AUSTIN, Texas — State regulators Thursday agreed to “marinate” on an administrative law judge’s order approving AEP Texas’ request to connect a pair of utility-scale lithium ion battery facilities to the ERCOT grid.
Public Utility Commission Chair DeAnn Walker said she will file a memo in the docket (46368) explaining how she would like to move forward, while Commissioner Brandy Marty Marquez asked for another chance to discuss the matter publicly and said a rulemaking may be needed.
“The PFD [proposal for decision] did make some strong points,” Marquez said. “A lot of what we’re working through is a market that we all love and how to [incorporate batteries]. They are coming, so how does that happen?”
The order is opposed by a “diverse range of market participants,” observed Emily Jolly, legal counsel for Luminant and TXU Energy, which oppose AEP’s proposal. The opponents include Calpine, the state Office of Public Utility Counsel and several consumer organizations, who argue that allowing the assets to be included in AEP’s regulatory base would harm competition.
“The goal of competition is to minimize regulatory facilities, not encourage them to proliferate,” Jolly said. “What the PFD does not explain is why preserving the market structure is beneficial. Competition fosters innovation and efficiency. We’ve seen that play out” in ERCOT.
Attorney Kerry McGrath, representing AEP, said the batteries would be used “very, very infrequently. Twelve times a year, on average.” They would also not be used for commercial activities, he said.
AEP filed its application in 2016. ALJ Stephanie Frazee’s October decision would allow the facilities to be classified as distribution assets and included in AEP’s cost-of-service rates.
The company wants to install the 1-MW and 50-kW battery facilities in remote areas of West Texas, setting them to automatically discharge during an outage or to serve additional loads. It has proposed the energy be accounted for as “unaccounted-for energy (UFE),” which ERCOT defines as the difference between the system’s total generation supply and the total system load plus losses.
“By allowing these facilities to be settled through UFE, you would be charging one set of customers when the battery is charged, then give free energy away to another set of customers,” said attorney Katie Coleman, speaking for the Texas Industrial Energy Consumers trade association. “The settlement mechanism was never intended for this purpose. We’re concerned about distortions to pricing in the market and ratepayer-subsidized facilities participating in the wholesale market.”
PUC staff also intervened, saying the commission should open a rulemaking if it approves the ALJ’s order. OPUC’s Sara Ferris agreed with staff and said the batteries should be classified as generation assets.
“The rulemaking should be sufficiently broad to encompass other alternatives besides batteries,” Ferris said.
“I agree a rulemaking is in order here,” Marquez said. “This is new.”
VALLEY FORGE, Pa. — PJM’s Tim Horger provided an update on the RTO’s efforts to comply with FERC’s plan on fast-start pricing at last week’s Market Implementation Committee meeting. The commission last month withdrew its Notice of Proposed Rulemaking on fast-start pricing because it said a uniform set of requirements isn’t appropriate for all RTOs and ISOs. Instead, it called on PJM, SPP and NYISO to make changes. (See FERC Drops Fast-Start NOPR; Orders PJM, SPP, NYISO Changes.)
Horger said PJM’s initial response is due Feb. 12 and that a final order is expected on Sept. 30. FERC indicated that PJM should:
Allow for relaxation of all fast-start resources’ economic minimum operating limits by up to 100%, such that the resources are considered dispatchable from zero to their economic maximum operating limit for the purposes of setting prices;
Apply the relaxation of a resource’s economic minimum operating limit to all fast-start resources, not just block-loaded fast-start resources;
Consider fast-start resources within dispatch in a way that is consistent with minimizing production costs, subject to appropriate operational and reliability constraints;
Modify pricing logic to allow the commitment costs of fast-start resources to be reflected in prices;
Include in the definition of fast-start resources a requirement that those resources have a minimum run time of one hour or less;
Include in the definition of fast-start resources a requirement that those resources be able to start up within one hour or less; and
Set forth its rules and practices regarding the pricing of fast-start resources.
Horger said PJM plans to “generally support” the suggestions and provide additional feedback, including the definition of “fast start.” It will also supply recommendations on the relaxation method between economic minimum and “integer relaxation” — a pricing method designed to minimize uplift costs.
Day-Ahead Market LMP Confusion
Horger also provided an explanation of a situation that created stakeholder confusion when PJM announced it planned to revise day-ahead market LMPs, then retracted that plan: The aggregate percentages for the IMO interface — the pricing point between PJM and Ontario’s Independent Electricity System Operator — for Dec. 26 to 30 were “slightly off.”
Upon further review, staff determined that the issue was minimal and didn’t violate the Tariff, so they decided to retain the original values instead of disturbing the market.
Stakeholders pointed out that PJM’s series of communications, which initially said a change would be made before later reversing that decision, was confusing.
“Your feedback is on target. … We probably caused some confusion by jumping the gun,” PJM’s Stu Bresler said.
The normal process would be to announce that an issue was found and then later announce revisions will be made once the determination is complete, he said, instead of announcing them both initially.
“Historically, when we think a situation is cut and dry, we combine the first two steps: announcing the issue and saying we’re going to change things,” he explained. “We should have issued the notification that we found something, but not” the announcement that changes would be made.
