NRG Energy earned $306 million last quarter, up 65% from the same period a year ago on strong returns for the company’s generation business.
The generating arm pulled in $595 million, compared with $272 million a year earlier, but fluctuating prices in Texas and California squeezed the company’s retail business, which posted a loss of $127 million for the quarter.
CEO Mauricio Gutierrez said during a Nov. 8 earnings call that he was “pleased with the operational and financial performance of our integrated platform during a period of extreme price volatility. … During periods of high prices, our generation business benefits while our retail business experiences some margin compression.”
The company presentation highlighted the closing on the sale of NRG Yield and its Renewables platform as a milestone. It also announced an incremental $500 million stock repurchase in addition to the $1 billion announced earlier in the year, bringing total share repurchases to $1.5 billion.
Gutierrez said NRG expects to close on the sale of its 3,555-MW South Central portfolio of generation assets in Texas by year-end and the sale of its 500-MW Carlsbad Energy Center in California in the first quarter of next year.
(Top) Peak load growth remains strong in ERCOT. Peak load growth remains strong in ERCOT. (Bottom) ERCOT power prices came in lower than forwards because of near-perfect generator performance. | NRG
Price Volatility and MOPR
Warmer-than-normal weather across the company’s core markets led to higher demand last quarter, particularly in Texas, which set a new record peak load of 73 GW. Despite robust loads, actual prices were mixed across markets compared with expectations, with real-time prices in ERCOT coming in significantly lower than projected.
A combination of near perfect performance by generators during the July heat wave and milder temperatures in August resulted in prices 77% lower than expected at the beginning of the summer, Gutierrez said.
He noted that most of the current reserve margin in Texas is made up of capacity from renewable generation — non-dispatchable capacity that could potentially lead to fluctuations in the actual amount of generation available to serve load.
The California market was a different story, with prices settling well above expectations, mainly because of restricted gas deliverability, he said. The combination of once-through cooling unit retirements and the emergence of community choice aggregators have resulted in recent increases to Western capacity prices.
In the East, energy prices were pretty much in line with expectations, and the company’s focus is on both capacity and energy market reforms, Gutierrez said.
“As you know, FERC has stated that the existing capacity market in PJM is unjust and unreasonable, due to the negative impact of subsidized units,” Gutierrez said. “Let me reiterate that we believe a strong MOPR [minimum offer price rule] is the simplest and most effective way to reduce the harmful impact of subsidies on the capacity market.”
PJM and ISO-NE also are working on fuel security, which should lead to additional revenues for generators that have on-site fuel capabilities, he said.
“This is very much at play, but all these regulatory changes are designed to improve the current status quo and are positive for our portfolio,” Gutierrez said.
VALLEY FORGE, Pa. — PJM’s Brian Chmielewski told attendees at last week’s Market Implementation Committee meeting that the Board of Managers’ investigation of the GreenHat Energy financial transmission rights default will run through the new year, with a report and recommendations to follow.
There will updates on a roughly weekly basis, CFO Suzanne Daugherty said, suggesting Thursday as the best day for stakeholders to look for them.
The default is expected to become the largest ever in PJM’s FTR market and has spurred RTO policy changes to limit the risks that allowed it to occur. The RTO recently filed a lawsuit in Texas in an attempt to recoup some payments the defaulting company promised but never delivered. (See GreenHat: (Some of) the Rest of the Story.)
Day-ahead Market Timeline Manual Changes
Stakeholders approved by unanimous acclamation changes to the day-ahead deadlines described in Manual 11, made possible by improved computing ability. PJM’s Keyur Patel explained that market participants will have until 11 a.m. to submit day-ahead bids and offers, and the clearing window will be reduced to 2.5 hours. The deadline for posting day-ahead results will remain at 1:30 p.m. or as soon as practicable thereafter.
While the overall proposal has already been approved by PJM’s Markets and Reliability Committee, the manual changes have not yet been addressed. (See “Day-ahead Market Timeline,” PJM MRC/MC Briefs: Oct. 25, 2018.)
PJM’s Tim Horger said implementation will likely occur in mid-December to make sure all market participants are aware of the changes. Staff confirmed that they planned to file the changes at FERC on Nov. 8.
Must-offer Exception Changes
Stakeholders chose PJM’s proposal over a proposal from the Independent Market Monitor for changing the rules describing how capacity resources secure exceptions to their requirement to offer into capacity auctions. (See “Must-offer Exception,” PJM Market Implementation Committee Briefs: Oct. 10, 2018.)
The PJM proposal received 0.79 in favor in a vote that had a 0.5 threshold, while the Monitor’s package received 0.22 in favor. PJM’s proposal was also preferred 0.78 over the status quo.
PJM’s Susan McGill explained the RTO’s rules for how capacity interconnection rights (CIRs) can be transferred and the impact on projects in the interconnection queue. PJM’s Pat Bruno reviewed the RTO’s proposal.
Monitoring Analytics’ Alexandra Salaneck summarized the Monitor’s alternative proposal, which would remove the ability for a unit to request that it retain its capacity resource status as late as 135 days prior to an impending status change to becoming an energy-only resource. The change would have basically allowed resources to get an exception from just one Base Residual Auction, Salaneck explained.
“What we’re trying to prevent is flip-flopping out of and back into [the Reliability Pricing Model],” she said.
Gary Greiner of Public Service Enterprise Group questioned the need for removing that provision.
