CARMEL, Ind. — MISO is moving ahead with developing an automatic generation control (AGC) program designed to rapidly deploy 400 MW of fast-ramping resources by regulating either up or down in response to fluctuations in load.
Speaking during a Dec. 14 Market Subcommittee meeting, Pavan Addepalle of MISO’s market engineering group said the RTO is moving from a conceptual design phase to detailed design with a vendor. MISO hopes to implement AGC by late 2019.
Addepalle said MISO will add new real-time market hourly offer parameters to accommodate the faster units but use the RTO’s existing market and settlement rules to clear regulation. Resources must have a minimum 80-MW/minute ramp rate and a regulation limit of 1 MW or more to be eligible to participate in the program.
In response to a question from Northern Indiana Public Service Co.’s Bill SeDoris, MISO staff said resources under AGC will be cleared in the same market as other resources, but that fast- and slow-responding resources will be divided into pools waiting on separate dispatch signals.
“We’re going to have a single energy market but realize that resources have different parameters and constraints … and design a market that is capable of using separate resources differently,” said MISO Executive Director of Market Design Jeff Bladen, adding that the RTO will not follow in PJM’s footsteps in creating a separate regulation market.
ITC Holdings’ Ray Kershaw said the new designation, while amenable for pumped energy storage, is not an ideal use for batteries.
Addepalle said MISO did not approach the proposal with a specific type of generation in mind.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:40)
Members will be asked to endorse the following proposed manual changes:
A. Manual 1: Control Center and Data Exchange Requirements. Revisions developed to update NERC references and procedures related to outages and system-restoration planning. PJM members will be required to send the RTO data on transmission megawatt and MVAR flows and bus voltages at greater than or equal to 100 kV, down from 345 kV.
B. Manual 10: Pre-Scheduling Operations. Revisions developed to comply with NERC standards as part of a periodic review of the manual. Generators will be required to notify PJM of operating conditions that could result in a single contingency causing an outage of multiple generators.
C. Manual 14D: Generator Operational Requirements. Revisions developed as part of a periodic review. Generators will need to be modeled in eDART consistent with the PJM energy management system model.
3. Manuals 3 and 13 Revisions and Gas Pipeline Contingencies (9:40-10:10)
A. Members will be asked to endorse proposed changes to Manual 3: Transmission Operations and Manual 13: Emergency Operations, which include processes for addressing gas pipeline disruptions that affect generator reliability.
B. Members will also be asked to endorse manual revisions proposed by gas-fired generators to document compensation mechanisms for generators directed by PJM to take action related to a pipeline contingency. (See related story, “Gas Generators Block PJM Pipeline Plan,” PJM OC briefs: Dec. 12, 2017.)
Members will be asked to endorse revisions to the Tariff, Manual 28: Operating Agreement Accounting and Manual 6: Financial Transmission Rights resulting from special sessions on FTR issues. The revisions will address changes to long-term FTR modeling for future transmission expansion, streamlining management of overlapping FTR auctions and allocating any surplus funds from day-ahead congestion and FTR auction revenue. (See related story, “FTR Discussions,” PJM MIC briefs: Dec. 13, 2017.)
5. New Service Request Study Methods (10:40-11:00)
Members will be asked to endorse changes to the procedures for the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
6. Energy Market Price Formation Problem Statement & Issue Charge (11:00-12:00)
Members will be asked to endorse PJM’s proposed problem statement and issue charge to changes price formation in the energy market. The RTO has proposed revisions that would allow inflexible units to set LMPs. The Independent Market Monitor has proposed an alternative problem statement and issue charge that would take up to two years to examine all components of energy market price formation and determine if changes are needed. (See “Questions Remain as PJM Continues Push for Price Formation Revisions,” PJM Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
7. Capacity Construct/Public Policy Senior Task Force (CCPPSTF) (12:45-1:45)
Members will be asked to endorse Tariff revisions associated with the Monitor’s “MOPR-Ex” proposal to change the minimum offer price rule. The Monitor is proposing to amend the version endorsed by the Capacity Construct/Public Policy Senior Task Force to revise exemptions for state renewable portfolio standards. (See related story, IMM Battles Exelon on MOPR-Ex Proposal.)
8. Incremental Auction Senior Task Force (IASTF) (1:45-2:00)
Members will be asked to endorse a proposal developed by the Incremental Auction Senior Task Force to address concerns of excess capacity and low clearing prices. Although Proposal A” did not receive enough support at the IASTF to be automatically considered at the MRC, stakeholders moved for an endorsement vote. (See “Stakeholders Move Incremental Auction Proposal,” PJM Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
FERC last week set hearing and settlement proceedings for a new Ohio merchant plant, saying it had not provided sufficient backing for its reactive power revenue requirement (ER18-92, EL18-32).