Market Impacts of Cold Weather
PJM’s Joe Ciabattoni told stakeholders to expect more uplift from the cold snap that occurred over the holiday break, but “nothing near” the market impacts from the cold streak in 2014 known as “the polar vortex.”
“We had a couple of $2 million days,” he said, but “I don’t think that the magnitude will be anything near what we saw in the polar vortex” when there were days of $86 million and $50 million. The difference this time, he said, was that the cold temperatures were sustained.
“In 2014 and 2015, the temperatures were more extreme, though not as long of a time frame,” he said.
Unplanned outages began to “crop up” near the end of the cold period on Jan. 6, but conditions never triggered requirements that maintenance outages close out within 72 hours. Ciabattoni said there were “plenty” of new 30-minute reserves measurements developed to help address gas pipeline contingencies.
“We’re getting [outage] tickets in early, as opposed to the polar vortex, when we were surprised by some outages,” he said.
Stakeholders approved a problem statement and issue charge on remapping financial transmission rights nodes. PJM’s Brian Chmielewski explained that the nodes where FTRs begin or end can be terminated based on changes in load, generation or system topology. When that happens, an “electrically equivalent” node must be identified to replace the terminated one. PJM’s current process for that search “may not guarantee an optimum substitute” that provides the same economic value and might lack transparency.
Direct Energy’s Marji Philips expressed concern with the wording of the problem statement.
“The problem is if PJM can’t find [an electrically equivalent node], it just flat out terminates the FTR,” she said. “I’m not sure the statement actually captures that.”
Rules Endorsed for Enforcing Regulator Requirements on EE
With three abstentions, stakeholders endorsed rule changes that will allow state and local regulators to manage energy efficiency participation within their jurisdiction if they receive FERC approval.
PJM’s Pete Langbein explained the process, which stems from a December ruling in which FERC established its “exclusive authority” over EE participation in wholesale markets while also preserving a carveout it had previously approved for Kentucky utilities. (See FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out.)
Under the new process, PJM must alert all affected electric distribution companies about the impact of any such FERC approvals. EE that cleared the auction but isn’t allowed to deliver into a particular jurisdiction may be relieved of the commitment. EE providers will need to itemize deliveries in American Electric Power and Duke Energy zones whether or not they are in Kentucky. EDCs will review a list of whether that provider is allowed to deliver in Kentucky based on the relevant regulators.
Financial Traders Question IMM on Long-Term FTR Concerns
Seth Hayik of Monitoring Analytics, PJM’s Independent Market Monitor, presented analysis of data that the Monitor argues show that long-term FTRs aren’t improving the market. Financial stakeholders, who trade in the long-term FTR markets, questioned the findings.
Long-term FTRs, which are available for each of the next three planning years or a combination of all three, are intended to provide hedges for transmission congestion by reflecting the conditions expected in the future situations.
“They’re not reliable,” Hayik said. “What comes out of the long-term FTR modeling doesn’t necessarily reflect what’s going to” happen. PJM has taken steps to correct what it could in the model for the nearest planning year, but “I don’t know that there is a solution for those models” for the subsequent years, he said.
Financial traders acknowledged that the risk of erroneous predictions is intrinsic to forward markets.
“Generally, forward markets are forward markets, and you buy in those markets without perfect vision of what will happen when those become spot markets,” Vitol’s Joe Wadsworth said. “That’s true of any future market. You don’t have foresight into what could go right or could go wrong in those markets. You make your decision on value.”
“Look how competitive the markets have become,” DC Energy’s Bruce Bleiweis said. “That’s the evolution of a market; they become more and more competitive over time.”
The Monitor said prices have really been driven down by 50% reductions in line congestion, but Bleiweis said its data showed that market alignment has improved by 90%. He credited the long-term FTR market for the additional improvement.
“We support what [the Monitor] is doing,” she said. “We would like to understand the impacts.”
Monitor Joe Bowring said better market structure in the single-year products “doesn’t mean the outcomes are competitive, and the outcomes are what we need to focus on.”
“In a competitive market we would expect to see the excess profits competed away, but that has not happened,” he said.
Stakeholders Battle PJM, Monitor on Market Path Alignment
Stakeholders continued to criticize proposals by PJM and the Monitor on a rule for evaluating designated market paths for energy sales coming into the RTO. The members have called for caveats that would allow them to explain their reasoning for paths PJM or the Monitor find questionable.
Along with their existing joint proposal, PJM introduced one that didn’t include Monitor endorsement. It excludes applying the rule to scheduled long-term path activity — annual, monthly or weekly — but allows for “potential referral” to FERC enforcement if “manipulative behavior” is suspected.
The proposal placated no one.
“The whole point of the original proposal was to have a rule. If there is no enforceable rule … then the rule is meaningless,” Bowring said. “I think the point of the rule is clear: It’s to prevent one participant from taking actions at the same time in different directions, explicitly manipulating the market.”
American Electric Power’s Brock Ondayko complained that the proposals seemed to tell participants “you can’t do this transaction because when we put it together with your other transactions, we see this grander transaction and that’s not allowed even though it might make complete financial sense to do that.”