“I understand the process to be quite rigorous when someone asks for a must-offer exception,” Greiner said. “We’re in a dynamic business environment. There are a lot of reasons” why the provision might be necessary.
The Monitor’s idea struck a chord with Dave Mabry, who represents the PJM Industrial Customer Coalition. He said the “jumping in and out” of BRAs might cause approved transmission projects to become unnecessary.
“I think we’re leaning toward the IMM proposal,” he said.
FTR Forfeiture Proposal Endorsed
Stakeholders endorsed a proposal developed by Exelon, NextEra Energy and VECO Power Trading over an alternative proposed by PJM to revise the RTO’s rule on when FTR profits should be forfeited. (See “FTR Forfeiture,” PJM Market Implementation Committee Briefs: Oct. 10, 2018.)
The joint proposal received 0.85 in favor in a vote that had a 0.5 threshold and 0.74 in favor compared to the status quo. PJM’s proposal originally received 146 votes in favor, or 0.53, and would have exceeded the 0.5 threshold, but staff announced after the vote had been recorded that a participant informed staff in a timely fashion that it had submitted its 14 votes incorrectly. They were changed to oppositional votes, leaving the proposal with 132 votes in favor, or 0.48, and just below the threshold.
Monitoring Analytics’ Seth Hayik presented concerns the Monitor has with changing the rule and reiterated its preference for the existing penny test, which focuses on the actual impact of virtual trades on FTR profits rather than the traders’ intentions.
“We can’t prove intent; we can’t measure intent,” Hayik said. The existing rule is “meant to deter [manipulative behavior] and to catch it,” he said.
The joint proposal’s impact test would have a threshold of FTR flows greater than or equal to 10% across a constraint.
Gabel Associates’ Mike Borgatti, who represents NextEra, agreed that such behavior needs to be eliminated, but that the current rule is too strict for market participants to risk using virtual trading for fear of triggering forfeitures. He said PJM and the Monitor should be able to monitor and take actions against bad behavior, and that being unable to determine intent is “not a sufficient basis to justify a rule” that impedes use of the products.
Stakeholders and the Monitor also battled over the implications of a graph that showed reduced forfeitures since the rule has been in place.
“The only thing we can conclude is that hopefully the feedback is working,” Hayik said.
“That graph is just showing that we have stopped virtual trading,” Exelon’s Sharon Midgley said.
Greiner concurred that PSEG’s use of virtual products has also “dropped precipitously.”
“We have virtually stopped using this as a hedging tool that we used pretty consistently prior to recent changes,” he said.
PJM’s Chmielewski said it’s unclear yet whether the RTO will pursue rebilling if the proposed changes are implemented.
Gas Pipeline Contingencies
Stakeholders endorsed a Calpine proposal over several alternatives on compensating generators who are switched from their preferred gas pipeline because of pipeline contingencies identified by PJM.
Calpine’s proposal received 0.75 in favor on a vote with a 0.5 threshold and 0.99 in favor over the status quo. PJM’s alternative received 0.42. Direct Energy’s proposal received 0.42, and a proposal developed at the meeting to merge elements of the Calpine and Direct Energy proposals received 0.4 in favor.
The Calpine proposal would provide a broader scope of factors and time for which a unit can recover costs during and after a PJM fuel-switch directive. Direct Energy’s proposal would have allowed generators to receive “a just and reasonable rate” that would be treated as balancing operating reserves.
Direct Energy’s Marji Philips said she was frustrated that PJM had decided to direct generators on what fuel sources they must use, but because the policy exists, there “should be some compensation.”
“I don’t believe PJM should be directing an entity to switch fuels,” Philips said.
She argued that the new policy would create more payments for issues that are supposed to be paid for by PJM’s Capacity Performance rules.
RENSSELAER, N.Y. — New York electricity market stakeholders on Friday reviewed three separate studies to evaluate the implications of a carbon charge in NYISO’s energy markets.
The reports by the Brattle Group, Daymark Energy Advisors and Resources for the Future (RFF) find similar reductions in systemwide carbon emissions from a carbon charge: less than 1 million metric tons, according to the ISO’s synthesis of the studies
Michael DeSocio, the ISO’s senior manager for market design, told the Integrating Public Policy Task Force (IPPTF) Nov. 9 that “all the analyses were generally supportive of each other.”
All three studies isolate the effects of a carbon charge by modeling both a “base case” without carbon pricing and a “change case” with carbon pricing, but they each differ in the years evaluated. The Brattle study evaluates effects in 2020, 2025 and 2030, while Daymark’s analysis evaluates 2021-2025, 2030 and 2035. The RFF analysis focuses solely on 2025. (See NY Details Carbon Charge on Wholesale Suppliers.)
Daymark Energy Advisors’ projected carbon emissions under a New York carbon pricing policy. | Daymark
Analytical Results
Daymark’s Marc Montalvo said that his group’s study found that “carbon emissions in New York are about flat. There’s not really a material change as a consequence of the introduction of the carbon charge.”
RFF’s Dan Shawhan said his group’s updated results show “a CO2 emissions reduction of 0.2 million tons in the simulated year, which is 2025, and that’s about 0.65%, so about two-thirds of a percentage point reduction in New York emissions. And I don’t disagree with the characterization that you could describe that as not a big change in emissions.”
Brattle’s Sam Newell agreed and said “a lot of what’s happening here is we’re comparing to a base case that already has in place the Clean Energy Standard and other mechanisms to reduce emissions.”