The 747-MW Carroll County Energy combined cycle plant, expected to go in service this month, is seeking compensation for its generator, associated exciter equipment, step-up transformers and other equipment under allocation factors representing their contribution to both reactive service and real power.
Carroll County Energy Plant Schematic | Power Technology
The commission said the plant’s owners had not demonstrated that its proposed revenue requirement was just and reasonable. “CCE’s filing has no underlying support for the costs claimed for this new generation facility, and the balance of plant investment allocator and the accessory electrical equipment allocator may be excessive. We further note that the components of the accessory electrical equipment are not provided,” the commission wrote.
FERC said that, if no settlement is reached, it expects to issue a decision within eight months of the filing of briefs opposing exceptions to the initial decision by an administrative law judge. “If the presiding judge were to issue an initial decision by July 31, 2018, we expect that, if the proceeding does not settle, we would be able to render a decision by May 31, 2019.”
The plant’s owners include TIAA, Chubu Electric Power, Ullico, Prudential Financial and Advanced Power, a Boston-based development company that oversaw construction and will manage the start of commercial operations. Chairman Kevin McIntyre did not participate in the decision.
AUSTIN, Texas — The Great Plains Institute last week convened state officials and other stakeholders from across the Midwest for a one-day workshop exploring trends in SPP’s footprint. The workshop, which was streamed on the Internet, featured multiple perspectives on ongoing challenges and included panels on wind development and SPP’s proposed expansion with the Mountain West Transmission Group.
Lanny Nickell, SPP’s vice president of engineering, recalled a time less than 10 years ago when the RTO thought if it ever exceeded 25% wind penetration, “it’d be a miracle.”
It’s the miracle that keeps on giving. SPP, the first North American RTO to exceed wind penetration levels of greater than 50%, saw that level reach 56.25% on Dec. 4, when wind resources accounted for a record 14,150 MW of energy.
“We’ve exceeded [25%] by far, because of our large geographical footprint,” Nickell said. The RTO added the Integrated System in 2015 and is now working with Mountain West to add its entities to its membership rolls.
SPP has added almost 12.5 GW of wind capacity since 2010, giving it 17.75 GW of installed wind. With the addition of another 5.3 GW that have interconnection agreements but are not yet in service, the RTO’s wind capacity will exceed its minimum load of just more than 20 GW. Another 35 GW of wind capacity is under various stages of review in SPP’s generator interconnection queue.
| SPP
The RTO has approved $7 billion in transmission infrastructure since 2005 to accommodate the growth in wind energy, with another $3 billion planned. Half of the build are 345-kV facilities; the rest are primarily 100- to 300-kV infrastructure.
| SPP
“We don’t add transmission because we like transmission. We do so because it’s beneficial and helps keep the lights on,” said Nickell, who hinted at the need for 765-kV infrastructure in the future. “In order to reliably deliver the amount of wind that’s been requested, we’re probably going to need something more than just 345-kV.”
Nickell compared one of SPP’s windiest states, Kansas, with Denmark as an example of the RTO’s operational capabilities. He said Denmark had 116% wind penetration in 2015 and noted, “You can’t do that unless you’re exporting wind.” But when Kansas hit a wind penetration level of 106% on April 24, it wasn’t exporting wind out of the RTO.
| SPP
“It’s because we have a regional transmission organization,” Nickell said. “We can facilitate [those wind levels] and still keep the lights on.”
As more wind energy comes online, Nickell said, wind developers must face the question of what to do when energy exceeds load. “Exporting it does make sense, unless wind developers want to have their wind curtailed,” he said.
Landowner Opposition Formidable Obstacle to Tx Projects
Several speakers discussed the opposition Clean Line Energy Partners has faced from landowners and regulators in its plans to connect renewable resources with urban centers via long HVDC transmission lines.
“You’re going right back to the not-in-my-backyard thing,” said Ted Thomas, chair of the Arkansas Public Service Commission. “That’s causing intense pushback. ‘My granddaddy had this land. This is our family property. I don’t want this big, honking thing coming through here. You don’t understand, this property is not for sale.’”
“Siting is difficult,” agreed Missouri Public Service Commissioner Steve Stoll. “Anytime you’re dealing with private rights and eminent domain, it’s difficult. You can say you’re helping our area by giving us the ability to sell our homes and attract business, but [the landowners] don’t see much value in it.”
“But even if [interregional] projects are built, it doesn’t draw down that massive supply of wind in the Oklahoma Panhandle,” Thomas said.
Nickell said another impediment to selling wind outside SPP is the cost of the transmission facilities themselves.
“It boils down to the question of who pays,” Nickell said. “Should the customer who wants to buy that energy pay for the upgrades to deliver it, as well as the cost of renting the transmission facilities? Or should there be a recognition of benefits to others that helps fund these projects?”
