people who are just going to be complainers, but I don’t agree that the average consumer expects their lights never to go out and expects it to be back up in 20 minutes. I think they understand that it’s difficult,” she said.
LaRossa held up his cell phone and said customers are concerned with recharging mobile devices.
“It’s not an easy balance to make here, but if we don’t succeed at this, we’ll lose the industry. We have to figure this out together. We can’t be fighting among ourselves.”
John Norden, director of operations for ISO-NE, questioned the usefulness of RTO wholesale markets during catastrophic “black sky” events, such as an electromagnetic pulse attack.
“I think markets can play a role, possibly, but a limited role. I mean, there’s really got to be a will to do it,” he said. “Markets work extremely well for the things that we handle on a day-to-day basis or maybe a one-in-10-year type of basis. It’s the things that have never occurred before that the markets I don’t think are going to be [able to] answer.”
He pointed instead to the industry-regulatory partnerships. American Electric Power, Berkshire Hathaway Energy, Duke Energy, Edison Transmission, Eversource Energy, Exelon and Southern Company Services formed a company, Grid Assurance, to reduce the cost of stockpiling transformers and other critical assets through combined buying power and inventory pooling. The purchases require state regulators’ approval.
“That was not done in a market regime,” he said. “It was done through strong collaboration between the asset owners and the regulatory community.”
LaRossa also questioned how markets will cope with resilience levels that are mandated by states.
“If it’s going to be a basic service, I’m not sure how the markets play at that,” he said. “What’s going to be considered the regulated service and what’s going to be considered the market?”
PJM’s Craig Glazer wrapped up the conference promising that staff will digest the conversation and return with an updated resilience roadmap that adheres to what stakeholders want to address.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-10:00)
Members will be asked to endorse the following proposed manual changes:
F. Manual 28: Operating Agreement Accounting. Eliminates redundant language and clarifies procedures associated with the implementation of intra-day offers.
3. Primary Frequency Response Senior Task Force (PFRSTF) (10:00-10:10)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions to clarify definitions.
5. Balancing Ratio (10:20-10:45)
Members will be asked to endorse a problem statement and issue charge regarding calculation of the balancing ratio used in determination of the market seller offer cap.
1. Governing Document Revisions regarding Limitation on Claims (1:25-1:35)
Members will be asked to endorse proposed Tariff and Operating Agreement revisions related to the limitation on claims.
2. TEAC Redesign (1:35-1:50)
Members will be asked to approve proposed Operating Agreement revisions regarding redesign of the Transmission Expansion Advisory Committee and expanding the short-term proposal window from 30 days to 60 days.
3. Nominating Committee (1:50-2:00)
Members will be asked to elect members of the 2017-2018 Nominating Committee.
Officials remain optimistic about MISO’s interregional transmission planning process with SPP despite its failure to produce a single project even after producing two coordinated studies since 2014.
MISO recently declined to approve a South Dakota transmission project that would have traversed both RTOs, the only potential feasible project to come out of the latest coordinated study that wrapped up this year.
Staff last month told MISO’s Planning Advisory Committee in mid-August that it no longer recommended the $5.2 million, 115-kV Split Rock-Lawrence circuit project in South Dakota, which would have been the RTOs’ first-ever interregional project. Staff instead recommended following an updated operating guide from line owner Xcel Energy and operating the Lawrence–Sioux Falls line in an open circuit to shift some congestion to the nearby Sioux Falls–Split Rock 230-kV line. (See SPP Glum as MISO Axes Last Interregional Project.)
During MISO Board Week in September, Vice President of System Planning Jennifer Curran said she thought the RTOs’ interregional process worked as intended because MISO’s regional review identified a “cheaper option” than a costly interregional project.
MISO has vowed to continue interregional communication and planning with SPP.
“MISO continues to work aggressively to try to identify cost-effective interregional projects to help ensure a robust transmission network that can mutually benefit our members,” MISO Manager of Interregional Planning Eric Thoms told RTO Insider. “In this recent case, the interregional process was successful in finding an appropriate solution to meet the need. In this case, a superior regional solution was identified after additional analysis.”