“I don’t think we’re going to be very supportive of the idea of just prohibiting paths and referring people” or immediately resettling transactions because stakeholders could “get caught in a net,” said Carl Johnson, who represents the PJM Public Power Coalition.
Bowring assured that there’s no “automatic referring” in the joint proposal, but he reiterated that a definitive rule is necessary. “These can occur and will occur if permitted. We know that for a fact,” he said.
“A lot of what PJM [and the Monitor are] suggesting they’re going to do is discriminatory,” said Stephen Kelly of Brookfield Energy Marketing. “Every other company in this room is able to do that transaction.”
He called for allowing stakeholders “to present hard evidence … that these are separate transactions” based on different strategies. “We don’t think that’s asking too much.”
Emergency Pipeline Switching Instructions Sparks Rights Debate
PJM’s Rich Brown presented a proposed problem statement and issue charge on fuel switching that sparked pushback from stakeholders.
The proposal focuses on how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as backup oil or a different pipeline. Gas-fired operators argued that PJM’s plan would disincentivize flexibility and fails to recognize or sufficiently compensate operators who have paid extra for guaranteed pipeline capacity.
Being forced to switch fuel sources can decrease unit performance and increase the risk of the plant tripping off, Calpine’s David “Scarp” Scarpignato said, so “I’m actually being put in a worse situation for being more flexible.”
PJM’s Chantal Hendrzak acknowledged the RTO might need to identify other “attributes” for which generators should be compensated.
“There’s a recognition to do that,” she said. “It’s something that we realize that we need to talk about, but not only talk about, but figure out how to do.”
“In general, what you’re trying to do is a good thing,” said John Horstmann of Dayton Power & Light. “Given the fact that you’ve never done this before … what is the rush? … It looks like a short-term reaction with some big implications for generation-ownership rights and financial risk that are unresolved.”
“We have learned a lot,” Brown said. “As we educate ourselves, that has led us to operationalizing gas contingencies.”
Putting it all together, Hendrzak said, “that conversation might take a while.”
Bowring called the proposal “very reminiscent of cost-of-service in its worst sense. … This approach relies on command and control rather than market forces.
“I would ask you to put the market design elements into this,” he said. “How to get gas constraints into the market, that’s the real issue.”
Other stakeholders questioned who would pay for the additional compensation.
“We don’t think the costs should be on load,” said Dave Mabry, who represents the PJM Industrial Customer Coalition. The costs should be on the generators who don’t have guaranteed service to ensure “we are incenting folks to get the fuel supply they need and firm that up if necessary.”
Citigroup Energy’s Barry Trayers noted that the Capacity Performance rules and payments were designed to handle those needs.
PJM staff said they are in contact with pipeline companies to discuss these issues but stopped short of confirming they will be involved in the stakeholder process.
“It would be great if we could get some participation in the stakeholder meetings,” Hendrzak said. “I’m not sure if that will actually happen.”
VALLEY FORGE, Pa. — PJM’s Chris Pilong and Joe Ciabattoni told the Operating Committee last week that the RTO’s generation fleet passed muster during the recent cold snap despite several of the highest winter daily demand peaks it has ever seen.
Pilong reviewed operational events from last month, which included four high system voltage alerts in November and 11 cold weather alerts in December that began on Christmas morning and persisted through to this year. He said it was “probably the longest cold stretch … I’ve seen,” but that “everything went very smoothly.”
“Our system operators were able to do a great job thanks to your operators,” he said.
The evening peak load of 138,465 MW on Jan. 5 came within 5,250 MW of PJM’s winter peak record set on Feb. 20, 2015. Throughout the first week of the year, coal generation accounted for nearly 40% of the output, with nuclear and gas each producing about a quarter of the supply, which Pilong called “a fairly consistent story for the fuel mix.”
He acknowledged there was “a higher volume of oil than would typically be seen” at between 9,000 and 14,000 MW for the week, caused by gas-fired units switching to alternative oil supplies.
“The higher gas prices [were] making coal and oil a little more economic,” he said.
Unplanned outages hovered around 8% until the wind picked up at the end of the week and unplanned outages increased to 22,906 MW, or 11.5%, on Jan. 6, Ciabattoni said. Of that, 9,220 MW (40%) were gas units with operating problems and 3,143 MW (14%) were gas units reporting supply issues. Except for Midwestern hubs around Chicago, gas prices throughout the RTO spiked to more than $80/MMBtu on Jan. 5, with some above $120/MMBtu. The data were preliminary and came from PJM’s eDART self-reporting system. RTO staff communicate with unit operators to confirm the details of reported issues, Ciabattoni said.
PJM’s Manual 13 anticipates that 8,000 to 10,000 MW of forced outages are expected during such conditions, Pilong said. There was a “similar uptick” during the 2014 situation often referred to as the “polar vortex,” he said, but the difference was that there was really “no advanced notice” in 2014. Staff had to call on 2 MW of generation for every 1 actually needed, he said, because “it was a 50/50 shot that we would get it.”
“So even two hours’ notice allows us to change our plans,” he said.
Ciabattoni noted that December outages — both generation and transmission — were down slightly year-over-year. The load forecasting error was higher than December 2016 — 2.54% on-peak and 2.18% off-peak compared to 2.09% and 2.14%, respectively — but the RTO average error of 2.36% was still within the 3% target. There was an outlier of nearly 5% on Dec. 22.
