ISO-NE power prices last year climbed from record lows, but they didn’t recover by much.
The RTO said Tuesday that cheap natural gas and declining regional demand left 2017 average wholesale prices at the second-lowest level on record.
In 2016, prices dropped to their lowest levels since New England’s current competitive electricity markets were established in 2003, according to ISO-NE.
Prices averaged $33.94/MWh in 2017, up 17.3% from the previous year but nearly 35% under 2004 levels. Last year’s wholesale market value of $4.5 billion was also the second-lowest on record, compared with 2016’s record low of $4.1 billion.
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ISO-NE attributed the soft market to the second-lowest natural gas prices since 2003 ($3.72/MMBtu) and mild weather throughout much of the year. Gas prices averaged $3.09/MMBtu in 2016.
Gas-fired generation last year accounted for 48% of the power produced within New England and 41% of the region’s total energy mix, including imports.
The RTO said the extreme cold that arrived the last week of December constrained gas supplies and drove up prices, yielding $396 million of the month’s total electricity sales of $856 million.
But aside from December, consumer electricity demand remained light, averaging 121 GWh in 2017, down 2.7% for the year, according to preliminary numbers, ISO-NE said.
“Wholesale power prices were low in 2017 because of low fuel costs and relatively low consumer demand for power during most of the year,” ISO-NE CEO Gordon van Welie said in a release. “However, the last week of December illustrates the impact of constrained natural gas supplies on electricity prices. The challenging operating conditions also highlighted a growing need for competitive markets to more transparently signal the potential costs of inadequate fuel security, which creates the potential for significant reliability risks to the region.”
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August and June of last year saw the seventh and eighth lowest monthly price averages on record, at $23.77/MWh and $23.93/MWh, respectively. ISO-NE’s nine lowest-priced months all occurred in 2015, 2016 and 2017. The RTO’s highest prices occurred in January 2014 during that winter’s “polar vortex,” when prices averaged $162.88/MWh.
The RTO also said consistently improving transmission congestion played in role in keeping 2017 prices low. ISO-NE said that about $10 billion in transmission upgrades since 2002 has dropped congestion and reliability-related costs from more than $700 million in 2006 to about $57 million in 2017.
A coalition of consumer advocates, environmentalists, wind and solar developers and public power laid down a marker in FERC’s resilience docket Tuesday, calling on the commission to “review the design of organized wholesale electricity markets, particularly capacity constructs.”
The group — the American Public Power Association, Large Public Power Council, National Rural Electric Cooperative Association and the Transmission Access Policy Study Group from public power; the Electricity Consumers Resource Council (ELCON) and National Association of State Utility Consumer Advocates, representing load; and green energy proponents Natural Resources Defense Council, American Council on Renewable Energy, American Wind Energy Association and Solar Energy Industries Association — sent a letter to the commission listing five “principles” it said FERC should embrace in future rulings.
The group said the letter would be filed in the dockets on the intersection of markets and state policies (AD17-11) and on grid resilience (AD18-7). RTOs have a Friday deadline to file their responses to the commission’s questions in the resilience docket, which the commission opened when it dismissed Energy Secretary Rick Perry’s call for price supports for coal and nuclear generators. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
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The principles: technology-neutral market rules; wholesale market rules that respect state and local resource choices and don’t make customers pay twice; allowing self-supply without RTO “second guessing”; no guaranteed recovery of investment costs for particular resources or technologies; and allowing markets “to function and stabilize before new solutions are deemed necessary to be implemented.”
“The capacity constructs include design features that may limit choice, create conflicts with state and local policy objectives, over-procure or unnecessarily retain capacity, and raise costs for customers,” the letter says, calling for avoiding “costly over-procurement.”
“We as a group are committed to contributing to solutions,” the letter continued. “We emphasize that solving this challenge directly and holistically, rather than layering costly Band-Aids on top of organized wholesale markets, will benefit customers most in the long run.”
FERC may ultimately rule that the coalition’s effort to inject a review of the capacity markets in PJM, ISO-NE and NYISO is out of the scope it set in the resiliency docket. The commission directed all RTOs and ISOs to identify their resilience risks; whether they should assess their resource portfolios against contingencies from the loss of key infrastructure; and the bulk power system attributes that contribute to resilience.
But the breadth of the coalition indicates that disenchantment with mandatory capacity markets — which public power has questioned since their inception — has grown as state officials attempt to execute climate policies in the face of markets that ignore carbon emissions.
The group’s letter, however, noted the limits of the alliance, saying, “These design principles work together; individual signatories do not necessarily support every principle if other principles are not also honored.”
SAN DIEGO — Some states are creating energy policies without enough regard for grid reliability, possibly forcing federal regulators to intervene in the future, FERC Commissioner Robert Powelson said last week.
“We are seeing states that are pushing the envelope in some of these market constructs, with no understanding of what this means to overall electric reliability,” Powelson told the Western Power Trading Forum (WPTF) on March 2. “It is pushing the RTOs and the ISOs to a very ‘back-to-the-wall’ scenario, and that’s not good.