“SPP will have to grapple with what’s a fair cost to move wind out of the SPP footprint, and how that should work,” Stoll said. “It’s the biggest challenge since national electrification.”
Xcel Energy’s Steve Beuning, one of the leaders of the Mountain West’s proposed membership in SPP, thanked the RTO for working with the Rocky Mountain entities and helping them increase their access to renewable resources.
“There’s an operational benefit that comes from the pooling of resources,” said Beuning, Xcel’s director of market operations. “That expansion of balancing diversity into a broader footprint is different. It didn’t exist when other RTOs were formed.”
“Any RTO can put a market together. I don’t know that we do a market any better than PJM, or any better than MISO, or any better than CAISO,” Nickell said. “From what we’ve been told, it’s how we do what we do that was important to the Mountain West group. They appreciate our stakeholder-driven culture. They appreciate our collaborative nature, the relationship-based culture.”
At some point, the Colorado Public Utilities Commission will be asked to give its regulatory approved to the merger. PUC Chair Jeff Ackermann said he is viewing the expansion in three parts.
“There’s the part about reliability, the part about transmission and the market,” Ackermann said. “It comes through really clear … that the culture and how SPP chooses to operate spills into the governance subject. I’ve heard a lot of good stuff about that pursuit of consensus, but the world we live in doesn’t lead to consensus. As you add more parties to things, and they haven’t had experience with discord, how is that done? How do you deal with discord? How do you factor in whatever is the next iteration, and how does that fit into the market?”
“Bringing those distant resources to urban centers is why we value those regional organizations,” said the National Resources Defense Council’s John Moore, director of the Sustainable FERC Project. “With all of the discussion around this integration, you ask, ‘Is this good for the customer?’ We hope so. We don’t want to see the balkanization that you see in the east, with interregional barriers … the last thing we want to see in the west is three or more RTOs developed.”
Speaking on a panel on wind power, Vanessa Tutos, director of government affairs for EDP Renewables, said the economic benefits of renewables are clear, “irrespective of your political persuasion.” She cited a two-thirds drop since 2009 in the cost of wind energy, $128 billion of private investment and more than 20,000 wind industry jobs.
“Job opportunities are coming back to these rural areas,” Tutos said. “When you have a wind farm, you maintain the agricultural capabilities. The wind turbines, though they alter the landscape, allow [farmers] to maintain that form of life.”
But while the wind industry provides economic benefits, it doesn’t do it alone, Tutos said.
“Transmission planning is very important. I love the idea of a 765-kV overlay. I know reliability organizations don’t work that fast … but what wind generation is trying to do is ensure [that] the maximum amount of wind can be integrated in a reliable and efficient way. SPP has a huge opportunity to help implement policies to help reach a 21st century economy.”
“If you don’t have adequate transmission, things will grind to a halt,” said the Wind Coalition’s Steve Gaw. “If building transmission results in a lower cost of power, you’re doing your consumers a disservice by not examining [those options]. We have not gotten close to what low-cost energy would do to the [SPP] footprint. It’s not just transmission capacity; it’s also the scheduling of power across interfaces, and how much you have to pay for energy in pancake rates.”
Alternatives to DOE NOPR
Several speakers suggested there are better alternatives to the Department of Energy’s Notice of Proposed Rulemaking to provide price supports to coal and nuclear generation. (See McIntyre Takes FERC Chair; Wins Delay on NOPR.)
Rob Gramlich, a consultant who served as an adviser to former FERC Chairman Pat Wood III, said he expects the discussion in D.C. to become focused on price formation and market-based approaches.
“Obviously, the proposed resiliency rule is a major focus,” he said. “But since 90% of [the rule’s] eligible generators are in PJM, and PJM is more committed to markets than anyone else, it’s hard to imagine PJM doing anything to upend those markets. I’m not sure what we get from resiliency that we didn’t get from other new rules.”
“If it was me running the whole thing and giving them advice, it would be 180 degrees from what [the Trump administration is] doing,” Thomas said. “They ought to be embracing the fact that markets serve consumers. Markets serve consumers, and the administration should not squander opportunities to make that point.
“We should let the NERC engineers tell us when we have problems. We always say we might have a crisis in 30 days. Well, we had a crisis. It was the polar vortex, and it got to the edge of reliability problems. The next year, we had a weather event that came close to the polar vortex, but it didn’t cause a problem. Why? Because we had engineers study the problem and come up with solutions. Let the markets serve consumers, and let engineers tell us what the problems are.”
Stoll suggested another potential solution to the reliability issue: small (50-MW) modular nuclear reactors (SMRs) that are brought onsite already assembled. Taking great pains to say he was not shilling for the technology, he offered up SMRs as a source of baseload power.