“Is 3% right [as the target]? I’m not sure that it is, but we’ve been using it for a while,” PJM’s Mike Bryson said in response to a stakeholder question, adding that “we’re very open to using another metric.”
Staff explained that the calculation is the compilation of the absolute value of the error between each day’s hourly peak and the forecast from eight hours previous. Forecast development begins up to seven days ahead of time with wind chill and other weather expectations and can be adjusted up to an hour ahead of delivery.
Balancing authority area control error limit (BAAL) performance remained at 99.8% from November through December. Both the number and total time of excursions outside the target limits were near yearly lows in December.
PJM’s David Schweizer discussed the timeline for the RTO’s five-year black start request for proposals, which will open Feb. 1 with a pre-bid web conference scheduled for Feb. 6. Participants will have until March 8 to submit basic proposals, on which PJM will provide responses by March 30.
“We’re looking very heavily at fuel assurance as an evaluation component,” Schweizer said.
Final proposals will be due May 31, and Schweizer said applicants should expect to start seeing awards soon thereafter.
“We’re going to do a lot of this [analysis] in parallel, so we’re not going to get to the end and post the awards,” he said. “We will award the black start service as we run through the plans.”
Generation Transfer Seen as Overly Lengthy
Stakeholders endorsed changes to how generation ownership is transferred despite a concern about PJM’s requirement that owners submit initial information 45 days ahead of the transfer.
PJM’s Rebecca Stadelmeyer, who is overseeing the proposed changes, estimated that the initial information is about 65% of the amount needed for the RTO to ensure “what the member is seeking to do is reflected in our systems.” She said she wanted to avoid last-minute problems.
“That has occurred more than I want to count,” she said.
Chris O’Hara, PJM deputy general counsel, said 45 days is “a rational amount.”
“It’s not as simple as switching a toggle switch on an account,” he said.
Committee Changes
Ken Seiler, who chairs the OC, is switching jobs with Paul McGlynn, who chairs the Planning Committee. February will be Seiler’s last month chairing the OC. Dave Souder will then run the committee until McGlynn takes over.
CARMEL, Ind. — MISO staff asked the Resource Adequacy Subcommittee on Wednesday for feedback on the group’s priorities for 2018.
The RTO is eyeing a few initiatives from 2017 that have not been completed, including:
How capacity accreditations should be granted to battery storage based on operating characteristics;
If units on an extended outage should still be allowed to offer into the capacity auction; and
If MISO should take steps to alleviate partial unit clearing, in which the RTO’s algorithm clears a marginal unit on a pro rata basis. This can result in resources clearing a fraction of their unforced capacity values, leading to higher costs than capacity revenues.
Michael Chiasson of Potomac Economics, the Independent Market Monitor, said he was concerned that if a resource decides not to offer into the Planning Resource Auction because of a lengthy planned outage, the Monitor could construe the move as physical withholding.
MISO staff also want the RASC to finalize Tariff changes to implement external resource zones for the 2019/20 PRA.
The committee also will discuss an upcoming whitepaper on resource availability and need, and whether to create minimum capacity procurement requirements to address the increase of intermittent renewable generation and an aging baseload fleet more susceptible to outages.
“We’re going to have a discussion on how PRA rules can support year-round operational adequacy,” said MISO Manager of Resource Adequacy John Harmon.
Harmon also said the RASC could decide how to import capacity from Ontario’s Independent Electricity System Operator (IESO).
“Ontario is interested in developing its export capacity to MISO via its interface with Michigan,” Harmon said.
Harmon said Ontario has never qualified as a balancing authority to export capacity into the RTO. The province would like to become a qualified external supplier in time for the 2019/20 capacity auction.
Customized Energy Solutions’ David Sapper said he understood that Ontario’s transmission service isn’t analogous to MISO because it does not offer firm point-to-point transmission rights.
“The sticking point is really that firm transmission piece,” Harmon said. Before the province can become an external supplier, MISO must also receive a commitment from Ontario to curtail non-firm exports during capacity emergency events, Harmon added.
Although Ontario has signaled a willingness to make some changes over the last year, Harmon said it’s too early to know if it will create firm transmission service. IESO currently sells transmission rights that entitle the owner to a payment if the price of energy in Ontario is different from the price in an intertie zone, allowing hedging of congestion risks and price volatility.
MISO is asking stakeholders to submit any additional 2018 improvement candidates and suggested prioritization by Jan. 26 to radequacy@misoenergy.org. MISO staff said they will review and prioritize the issues in February and finalize a plan to tackle them by the March RASC meeting.
FERC on Thursday refused Constitution Pipeline’s request to find that New York environmental regulators had failed to act in a timely manner on the company’s water permit application (CP18-5).
The New York Department of Environmental Conservation rejected Constitution’s application in April 2016, saying the company had not included sufficient information for the agency to determine whether its 124-mile natural gas pipeline met state water standards. The pipeline, originating in Susquehanna County, Penn., would deliver 650,000 dekatherms of gas per day.