“FERC is going to have to rightly interject itself into some of these states,” he said.
Powelson addressed the WPTF in an informal speech interjected with humor and endorsements of his beloved Philadelphia Eagles, the reigning Super Bowl champions.
He noted that California and states in New England are pushing more renewables onto the system, creating issues such as CAISO’s “duck curve” and forcing oil units to run during this winter’s “bomb cyclone” in ISO-NE. He also said that four years ago he would have laughed if someone told him that gas-fired units in some California zones would be coming to FERC for approval for reliability-must-run contracts. (See FERC Orders Hearing, Settlement Talks for Calpine RMRs.)
Other California issues that concern Powelson: the possible phase-out of the Aliso Canyon gas storage field, as well as the retirement of the San Onofre and Diablo Canyon nuclear power plants.
While Powelson said he respects states’ rights, he added that “in some of those cases, the states get to choose the winners and losers in those markets, but the FERC has to deal with the moral hazards created by those decisions.”
Organized markets are benefiting consumers, who are increasingly becoming “prosumers” through using technology such as smartphones to manage energy usage, Powelson said. States like Nevada are considering retail competition, penetration of renewables is growing and FERC is contributing through actions such as its recent order on energy storage, he noted. (See FERC Rules to Boost Storage Role in Markets.)
But states cannot consider the policy aspect without heavily considering system balancing and reliability, he said. He also suggested the industry more strongly promote organized market competition to state governors and leaders, and he discussed a “cooperative federalism model” for FERC.
“There is a tectonic shift taking place across the ISO and RTOS, and a lot of that is driven by states,” Powelson said, pointing to the growth of markets across the West. “The fever of electric competition and competitive markets is going viral these days, and I think that’s a good thing.”
But he acknowledged there are differences in regional markets, “and you have to respect that, and I am learning that rather quickly.” He said, “I was warned not to talk about capacity markets” at the WPTF meeting, drawing laughter.
Powelson also mentioned the Department of Energy’s proposed grid resilience pricing rule that would have bolstered nuclear and coal units to maintain reliability, which he called “DOA.” (See Powelson, Regulators Talk Resiliency, Slam DOE NOPR.) He said that FERC’s rejection of the proposal shows that the rule of law and independence still matter at the commission.
VALLEY FORGE, Pa. — PJM won’t be offering market compensation to comply with FERC’s requirement that almost all resources provide primary frequency response (PFR), but the RTO is willing to give everyone a shot at recovering any upgrade costs to provide it.
RTO staff unveiled their newest proposal on the issue at a meeting of the Primary Frequency Response Senior Task Force (PFRSTF) on Wednesday. The idea generated some stakeholder interest but also created plenty of concern in light of FERC’s recent ruling. (See FERC Finalizes Frequency Response Requirement.)
“In general, we’re going to disagree with all of this,” said Carl Johnson, representing the PJM Public Power Coalition. “We are not in favor of where PJM is going with this.”
Johnson said it would create a substantial cost to customers for something that should be baked into the cost of doing business. He said PJM would likely hear from the consumer advocates on the issue.
Staff said they couldn’t quantify the overall cost but would get back to stakeholders with estimates.
Applicable units could seek the cost recovery or include it in their capacity offers, but they couldn’t do both. Howard Haas of Monitoring Analytics, the Independent Market Monitor, outlined a situation in which units that sought the recovery could also clear the auction at a clearing price set by another unit’s bid that includes the upgrade costs.
“From our position, that would be double recovery,” he said.
The Monitor’s proposal argues that units already have opportunities to recover the cost through capacity or energy offers.
“I’ve got good news for you,” he said. “You’re already being compensated.”
CPower’s Bruce Campbell said he would have to review how distributed energy resources are handled in his company’s proposal.
PJM’s proposal also increased its proposed threshold for exempting units, from 10 MW to 20 MW, because the potential benefit from such small units might not outweigh the upgrade costs.
Brock Ondayko with American Electric Power disagreed with Haas on whether units could seek recovery. AEP’s proposal would allow units to petition FERC for recovery if they feel they need it and can justify the request. Ondayko said he would consider PJM’s one-time recovery proposal, but he also mentioned concerns about the cost to customers because provision of PFR isn’t a NERC requirement.
PJM’s Glen Boyle said PFR is a requirement for balancing authorities and therefore an “implicit” requirement for resources.
FirstEnergy’s Jim Benchek agreed with other members that PJM’s proposal seemed to be giving some BAs “a free pass.”
“Is this a solution looking for a problem?” he asked.
AEP’s proposal diverged from PJM’s on how performance would be evaluated. Both agreed that the calculation should be a quarterly pass/fail test on whether units provided at least half of the PFR they were expected to provide. AEP suggested a higher deviation and longer duration of frequency outside the deadband settings before performance could be evaluated.
“There should be something there that makes it possible to identify the unit response from the noise,” AEP’s Jim Fletcher said.
PJM’s Danielle Croop said staff would consider rolling that into their proposal.
“If we’re going to put that minimum of five or six events in there … we want to make sure that we’re still able to perform these evaluations on a quarterly basis and that it’s not that we’re sitting around waiting for events to happen,” she said.