“I wouldn’t want to put all our eggs in the natural gas basket. We don’t know what’s going to happen with natural gas,” Stoll said. Referencing the Utah Associated Municipal Power Systems’ work with SMRs, he said, “They rely on coal, but they’re going to put the first [SMRs] in their footprint. If everything goes right, they plan to replace their coal plants with SMRs. It’s a very interesting technology, and a technology the rest of the world is working on.”
Thomas agreed, saying the SMR market will likely be ready by the mid-2020s.
“We don’t need to be focused on subsidizing nuclear energy. We probably have a window with gas that will take us to that,” he said.
New gas-fired and dual-fuel generation coming online in the next few years will be enough to maintain reliability after the 2,311-MW Indian Point nuclear plant shuts down completely in 2021, NYISO said Wednesday.
An ISO report assessing the reliability needs arising from the staggered closure of Indian Point Units 2 and 3 cited three major projects totaling 1,818 MW now under construction: the 120-MW Bayonne Energy Center II uprate in NYISO Zone J, and the 678-MW CPV Valley and 1,020-MW Cricket Valley plants in Zone G.
Indian Point
NYISO had been reluctant to perform a reliability needs assessment prior to formal notice of deactivation from Indian Point owner Entergy, which it received in November. However, in March 2017 both the Public Service Commission and the ISO predicted that the plant’s closure would present no problems for the state’s bulk power system. (See NYISO, PSC: No Worries on Replacing Indian Point Capacity.)
The report also analyzed a scenario without the three new projects. The Lower Hudson Valley (Zones G-J) would need other solutions to maintain reliability, “including generation, transmission, energy efficiency and demand response measures.” Transmission constraints into the valley from upstate (Zones A-F) and Long Island (Zone K) would make additional resources in any other zone unable to effectively resolve a deficiency, the report said.
While a generic addition of at least 200 MW by 2023 anywhere within Zones G-J would resolve the deficiency over a five-year horizon, a deficiency through 2027 would require additional resources ranging from 400 to 600 MW, depending on type and location of the resources within the valley, the ISO found.
The ISO determined the new capacity needed to compensate for the loss of Indian Point under the scenario by adding generic “perfect capacity” resources to zones in 100-MW blocks. “Perfect capacity” represents a hypothetical resource not subject to derates and not tested for transmission security or interface impacts.
| NYISO
New York City and Westchester County depend on Indian Point for 25% of their electricity, and the village of Buchanan and surrounding area rely on it for jobs and taxes. Gov. Andrew Cuomo in February formed the Indian Point Closure Task Force to explore ways to mitigate local tax and workforce impacts. The group next meets on Dec. 19 in Cortland.
Entergy agreed to deactivate Units 2 and 3 by April 30, 2021, under a deal reached with Cuomo in January. The agreement would allow the plants to operate for two additional two-year increments — with final closure slated for 2025 — if an emergency affected reliability in the New York City area. Unit 1 at the plant was shut down in 1974.
Cuomo had long sought the total closure of the plant, saying it was inherently unsafe to risk having a nuclear accident occur just 40 miles north of midtown Manhattan. (See Entergy to Shut Down Indian Point by 2021.)
With a permanent chairman and full complement of commissioners now in place, FERC will likely modify “and keep moving” the Department of Energy’s controversial proposal to offer price supports to coal and nuclear plants, according to one industry analyst.
Tezak | ClearView Energy Partners
Christine Tezak, managing director of research for ClearView Energy Partners, said Wednesday her firm expects the commission to acknowledge the administration’s concerns and to take some action on the department’s Notice of Proposed Rulemaking (RM18-1).
Chairman Kevin McIntyre, who was sworn in Dec. 7, requested a 30-day delay for FERC to address the NOPR, which was granted by Energy Secretary Rick Perry. The commission now has until Jan. 10 to take action. (See McIntyre Takes FERC Chair; Wins Delay on NOPR.)
“The NOPR DOE sent over articulates a pretty straightforward concern that closing [baseload] power plants is bad,” Tezak said during a Texas Renewable Energy Industries Alliance webinar on the proposal. “It couches that concern by saying there could come a day under extreme circumstances where we would be really sorry not to have those plants around.”
Given broad opposition to the NOPR, Tezak thinks Commissioners Cheryl LaFleur, Robert Powelson and Richard Glick would all like to set aside the directive. She said LaFleur and Powelson reportedly prefer to close the docket and issue a Notice of Inquiry to RTOs with a 90-day timeline. Glick is also thought to be amenable to that option, Tezak said.
“I’m not sure that’s going to control the day,” she said. “The chairman does set the agenda. We think a variety of unusual circumstances are likely driving the commission to keep moving on the proceeding and to be responsive to the DOE’s concerns.”
| DOE Staff Report
It’s “feasible” FERC could issue an Advanced Notice of Proposed Rulemaking or a revised NOPR and keep the docket open if McIntyre can persuade two commissioners that action is required, Tezak said. “A revised rulemaking is not a final rule.”