Communication Breakdown?
MISO shared its decision with SPP “in advance of the Aug. 16 Planning Advisory Committee,” Thoms said, adding that planning staff from both RTOs participated in a joint conference call in early August to discuss the information.
“We are committed to communicating study results with our partners as soon as appropriate,” Thoms said.
SPP COO Carl Monroe last month told RTO Insider that his RTO only discovered MISO’s decision through posted meeting materials and news coverage. Monroe has since walked back the comments.
“I regret misstating that SPP was unaware of MISO’s intent not to recommend the project for construction and have spoken with Mr. Thoms directly to acknowledge the error,” Monroe said. “We’re pleased with MISO’s expressed commitment to improving coordination between our organizations, and SPP likewise will do everything in our power to support interregional coordination in the interest of greater reliability and affordability across our industry.”
Thoms said the RTOs’ latest coordinated study was not conducted in vain, as MISO discovered “differences in operations and transmission service treatment that [may] arise as a potential barrier to future interregional projects.” He said MISO and SPP plan to work to better align the unnamed differences and added that they ultimately did not affect the chances of the South Dakota project proposal.
According to Thoms, MISO reached out to SPP during the coordinated study process more frequently than is required by their joint operating agreement, which outlines the procedures for interregional coordination. The JOA stipulates that the Joint Planning Committee, comprising staff of both RTOs, must meet no less than twice per year.
In addition, MISO and SPP corresponded “numerous” times during the year to discuss interregional stakeholder meetings and study data, modeling and results, Thoms said. He added that the coordinated system plan itself requires supplementary meetings to update and finalize the study.
‘Work in Progress’
MISO may still have ideas about how to improve communication with SPP regarding interregional planning, although Thoms is holding those cards close to his chest. In 2016, rather than embark on another coordinated system study, MISO suggested that the RTOs spend the year improving the study process, advice that it eventually abandoned.
“MISO and SPP continue discussions around a long-term coordination effort. At this time, those details are still being developed,” Thoms said.
He added that MISO staff are committed to “working with SPP and other stakeholders to foster effective communication and mutual understanding around these projects.”
MISO’s seams | MISO
Missouri Public Service Commission economist Adam McKinnie hails from a seams-heavy state and is often a vocal critic of the RTOs’ inability to produce interregional projects. While he declined to comment on how communication procedures between MISO and SPP could be improved, he did say there is benefit to the RTOs working together and identifying interregional projects.
“We’ve been trying to do this for years,” MISO Board of Directors Chairman Michael Curran said of interregional projects at a Sept. 21 meeting. “It has been a long struggle, and you can only do so much when your neighbor isn’t willing to coordinate, but that coordination is starting.
“Only good things can happen from here,” he told MISO stakeholders. “We’re on our way to an intermarket system, but don’t get too excited just yet — it’s a work in progress.”
BALTIMORE — PJM’s Craig Glazer wrapped up last week’s Grid 20/20 conference by joking that the National Council of Teachers of English had tweeted an objection to the forum using “resilience” and “resiliency” interchangeably.
“They didn’t tell me what the right answer was,” he said, but that Dave Anders, who leads PJM’s stakeholder engagement process, promised a sector-weighted vote on which term stakeholders preferred.
The quip provided some insight into the challenges of addressing grid resilience. If getting the term right is hard, agreeing on a definition is harder. Harder still is determining what actions should be taken, who will take them and how all the disparate responsibilities and demands are integrated into an improved system.
Many of the gray areas and friction points were on display at the conference. Government representatives promised they could be trusted with sensitive corporate information while company representatives hesitated to offer too much. Gas-fired generators cited the importance of fuel security, while gas pipelines said generators have declined to sign the firm contracts that would guarantee fuel delivery. Everyone seemed to agree that more redundancy should be built into the system, but that it can’t be too complex or too costly.