Staff noted that in the 2017 operating year, there would have been 14 events that fit AEP’s standards, which wouldn’t allow for the six events per quarter that PJM planned to use for evaluation. AEP proposed evaluating five events each quarter because they would be “more meaningful,” Ondayko said.
AEP also suggested researching the importance of synchronous inertial response and preserving “what we have today because once it’s gone, it’s gone for good,” Fletcher said.
“If you look at interconnections that are losing their synchronous inertial response, like Texas, you’ll find that they have to resort to paying load resources to compensate for the fact that there isn’t enough primary frequency response anymore to cover that deficit, so the operation of the grid becomes more erratic … and the need for primary frequency response goes up, but there’s limited capability,” Ondayko said. “We recommend that this type of concept be considered in the future, at least recognizing the issue of how it impacts restoration.”
MISO’s Energy Storage Task Force has been left wondering if it will help shape the RTO’s response to FERC’s sweeping storage participation order issued last month.
The task force has yet to learn its role in working with MISO staff to craft market rules to comply with Order 841, which directs RTOs and ISOs to remove barriers preventing storage from participating in energy, capacity and ancillary service markets. RTOs will be given 270 days from publication in the Federal Register to file revised tariff language with FERC outlining a participation model and another year to implement the changes.
“Frankly, we don’t know how this will affect the task force,” task force Chair John Fernandes said during a March 1 meeting. He added that MISO’s Steering Committee would have to issue a directive for the task force to begin specifically considering Order 841 compliance. Until then, the group will continue to examine what MISO rules might need to be revised or added to enable storage to participate in markets. (See MISO Staff, Stakeholders Envision Expanded Storage Participation.) Wisconsin Public Service’s Chris Plante pointed out that MISO doesn’t necessarily run compliance filings by stakeholders before they are filed with FERC.
The RTO says it will use stakeholder input on the compliance filing, although it’s not yet clear how extensively stakeholders or the task force will guide the process.
“MISO is actively working on the Order 841 compliance filing though it has not yet appeared in the Federal Register,” spokesman Mark Brown said. “While the compliance obligation lies with MISO, MISO intends to leverage its stakeholder groups to get input from stakeholders as it works through the issues as identified in the filing. This includes the Energy Storage Task Force and other stakeholder subcommittees.”
Fernandes said FERC’s order defines storage as resources that can inject into the grid, making them eligible for make-whole payments and qualification as capacity resources.
“FERC was clear that they don’t want to change market rules to accommodate storage, but they want it to be able to participate,” Fernandes said. “The idea of this order is to allow storage to participate in markets considering their operating characteristics.”
Energy Storage Association Vice President of Policy Jason Burwen said his organization is still reviewing the order to determine which storage directives are firm and which might allow more latitude.
Invenergy’s Grand Ridge Battery Storage Facility | BYD
MISO Director of Market Engineering Kim Sperry reminded stakeholders that there’s a 30-day window to ask FERC for clarification on the order.
Fernandes said it’s unlikely FERC’s rule will become effective within 90 days without delays.
“The effective date in the Federal Register assumes that all six markets say, ‘great,’ and have zero questions. The odds of that happening are between zero and zero,” Fernandes said.
He said that while Order 841 did not address storage acting as transmission, the task force will nevertheless continue to discuss MISO valuing “storage-as-wires.”
“We are going to have to go outside the bounds of Order 841 to talk about storage as transmission,” he said.
Dave Johnston, a staffer with the Indiana Utility Regulatory Commission, said he was troubled the order seems to allow distributed assets into the wholesale market, seemingly over the heads of state regulators.
“This may impede on state law,” Johnston said.
“I don’t think your concern is overblown,” Fernandes said. “I think FERC very firmly planted its flag and said the wholesale market is our sandbox.”
However, Fernandes said he didn’t think FERC intended to trample state jurisdiction. Indianapolis Power and Light’s Lin Franks said she thought FERC was simply trying to include distributed assets within the definition of storage resources.
“I think, to me, FERC did exactly what it’s supposed to do; it provided an endpoint and left it up to the RTOs how to get there, recognizing how unique each of these markets are,” Fernandes said.
FERC has ordered a technical conference for April 10-11 on whether it should treat aggregated distributed energy resources the same as it directed for storage in Order 841. (See FERC Rules to Boost Storage Role in Markets.)
IPL Complaint
Some stakeholders asked if the Order 841 compliance filing would affect the outcome of IPL’s FERC complaint against MISO’s restrictive storage participation rules, which prompted the RTO to propose revising its Tariff to include a stored energy resource type II to facilitate participation (ER17-1376). (See MISO Rules Must Bend for Storage, Stakeholders Say.) MISO planned for the new resource to be in use while it waited for a more comprehensive FERC storage rule, and some stakeholders are wondering if the filing would now become inconsequential.
MISO legal staff at the meeting said FERC must decide between accepting, accepting in part or rejecting its Tariff filing, or rendering the filing moot in favor of waiting for its Order 841 compliance filing.