But both the RFF and Brattle studies say that a carbon pricing policy can also be expected to reduce emissions in ways not captured in the modeling.
The carbon charge is another way of accomplishing decarbonization with more dollars put toward a market-oriented approach, and less money relying on targeted programs, Newell said.
“In both cases there’s decarbonization, so it’s not a surprise that there’s not some major change in carbon with the introduction of this policy,” Newell said. “Directionally it’s going to be an improvement because it finances some low-cost forms of carbon abatement, and there are probably some long-term investment effects.”
All studies find higher statewide locational-based marginal prices resulting from a carbon charge, with increases most significant downstate. The Brattle analysis finds LBMPs would rise by less than the Daymark and RFF studies.
Differences in LBMP changes can be at least partly explained by differences in each study’s modeling of the market heat rate, and also in part by assumptions regarding the net social cost of carbon in each study, the ISO’s summary said.
The studies assume similar carbon charges through 2025, but the Daymark study finds LBMP impacts would increase from 2025 to 2035. In contrast, Brattle finds lower carbon charges in 2030 than 2025 because of assumed increases in the Regional Greenhous Gas Initiative price, resulting in carbon charges of $45.40/ton in 2030, compared with $57/ton in 2030 assumed by Daymark.
Brattle and RFF both find collected carbon revenues on the order of $1.5 billion per year; Daymark finds declining carbon revenues, falling from $1.4 billion in 2021 to $1 billion in 2035.
Stakeholder Requests
DeSocio presented an update on NYISO’s progress in meeting stakeholder requests for further analysis on certain points.
Analysis is under way on augmenting the Brattle analysis with 2022 results and considering the effects of carbon pricing on repowering and retention, and should be ready for discussion at the Nov. 26 task force meeting, he said.
The ISO also said it does not recommend following a stakeholder suggestion to lower the 2030 RGGI price estimate because such a move is not supported by analysis based on results provided to date, DeSocio said. As RGGI is adjusted downward both with and without carbon pricing, the other parts of the analysis approximately scale. Because the overall impact is near zero, the scaled impact is near zero.
To consider the consequences of no carbon pricing, including estimates of the costs of various buyer-side mitigation scenarios, and the consequences of NYISO’s AC transmission project in western New York, the ISO is still considering how it might structure such analyses and will update the IPPTF at its next meeting, he said.
Regarding the effects of a carbon charge on existing renewable energy credit contracts and future REC contracts, DeSocio said, “In our analysis to date, we are not suggesting that REC contracts go away. Certainly the price of a REC contract may go down because the carbon price is being realized and therefore the delta payment that a renewable resource is getting is less, but in the analysis so far, we haven’t shown that to go to zero.” (See NY Carbon Task Force Looks at REC, EAS Impacts.)
The Daymark study does not evaluate changes in REC and zero-emission credit prices stemming from a carbon charge, but it finds the following gross profit margin (revenue minus fuel costs) average increases: upstate nuclear plants 70%; upstate solar 48%; upstate wind 46%; downstate offshore wind 47%; and downstate solar 51%, according to the ISO synthesis.
The RFF analysis finds the carbon charge would reduce REC prices from $43/MWh to $24/MWh and would reduce ZEC prices from $14/MWh to $0/MWh in 2025.
The Brattle analysis finds the carbon charge would reduce ZEC prices from $25/MWh to $12/MWh in 2025, while REC prices would fall from $22/MWh to $3/MWh in 2020, $25/MWh to $7/MWh in 2025 and $28/MWh to $12/MWh in 2030.
The task force next meets on Nov. 26. It plans to announce a proposal to incorporate carbon pricing into the state’s wholesale market next month.
OGE Energy beat expectations last week, reporting third-quarter earnings of $205 million ($1.02/share), up from a year ago, when it earned $183 million ($0.92/share).
A Zacks Investment Research survey of analysts had projected earnings of 96 cents/share.
“Good companies grow, and that is clearly what we are doing,” CEO Sean Trauschke said during a Nov. 8 conference call with analysts.
OGE’s regulated utility, Oklahoma Gas & Electric, contributed 92 cents/share during the quarter, thanks to new rates in Oklahoma, favorable weather and increased customer demand.
OG&E crews at work | OGE Energy
The Oklahoma City company also received earnings of 14 cents/share from Enable Midstream Partners, a gas-gathering and processing joint venture with Texas utility CenterPoint Energy.
Enable said Nov. 7 that it processed record amounts of natural gas during the third quarter. OGE holds a 25.7% limited-partnership interest and a 50% management interest in Enable, while CenterPoint owns a 54.1% share.
OGE increased and narrowed its year-end guidance to $1.59 to $1.61/share, up from $1.43 to 1.53/share.
OGE shares finished the week at $38.08/share, up almost 16% since the beginning of the year.
CenterPoint Earnings Drop 4 Cents
CenterPoint reported third-quarter earnings on Nov. 7 of $153 million ($0.35/share), a drop from a year earlier, when it earned $169 million ($0.39/share).
Revenues totaled $2.2 billion, up from $2.1 billion a year ago, thanks to increased rates and a growing customer base.
CenterPoint Energy EV | CenterPoint Energy
CEO Scott Prochazka told analysts during a conference call that the Houston-based company in October completed the equity and fixed rate debt components of the financing for its $6 billion acquisition of Indiana utility Vectren. Prochazka said the acquisition is still expected to close in the first quarter of 2019 and has targets in place “that are in line” with an $50 million to $100 million in pretax earnings by 2020.
