FERC last week rejected a CAISO proposal to extend the life of a program designed to protect some renewable energy resources from being assessed uplift costs associated with their variable output (ER17-1337).
The ISO established the Participating Intermittent Resource Program (PIRP) in 2014 as part of enhancements to its real-time market under FERC Order 764. PIRP provided older variable energy resources (VERs) a three-year transition period in which to acquire the capability to respond to dispatch instructions, during which they would avoid being assessed for startup costs for conventional generation needed to respond to uninstructed, intermittent output.
The program also accommodated renewable resources that needed additional time to renegotiate long-term power purchase agreements that expressly prohibited them from responding to real-time price signals.
CAISO earlier this year proposed to extend PIRP for an additional year until Apr. 30, 2018, contending that several resources operating under the program required more time for the transition. The ISO contended that the nine resources using the program had received a net benefit of $5.6 million between 2014 and 2016, an amount that was not expected to increase significantly with a one-year extension. The cost of extending the measure would continue to be allocated across all ISO scheduling coordinators.
In denying the extension, FERC said that “CAISO has not argued that the three-year transition period was an unreasonable time frame, or that circumstances have changed since the commission originally accepted” PIRP. The commission also noted that extending the program would expose market participants to additional uplift charges for another year while not guaranteeing that the protected resources would resolve their challenges during that time.
“Further, CAISO does not assert and the record does not indicate that allowing the protective measures to expire on April 30, 2017, would pose a risk to reliability, or that the relevant VERs would suffer significant financial losses as a result of their expiration,” the commission said.
The commission also agreed with Pacific Gas and Electric that allowing PIRP to remain in place would not give the relevant resources an “economic incentive” to respond to CAISO dispatch signals.
“CAISO itself has highlighted the need for resources to respond more quickly to CAISO dispatch instructions to curtail generation during oversupply conditions,” the commission said.
Calpine announced Friday it has agreed to be acquired by Energy Capital Partners and other investors for $5.6 billion in cash, or $15.25/share, a 51% premium to Calpine’s share price when news of a potential deal became public in May, and a 13% bump from Thursday’s close.
Energy Capital Partners, a private investment firm, is being joined by a group of investors led by the Canada Pension Plan Investment Board, which said it will invest $750 million, and Access Industries, a privately held company with investments in a wide variety of industries and companies, including Warner Music Group, Houston-based oil and natural gas producer EP Energy, and Russia-based aluminum manufacturer UC RUSAL.
The investors will be purchasing Calpine’s 26-GW fleet of 80 power plants in operation or under construction, the largest fleet of natural gas generators in the U.S. Its assets are concentrated in California (5,500 MW of natural gas and 725 MW of geothermal); Texas (13 combined cycle plants totaling 9,000 MW) and the East (31 plants totaling 9,400 MW in 14 states and Canada, most of them in PJM and ISO-NE).
In addition to its generation assets, Calpine also has two retail businesses — Calpine Energy Solutions and Champion Energy — which operate in 25 states, Canada and Mexico.
| M.J. Bradley & Associates (2017); “Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States”
M.J. Bradley & Associates ranked Calpine as the nation’s 10th largest power producer in 2015. Calpine claims to be the top-ranked generator in gas-fired capacity in Texas, with a No. 2 ranking in California and No. 3 rankings in the Mid-Atlantic and New England states.
Undervalued
During a call to discuss second-quarter results before the deal was announced, CEO Thad Hill explained the rationale for going private, saying “the public equity markets have undervalued our business and underappreciated our strong track record of executing on our financial commitments and our stable cash flows.”
Hill, who became COO in 2010 was promoted to CEO in 2014, said the acquisition will not change the company’s operations. The company will maintain its headquarters in Houston and its current management team, he said.
The sale will allow the company to “continue to strengthen our wholesale power generation footprint, while benefiting from ECP’s support, industry expertise and long-term investment horizon,” Hill said in a statement.
| Calpine
ECP partner Tyler Reeder confirmed that the deal would not result in operational changes, saying that the investors “see significant value in Calpine’s operational excellence and strong and stable cash flows, and have been impressed by the company’s exceptional leadership and talented employees.”
“We do not intend to make any changes to the company’s financial policy or previously announced $2.7 billion deleveraging plan,” he added, referring to plans to pay off the debt in full by 2019.
Including debt, The Wall Street Journal reported, the deal’s enterprise value is $17 billion.