FERC last week accepted MISO’s plan to allocate Michigan ratepayers $24.6 million in refunds for overcharges stemming from RTO-ordered system support resource agreements imposed on a Wisconsin Electric Power Co. coal-fired plant.
The commission directed MISO to execute the reallocation — which includes interest — over a 10-month period beginning Feb. 28 (ER14-2952-005).
FERC ruled in late October that WEPCo overcharged ratepayers on Michigan’s Upper Peninsula by almost $23 million for agreements that kept the 344-MW Presque Isle coal plant in Marquette, Mich., running in 2014 and early 2015 for reliability purposes. The commission directed MISO to calculate the refunds over the RTO’s objections that it did not provide clear guidance on how to do that. (See $23 Million Owed to Ratepayers in Presque Isle SSR Case.)
Presque Isle power plant | WEPCo
Now, Constellation Energy Group owes the largest share of SSR costs at $13.6 million, followed by Cloverland Electric Cooperative ($6.3 million), Upper Peninsula Power Co. ($4.9 million) and the city of Escanaba ($1.1 million). WPPI Energy is owed $3 million from Michigan LSEs. MISO redacted the monthly refund report in a public version of its filing because it would reveal “insight into monthly load patterns,” according to the RTO.
MISO had proposed to invoice the resettlements as a lump sum on Dec. 19, instead of over the original 14-month timeline. FERC determined that a 10-month distribution was more appropriate because it corresponded with the established April 3, 2014, refund effective date through the Jan. 31, 2015, termination of Presque Isle’s second SSR agreement.
AUSTIN, Texas — Infocast’s annual ERCOT Market Summit once again drew ISO staff, market participants and others for panel discussions on market reform, grid resiliency, resource adequacy, transmission constraints, wholesale price volatility, and integrating utility-scale solar power and battery storage.
Participants Caution Against Market Changes Before Summer
Some of ERCOT’s more vocal members urged caution as the market approaches a summer with projected record demand but with almost 8 GW less in generation after a wave of retirements and delays in planned projects.
The Public Utility Commission of Texas is considering withdrawing reliability unit commitments (RUCs) and reliability-must-run capacity from the operating reserve demand curve (ORDC), a real-time price adder that reflects the value of available reserves and is intended to incentivize resources to produce more energy and reserves. PUC staff said this would ensure that scarcity pricing is accurate and reflective of market dynamics. (See “Commissioners Delay Action on Removing RUCs from ORDC,” Texas PUC Briefs: Feb. 15, 2018.)
But that would be a mistake, said Katie Coleman, legal counsel for Texas Industrial Energy Consumers. “Since 2012, we have spent a lot of time and effort designing the ORDC. We specifically discussed including RMR and RUC capacity. Ideally, the ORDC values should reflect the actual amount of reserves, which accurately reflects the likelihood of load shed. We did a bunch of other things instead, to try and put more money in the market,” she said, referring to RUC’s $1,500 price floor — “which is higher than any unit’s actual cost” — and pricing RMR at the $9,000/MWh cap.
“We’ve built this machine, and we’re about to have a summer where it’s tested. Let’s see how it goes, then come back, and see if there are areas that really need refinement.”
“Part of the problem the last five years is we have never really defined what we are solving for from a reliability point of view,” said Barksdale English, Austin Energy’s interim chief of staff. “What is important to us? Is it short-term interval-to-interval reliability? Is it long-term five-, 10- or 15-year reliability? Until we figure out what we are solving for, having proposed solutions sort of seems like having the cart before the horse.”
English jokingly referred to his “multiple personality disorder” as a generation-owning municipality competing in ERCOT’s wholesale market. “I can get really excited about $9,000/MWh for wholesale generation, but then — oh my gosh — what about my consumers? Then, my City Council gets mad at me because I’m paying too much money.”
Beth Garza, director of the ERCOT Independent Market Monitor, cautioned against blurring the difference between a load-shed event and a blackout. “That’s a very important difference. Those loads are being paid to provide a service,” she said.
“I fully expect many of those services will be called on this summer that have never been called on before. If those services are called on, they’ve been curtailed or are no longer consuming, but they’re being paid for providing a service,” Garza said.
“At what levels does ERCOT take emergency actions? When does load shed begin?” asked Strasburger & Price’s Mark Walker, before answering his own question (when operating reserves reach 1,000 MW). “Hitting the offer cap with only 2,000 MW of available capacity left is sensible. If you look at actual prices when RUC resources are deployed by ERCOT under pressure from load, congestion and intermittent resources swings, the prices today really don’t reflect that we’re in an emergency situation or a serious reliability condition.”
Role-playing Reveals Markets Concerns
In a discussion on how low power prices are affecting the strategies of plant owners in ERCOT, summit organizers asked the panelists to role-play the different aspects of generation investment.
Federal Power Co. CEO Steve Gilliland, filled his natural role as a developer, and Tom Rose, CEO of Clean Energy Technology Association, played the investor. That left Cratylus Advisors’ Mark Bruce, who represents Southern Cross Transmission in its bid to become the ISO’s first DC tie operator, to play the regulator.