Base on comments filed, Tezak said FERC has several other options to consider besides adopting the NOPR as written — unlikely, she said, given its lack of support and criticism for being vague:
To “go even bigger” and offer 15-year cost-of-service contracts to all coal- and nuclear-fired generators;
Adopt cost-of-service payments now and devise a permanent fix later;
Revise or refine the NOPR, define “resiliency” and procure it starting in 2019;
Study first, and act later; and
Just say “no” and close the docket.
While serving as interim chairman before McIntyre’s arrival, Commissioner Neil Chatterjee proposed a “show cause” order requiring grid operators to compensate resources that may provide resilience benefits and are at risk of retirement as an interim measure while the commission conducts a longer-term rulemaking.
“With apologies to Lynyrd Skynyrd, we called the variant Neil Chatterjee seemed to endorse ‘Gimme Two Steps,’” Tezak said. “[The NOPR] is a very, very broad proceeding, notwithstanding the criticism. It’s not a popularity contest or an election. Expert opinions matter, and there is a lot of different evidence in the docket. Looking ahead, that’s important to consider even if [many parties] would like to see FERC shelve the whole mess and move on.”
Industry consultant Alison Silverstein, who — “through a bizarre chain of events” — helped organize and write the DOE’s “Staff Report on Grid Reliability and Markets,” referred to the NOPR’s “premature” retirements of baseload plants as “road kill.”
| DOE Staff Report
“The DOE staff said there was no such thing as premature retirements,” Silverstein said during the webinar. “If you believe in markets, then those things retired when they were no longer needed. Almost all of them retired because they were no longer economic.”
The root causes — low natural gas prices and the growth of renewables — were so obvious, the DOE report did not address them, Silverstein said.
She defined grid resiliency as the system’s ability to absorb, restore and quickly recover from major adverse events. Reliability has short-term (withstanding sudden disturbances) and long-term (resource adequacy) dimensions, Silverstein said.
“It’s important to articulate the problem we’re trying to solve here,” she said. “Resiliency and reliability is very different for a power plant than the grid as a whole. For my money, we can buy a lot of transmission and distribution improvements and provide economic support for coal miners for the billions of dollars it would cost to subsidize uneconomic coal and nuclear plants.”
CARMEL, Ind. — MISO will pre-emptively refile its current resource adequacy construct for FERC approval Friday in an effort to dispel concerns that a future ruling could undo parts of the plan the commission itself had previously suggested.
MISO’s concerns stem from a July D.C. Circuit Court of Appeals ruling that found FERC overstepped its authority under the Federal Power Act when it prescribed revisions to PJM’s capacity market buyer mitigation rules in 2012 (15-1452).
That D.C. Circuit decision partially vacated FERC’s approval of PJM’s changes to its minimum offer price rule (MOPR) and remanded the case back to the commission for further action. As a result, the commission last week rejected the previously approved MOPR changes and required PJM to reinstate its previous design. (See On Remand, FERC Rejects PJM MOPR Compromise.)
Fearing that parts of its resource adequacy construct could be similarly vacated, MISO said it would refile Module E-1 of its Tariff on Friday, putting language already approved by FERC before the commission once again.
“This filing will contain only our existing Tariff language and will not propose any changes,” MISO corporate counsel Jacob Krouse told stakeholders at a Dec. 13 Resource Adequacy Subcommittee meeting.
In 2011, FERC accepted MISO’s current resource adequacy proposal, which replaced a monthly capacity auction framework with an annual auction and use of coincident peak demand forecasts to establish planning reserve requirements (ER11-4081). In that order, FERC directed MISO to remove its proposed MOPR provisions and instead use a peak load contribution methodology as its default methodology for assigning capacity obligations among other directives.
“We are giving FERC the opportunity to find our original filing just and reasonable … regardless of any procedural defects in the original order,” Krouse said.
Manitoba Hydro’s Audrey Penner asked why MISO’s well-established resource adequacy construct must go before FERC again.
“What is outstanding that would require MISO to refile?” Penner asked.
Krouse called the reasons behind the filing “procedurally complex” and said MISO seeks to pre-empt the possibility that FERC will ask the RTO to refile a revised construct in the event that the commission also overstepped its authority when it approved the original filing six years ago.
“MISO is unsure how and when FERC will act,” Krouse said.
The RTO is asking FERC to decide on the matter by March 1. If FERC doesn’t act on the Section 205 filing before the requested effective date, the filing is automatically considered accepted, Krouse said, though he thinks it “unlikely” the commission won’t address the filing.
Responding to a question from Indiana Utility Regulatory Commission staffer Dave Johnston, Krouse said the RTO will provide three pieces of staff testimony supporting the efficacy of the current resource adequacy construct. FERC liaison Chris Miller also said he expected MISO to quote at length the commission’s 2011 acceptance of the construct.