The deal allows Calpine a 45-day “go-shop” period to seek a higher offer. The company would have to pay the ECP group a $142 million termination fee for canceling the deal. The fee would be reduced to $65 million if Calpine terminates the agreement within 106 days.
“We don’t think it is likely there is a topping bid,” Greg Gordon, an analyst at Evercore ISI, wrote in a research note, according to Bloomberg. “It was probably very hard to pull together an equity consortium for this size of a deal and it was a competitive process.”
The acquisition is subject to approval by Calpine stockholders, antitrust regulators, FERC and state regulators, including those in New York and Texas, the company said. Closing is targeted for the first quarter of 2018.
Seesaw Ride for Investors
York Energy Center | Calpine
Founded in 1984, Calpine went public in 1996 and grew steadily over the next several years before falling into bankruptcy in 2005. It moved its headquarters from California to Houston after exiting bankruptcy in 2008.
Like other independent power producers, Calpine has been pinched by low power prices and competition from renewables.
NRG Energy, which lost $626 million last quarter, is planning to sell as much as $4 billion of its assets, and last month it ordered an undisclosed number of layoffs. Dynegy, which lost $296 million in the second quarter, is reportedly considering an acquisition by Vistra Energy. (See Report: Vistra Energy Suggests Takeover of Dynegy.)
Calpine’s 2016 profit of $92 million was a 60% drop from 2015. It reported a second-quarter loss of $216 million after losing $56 million in the first quarter. Rising gas prices have resulted in reduced capacity factors for the company’s non-peaker plants, falling to an average of 43.6% in the first six months of the year from 48.8% a year earlier.
After peaking at almost $25/share in late 2014, Calpine’s share prices fell as low as $10 in April before news of a potential deal. Shares closed Friday at $14.92.
Energy Capital’s Plans
Based on its history, ECP may not keep Calpine for very long.
In 2015, it sold EquiPower — a company it created five years earlier to oversee a portfolio of fossil generators in the eastern U.S. — to Dynegy. In 2008, two years after acquiring it, ECP sold FirstLight Power Resources, a 1,440-MW portfolio of mostly hydro generation, to a subsidiary of GDF SUEZ, now ENGIE.
The firm also helped Dynegy finance its $3.3 billion acquisition of 17 U.S. power plants, selling its stake to Dynegy last year for $750 million. The company was Dynegy’s largest stakeholder as of June, according to Bloomberg.
ECP’s current holdings include Wheelabrator Technologies, which generates power from municipal solid waste and other renewable waste fuels.
FERC last week asked for additional comments on the rule it proposed in November that all newly interconnecting generators provide primary frequency response.
The Notice of Proposed Rulemaking, which reflected both reliability concerns and the technological advances of renewable generators, proposed revising the pro forma Large Generator Interconnection Agreement (LGIA) and Small Generator Interconnection Agreement (SGIA). (See FERC Proposes Frequency Response Requirements for Renewables.)
On Friday, the commission issued a notice requesting supplemental comments on electric storage and small generators (RM16-6).
The commission said it was prompted by the Energy Storage Association (ESA) and other commenters who said that the NOPR failed to address storage’s “unique technical attributes” and could discriminate against them.
ESA said that the proposed use of nameplate capacity as the basis for primary frequency response service and the fact that electric storage resources can operate at the full range of their capacity — without a minimum set point — would require them to provide a “greater magnitude of [primary frequency response] service than traditional generating facilities.”
“In light of these concerns, the commission seeks additional information to better understand the performance characteristics and limitations of electric storage resources, possible ramifications of the proposed primary frequency response requirements on electric storage resources, and what changes, if any, are needed to address the issues raised by ESA and others,” the commission said.
FERC also asked for more information on commenters’ concerns that small generating facilities could face disproportionate costs in providing frequency response.
Commenters including the Sierra Club, the Sustainable FERC Project and the National Rural Electric Cooperative Association said that the NOPR failed to prove the commission’s conclusion that “small generating facilities are capable of installing and enabling governors at low cost in a manner comparable to large generating facilities.”
Comments will be due 21 days after publication of the notice in the Federal Register.
Connecticut regulator John W. “Jack” Betkoski III, the new president of the National Association of Regulatory Utility Commissioners, last week called for more transparency at the New England Power Pool and said he plans to focus his NARUC tenure on the “water-energy nexus.”