Asked what kind of signals the ORDC was giving investors, Gilliland said, “It’s not giving signals big enough and substantial enough.”
“What drives the financier and developer is cash and cash flow,” he said. “I don’t believe that system is giving a clear enough signal for a long enough period of time that convinces me new generation is warranted. I don’t believe it will be allowed to be a significant enough number. It’s going to like moving the deck chairs around on the Titanic.”
“As the regulator, that statement scares me because that ship didn’t make it,” Bruce deadpanned. “The ORDC was not intended to be a substitute for scarcity pricing. It is a construct intended to correct the anomalies in pricing that result from out-of-market actions of the grid operator.
“I applaud the Texas commission for resisting the call to pad the ORDC,” Bruce continued. “That doesn’t help the fundamentals. We’ve had significant periods of time where the system is overbuilt, and the prices will be, and should be, in the dirt during those periods. And that’s the rub, a political rub. The economically optimal reserve margin is quite a bit smaller than the official, cushy planning reserve margin. We’re about to live in the gap between the two, and the political leadership of the state is going to have to decide whether to let the market speak. The economics will reveal in themselves, and then the politics will play catch-up.”
Rose, reminding the audience that he was playing the financier, said, “All this is fairly interesting. Existing generators are going to have a great Christmas this August, but I am going to hold off on new investment until we see how the summer works out.
“I don’t think anyone will argue we’re moving into unchartered waters. That excites me. It might be a risk to some, but it’s a reward to me. If there are involuntary disconnections or if prices go up or down, you’re going to see a governmental reaction,” Rose said. “Reliability the last 10 years has been taken for granted. I already hear people talking about reregulating the market. Mark and I know that’s not going to happen. As he said, ‘There is no Plan B.’”
Generators: ORDC Won’t Incent New Generation
Generation owners in ERCOT debated the effectiveness of the ORDC, one of several pricing mechanisms the ISO says will help respond to tightening reserve margins this summer. (See ERCOT: Tight Summer Margins No Cause for Alarm.)
RTO Insider’s Tom Kleckner moderates a panel on ERCOT wholesale price volatility during Infocast’s ERCOT Market Summit. Panelists include (l-r) Skylar Resources’ Gerald Balboa, Citigroup’s Yashar Barut, ERCOT’s Kenan Ögelman and Engie Resources’ Andrew Elliott. | Infocast
“The ORDC, which is a scarcity pricing mechanism, is absolutely working as designed,” said Dynegy’s Bob Helton during a panel discussion on resource adequacy. “The question is, is it getting us to where we want to be, which is reliability equilibrium and economic equilibrium?”
The Lower Colorado River Authority’s Randa Stephenson said the ORDC should not be seen as a signal for additional generation development. Continued growth in wind generation is expected to pick up much of the slack for recent retirements of baseload generation, and while 2018 futures are trading around $140/MWh, the market has already considered the plant closings by Vistra Energy and others. (See Vistra Energy to Close 2 More Coal Plants.)
“Is there enough scarcity to signal a generation buildout? No, not even a peaker,” Stephenson said. “If you look out into the future, the market knew Vistra was going to happen. Summer of 19, 20 prices didn’t move up that much. I don’t think the signals are out there to justify new build.”
Stephenson said demand response mechanisms are having a greater effect on the market.
“As a generation owner … ORDC is icing on the cake,” she said. “You see a lot of demand response looking at chasing those high-demand periods. You see a drop of 2,000 MW, and that takes away the scarcity prices you were anticipating.”
“ORDC was never introduced, never is and never will be a resource adequacy tool,” Helton said. “It’s for scarcity pricing, a poor man’s co-optimization. It does help with missing money and equilibrium in the market. The correct place for reserves to be is an economically optimal reserve margin. You will likely have load-shed events, but that’s the economical thing to do.”
Susan Pope, managing director of FTI Consulting’s economic practice, told attendees during her keynote address that she and her coauthor on a report recommending ERCOT market reforms believe that the state’s transmission planning policies have “materially” raised costs.
Pope said Texas’ Competitive Renewable Energy Zones (CREZ) initiatives, a $7 billion program that built 2,800 miles of new transmission to deliver West Texas wind energy to the state’s urban centers, was an out-of-market investment “not being made by at-risk investors who need to recover the full costs of their investment.”
CREZ was part of more than $10 billion in transmission investments that have been added to total system costs over the past five years, she said.
“ERCOT regional transmission planning favors transmission for reliability problems, using very conservative assumptions for new generation,” Pope said. “The analysis only includes resources that have committed to construction. Transmission investments will be identified and will pre-empt market-based generation solutions driven by energy-only prices, that could be alternatives to solving reliability problems.
“The over-investment in transmission is partly because of the long lead times to build transmission,” she said. “Those planning can end up with extremely expensive solutions to solve reliability. Continuing to build this transmission reduces energy prices because it resolves all the congestion before it has a significant effect on prices.”