“The fact is we’re not going to be able to be 100% secure, so we’re going to have to make choices,” said Stefanie Brand, director of New Jersey’s Division of the Rate Counsel. “I think those questions need to be answered at the beginning or else we’ll be throwing solutions at a problem that hasn’t been defined.”
Transparency
Several panelists representing government interests urged companies to share information and procedures to see if there are ways to help each other.
State governments “are all very eager to hear from the private sector in their various states about what they’re doing and how they can work together,” said Tim Blute, director of the National Governors Association’s Homeland Security & Public Safety Division.
Bill Lawrence, who runs NERC’s Electricity Information Sharing and Analysis Center, assured attendees that his group maintains separation from the corporation’s compliance monitoring enforcement program to ensure that any information volunteered by companies “will not get them audited.”
“At the end of the day, this is all going to come down to trust,” said Col. Victor Macias of the National Guard Bureau. He said the nation’s 3,300 National Guard facilities are prepared to help but need to know ahead of time what they’ll be expected to do.
Part of that may be led through the Department of Energy, which was given “far-reaching authority” through the 2015 Fixing America’s Surface Transportation (FAST) Act to issue emergency orders “to do whatever [the secretary of energy] thinks is necessary to restore the reliability of the bulk power system,” said Paul Stockton, managing director at consulting firm Sonecon and a former assistant secretary of defense.
“A cyberattack will attract much more direct U.S. government attention” than any prior blackout, he said.
The industry needs to help DOE figure out what those emergency orders should be “so they’re actually helpful to you in protecting and restoring grid reliability instead of being in the way or worse,” he said.
Companies expressed reservations that too much transparency can be a hindrance.
“Once you identify a cascading risk, how in an open stakeholder process do we get this risk mitigated without giving an adversary a blueprint of how to take down the network?” asked David Roop, director of electric transmission operations and reliability for Dominion Energy.
“There are so many things now that we’re at risk with that many of us don’t understand. It’s hard because too much transparency can create more vulnerability for us, more risk,” Southern Co. Vice President of Transmission Katherine Prewitt said. “I think we just have to talk about it and decide. We’re going to get it wrong sometimes, but we’re going to get it right sometimes too.”
“As far as anything that is public, we work very closely on what are the appropriate questions to ask, what we’re willing to put out publicly,” said Laura Ritter, lead security policy adviser for Exelon. “It’s not that utilities don’t want to share, but there is a limit at the point of you’re just giving information now to the adversary.”
Gas-Electric Coordination
With PJM’s generation fleet quickly transitioning to flexible, more responsive gas-fired units, fuel security has been a persistent issue. Gas is plentiful and relatively cheap, but it must be transported through pipelines that can’t always deliver enough fuel for generators when heating demand is high.
“When we’re in a heavy winter-weather event, and we have a lot of operational flow orders on the gas system, that’s a critical time. Should we be operating differently? Should we look at conservative operations in certain circumstances?” PJM CEO Andy Ott asked in his opening remarks.
“We need to look at … what happens when a compressor station goes out on a pipeline, what happens [when] a pipeline itself goes out, how quickly do we lose the fuel source, how quickly do we lose a generator from an operational perspective,” he said. “Do we look at operating reserves? Do we need to deploy spinning reserves differently to make up for those types of events?”
Richard Kruse, vice president of gas pipeline company Enbridge, said the issue is more basic than that.
“Currently, electricity to a significant degree is using capacity that is released from primary customers and, as such, until it’s scheduled, it’s interruptible,” he said, adding that generation units can account for up to a third of Enbridge’s pipeline capacity during nonpeak periods.
“What keeps me up at night is those days when it gets cold and our traditional firm customers are using their capacity as they’re entitled to and [generating units are] forced off. That can happen … from weather conditions very quickly,” he said. “In terms of giving PJM any assurance that tomorrow — before the [capacity-use] nominations come in — we can guarantee that this power generation will be able to run is beyond our knowledge base. It will depend on how that generator contracts. It will depend on where he’s sourcing his gas. And it will depend into how he fits into a queue that’s deemed very complicated.”