Betkoski, vice chairman of the Connecticut Public Utilities Regulatory Authority, had been serving as NARUC’s first vice president before assuming the presidency on Aug. 14 from former Pennsylvania regulator — now FERC Commissioner — Robert Powelson. He will complete Powelson’s term and in November begin a full 12-month term.
In an interview, Betkoski told RTO Insider about his priorities at NARUC.
“You usually roll [priorities] out in November, but I’m probably going to [do] something with the whole water-energy nexus,” he said. “That’s certainly very important to what we do as regulators. You need both water for energy and energy for water. It’s something that we as regulators could highlight. I’ve always felt very passionate about the water cases that I’ve been involved in.”
NARUC committees set up to explore the issue would be divided equally between electric and water utility regulation, he added.
“Thank goodness that we have iPads and computers and everything else, because I can certainly fill my responsibilities here in Connecticut with my dockets but also be doing the great work we have to do with the national organization,” Betkoski said. “There’s so much going on, and the whole re-composition of [a quorum] at FERC, that’s going to be something that in my new role we’ll be getting reacclimated to, a fully staffed FERC organization within the next couple months.”
Betkoski declined to comment on dockets currently before PURA, on the state-federal tensions that prompted a FERC technical conference in May or on PURA’s role under Gov. Dannel Malloy’s executive order to assess the economic viability of Dominion Energy’s Millstone nuclear plant. “Katie is the lead commissioner on that joint proceeding,” he said, referring to PURA Chair Katie Dykes. (See related story, Commenters Seek Broader Response on Millstone, Renewables.)
Betkoski also demurred on elaborating on his plans for NARUC and the water theme: “It’s not even a week since I took over, so it’s really transitional right now.”
NEPOOL Transparency
Betkoski was surprised to learn last year that most stakeholder meetings of the New England Power Pool, which advises ISO-NE, are closed to the public and the press. Most meetings of the other six RTOs and ISOs are open.
NEPOOL is “doing something that impacts ratepayers, and anything like that should be as transparent as possible,” Betkoski said. “I know that’s certainly the way we operate here. I’ve been a commissioner for 20 years, and certainly I encourage people to come to public hearings and certainly have never kicked journalists out of public hearings, and I think the same should hold true for them.”
Jack Betkoski talks about storm-related outages on a TV program in November 2013 | Connecticut Public Utilities Regulatory Authority
If a discussion concerns proprietary information, the regulatory agency can go into executive session, but other than that the meetings should be open, he said.
Betkoski will be formally installed as president in November at NARUC’s Annual Meeting and Educational Conference in Baltimore. Wisconsin Public Service Commission Chair Ellen Nowak will also be formally installed as first vice president in Baltimore, while the second vice president position she is vacating will be filled at the same meeting.
A Democrat from Beacon Falls, Betkoski has served on Connecticut’s utility regulatory authority since 1997, when it was known as the Department of Public Utility Control. Malloy appointed Betkoski to the newly created PURA in 2011 and reappointed him to a four-year term that began in 2015. He is a past president of the New England Conference of Public Utilities Commissioners.
He has served on NARUC’s executive committee since 2012 and is currently chairman of the Connecticut Water Planning Council and a member of the American Water Works Association Research Foundation’s Public Council on Drinking Water Research. He previously served as a member of the EPA National Drinking Water Advisory Council’s Water Security Working Group.
The department and other market participants recently submitted comments on CAISO’s straw proposal for its Commitment Cost and Default Energy Bid Enhancements (CCDEBE) initiative. The proposal is designed to more accurately reflect unit commitment costs and overhaul the way the ISO calculates the default energy bid (DEB), which replaces bids of units found to have market power. (See CAISO Developing New Bidding Rules.)
The Monitor said it continues to recommend that CAISO split the proposal into parts and that more time is needed to develop dynamic mitigation. “The development and implementation of dynamic mitigation of commitments costs is relatively complex and the ISO has made very limited progress on developing technical details of an approach for actually implementing this,” it said.
“Given the flaws and lack of detail in the ISO’s commitment cost mitigation design,” the Monitor does not support a proposal to raise the caps on market-based commitment cost bids above the current level of 125%.
One of CAISO’s rationale for the new program is incentivizing flexible resources. The grid operator says that overly constrained supply offers discourage participation by some resources in the ISO and the Western Energy Imbalance Market (EIM), where the changes would also apply.