NRG Energy and Calpine commissioned Pope and William Hogan, research director of the Harvard Electricity Policy Group, to write a report assessing ERCOT’s energy-only design. The report asserts that subsidized renewable resources, socialized transmission costs and the lack of local scarcity pricing have “exposed areas where there is a need for adjustments” to ERCOT’s pricing rules. The Texas PUC held two workshops last year to discuss the report and other potential market reforms. (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
During a discussion on transmission congestion constraints and how to address them, Brad Schwarz, Hunt Power’s director of system planning, described the CREZ initiative’s unintended consequences.
“CREZ was building transmission ahead of the generation, in the hopes the generation would come. It has happened,” Schwarz said. Then came the state’s oil and gas boom in recent years, he said.
“We would have been struggling to serve those loads without the CREZ,” Schwarz said. “We were able to serve more oil and gas load and bring more economic development to the state of Texas. You never really undervalue a transmission line. Once it’s out there, it finds value.”
Energy Storage Offers Solution to Congestion Issues
Kip Fox didn’t hide his disappointment over Texas regulators’ recent rejection of an American Electric Power request to connect a pair of utility-scale battery facilities to the ERCOT grid. AEP’s application ran into opposition from consumer organizations and market participants who argued that allowing the assets to be included in the regulatory base would harm competition. (See “Staff Opens Battery-Storage Rulemaking,” Texas PUC Briefs: Feb. 15, 2018.)
“We had an alternative to building a long distribution line. It was a $1.6 million solution to a $12 million problem,” said Fox, president of Electric Transmission Texas, a joint venture between AEP and Berkshire Hathaway Energy subsidiaries. “Unfortunately, since those [applications] were denied, without prejudice, we’re kind of back to square one.”
He said with batteries’ ability to provide frequency support and resolve overloading problems, “it makes more sense to run a battery eight to 10 times a year, rather than building a line.” Fox suggested Fluence Energy’s use of a portable battery in downtown Indianapolis presents a possible solution to congestion issues.
“We would like to move a battery around and solve that problem,” he said. “When the congestion is gone in five years because a transmission line hasn’t been built, we will have saved the ratepayers a lot of money.”
Tim Ash, Fluence’s market director for the eastern U.S., said other RTOs are wrestling with the same concerns over battery storage ownership and its effect on markets.
“There’s a much, much bigger market for energy storage,” Ash said. “It solves a reliability issue, which occurs maybe 10 times a year. The economic benefits are there today. The question is how to get the rules to unlock those benefits.”
FERC last month directed RTOs and ISOs to allow energy storage resources full access to their markets, an order that does not apply to ERCOT (RM16-23). (See FERC Rules to Boost Storage Role in Markets.) Asked if FERC’s directive might influence the PUC, which regulates ERCOT, to follow suit, Fox said, “Hell, yeah!”
“I’ve seen many times where the commission defaults to where FERC opens up the rules,” Fox said. “I find those rules are sometimes a little behind, sometimes a little ahead. There will be some pressure at all levels of the [state] government.”
Jack Farley, CEO of Apex Compressed Air Energy Storage, pointed to a 2012 PUC order that allows energy storage resources in ERCOT to pay wholesale prices for recharging, with no retail or transmission or distribution fees. “The energy market averages 40,000 MW and the ancillary services market is about 5,000 MW. In terms of participating in ERCOT energy and ancillary service products, I don’t think there are barriers today for energy storage resources,” he said.
“We will see energy storage adopted early,” said a more optimistic John Bonnin, vice president of energy supply and market operations for San Antonio’s CPS Energy. “As the technology improves, we will see it displace other applications in other parts of the market. If we meet again in five years, every one of us around here will have some sort of storage on their system. We all have to get smarter about the effect all that capacity will have on pricing, fuel and dispatch. It’s going to be disruptive.”
Developers See Bright Future for Texas Solar
A panel of solar developers gave high marks to the Texas market, which could see up to 8 GW of solar growth over the next few years.
“Texas is attractive because of low pricing. Wind is the headline, but at the same time, if the load continues to grow, we can make the case that there’s a match there for solar too,” said Andrew Fay, origination manager for First Solar.
Shalini Ramanathan, vice president of origination for RES Americas, said price pressure “is the reason we’re seeing so much development in West Texas and with large projects. If we can be competitive, we can do more 20-MW projects in other parts of the state. I think there’s a bias to larger West Texas solar.”
Spivey Paup, Recurrent Energy’s development director, said even West Texas, with its oil and gas infrastructure, can pose challenges.
“But once you get out of the Permian Basin, that complication goes away,” Paup said, referring to Texas’ rich petroleum fields. “We need to find a balance between strong resources and development complications. Renewables and solar were born and bred in California, but we can blow them up to scale and send California packing.”
Charlie Hemmeline, executive director of the Texas Solar Power Association, said current rules have resulted in “steady interest” in sun-powered generation in the state.
“We’re not going to ask for new polices or mandates or incentives,” he said. “We want it to work the way Texas wants it to work. ‘Don’t do anything bad to us’ is the primary policy ask.”