CenterPoint’s share price lost 51 cents following the earnings announcement, finishing the week at $28.16.
MARLBOUROUGH, Mass. — Can New England balance reliability, economics and public policy in a fast-changing energy world? How will the region better prepare itself to handle winter cold snaps than in the past?
These and other questions arose at the Northeast Energy and Commerce Association’s 17th Power Markets Conference on Nov. 8. Here are highlights of what we heard.
Ashley Brown, executive director of Harvard University’s Electricity Policy Group, said, “My fear today is that we’re moving back to a battle between various special interest groups and further politicizing the sector.”
Resource selection based on economics, reliability and social benefits has given way to state subsidies and mandates that often work against public policy environmental goals, with uneconomic resources chasing bailouts instead of focusing on how to become more efficient, he said.
“Part of the problem … is that we have simply failed to internalize social considerations in economics,” Brown said. “The lack of a carbon policy in the U.S. is not only intellectually bankrupt, but it does in fact penalize emissions-free resources.”
Mark Karl, ISO-NE vice president for market development, said the region is moving into an era in which more resources have less fuel security. The grid operator is concerned the situation will get worse.
Fuel logistics become an issue in winter, whether because of natural gas pipeline constraints, limited dual-fuel storage or reduced ability to deliver oil by truck, he said. The significant retirement of large non-gas-fired generation is an important factor, as is the type of oil used.
“For example, some generators are burning No. 6 oil, which is basically almost asphalt, so in the wintertime, when that stuff gets cold, it gets pretty difficult to pump and move,” Karl said.
The retirement of two nuclear plants and the Brayton Point coal plant in recent years might be good for the environment, but collectively it presents a challenge for reliability, he said.
Karl said ISO-NE is looking to create a new reserve service referred to as “the energy inventory reserve constraint.”
“We’re proposing to incorporate into the real-time market an additional constraint that looks at the ability to provide energy storage or an energy bank,” he said. “I want to be careful here because it’s easy to think about this from the standpoint of conventional generator fuel, but this will apply to any sort of resource that has the ability to maintain essentially a reserve bank of energy that can be converted into electricity when needed.”
The idea is to optimize the use of limited energy over more extended periods compared with how markets are currently designed to optimize energy over the course of an operating day, he said.
Outside the marketplace, operators also worry about the next day and the days that follow, and sometimes order an oil-burning unit offline for a weekend anticipating the need to provide reserves come Monday, “so that’s an out-of-market action that does cause distortions in the marketplace,” Karl said.
Brett Kruse, vice president of market design at Calpine, said ISO-NE could use a six- or seven-day-ahead market to effectively manage storage in a way that avoids having to take out-of-the-market actions.
The proposal could help the RTO manage how it deploys plants day to day and provide an insurance policy to keep a certain amount of storage in the system, he said.
“There are a lot of questions about that and how it would be priced, but it’s conceptually a pretty good idea,” Kruse said.
But he also had some reservations about the plan. “Looking at the way they’re presenting it now, where it’s a voluntary forward market, and won’t have any mitigation, which is a key aspect to go with that, we think it has some potential, although it’s hard to see how a lot of load will come into that,” he said.
David Cavanaugh, vice president of regulatory and market affairs for Energy New England, an energy services firm, said the RTO’s thinking at first glance seems robust, as its design extends beyond the winter period into a period where the bulk power system has more renewables and, perhaps, storage resources.
“I’m not sure the sophistication of this model gets us there … but we can be informed by other interim efforts such as the opportunity cost model set for use this winter,” Cavanaugh said. “I think the design is well thought out … just have some concerns when I look at the multi-day-ahead market, its voluntary participation,” in terms of maintaining adequate fuel stocks.
Abigail Krich, president of Boreas Renewables, said she sees a market design that, “even though it was triggered by fossil fuel issues, could work with that transition to a clean energy system that relies on intermittent generation. It looks like something that makes sure we have a dispatchable store of available energy in reserve.”
“I question whether we need all of these pieces in the proposal or whether we might just use some of them,” Krich said.
Public Policies
Discussing the race for renewables at the state level, Peter Fuller of Autumn Lane Energy Consulting said the tension in these markets is understandable. While consumers have benefited greatly from the markets, and investors and market participants have an expectation that everyone in the market will play by the same set of rules, states pursuing policy objectives don’t necessarily feel bound by those rules. In addition, the states have not been able, individually or collectively, to identify exactly what they want in a way that an RTO can create a market for it, he said.
Rather, states want to maintain control of resource decisions as policy objectives continue to evolve over time. “As much as anything they want to control that,” Fuller said. “If I’m a governor or legislator thinking how I want to transform the energy system in my state, my first instinct is not to send somebody to [the New England Power Pool] or to PJM to offer proposals, to come up with a matrix or a set of market rules and see how that plays out.” States are more likely to take direct action that then can cause dislocations in the markets.
Day Pitney attorney Sebastian Lombardi, who serves as counsel to NEPOOL, said that overlaying all the fuel security and grid resilience efforts is the need for regions to continue to engage in efforts to help bridge the divide between evolving state and federal policies and the market.
“From a state policy perspective, the competitive markets are not always achieving what they’d like the markets to achieve,” Lombardi said.
Darlene Phillips, senior director for strategic policy and external affairs at PJM, explained the RTO’s proposed revamp of its capacity market.