Northern Indiana Public Service Co.’s Bill SeDoris asked how MISO would respond to a rejection by FERC.
“Where do we go from there?” SeDoris asked, pressing to know whether the RTO would begin operating under pre-2011 resource adequacy rules.
Krouse said his own recommendation would be that MISO continue with its existing construct until the commission acts on either MISO’s refiling or the court’s remand.
PJM has similarly said that restoring its old rules is “not a viable option” and continues to operate according to its filed rate while it awaits FERC action on the ruling.
Dynegy’s Mark Volpe asked how MISO would respond if the commission issues an order on remand before it acts on the filing. Krouse said the RTO would reassess and adapt should that happen.
This fall, Krouse warned that the D.C. Circuit’s ruling limiting FERC’s ability to issue guidance on proposals might sway the commission in the future to issue more rulings that either accept or reject filings in their entirety.
Dominion Energy’s bid to win state subsidies for its Millstone nuclear plant took a hit Thursday as consultants hired by Connecticut said the plant is likely to remain profitable through 2035 even under low natural gas prices.
The report by Levitan & Associates concludes “there is no ‘missing money’ required to ensure Millstone’s financial viability through the existing term of Millstone’s Unit 2 operating license” in 2035.
The report projects that in 2022 the plant will earn after-tax net cash flow of $100 million under a low gas price/high operating cost scenario to more than $200 million under the reference case that assumes “business-as-usual” conditions.
“Under the reference case, the present value of Millstone’s after-tax cash flows [through 2035] is about $2.4 billion. This number is reasonably representative of Millstone’s enterprise value. Under the low gas price case, with all costs increased by 10%, the present value is $1.3 billion,” the consultants wrote. “However improbable the array of market and operating assumptions underlying the low gas price case with all costs increased by 10% may be, the associated enterprise value of $1.3 billion represents a conceivable ‘worst case’ for testing Millstone’s financial viability.”
The consultants added a caveat to their analysis, saying that if Dominion were required to replace its existing system with cooling towers as part of its National Pollutant Discharge Elimination System permit renewal, “it is likely that cash flow from energy and capacity sales would be insufficient to rationalize the investment.”
“We are still reviewing the report and don’t have a comment at this time,” Dominion spokesman Ken Holt said Thursday evening.
Connecticut Gov. Dannel Malloy ordered state regulators in July to assess the economic viability of the plant and determine whether the state should provide it financial support. Malloy’s executive order also directed the state Department of Energy and Environmental Protection (DEEP) and the Public Utilities Regulatory Authority (PURA) to assess the role of large-scale hydropower, demand-reduction measures, energy storage and emissions-free renewable energy in helping Connecticut meet its ambitious targets to cut its carbon output. (See CT Gov Orders Financial Analysis of Millstone Plant.)
DEEP and PURA released the Levitan study yesterday along with a draft report summarizing its conclusions and a request for comments on it, which are due Jan. 8. There will be a public hearing on the report Dec. 19 at Waterford High School.
PURA Chair Katie Dykes and DEEP Commissioner Robert Klee said during a press conference Thursday that the agencies will file a final report with their recommendations by Malloy’s Feb. 1, 2018, deadline.
Dykes said the regulators’ draft report contains no conclusion. “This report is laying out the dots,” she said. “It’s not necessarily connecting the dots.”
The regulators’ draft report noted “significant inherent difficulties” in evaluating the financial viability of a nuclear plant such as Millstone in a restructured market. “Merchant generators’ financial goals may exceed the regulated rate of return earned by cost-of-service generators, given merchant generators’ exposure to the risks of low energy prices, unplanned outages, and other costs that a regulated generator can recover from electric ratepayers,” the regulators said.
“Such is the challenge in assessing the financial viability of Millstone, and the advisability of mechanisms that would shift some of the risk of energy price volatility to the ratepayers of Connecticut. Despite DEEP and PURA’s specific data requests, Dominion only very recently provided a limited, two-page, high-level document with forward-looking financial projections. The document lacked the standard documentation supporting the projections concerning its actual financial condition. Thus, [Levitan] was limited to modeling Millstone’s financial viability using the best publicly available information.”
Levitan’s conclusions were consistent with findings of a study funded by subsidy opponents, including Calpine and Dynegy, which Dominion rejected as “loaded with gross assumptions and preposterous claims, with no real data.” Dominion, which purchased the 2,111-MW facility in 2001 for $1.28 billion, has said Millstone is more expensive to operate than other two-unit nuclear plants because its two units are of different designs. (See Millstone No Dead Weight for Dominion, Says Opponents’ Study.)
Levitan said its report was based on simulations modeling the New England wholesale energy market under several scenarios covering natural gas prices, expanded clean energy deployment and generation entry and retirements.