EVs, With or Without Drivers, are Coming
During a discussion of changing perspectives among end-use customers, Rob Threlkeld, General Motors’ global manager for renewable energy, noted he had driven from Detroit to Lansing, Mich., without once touching the steering wheel of his Cadillac CT6, thanks to its Super Cruise semi-autonomous driver-assistance system. The car comes in a plug-in version in addition to four- and six-cylinder engine models.
“In a year, the driver will touch the steering wheel much less,” Threlkeld predicted.
He had a believer in Champion Energy Services CEO Michael Sullivan, who owns a Tesla. He said the more mainstream CT6, which starts at about $85,300, will be more broadly available and easier to purchase than the special-order Tesla models.
“When you order Tesla, it’s like ordering an Italian shoe from a cobbler in Milan,” he said.
Both Threlkeld and Sullivan agreed that electric vehicles pose a sea change for the electric industry.
“We have been working closely with a lot of utilities, especially those progressive ones that are really interested in this space. It’s load growth, and that interests them,” Threlkeld said.
“If the projections are right, my teenage kids will never drive an internal-combustion car,” Sullivan said. “If everybody’s driving an electric car, that’s a major change to the industry, especially if somebody can capture storage in a really dense way.”
In two orders issued on the same day last week, FERC both vacated and reinstated MISO’s entire resource adequacy construct, ultimately leaving the RTO’s current capacity auction format — and past auction results — undisturbed.
FERC’s two Feb. 28 decisions concurrently reversed its 2012 acceptance of MISO’s resource adequacy rules (ER11-4081) and accepted the RTO’s refiling of the rules (ER18-462).
To protect its market from “potential disruptions,” MISO in December pre-emptively refiled its entire resource adequacy construct in response to the D.C. Circuit of Appeals’ ruling that FERC overstepped its “passive and reactive” role when it prescribed revisions to PJM’s minimum offer price rule. MISO was concerned about the impact of that decision on some of the resource adequacy rules that had been guided by FERC’s recommendations. (See MISO Seeks FERC Reapproval to Keep RA Rules Intact.)
Following the PJM decision, the D.C. Circuit granted FERC a voluntary remand to once again consider MISO’s 2011 market revisions.
In the order on remand, FERC said in light of the court’s PJM decision, “the modifications set out in the [resource adequacy orders] could be considered to be major modifications to MISO’s 2011 filing. Accordingly, because we cannot find MISO’s 2011 filing to be just and reasonable without our modifications, we reverse the commission’s conditional acceptance of MISO 2011 filing, and we reject MISO’s 2011 filing in its entirety.”
FERC at that time rejected MISO’s proposed mandatory auction requirement and minimum offer price rule and ordered the RTO to phase out grandmother agreement provisions after the 2014/15 auction. Taken together, the revisions “would likely be considered to result in an ‘entirely different rate design’ than both MISO’s proposal and MISO’s prior rate scheme,” FERC said, acknowledging it had exceeded its authority under the Federal Power Act, “notwithstanding that MISO consented to those revisions.”
No Auction Do-Overs
However, FERC found that rerunning the last five years of MISO’s Planning Resource Auction under the pre-2011 monthly auction rules would be infeasible and unnecessary.
“Such a remedy would be extremely complex, subject to controversy and further litigation, and cause significant disruptions and burdens,” the commission said. “It would be highly difficult, if not impossible, for the commission or MISO to reasonably provide retroactive relief, by rerunning the auction for the 2013/14 planning year through the present.”
The commission then addressed MISO’s refiling, determining that the RTO’s current auction format should remain unchanged.
MISO Independent Market Monitor David Patton used the refiling as an opportunity to again urge FERC to order the RTO to employ a sloped demand curve in its capacity auction in order to produce more efficient pricing. (See MISO Monitor to FERC: Order Sloped Demand Curve.)
But the commission said MISO’s vertical curve was just and reasonable, noting that 90% of load is served by vertically integrated utilities. It said that, at any rate, pricing takes a backseat to the main objective: maintaining reliability.
“We … disagree with the Market Monitor’s contention that a vertical demand curve leads to prices that are not just and reasonable by failing to recognize the diminishing marginal benefits of excess capacity. MISO’s resource adequacy construct was developed to ensure that [load-serving entities] in MISO acquired sufficient capacity each year to maintain the one-day-in-10-year reliability standard. Although certain constructs may value capacity beyond that amount, doing so is not essential to MISO’s construct fulfilling this principal objective,” the commission said.
MISO maintains that its vertical demand curve and its annual resource adequacy survey with the Organization of MISO States “combine to provide just and reasonable signals.”
MISO potential GW additions according to 2017 OMS MISO annual survey | MISO
The commission also dismissed several other protests from stakeholders, including complaints that supply offers above $25/MW-day (about 10% of MISO’s cost of new entry) are read as an attempt to exercise market power under current capacity auction rules and that LSEs participated in price suppression in the 2017/18 auction.
FERC instead said that 2017/18’s low clearing price of $1.50/MW-day should be taken as the simple effect of supply and demand in MISO.