Constitution asserted that the DEC had waived its authority under Section 401 of the Clean Water Act by failing to issue or deny a water quality certification for the project within the stipulated one-year “reasonable period of time,” contending that a cycle of withdrawal and resubmission of its application had not changed the effective start date for the agency to act.
Though the company first submitted its application in August 2013, it withdrew and resubmitted it several times at the request of the DEC. It submitted its final application on April 27, 2015, and the DEC ruled on April 22 the next year.
In its Jan. 11 order, the commission said that “that once an application is withdrawn, no matter how formulaic or perfunctory the process of withdrawal and resubmission is, the refiling of an application restarts the one-year waiver period under Section 401(a)(1).”
The commissioners said they “continue to be concerned, however, that states and project sponsors that engage in repeated withdrawal and refiling of applications for water quality certifications are acting, in many cases, contrary to the public interest and to the spirit of the Clean Water Act by failing to provide reasonably expeditious state decisions. Even so, we do not conclude that the practice violates the letter of the statute.”
The Cannonsville Dam is located on the West Branch of the Delaware River in Delaware County, NY, through with the proposed Constitution Pipeline would run | NYDEC
FERC, however, also refused a formal hearing request by the Sierra Club and local environmental organizations Catskill Mountainkeeper and Riverkeeper, saying they raised “no material issue of fact that the commission cannot resolve on the basis of the written record.” The groups wanted the commission to reconsider its 2014 approval of the pipeline.
Gov. Andrew Cuomo on Thursday issued a statement commending the commission “for ruling in favor of New York’s efforts to prevent this project from moving forward,” saying that “the Constitution Pipeline represented a threat to our water quality and our environment.”
Last September, the commission ruled against the DEC on the same issue regarding the Millennium Pipeline, finding the agency had waived its authority by failing to act within the one-year time frame (CP16-17). (See Environmentalists Denounce FERC Millennium Pipeline Ruling.)
Connecticut regulators are getting mixed signals from power industry participants as they approach a Feb. 1 deadline for issuing a report on the economic viability of the Millstone nuclear power plant.
While some stakeholders say Millstone may be the most profitable nuclear plant in the country, others contend the plant must contract directly with the state in order to remain operational.
Gov. Dannel Malloy last July ordered the state Department of Energy and Environmental Protection (DEEP) and the Public Utilities Regulatory Authority to assess the current and future viability of the plant and determine whether the state should provide financial support (17-07-32). (See CT Gov Orders Financial Analysis of Millstone Plant.)
The governor’s move came a month after the state’s General Assembly failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state’s procurement process reserved for renewable energy resources such as large-scale hydropower, wind and solar (S.B. 106).
Plant owner Dominion Energy is seeking guaranteed state contracts for its nuclear units, claiming they operate under the same financial constraints from low natural gas prices that led New York and Illinois to provide state subsidies for some of their nukes.
The Electric Power Supply Association filed comments with the state this month, contending that Millstone’s profitability made any ratepayer subsidy unnecessary.
“EPSA believes — and the draft Levitan report confirms — that Millstone will remain economically viable through 2035,” said EPSA, referring to a Levitan & Associates report sent to the governor last month. (See Millstone Likely Profitable Through 2035, Conn. Consultant Says.)
EPSA also submitted a new study by Energyzt Advisors that said “numerous studies have shown that the plant is profitable — perhaps the most profitable nuclear plant in the United States.” The study also recommended regulators put a “price or cap on carbon for all sectors in the state and let market forces determine which carbon reduction investment provides the greatest payback.”
EPSA CEO John E. Shelk said Energyzt’s new analysis “identifies a wide range of strategies state policymakers can implement to protect and grow jobs, manage costs and reduce emissions for the long term.”
Dominion: Flawed Economics
Dominion’s Jan. 8 filing with DEEP and PURA accused the Levitan study of “mixing apples and oranges” in using the company’s regulated, Virginia-based nuclear plants as a proxy for Millstone’s cost projections.
“Millstone Unit 2 and Unit 3 are entirely different designs requiring separate control rooms, separate spare parts inventory, distinct operator training and separate teams of licensed operators,” Dominion said. “In addition, Millstone’s larger physical footprint requires a larger security staff and has higher site maintenance costs including utility costs, building maintenance and snow removal.”
Dominion also cited higher labor costs in Connecticut, saying its plants in Virginia are located in lower-cost rural areas.
In addition, Dominion said the Levitan report “understates the upcoming capital requirements of Millstone as critical station components reach their end-of-life cycle and need to be replaced to maintain the company’s core commitments of safety and operational efficiency. It is important in this regard not to confuse operating cash flow, much of which must be reinvested in the capital needs of the station, with profitability.”
The General Assembly submitted comments last week encouraging PURA and DEEP to “hedge against natural gas by opening a bidding process to receive bids from nuclear generating facilities, including Millstone, to purchase power directly by long-term contract.”
The legislators argued that “since Millstone’s power is currently purchased by hedge funds and financial institutions, these groups are receiving the benefit of price spikes today due to the current ‘cold snap.’”