There are three power suppliers subject to the DEB: Arizona Public Service and Berkshire Hathaway’s PacifiCorp and NV Energy. In comments filed Aug. 15, NVE said it supports increasing the flexibility of supply bids and reforming the DEB methodology “to ensure appropriate recovery of actual supply costs.”
The Western Power Trading Forum said it supports the concept of the revised proposal but asked for additional information on the frequency of mitigation. The group supports CAISO’s proposed hourly minimum load offers, market-based commitment costs subject to mitigation and improved estimates of commitment costs. It also offered suggestions on details of the market design.
Pacific Gas and Electric said it supports part of the proposal but wanted additional detail before it would endorse the changes. “PG&E continues to have concerns about committing to move forward with a dynamic mitigation design while many questions remain regarding design details, feasibility and cost,” the company said. It said that more analysis is needed and that the dynamic mitigation should be split off from the rest of the CCDEBE proposal.
CAISO has acknowledged that its time schedule has been rapid since the original straw proposal was issued on June 30, but it says it is aiming for approval at the Nov. 1 Board of Governors meeting. The ISO said that some parties are anxious to have the new rules approved.
After originally setting an Aug. 10 deadline for comments — only eight days after the revised straw proposal was posted — CAISO extended the comment period to Aug. 15.
The ISO has made several changes to the package based on stakeholder input. The initiative has other market adjustments, including alterations to the use of gas indices and rules to allow cost-based energy offers above $1,000/MWh, in compliance with FERC’s November 2016 Order 831.
Some stakeholders thought the EIM Governing Body should sign off on the changes, but CAISO declined, saying it would offer only an advisory vote to the body since the initiative applies across all CAISO markets.
CAISO’s proposal to provide transmission revenue to balancing authority areas (BAAs) that wheel power between other BAAs received a wary response from Western Energy Imbalance Market (EIM) stakeholders last week.
Currently BAAs that wheel power are only paid if the system is congested.
The compensation change is part of a package of refinements that CAISO is developing, including fundamental changes to the way transmission is treated in the developing market. EIM entities filed comments on the proposals Thursday.
Powerex Sells Power from BC Hydro Plants Such as the Revelstoke Dam
Wheeling is on the increase as the EIM grows and more regions are added. When Powerex is integrated in April 2018, for example, Puget Sound Energy will be positioned to wheel power from British Columbia to the south. Powerex markets a BC Hydro portfolio of about 17,000 MW of generating capacity, about 12,000 MW of which is hydro.
Powerex said it supports the compensation proposal and wants CAISO to adopt a net wheeling charge on all EIM transactions to pay for it. The Province-owned company said that such transactions represent a significant portion of import and export volumes, “which suggests that such transactions may be critical to the EIM’s ability to generate benefits.”
But the company said that any wheeling charge should not impede economic dispatch and reduce EIM benefits. It is “critical that any such charge be designed in a manner that ensures that the incremental hurdle rate that is created is as small as possible. Such transactions may be critical to the EIM’s ability to generate benefits,” it said.
PacifiCorp, which has been operating in the EIM since the market went live in November 2014, said it has concerns about the proposal, arguing that “it is too early to understand if there is truly a market problem to be solved.” The company said CAISO should wait until after Portland General Electric, Powerex and Idaho Power are integrated to get a better understanding of how resources will be scheduled in the expanding market. PacifiCorp owns about 10,600 MW, including about 2,500 MW of wind, and plans to retire 3,650 MW of coal-fired capacity by 2036.
PacifiCorp’s Hunter Coal-Fired Plant Near Castle Dale, Utah
It is possible that the increased wheeling over the past nine months was related to “anomalies” such as excess hydro or the outage at the Aliso Canyon natural gas storage facility, the Berkshire Hathaway-owned company said.
“PacifiCorp recommends that the initiative be postponed and continue to be monitored so that new entrants can make informed comments that truly reflect transfers across their systems,” the company said.
The company also noted that CAISO had proposed market changes to accommodate the integration of Powerex, but that most of the additional functionality would not apply to PacifiCorp. The company believes Powerex will not be required to participate in security-constrained economic dispatch in its BAA like other EIM entities.
CAISO has two plans for the charges: an added “hurdle rate” into transmission costs that is distributed to participants in the transaction through a congestion offset; and an “ex-post” payment to entities facilitating the transmission that would be collected directly from the source and sink BAAs.