The Extended Resource Carve-out proposal would allow specific, state-subsidized resources to opt out of the capacity market and PJM to adjust market clearing prices as if the resources were still in it. (See related story, PJM Stakeholders Hold Their Lines in Capacity Battle.)
“If you don’t want your subsidized resources to get a minimum offer for price and go into the market, we will allow you to take those resources out of the market,” she said. “One of the things that FERC did not like about our original approach is that we actually paid those resources a payment.”
When it comes to existing renewable resources, PJM’s minimum offer price rule would have very little impact because the price would be zero, she said. The RTO applies a 20-MW threshold to renewables for the MOPR, which most of them don’t meet, though that situation might change with large-scale offshore wind coming along.
ATLANTA — NERC stakeholders are expected to consider a new standard authorization request (SAR) to address inverter-based resources after the Standards Committee rejected two SARs proposed by CAISO in September, officials said last week.
CAISO submitted the SARs in May, saying it had recorded at least 14 occasions since August 2016 when inverter-based solar generation incorrectly tripped or ceased to operate during the routine high-speed clearing of short circuits on bulk electric system (BES) transmission. NERC has issued several reports and alerts following the two most serious incidents: the August 2016 Blue Cut wildfire, when 1,200 MW of solar disconnected; and the October 2017 Canyon 2 fire, which resulted in the loss of more than 900 MW. (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)
Most solar PV generation (top map) is below the 75-MW threshold requiring registration with NERC (bottom map). | NERC
The ISO proposed incorporating performance requirements for inverter-based resources connected to the BES in a revised NERC standard PRC-024, or developing a new standard for such resources and clarifying that PRC-024 applies only to synchronous generation.
At its Sept. 13 meeting, however, the Standards Committee rejected both SARs by a 12-5 vote on a motion by Dominion Energy’s Sean Bodkin, who noted the Institute of Electrical and Electronics Engineers (IEEE) is addressing the issues in Standard 1547-2018.
NERC is working with IEEE on the standards for inverter settings and developing instructions on compliance monitoring and enforcement activities related to the issue, James Merlo, NERC vice president of reliability risk management, told the Member Representatives Committee (MRC) at its quarterly meeting Nov. 6.
FERC Commissioner Cheryl LaFleur, who attended the MRC and Board of Trustees meetings, said she was concerned about the rejection of the SARs, saying “nothing clarifies the mind like an enforceable standard.” She said it was better for NERC and its stakeholders to design standards rather than respond to directives from FERC.
NERC CEO Jim Robb said he was disappointed that the two SARs “met with such headwinds at the Standards Committee.”
“I think we need to get over the notion that any standard creates peril and get to the point where standards create certainty,” he said. “And I think, particularly, in the case of these inverter resources, that’s a very, very important thing for us to do. … These resources are not going away. They’re already at scale in the West, and they will [soon] be at scale … in many parts of the country.”
Merlo said the Operating and Planning committees and the Inverter-Based Resource Performance Task Force will seek a new SAR to modify PRC-024 that will build on a white paper to be released in about two weeks identifying gaps between current standards and what’s needed by grid operators. “The expectation is the Standards Committee would take that up in December,” Merlo said.
“I’m optimistic that that will accomplish much of what we wanted to accomplish through the original two SARs,” Robb said.
The work may not stop with revisions to PRC-024, said Howard Gugel, NERC senior director of engineering and standards. “Then that task force is also going to go forward to say, ‘given that this is a brave new world and we have these resources, is there another standard that we should write that says how they should actually operate?’” he said in an interview. “And it’s not just limited to solar. … [idle EVs injecting energy into the grid are] an inverter resource also.”
NERC has already asked solar generators to modify their inverter settings to ensure voltage excursions don’t result in momentary cessation (MC) — when they stop injecting current into the grid. For inverters that cannot use another ride-through mode, NERC asked that MC settings be reduced to the lowest voltage value possible and that the recovery delay be reduced to one to three electrical cycles.
In arguing for the SARs, CAISO’s Keith E. Casey, vice president of market and infrastructure development, noted that NERC guidelines are not enforceable.
“Due to a lack of any standard addressing the minimum performance of inverter-based generation connected to the BES, original equipment manufacturers often apply standards for resources connected to the distribution system to BES resources,” Casey wrote.
NERC reported that most of the lost solar generation in the Blue Cut fire resulted when inverters incorrectly perceived a low frequency condition and tripped, not returning to service for five minutes or longer. “Five minutes may make sense on a rooftop, but five minutes is an eternity on the bulk electric system,” Merlo said.
NERC, which originally surveyed 13,543 MW of solar PV as potentially using momentary cessation, now believes all but about 1,952 MW do not use it or can overcome it with modified settings. (The survey covered only utility-scale solar generators at or above 75 MW, the threshold for generators that must register with NERC.)
“We understand a lot more than we did when we first saw the event just 18 months” ago, Merlo said.
MISO is working to create market rules for capacity reserves that can be supplied within 30 minutes, though the RTO won’t have a sophisticated enough technology platform to support the new product for more than two years.
RTO staff told the Market Subcommittee on Nov. 8 that the earliest the new product could be rolled out is the first half of 2021 because it will require the new market platform.
MISO Director of Market Design Kevin Vannoy said the short-term reserve product will address issues that are “more severe” than can be solved by either the ramp product and regulation reserve, which is supplied within seconds, or issues that are “less severe” than the Disturbance Control Standard events requiring the RTO’s 10-minute contingency reserves.
“The idea is to get the 30-minute reserves reflecting actual needs [of the system] rather than trying to have the 10-minute reserves covering it,” Vannoy said.