The consultants said they constructed a worst-case scenario increasing their proxy operating costs by 10%.
Because Dominion indicated last March that the plant will compete in ISO-NE’s Forward Capacity Auction next year, the company expects it to continue operations into at least 2022. Thus, the financial analysis considered only the period between 2022 and 2035, when the license for Millstone Unit 2 expires.
Malloy issued the executive order after Connecticut legislators failed to pass a bill sought by Dominion to boost the plant’s revenues.
Some subsidy supporters have said the loss of the plant would jeopardize the state’s ability to comply with the Global Warming Solutions Act of 2008, which mandates cutting greenhouse gas emissions to 10% below 1990 levels by 2020, and to 80% below 2001 levels by 2050.
Millstone supplies the equivalent of half of Connecticut’s electricity, but Dykes said the state is “long generation.”
Sempra Energy’s $9.45 billion bid for bankrupt Energy Future Holdings and its 80% interest in Oncor cleared a second major hurdle within a week after the California-based company reached a settlement agreement Thursday with several key Texas stakeholder groups.
The agreement represents a “significant step forward” and demonstrates “positive momentum” for Sempra’s proposed acquisition of a majority stake in the Texas utility, both companies said. Under the settlement, the parties have agreed that the acquisition is in the public interest, meets Texas statutory standards and will bring substantial benefits.
On Monday, FERC filed a boilerplate order approving the acquisition. (See “FERC OKs Sempra Acquisition of Oncor,” Company Briefs.)
Parties to the settlement agreement include the Public Utility Commission of Texas staff, the Office of Public Utility Counsel, Steering Committee of Cities Served by Oncor and Texas Industrial Energy Consumers. They will ask the PUC to approve the acquisition, consistent with the governance, regulatory and operating commitments in the agreement, the companies said.
Sempra said the agreement includes regulatory commitments that preserve the existing Oncor ring-fence and the independence of the utility’s board of directors. To protect Oncor, its customers and employees, the commitments also include extinguishing all debt currently held by EFH and Energy Future Intermediate Holding Co., the company said.
One consumer representative called the settlement a “good deal for customers,” saying Sempra agreed to a more robust ring-fence than was in place earlier for EFH or Berkshire Hathaway Energy, which appeared to have a solid $9 million all-cash offer until Sempra stepped in. (See Sempra Outmuscles Berkshire for Oncor.)
| Sempra Energy
Sempra CEO Debra Reed said she was pleased with the support from the groups. “We strongly believe that this transaction will benefit Oncor customers and the state of Texas, and we are working with the PUC to facilitate its comprehensive review of our proposal.”
The PUC now holds the key to approval. The commission said in October it would complete its review within 180 days — by early April 2018. It has scheduled a Feb. 21-23 hearing on the acquisition in Austin. (See Texas Regulators Seek More Details on Sempra Oncor Bid.)
The PUC has seen a changeover among its commissioners since the unsuccessful attempts by Hunt Consolidated and NextEra Energy to acquire Oncor. Chair DeAnn Walker and Arthur D’Andrea have replaced Donna Nelson and Ken Anderson, respectively, with Brandy Marty Marquez the only holdover.
Sempra Energy headquarters | Sempra Energy
“Our partnership with Sempra Energy will result in a strong, well-capitalized Oncor that will help Texas continue to grow and invest in a safer, smarter, more reliable electric grid in the years to come,” Oncor CEO Bob Shapard said. “This settlement agreement moves us one step closer to ending the EFH bankruptcy process.”
Sempra announced the deal in August. It was approved by the U.S. Bankruptcy Court in Delaware in September but is still subject to a confirmation hearing by the court after PUC approval.
NERC released its annual Long-Term Reliability Assessment on Thursday, calling for more efforts to preserve “essential reliability services” provided by coal and nuclear plants but saying it is agnostic as to how FERC and regional grid operators do so.
“FERC should consider the reliability and resilience attributes provided by coal and nuclear generation to ensure that the generation resource mix continues evolving in a manner that maintains a reliable and resilient” bulk power system (BPS), the 2017 report said.
NERC’s concerns that the increase in natural gas and renewable generation could endanger grid resilience puts it squarely in the middle of the debates over state nuclear subsidies and Energy Secretary Rick Perry’s call for price supports for coal and nuclear plants in organized markets.
“The changing composition of the North American resource mix calls for more robust planning approaches to ensure adequate essential reliability services and fuel assurance,” the report said, calling for new metrics to supplement reserve margins and requirements that all new generation provide voltage support and frequency response.
“What would be a bad thing is if we bring on a lot more gas-fired generation but all that gas-fired generation … can be interrupted, especially during winter peak times,” John Moura, NERC’s director of reliability assessment and system analysis, said during a media briefing on the report. “We replaced coal and nuclear that has some resilience to extreme weather and they’re going to be there, with resources that don’t have that. That’s our responsibility to look at and call out but … we do not have the authority or really the view as to how the market should address that.”