Environment and Markets
Environmental organization Citizens Campaign for the Environment, which has more than 80,000 members in Connecticut and New York, said that it “strongly opposes any special deals for nuclear power under our state’s energy procurement markets. Allowing Millstone to compete with up-and-coming renewable technologies like wind and solar power would unfairly force Connecticut ratepayers to foot the bill for an antiquated, and yet highly profitable, power source.”
The Conservation Law Foundation submitted a draft proposal for a Dynamic Forward Clean Energy Market (DFCEM) that would allow Connecticut and other states in the region to procure clean and renewable electricity via a market administered by ISO-NE.
“The DFCEM market mechanism would allow Connecticut to procure the environmental attribute of new and existing zero-emission resources, including nuclear, on a least-cost basis through an auction mechanism that places all emissions-reducing resources on equal footing while allowing Connecticut to share emissions compliance costs with other states fairly and in proportion to each state’s climate and energy laws and regulations,” CLF said.
The group did not specifically address the issue of Millstone’s financial viability, but it referred to a November 2017 report by The Brattle Group that assumed “nuclear plants (with the exception of Pilgrim) retire after 60 years in service, or earlier if going-forward costs exceed market revenues.”
California faces a “severe shortage” of transmission capacity needed to tap potential New Mexico and Wyoming wind resources that would help the state meet its 50% renewable portfolio standard, CAISO said in a new study.
The findings regarding interregional transmission projects are supplements to CAISO’s 2016-2017 transmission plan, which was approved by the ISO’s Board of Governors last year. A second study released Jan. 5 looked at the impact of gas generator retirements scenarios, finding flexible capacity shortfalls at certain times.
The ISO assessed the feasibility of accessing 4,000 MW of wind from New Mexico and Wyoming to meet the 50% renewables goal and reached out to other Western planning regions to assess out-of-state portfolios. It said it had received feedback that its production cost simulations and power flow analyses do not fully capture the challenges of accessing out-of-state resources.
California needs more transmission capacity to fully access New Mexico and Wyoming wind power
The study was “a preliminary examination of transmission implications of meeting part of California’s 50% RPS requirement by assuming California’s procurement of 2,000 MW of wind resources in Wyoming and 2,000 MW of wind resources in New Mexico,” it said.
CAISO did not say whether the lack of transmission capacity would make the RPS goal unattainable. But wind energy interests are urging the ISO to explore additional transmission capacity to access low-cost regional wind resources, and the transmission projects included in the study represent billions of dollars in investment to serve California’s RPS.
The study is informational, CAISO said, and the results are not intended to direct interregional transmission, renewable generation development or policy direction.
The study looked at four large proposed transmission projects — TransWest Express, Southwest Intertie Project – North, Cross-Tie Transmission Line and Renewable Energy Express. It used two case studies based on two assumptions regarding resources and transmission.
Major transmission projects outside California have a large impact on grid operations, CAISO said. It noted that transmission constraints on a 230-kV network in southern Wyoming would have to be mitigated for California to realize the full benefit of the Western transmission system.
CAISO Studies Gas Retirements
In a second study on the risks of early retirement of uneconomic gas plants, CAISO said in some scenarios capacity shortages would occur in early evening, the new period of peak net load.
“Capacity issues start to emerge between 4,000 to 6,000 [MW] of retirement, considering some uncertainties in forecasts,” the study said.
CAISO studied six retirement scenarios of between 4,000 and 7,900 MW for four types of gas-fired technology. It found “unlimited renewable curtailment” is masking the need for flexible ramping capacity to meet morning and afternoon demand ramps.
| CAISO
Large amounts of renewable generation on the grid “is also putting economic pressure on the existing gas-fired generation fleet, especially for those generators not obtaining resource adequacy contracts.”
CAISO produces its transmission plan each year to assess system limitations and needed reliability improvements. As part of the 2017-2018 plan, the ISO examined proposed system improvements in the Moorpark area, where it is increasingly unlikely that NRG Energy will build the Puente natural gas power plant. (See NRG Signals Pull-out on Proposed Puente Plant.) The review is needed because of the expected retirement of up to 2,000 MW of generation, CAISO said in a Jan. 11 presentation. Comments on the analysis are due Jan. 18.
SAN FRANCISCO — California regulators last week issued several decisions that will affect the state’s energy resource mix and markets, including approving the retirement of the Diablo Canyon nuclear plant and replacing three reliability-must-run contracts for gas-fired generators with energy storage.
In its first meeting of 2018, the California Public Utilities Commission also approved exploring more uses for energy storage and pilot programs for new electric vehicle infrastructure. But staff delayed until Feb. 8 a vote on a proposal that would subject community choice aggregators (CCAs) to resource adequacy requirements, an idea that has drawn swift opposition from CCA supporters.
Fraction of Negotiated Cost Recovery
The CPUC unanimously approved the retirement of Pacific Gas and Electric’s 2,240-MW Diablo Canyon plant in San Luis Obispo County, the last remaining nuclear plant in the state. But the commission granted only a fraction of the $1.8 billion in cost recovery that was included in a joint proposal negotiated between PG&E and labor and environmental groups.
CPUC President Michael Picker said that with the decision, “We chart a new energy future by phasing out nuclear power here in California in 2024 and 2025.” Attending the meeting by teleconference, he called it “a very difficult and contentious case,” but “we agree the time has come.”