“We have needs that we make out-of-market commitments for, but they’re not modeled in the market,” said Bill Peters of MISO’s market design team.
The short-term reserves would be furnished by either online generators dispatched according to opportunity costs or offline generators, which would be dispatched based on an offer price.
Peters said short-term reserves would help manage flows on SPP transmission between MISO Midwest and MISO South and aid areas hemmed in by transmission constraints or short on nimble reserves. They also will help meet load and avoid volatility as the RTO adds more intermittent resources.
MISO’s final ranking of Market Roadmap improvements placed the creation of short-term reserves at the highest priority, beating out projects to better model combined cycle generators, and respond to shifting resource availability and need.
Peters said the reserves could have market-wide, regional and local response requirements. He said MISO would dynamically schedule the reserves to a load pocket or region, assessing the state of the system, capacity needs, amount of cleared energy and amount of cleared short-term reserves before dispatch. He also said the RTO is considering applying a demand curve to pricing. Peters said the generators that sign up to provide the service will be tested to demonstrate they’re able to provide capacity within 30 minutes.
MISO has scheduled a Jan. 15 workshop to further discuss the conceptual design of a short-term reserve product.
Pacific Gas and Electric’s stock price rose dramatically Friday after state California Public Utilities Commission President Michael Picker made a series of surprising public statements about the company’s future as it faces potentially billions of dollars in wildfire liability for the current Camp Fire, the deadliest in state history, and a series of devastating blazes in 2017.
On Thursday, Picker took part in a call with Wall Street analysts in which he said allowing PG&E to go bankrupt wouldn’t be good policy, Bloomberg News and other media outlets reported. He reiterated those comments in at least two newspaper interviews, and discussed the possibility of legislative action to relieve PG&E’s financial burden.
But Picker also said he was concerned about the utility’s lack of accountability. He told the Wall Street Journal that breaking up the company might be an option for regulators to consider. In a news release, the PUC president said he intended to expand an ongoing investigation into PG&E’s “safety culture” that the commission opened after the San Bruno gas line explosion in 2010.
“In the existing PG&E Safety Culture investigation proceeding,” Picker said in the statement, “I will open a new phase examining the corporate governance, structure, and operation of PG&E, including in light of the recent wildfires, to determine the best path forward for Northern Californians to receive safe electrical and gas service in the future.”
PG&E’s stock rose back to around $24 per share Friday after it plunged this week as the toll of death and destruction from the Camp Fire, the worst in modern California history, increased. The company fell under suspicion for starting the wildfire after one of the utility’s transmission lines was reported downed at the time and location of the fire’s ignition.
NASA’s Earth Observatory photographed the Camp Fire as it exploded late last week. | NASA
The news sent PG&E Corp.’s stock tumbling from roughly $48 per share on Nov. 8, when the fire started, to less than $18 per share on Thursday – a 62.5% drop in one week.
Similarly, Southern California Edison’s stock fell sharply as the Woolsey Fire raged in Los Angeles and Ventura counties, killing two and destroying more than 500 structures so far. Edison told state regulators it experienced an outage at a substation near where the fire started, the Los Angeles Times reported.
On Nov. 8, PG&E filed a report with the California Public Utilities Commission, saying it had experienced an outage on a 115-kV line near where the Camp Fire started and shortly before it was first reported. The company later wrote in a news release that the “information provided in this report is preliminary, and PG&E will fully cooperate with any investigations. There has been no determination on the causes of the Camp Fire.”
Early Thursday morning, firefighters responded to reports of a vegetation fire under transmission lines near Poe Dam, part of PG&E’s Feather River Canyon Power Project in rural Butte County. The California Department of Forestry and Fire Protection (Cal Fire) has identified the area as the approximate location where the fire started. A property owner in the area has told media outlets that she received an email from PG&E saying the company planned to do work on her land because its power lines were causing sparks.
Fanned by 35-mph winds, the fire quickly grew and destroyed most of the town of Paradise (population 27,000). As of Friday, it had killed 63 civilians, destroyed approximately 9,844 homes and hundreds of other structures and burned 142,000 acres, Cal Fire reported.
Previously the deadliest fire in state history was the Griffith Park Fire in Los Angeles in 1933, which killed 29 people, according to Cal Fire. The most damaging in terms of homes and other structures destroyed previously was the Tubbs Fire in Napa and Sonoma counties in October 2017, the cause of which is still under investigation.
The largest wildfire in modern state history, the Mendocino Complex of fires, occurred this summer, burning 459,000 acres in the rugged mountains north of San Francisco from July to September 2018.
The Camp Fire decimated the town of Paradise in the Sierra Nevada foothills. | Cal Fire
The Camp Fire has revived talk of PG&E’s possible bankruptcy, which became the subject of concern following a series of devastating wildfires in 2017. State fire investigators have said PG&E was responsible for 17 of the 21 blazes. The 2017 fires could subject the company to billions of dollars in liability under California’s unique system of holding utilities strictly liable for damage caused by power lines and equipment, regardless of negligence.
Earlier this year Gov. Jerry Brown proposed doing away with that system, known as inverse condemnation, arguing it threatened electric reliability and the state’s efforts to completely exclude carbon emissions from its power grid by the middle of the century.
Lawmakers tasked with formulating a major wildfire bill, SB 901, ultimately left inverse condemnation intact while creating a method by which utilities could issue long-term bonds to pay for some fire damage. (See California Wildfire Bill Goes to Governor.) Critics called the bill a bailout for the utilities, but Brown signed the legislation in September.