Fixing the issue “will require infrastructure, and that’s a big challenge,” he said, because the industry requires firm contracts to build new pipelines. He noted the difficulties his company faced in its efforts to build in New England.
“We have been unable to navigate the state policies about who can and who cannot contract for pipeline capacity,” he said. “If you have [firm] customers, we have proven with time you can navigate those waters. Without customers, you don’t get to first base.”
The inability to expand New England’s pipelines has left the region in a “precarious situation,” ISO-NE Director of Operations John Norden acknowledged.
“In the winter, it’s very difficult for generators to rely on gas that they don’t hold firm capacity rights to on the pipeline infrastructure, so New England is highly dependent upon liquified natural gas that comes from the Middle East — [which is] not exactly the best place to be relying upon for fuel supply — and from South America.”
Cost-Effective Construction
Transmission planners have long had to balance the desire to enhance reliability while limiting the impact of additional infrastructure on the public.
Utilities all have unique situations and demands to address, so “one of the things we got to make sure we don’t do is over-engineer our solutions,” Prewitt said. “If we over-engineer our solutions, we won’t get the result that we’re hoping that we’ll get in the end.”
Rob Manning with the Electric Power Research Institute touted the value of technology to solve problems.
“There are ways to increase our throughput. There are ways to reduce our footprint. There are options that we have for how we build and where we build and if we build that are technological solutions that we’ve got to explore,” he said.
Ott and Stockton called for “making critical facilities less critical” by building redundancies such as alternative transmission paths, but transmission representatives noted the tension that creates with the public.
“I don’t know that the general public always understands what it is that they’re getting” when a line is built in a new location, Prewitt said. “When we utilize a right of way that’s already there, we increase our risk. We have one circuit today, and we put two in tomorrow. A tornado comes through, and that creates a challenge.”
Ralph LaRossa, who heads Public Service Enterprise Group’s merchant generation arm, said the crews Public Service Electric and Gas sent to Florida to help with Hurricane Irma recovery have reported that concrete transmission poles were a “big winner.” He praised Florida Power & Light’s response but acknowledged “a lot of money was spent” because much of FPL’s transmission system is underground.
“How do you do that in a cost-effective manner and not burden the customer with all of that?” he asked.
Overlap Exists, but Implementation Key
Despite the concerns, most panelists acknowledged the value of the regional perspective provided by RTOs and ISOs.
“As we’ve been in PJM, it’s been very important to us because it’s given us more surety of supply in extreme events at a lower cost by being in a broader footprint,” Dominion’s Roop said. “As a vertically integrated utility that didn’t have to deal with it, you could just do your thing a whole lot easier, so [RTO membership] does have some constraints. But I think those constraints are minimal compared to the benefits you get out.”
LaRossa said the issue is knowing where to draw the line.
“There are some things that are naturally market-driven and there are other things that are naturally regulated. I think as we have matured as an industry, we’ve mixed that a little bit. And we just need to figure out where the right balance is for everybody,” he said.
“Although the methodology is different from organization to organization or government to private sector, I think there’s a lot more overlap in how we approach these things than there are differences. The hard part is trying to identify where those overlaps are and how they could be extrapolated and used on a wider scale,” said Jonathon Monken, PJM’s senior director of system resiliency and strategic coordination.
Mountain West Transmission Group said Friday it has completed initial discussions about RTO membership with SPP’s management team and will begin public negotiations through its stakeholder process.
The conversations began shortly after Mountain West, a coalition of 10 utilities primarily serving Colorado, Wyoming and Nebraska, announced its intentions in January to join SPP. In a press release, Mountain West said it had determined that membership in the RTO could reduce customer costs and make more efficient use of its members’ transmission and generation assets.