Diablo Canyon represents 6% of energy generated in California, but it is exacerbating overgeneration and curtailment of renewable resources. The plant is also aging and not needed for local reliability, Picker said. PG&E’s load is dropping with the growth of CCAs, direct access users (that buy directly from wholesale) and customer-based generation such as rooftop solar.
Picker said the order also directs PG&E to explore shutting the plant’s two units down earlier, in 2020 and 2022.
The CPUC rejected provisions in the joint proposal that would have paid for $1.3 billion in energy efficiency projects. An administrative law judge had proposed denying the efficiency cost recovery because the utility is already required to make that effort. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)
The commission also rejected provisions in the joint proposal that allocated $85 million to mitigate the impact of the plant’s closure on the local community. Local officials say the plant is the hub of the local economy, but the CPUC said it would not authorize assistance without legislative direction.
The CPUC did approve recovery of $211 million to retain PG&E employees until the plant closes, $11 million for employee retraining of workers and $19 million for license renewal expenses already incurred. The commission said replacement capacity would be addressed in its integrated resource plan proceeding.
Parties to the joint proposal include PG&E, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, Friends of the Earth, Natural Resources Defense Council, Environment California, California Energy Efficiency Industry Council and Alliance for Nuclear Responsibility.
PG&E said it was “disappointed” the full proposal was not approved, but it noted the CPUC increased funding for employee retention above what was in the proposed decision.
“The joint proposal represents an array of interests from many parties who joined together to promote the best path forward for our state and PG&E’s customers,” the utility said in a news release. “Since the full proposal was not approved, in line with our agreement, PG&E will be meeting to confer with our labor, community and environmental group partners in the days ahead about the decision, our next steps and the path forward.”
Commissioners noted the significance of the plant and the new challenges involved with retiring a major energy resource. Commissioner Martha Guzman Aceves called it a “landmark decision” to get a safer source of energy that is also clean. Commissioner Clifford Rechtschaffen noted that the commission intends to ensure the replacement capacity does not increase greenhouse gas emissions.
Elizabeth Echols, director of California’s Office of Ratepayer Advocates (ORA), said, “PG&E customers benefit from this decision because it protects customers from paying $1.56 billion in unnecessary costs, while providing important funding for PG&E employee retention and retraining programs. Today’s decision is well-supported by the evidence ORA and other parties provided in this case.”
The two units at Diablo Canyon went online in 1985 and 1986.
In its consent agenda, the CPUC passed a resolution to replace RMRs inked between CAISO and Calpine for the Metcalf, Yuba City and Feather River plants in PG&E’s service territory. The contracts have created tensions among ISO stakeholders and signal the state’s resource adequacy is not meeting reliability needs. The decision requires PG&E to hold solicitations to replace the RMRs with energy storage. (See CPUC Targets CAISO’s Calpine RMRs.)
Commissioner Carla Peterman also developed two decisions approved by the CPUC, including one adopting 11 rules governing multiple-use applications for energy storage. The decision creates a framework enabling energy storage companies to stack their offerings and provide more than one service to the wholesale market, distribution grid, transmission system and resource adequacy programs. The rule, developed in coordination with CAISO and other agencies, is supported by energy storage companies.
“This is the first time any commission has tried to do anything like this,” Peterman said.
Her other proposed decision supports new EV pilot projects, which she called “an important issue for the state of California.” It directs PG&E, Southern California Edison and San Diego Gas & Electric to invest $41 million in pilot projects for school buses, delivery trucks, airport/seaport equipment, truck stops and commuter locations. Other projects include the installation of fast charging for urban locations and car dealerships, the commission said.
The full list of the CPUC’s approved, withdrawn and held decisions from the Jan. 11 meeting is available here.
CARMEL, Ind. — History repeated itself during this month’s extreme cold snap — but only to a degree, MISO told stakeholders last week.
While the high load and generation outages during the arctic blast followed the pattern of 2014’s so-called “polar vortex,” this time the RTO managed to keep prices stable and maintain better reliability.
Tim Aliff, MISO director of system operations, said the RTO dubbed the weather event with a simple nickname.
“The best we could come up with was ‘cold snap,’” Aliff joked at Thursday’s Market Subcommittee meeting. “It doesn’t inspire the terror that ‘bombogenesis’ does, and ‘polar vortex’ was already taken.”
Aliff said that while there were major similarities between the polar vortex and last week’s artic conditions, MISO’s response to the demand and ensuing prices were very different, ensuring the RTO’s conservative operations declaration did not escalate to a maximum generation alert.
The recent low temperatures persisted longer and were on average lower than during the polar vortex, although the coldest day during 2014’s events was about 2 degrees Fahrenheit lower than this month’s. Demand peaked at 104.7 GW on Jan. 2, when low temperatures in the footprint averaged 0 F. During the polar vortex, MISO load hit an all-time winter peak of 109.3 GW on Jan. 6, 2014, when lows averaged minus 2 degrees.
Load topped 100 GW on five days during the recent cold snap, compared with two days during the polar vortex.
Polar Vortex (2014) compared to 2018 cold snap | MISO
“We were on average about 10 degrees colder than in 2014,” Aliff said.