PG&E executives recently said in an earnings call that the new law was insufficient, and they intend to seek an end to inverse condemnation through the courts and legislature. (See PG&E Outlines Fire Strategy in Earnings Call.)
Company CEO Geisha Williams also discussed the company’s new practice of proactively shutting down sections of its grid during conditions that made wildfires especially dangerous. The company warned last week that it might have to shut down power to areas, including Butte County, but then decided conditions there did not warrant it.
In its recent third-quarter earnings call, SCE said its equipment was likely a partial cause of the hugely destructive and deadly Thomas Fire last year. That fire was the largest in state history until this year’s Mendocino Complex far surpassed it. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
SCE’s stock price fell from more than $25 a share before the Woolsey fire began, also on Nov. 8, to around $21 per share in trading Thursday.
ATLANTA — NERC stakeholders are expected to consider a new standard authorization request (SAR) to address inverter-based resources after the Standards Committee rejected two SARs proposed by CAISO in September, officials said last week.
CAISO submitted the SARs in May, saying it had recorded at least 14 occasions since August 2016 when inverter-based solar generation incorrectly tripped or ceased to operate during the routine high-speed clearing of short circuits on bulk electric system (BES) transmission. NERC has issued several reports and alerts following the two most serious incidents: the August 2016 Blue Cut wildfire, when 1,200 MW of solar disconnected; and the October 2017 Canyon 2 fire, which resulted in the loss of more than 900 MW. (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)
The ISO proposed incorporating performance requirements for inverter-based resources connected to the BES in a revised NERC standard PRC-024, or developing a new standard for such resources and clarifying that PRC-024 applies only to synchronous generation.
At its Sept. 13 meeting, however, the Standards Committee rejected both SARs by a 12-5 vote on a motion by Dominion Energy’s Sean Bodkin, who noted the Institute of Electrical and Electronics Engineers (IEEE) is addressing the issues in Standard 1547-2018.
NERC is working with IEEE on the standards for inverter settings and developing instructions on compliance monitoring and enforcement activities related to the issue, James Merlo, NERC vice president of reliability risk management, told the Member Representatives Committee (MRC) at its quarterly meeting Nov. 6.
FERC Commissioner Cheryl LaFleur, who attended the MRC and Board of Trustees meetings, said she was concerned about the rejection of the SARs, saying “nothing clarifies the mind like an enforceable standard.” She said it was better for NERC and its stakeholders to design standards rather than respond to directives from FERC.
NERC CEO Jim Robb said he was disappointed that the two SARs “met with such headwinds at the Standards Committee.”
“I think we need to get over the notion that any standard creates peril and get to the point where standards create certainty,” he said. “And I think, particularly, in the case of these inverter resources, that’s a very, very important thing for us to do. … These resources are not going away. They’re already at scale in the West, and they will [soon] be at scale … in many parts of the country.”
Merlo said the Operating and Planning committees and the Inverter-Based Resource Performance Task Force will seek a new SAR to modify PRC-024 that will build on a white paper to be released in about two weeks identifying gaps between current standards and what’s needed by grid operators. “The expectation is the Standards Committee would take that up in December,” Merlo said.
“I’m optimistic that that will accomplish much of what we wanted to accomplish through the original two SARs,” Robb said.
The work may not stop with revisions to PRC-024, said Howard Gugel, NERC senior director of engineering and standards. “Then that task force is also going to go forward to say, ‘given that this is a brave new world and we have these resources, is there another standard that we should write that says how they should actually operate?’” he said in an interview. “And it’s not just limited to solar. … [idle EVs injecting energy into the grid are] an inverter resource also.”
NERC has already asked solar generators to modify their inverter settings to ensure voltage excursions don’t result in momentary cessation (MC) — when they stop injecting current into the grid. For inverters that cannot use another ride-through mode, NERC asked that MC settings be reduced to the lowest voltage value possible and that the recovery delay be reduced to one to three electrical cycles.
In arguing for the SARs, CAISO’s Keith E. Casey, vice president of market and infrastructure development, noted that NERC guidelines are not enforceable.
“Due to a lack of any standard addressing the minimum performance of inverter-based generation connected to the BES, original equipment manufacturers often apply standards for resources connected to the distribution system to BES resources,” Casey wrote.
NERC reported that most of the lost solar generation in the Blue Cut fire resulted when inverters incorrectly perceived a low frequency condition and tripped, not returning to service for five minutes or longer. “Five minutes may make sense on a rooftop, but five minutes is an eternity on the bulk electric system,” Merlo said.
NERC, which originally surveyed 13,543 MW of solar PV as potentially using momentary cessation, now believes all but about 1,952 MW do not use it or can overcome it with modified settings. (The survey covered only utility-scale solar generators at or above 75 MW, the threshold for generators that must register with NERC.)
“We understand a lot more than we did when we first saw the event just 18 months” ago, Merlo said.
SAN FRANCISCO — This year’s ACORE Renewable Energy Grid Forum took place in a high-rise hotel within blocks of the headquarters of tech revolutionaries Twitter, Uber and Airbnb, among many others. So it was fitting that the forum’s speakers, including Google’s head of global energy policy, grappled with what keynote speaker and FERC Commissioner Richard Glick called the “energy revolution.”