Recommendations
The report said:
FERC should support new products and revised market rules to ensure “essential reliability services” including frequency response and ramping.
State, federal and provincial regulators must recognize the long lead times for generation, transmission and natural gas infrastructure and the difference between regulated areas with long-term integrated resource plans and organized markets that can lose a generator with as little as 60 days’ notice.
State and federal policymakers, including the Department of Energy and FERC, should consider the impact of natural gas disruptions on the BPS when evaluating infrastructure requirements. Transmission planners and operators should identify reliability concerns resulting when a large share of gas generators rely on interruptible fuel contracts.
System operators and planners should gather more data on the “aggregate technical specifications” of distributed energy resources on local distribution grids to ensure accurate planning models, coordination of system protection and real-time situational awareness. Moura said the aggregate amount of behind-the-meter resources “is generally well known,” but that bus locations and technical specifications such as protection settings and voltage operating ranges are not.
In addition, NERC said it would conduct a “comprehensive evaluation” of its reliability standards to ensure their compatibility with nonsynchronous and distributed resources. “A lot of our standards were written largely for conventional generation, and words like ‘tripping’ or ‘spinning’ that are … well known when we’re talking about conventional generation don’t completely translate when we’re talking about asynchronous machines and inverters,” Moura said. “And so, we really need to look at our standards to make sure we’re not missing anything when we have more nonsynchronous machines on the system.”
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NERC also said it will monitor reserve margins, citing projected shortfalls in ERCOT and the SERC Reliability region. The reserve margin in SERC-E, which comprises utilities in the Carolinas that aren’t part of PJM, is expected to fall below the reference margin level beginning in 2020 because of the canceled expansion of the V.C. Summer nuclear power plant. The announcement of 4,600 MW of coal and gas retirements this fall means ERCOT reserve margins will fall below targets by summer 2018.
Higher Reserve Margins, Additional Metrics Needed
“As we see the resource mix change, we’re really making a call to action to industry and regulators to increase the robustness of the planning approaches,” Moura said.
In the past, he said, planners assumed fuel would be available and that there would be generators with sufficient inertia to control frequency response. Neither is a given, he said, as the mix changes to more gas and renewable generation.
The report said increasing variable generation may require more planning reserves to maintain the one-day-in-10-years loss-of-load-expectation, boosting target reference margin levels to 17% from 15%.
Since 2008, all but one of nine regions increased their reserve margins by about 2 percentage points. The exception was SPP, which has seen its reserve margin drop from 13% to about 12% over 10 years. ERCOT and Quebec are currently below 15%, although they have increased over the last decade.
Essential Reliability Services
Moura acknowledged that NERC has made the recommendation for preserving reliability services before. “But we wanted to reiterate it here: that all new resources, no matter the fuel, need to have the capability to support voltage and frequency response.”
He said FERC’s November 2016 rulemaking proposing changes to its pro forma generator interconnection agreements seeks to address the frequency response issue but said it’s up to states to implement the interconnection requirements. And even that, he said, is not sufficient. (See FERC Has More Questions on Frequency Response NOPR.)
Interconnection requirements don’t “guarantee any performance,” he said. “It requires them to have the capability and the [ability] to provide it, but in market areas, if they’re not bidding in and being incentivized to provide that frequency response, they don’t.
“We’re not in trouble right yet with frequency response,” he added. “But we see it on the horizon.”
Similarly, he said ERCOT’s establishment of a “critical inertia” level of 100 GW/s is “a really good approach to manage this. But a long-term mechanism will be needed as even more … wind will be coming on to their system.”
Gas Supply
The report notes that on-peak natural gas capacity has increased from 280 GW in 2009 to 442 GW today, with another 32 GW of gas capacity planned for the next 10 years. It projects the Florida Reliability Coordinating Council assessment area will rely on gas for 78% of its power by 2022.
“Areas can have and can rely on large amounts of natural gas as long as they have fuel assurance mechanisms, and Florida does that very well,” Moura said. “They have dual-fuel requirements as well as firm transportation … and the pipeline was really built for the natural gas generation in that area.”
Moura also said PJM’s Capacity Performance requirements and ISO-NE’s Pay-for-Performance program is “exactly what we’re looking for.”
“But the jury’s still out as to whether or not those penalties for nonperformance will compel generators to get dual fuel. … At least in New England, states have been very clear that new natural gas pipelines aren’t wanted.”
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The report also pointed out that the 0.61% (summer) and 0.6% (winter) 10-year annual demand growth rate for North America is the lowest on record. Despite flat loads, it noted grid operators added more transmission during 2006-2015 compared to 1991-2005.