This year’s arctic blast was tempered in part by wind’s 13% contribution to the resource mix, supplying 13.4 GW during the Jan. 2 peak hour. In 2014, wind supplied 6.6 GW during the peak.
“The highest locational marginal price was significantly lower than in 2014,” Aliff said. Real-time LMPs hit $281.23/MWh during the peak, compared with the $1,780.70 record price seen in 2014. During the bitter cold on Jan. 1 and 2, gas prices held to $4.63/MMBtu, jumping to $9 a day later when temperatures increased by 13 degrees. In 2014, gas prices ranged between $5.88 and $7 during three straight days of punishing cold.
Outage levels on the most frigid day remained at levels typical for the month of January, Aliff said, accounting for about 36 GW of unavailable generation during the peak, including more than 19 GW of forced outages. Natural gas forced outages, mostly attributable to fuel transportation and supply issues, accounted for almost 7 GW of unavailable generation, while equipment failure in coal generation accounted for slightly more than 2 GW of forced outages.
“That is kind of expected at this time of year. The utility gas supply is competing with the residential gas supply,” Aliff explained. MISO was better prepared for outages this year and was equipped with a more accurate list of gas-fired generators most likely to be affected by a dwindling gas supply.
“We had a better picture of what the generation limitations would be,” he said.
Ameren’s Jeff Moore asked if greater wind production helped MISO fare better during the cold snap.
“I think that there’s a lot that went into the lower LMPs,” Aliff replied. Other improvements made since the polar vortex, especially gas-electric coordination, helped MISO’s performance, he added.
MISO staff at the meeting promised to provide more outage analysis and data collection on the event.
Stakeholders: More Real-Time Communication
Multiple stakeholders asked MISO to consider issuing more immediate updates to members as it navigates challenging conditions.
ITC Holdings’ Ray Kershaw led the charge, asking that MISO distribute more real-time electronic communication to its members when faced with near-emergency or emergency conditions.
Market Subcommittee Vice Chair Megan Wisersky said there was a marked difference between MISO’s sparse communication and PJM’s frequent email updates to its members on the state of its system during the cold snap. “It seemed like there was a little bit of an information gap between the two approaches,” she said.
“It’d be nice to know what the capacity breakdown is,” said Customized Energy Solutions’ David Sapper.
Indiana Utility Regulatory Commission staffer Dave Johnston pointed out that, sometimes, “no news is good news.” He noted that MISO does alert state regulators when reliability issues arise. “But, of course, I’m not a market participant, and I’m not watching prices,” Johnston said.
MISO Senior Director of Systemwide Operations Rob Benbow said the RTO would consider the request and determine what information it could release in real time. “We understand the importance of good communication,” he said.
“Good markets are run with better information,” Wiskersky said.
November Sees Boost in Load, Prices, Wind
MISO released a November market report showing that lower temperatures that month boosted average load to 71.6 GW, up 3.6 GW from a year earlier, while the monthly peak jumped by 2.5 GW to 84 GW. Real-time and day-ahead energy prices both averaged about $27.30/MWh, 10% higher than last November. MISO reported an all-time wind record of 14.6 GW on Nov. 21, only to be exceeded by a new high of 14.7 GW on Dec. 5.
MISO and PJM will decide this spring whether to take another shot at a two-year coordinated system plan, which could result in the RTOs’ first large-scale interregional project.
The grid operators’ Joint RTO Planning Committee will make a decision by May 18 after discussing the issue at a March 30 meeting of the Interregional Planning Stakeholder Advisory Committee.
MISO and PJM staff last year already exchanged information on regional issues, market-to-market congestion, interconnection requests and newly approved projects near the RTOs’ seam. Those details should help the joint planning committee — comprising MISO and PJM planning staff — decide whether to pursue the study, MISO interregional adviser Adam Solomon said during a Jan. 12 IPSAC conference call.
The RTOs are calling on stakeholders to email a list of seams issues by Feb. 28 for the March IPSAC meeting. According to their joint operating agreement, the two grid operators then have 45 days to announce a decision on pursuing a plan.
The RTOs’ last coordinated system plan concluded in the fall without producing a viable interregional market efficiency project. One serious contender, a proposed 30-mile, 138-kV line near the Indiana-Illinois border, ultimately failed the joint 5% generation-to-load-distribution factor test, which requires each RTO to show that at least one of its generators has at least a 5% impact on the affected flowgate. (See MISO, PJM Reverse Support for Lone Interregional Tx Project.) Interregional market efficiency projects also must meet a 100-kV minimum voltage threshold and a 1.25-to-1 benefit-to-cost ratio based on each RTO’s expected share of the project’s total benefits.
Staff vowed to collaborate on ways to improve the coordinated system plan process after the study was concluded.
At EUCI’s Transmission Expansion in the Midwest conference in December, several stakeholders and panelists said that an effective wind transmission network in the Midwest will eventually require large-scale interregional projects. (See EUCI Panelists: Midwest Tx Plans Must Address Wind, Seams.)
Regardless of the outcome of the coordinated plan, the proposal window for interregional market efficiency projects — required under FERC Order 1000 — opens in November 2018. Stakeholders have until February 2019 to submit project suggestions.