Coming advances in electricity generation and distribution — such as mass storage, distributed renewables and computer algorithms that can monitor a vastly complicated grid — will make older modes seem like the horse and buggy at the dawn of the automobile era, Glick said. Back then, those invested in buggies would try to dissuade people from buying automobiles, he said.
“Every time a car would drive by someone would yell, ‘Get a horse,’” Glick told the audience at the Grand Hyatt San Francisco, near Union Square. “We’re kind of in that situation now” with fossil fuels and renewables, he said.
Another keynote speaker, CAISO CEO Steve Berberich, said the traditional model of centralized generation using fossil fuels is already “fraying around the edges” as the price of solar and wind power continues to plummet. The cost of storage is also falling, he said, and every state except Idaho has a renewable energy goal.
“Even conservative states such as Utah are pursuing [renewable energy],” Berberich noted.
The third keynote speaker, Laura Nelson, energy adviser to the Utah governor’s office, told the audience that the price of renewables has dropped 50% in the last five years, and Utah has increased its reliance from 1% to 8%, with big investments in utility-scale solar and geothermal power.
In a panel titled “Evolving Models for Electricity Markets,” Ralph Cavanagh, senior attorney with the Natural Resources Defense Council, said the biggest impediment to renewable integration is the fragmented Western grid.
Efforts to expand CAISO to an RTO for Western states had sputtered, he said, because other states were not willing to accept a board appointed by the California governor and confirmed by the State Senate, and California politicians weren’t willing to share control of the RTO. (See Can Calif. Go All Green Without a Western RTO?)
CAISO’s governance structure would need to change for California and neighboring states to participate in an organized wholesale market, he said. Gov. Jerry Brown supported the failed efforts at regionalization, partly as a means of achieving the clean energy goals of SB 100, which he signed in September. (See Calif. Gov. Signs Clean Energy Act Before Climate Summit.)
Mars Hanna, Google’s head of global energy policy and markets, said his company, like California, is trying to reach a goal of relying on 100% carbon-free energy. To get there, he said, “We need to be able to blend Wyoming wind with Nevada solar.”
Addressing the recent election, Rose McKinney-James, managing partner of Nevada-based Energy Works, said state voters had rejected Question 3, a ballot proposal to allow customers to choose their energy providers, largely because they were concerned about rates going up. (See related story, High Failure Rate for Western Ballot Measures.) Nevada’s electricity rates are 45% less than California’s, she said.
Another big factor, she said, was that NV Energy, the state’s monopoly electric provider, had announced plans before the election to develop 1,300 MW of solar generation. But that would only happen if the company remained a monopoly, she said.
Cavanagh agreed. “[NV] Energy reinvented itself” as green and clean, he said. “It gave us something to vote for.” Now “you’re going to have a revitalized [NV] Energy as a player in the West.”
Pat Reiten, senior vice president of government relations for Berkshire Hathaway Energy, also was on the panel. NV Energy is a subsidiary of Berkshire Hathaway, billionaire Warren Buffett’s company.
Reiten said the falling cost of solar had persuaded the company to invest in it. NV Energy once uselessly bid solar into California’s market at $100/MWh, far more than fossil fuels, he said, but the price now is $20 or $30/MWh and competitive with other energy sources. “That’s rather remarkable,” Reiten said.
On the stage at the Grand Hyatt near Union Square, McKinney-James turned to Reiten and said she and many others expect NV Energy to keep its commitments.
“We do have expectations, and there will be feet held to the fire,” she said, eliciting laughs from the audience.
After lunch, conference attendees were invited to submit questions via an app to panelists Angelina Galiteva, a member of CAISO’s Board of Governors and founder and chairwoman of the Renewables 100 Policy Institute, and Dan Reicher, executive director of Stanford University’s Steyer-Taylor Center for Energy Policy and Finance.
The first question was, “What is the biggest issue facing the grid as renewables proliferate?”
Intermittency, both speakers said, but they argued it isn’t as big a problem as many critics have contended.
Galiteva said she grew up in Tanzania, where local solar proved far more reliable than the spotty power supplied by a central generating station. “That’s where I fell in love with renewables,” she said.
Many criticize renewables such as wind and solar as being intermittent and unreliable, but Galiteva said she believes “renewables are more reliable than centralized power,” especially as renewable power sources proliferate.
The fact that renewable energy sources are distributed provides an inherent safety backup compared with centralized power, Galiteva said. “Look at the San Onofre power plant,” she said. The San Onofre Nuclear Generating Station, on the Southern California coast, shut down suddenly in 2012 after problems arose, and the grid lost the plant’s 2,350 MW.
Galiteva also pointed to the Aliso Canyon gas storage facility, a major resource for the Los Angeles area, which shut down after a massive leak was discovered in October 2015. Constraints on natural gas supply have resulted ever since. (See CAISO Seeks to Extend Aliso Canyon Rules.)
Reicher said intermittency was generally considered the main problem with renewables, but not all renewables are intermittent, he said. Hydropower, geothermal and biomass are regular, dependable sources, he said.
Storage, including pumped hydro, will make solar and wind more readily available during peak demand times, he said.
Floating wind farms off the coast of California, if ever approved by federal authorities, would be a reliable source of wind power. California’s coast has some of the most regular winds in the nation, and those winds pick up just as the state’s solar energy tapers off for the day, Reicher said.
“When you go to the beach in California,” he said, “the sun goes down and the wind comes up.”
NRG Energy earned $306 million last quarter, up 65% from the same period a year ago on strong returns for the company’s generation business.