Negotiations have reached the point where “[we] believe it is now appropriate to take our potential membership proposal to all SPP stakeholders,” Steve Beuning, Xcel Energy’s director of market operations, said in a statement on behalf of Mountain West.
SPP COO Carl Monroe said he was pleased Mountain West’s members had decided to proceed into the RTO’s stakeholder process. The next steps will include stakeholder, board and regulatory approvals, and revisions to SPP’s governing documents and processes, he said.
This will “ensure the people, technology and procedures are in place to ensure a smooth transition to [SPP] and our wholesale electricity market,” Monroe said. “We look forward to continuing our work with [Mountain West] … and providing them and their customers the value our members in the east have received for many years.”
A 2016 Brattle Group study found Mountain West could save $53 million to $71 million annually through 2024 by participating in a day-ahead market and replacing its nine tariffs with one. The utilities’ desire to eliminate pancaked transmission and participate in a modern market design started the group’s dialogue about RTO membership.
Representatives from the two organizations will review their work and next steps with SPP’s 95 members. They expect a months-long process for stakeholders to approve changes necessary to add new members. SPP took the same steps when it added the Integrated System in 2015 and Nebraska utilities in 2009.
The meetings will be held Oct. 13 in Denver and Oct. 16 in Little Rock, Ark. Registration will be available on SPP’s website by Sept. 29.
Mountain West has said it hopes to present a recommendation to SPP’s Board of Directors in January. The organizations could file with FERC in mid-2018, with full integration as soon as late 2019.
The Colorado Public Utilities Commission, which has regulatory jurisdiction over some Mountain West participants, has held two public information sessions on the proposal. (See SPP, Peak Reliability Pitch RC Services for Mountain West.) A third meeting scheduled for Oct. 20 in Denver will focus on governance, transmission planning, cost allocation and regulatory filings.
Mountain West’s 10 utilities — Basin Electric Power Cooperative, based in Bismarck, N.D.; Black Hills Energy’s utilities in Colorado, South Dakota and Wyoming; Colorado Springs Utilities; Platte River Power Authority in Fort Collins, Colo.; Public Service Company of Colorado, an Xcel operating company based in Denver; Tri-State Generation and Transmission Association, in Westminster, Colo.; and the Western Area Power Administration’s Loveland Area Projects and Colorado River Storage (CRSP) Project — serve about 6.4 million customers and own 16,000 miles of transmission.
“While Mountain West remains optimistic that an RTO would benefit its entire membership, each Mountain West participant will ultimately need to individually evaluate whether potential membership benefits its customers,” the group said. “Each will pursue regulatory or governing body approval, as applicable.”
FERC last week approved CAISO’s request to be relieved of its requirement to develop a conceptual statewide plan as part of its regional transmission planning process. The commission at its meeting also ruled on two disputes regarding the Western Energy Crisis of 2000/01.
The commission approved CAISO’s request, made in June, to eliminate the need for the statewide conceptual plan, which the ISO says is obsolete because of federal planning processes. (See CAISO Seeks to Drop Outdated Planning Role.) CAISO has developed the plan each year since 2010 as part of its lead role in the California Transmission Planning Group (CTPG). But the implementation of FERC Order 1000 superseded the CTPG, which is no longer operating.
“We agree with CAISO that the implementation of Order No. 1000’s regional transmission planning and interregional transmission coordination requirements have supplanted the benefits of developing a conceptual statewide plan, and that the tariff provisions to develop a conceptual statewide plan are now redundant and therefore unnecessary,” FERC said in its order.
The commission last week also approved an uncontested settlement filed last December between certain California parties and MPS Merchant Services, the successor to Aquila Merchant Services and Aquila Power. “The settlement resolves claims arising from events and transactions in the Western energy markets during the period of Jan. 1, 2000, through June 20, 2001, as they relate to MPS,” FERC said in the order.
Separately, FERC approved another energy crisis settlement between San Diego Gas & Electric and sellers of energy and ancillary services in CAISO and the now-defunct California Power Exchange.