“The low capacity prices, where they have arisen in MISO, accurately reflect MISO’s capacity surplus. The fact that prices have not signaled to independent generators a need to build, retrofit or even simply maintain existing resources is more indicative of a well-functioning capacity procurement construct than it is of an unjust and unreasonable construct,” the commission said.
PJM is experiencing an “unprecedented” switch from coal- to gas-fired generation while also managing the replacement of aging transmission infrastructure, staff concluded in the RTO’s annual transmission planning report.
The RTO received deactivation notices for 4,588 MW of generation in 2017, bringing the total since the end of 2011 to 34,967 MW. Deactivation requests in the eight years prior totaled 11,000 MW.
PJM greenlit $5.8 billion in transmission spending last year. That paid for 198 “baseline” projects to ensure compliance with NERC, regional and local transmission owner planning criteria, and 341 “network” projects to interconnect new generating stations. According to the RTO’s figures, that comes out to about $16 million per baseline project and about $8.6 million per network project.
On Feb. 14, PJM’s Board of Managers authorized another $397 million in transmission projects, dominated by TOs’ supplemental projects that are triggered by their own planning criteria. Transmission customers have complained about the uptick in such projects, which don’t require PJM board authorization but are included in the Regional Transmission Expansion Plan, because they believe TOs are using them to pad revenues. (See AMP Presses AEP, PSE&G on Transmission Projects.)
The recent approvals include two such efforts in the Public Service Electric and Gas and Dominion Energy territories. PSE&G plans to spend $115 million to construct a 230/69-kV substation with 69-kV ties to the Paramus and Dumont substations, and $98 million to convert the Kuller Road substation to 69/13 kV and construct a 69-kV network between the Kuller Road, Passaic, Paterson and Harvey stations. Dominion will replace existing infrastructure for a total of $50 million.
This chart shows how transmission projects approved over the past four years have transitioned from larger, “backbone”-type lines to smaller lines to address regional issues. | PJM
The remainder of the approvals consist of another Dominion project — $100 million to install three STATCOM dynamic reactive devices at two substations — and $29.5 million in spending spread across projects in the Baltimore Electric and Gas, PPL and Duke Energy Ohio/Kentucky territories.
Last month, FERC ordered PJM’s TOs to change their process for handling supplemental projects after finding the current approach does not comply with Order 890. TOs worked with PJM on the issue and last week proposed a plan to address the commission’s concerns (See related story, PJM, TOs Propose FERC Order 890 Compliance Plan.)
The PJM board has authorized $35.4 billion in transmission infrastructure spending since 1999. Baseline projects represent $27.9 billion of the total, with $7.2 billion authorized to interconnect 84,200 MW generation. Those figures include $181 million in cost overruns for 48 previously approved baseline projects and $540 million authorized for 336 network projects that were canceled after 257 generator interconnection requests were withdrawn, which reduced expenditures below authorized levels.
This chart shows how PJM expects the generation fleet to be transformed over the next five years. | PJM
But the numbers also provide some insight into development trends. PJM said the 2017 projects address market efficiency congestion and solve local reliability issues, and recent history shows a trend toward smaller lines rather than large, backbone-sized construction.
“Flat load growth, energy efficiency, generation shifts and aging infrastructure drivers — among others — continue to shift transmission need away from large-scale, cross-system backbone projects at 345 kV, 500 kV and 765 kV voltage levels,” the report states.
The generation interconnection queue is dominated by gas-fired facilities, and the deactivation list is littered with coal plants, but the fleet won’t be changing too much any time soon. PJM estimates that oil, wind, hydro and solar will all look about the same five years from now in 2023: slightly more than 10% of the total generation fleet.
Nuclear will drop slightly from somewhat less than 20% today to about 18% in 2023. Coal will also be down from around 31% today to about 28%. Gas increases significantly from roughly 40% today to more than 45%. PJM has said it can remain reliable with upward of 86% gas. (See PJM: Increased Gas Won’t Hurt Reliability, Too Much Solar Will.)
FERC last week instituted proceedings to examine the reactive rate schedules of two MISO generating facilities: the 471-MW RockGen natural gas plant in Christiana, Wis., (ER13-1589) and the 555-MW Carville steam and gas cogeneration facility in southeastern Louisiana (ER18-554).
The commission opened a Section 206 proceeding in a new docket (EL18-51) to re-evaluate RockGen’s reactive rates as a result of parent company Calpine’s proposed acquisition by an investor group led by Energy Capital Partners. FERC had accepted RockGen’s $700,000 annual reactive service revenue requirement in 2013.
The owner of the Carville plant, LS Power Development, asked on Dec. 28 for an annual reactive power revenue requirement of more than $1.1 million.
FERC said Carville didn’t provide proper evidence for multiple factors behind its revenue requirement: “Several components of Carville’s revenue requirement are not adequately supported, including, but not limited to, Carville’s fixed [operations and maintenance] expenses included in the fixed charge rate, the Carville facility’s production plant cost components and the accessory electric equipment allocator. Additionally, Carville utilized an outdated federal tax rate and incorrectly applied … methodology in calculating the Carville facility’s balance of production plant cost,” the commission said in its Feb. 28 order.