Monitor, Public Interest Groups Oppose
CAISO’s Department of Market Monitoring said both approaches would cause inefficiencies. The charge appears to be a proxy for other EIM benefits, the department said, and is “overly simplistic” for cost allocation. “These inefficiencies may result from a per-megawatt-hour fixed cost recovery approach influencing bidding behavior, or more directly through the hurdle rate, which may lead to inefficient dispatch of EIM resources,” the Monitor said.
A collection of public interest organizations also opposed the proposal, saying it could reduce overall EIM benefits and possibly reduce investment. The group includes Western Resource Advocates, the Natural Resources Defense Council and Western Grid Group.
“Not only will these schemes unnecessarily complicate the EIM’s market design, thereby undermining its benefits, but they appear to be a solution in search of a problem, given that all EIM BAAs are importing and exporting more than they are facilitating wheeling,” they said.
They also said that CAISO should not focus on minor inequities in the EIM because it distracts stakeholders from the benefits the market brings. If the ISO does pursue it, the groups support the ex-post payment approach, saying it is least disruptive to the market and would adapt well to a changing EIM.
Seattle City Light voiced strong opposition, saying that a more robust stakeholder review is needed before making such a change, noting that CAISO has not identified free riders or cost shifts. The municipal utility owns 2,000 MW of hydro and transacts in the EIM.
“City Light is particularly concerned with the proposal to address a benefits-related issue by implementing an additional cost to EIM entities. The addition of a new cost is an imprecise tool to address a concern over inequitable distribution of benefits,” the publicly owned utility said.
Portland General Electric in its comments said it “is not convinced that this initiative has been appropriately scoped, or that the market design, policy and regulatory considerations have been fully considered, and therefore does not believe it is prudent at this time to move forward with either of the ISO’s policy recommendations.”
Southern California Edison (SCE) also opposed the changes, saying that participating in the EIM does not guarantee uniform benefits to all entities and CAISO.
“While SCE understands that examining the actual benefits and costs after the fact rather than relying on estimates prior to EIM is a good practice, SCE believes that in this case, the data support the current practice and policy and that no changes are warranted,” the company said.
Arizona Public Service supported the proposal but said it should apply equally across the EIM and not offset the market’s benefits.
Most stakeholders support CAISO’s decision to eliminate from the package of market rule changes a plan to allow third-party transmission owners to participate in the EIM. There was lackluster interest from current EIM entities and it was thought the provisions would be little-used. (See CAISO Drops EIM Third-Party Transmission Plan.)
The ISO Board of Governors is due to review the package of changes at its Nov. 1 meeting.
FERC on Thursday approved MISO’s more stringent capacity withholding rule while also allowing the RTO to remove demand response and energy efficiency from market monitoring.
Commission staff had tentatively approved the changes in early spring but warned that the new rules could be overturned as unreasonable once FERC regained its quorum. (See FERC Staff OKs MISO Mitigation Changes; Refunds Possible.) With the quorum now restored, commissioners on Thursday approved the Tariff revisions retroactively Feb. 1 (ER17-806).
| MISO
MISO’s 50-MW minimum for physical withholding rules now apply to affiliated market participants collectively, rather than individually to each affiliated company. The RTO had already used the rule in April’s annual capacity auction.
“We find that it is reasonable for the Tariff to clarify that the 50-MW physical withholding threshold will apply jointly to affiliated market participants. As MISO suggests, this will prevent large suppliers from distributing their planning resources among multiple market participants to withhold capacity from the auction,” FERC wrote.
MISO’s Independent Market Monitor first recommended the change in its 2015 State of the Market Report, saying that as “capacity margins fall in MISO, the market will become more vulnerable to physical withholding.”
The order also allows MISO to exempt DR, EE and external resources from Planning Resource Auction mitigation measures. The RTO said DR and EE resources are too small to have market power. FERC agreed that encouraging the participation of such resources is “beneficial to the auction.”
FERC’s ruling also authorizes MISO to clarify that all planning resources “not otherwise exempted from market monitoring and mitigation” are eligible to receive a facility-specific reference level.
MISO has two bases for such proxies: going-forward costs for units that may consider retirement or mothballing, and the opportunity costs of selling capacity in the RTO, including the potential of selling for higher prices in bilateral trades.
Previously, MISO’s Tariff did not specify which resources were eligible to receive such reference levels. FERC said it was helpful for the RTO to establish that all planning resources except those explicitly exempted are “subject to potential mitigation for economic withholding and [have] the option to request a facility-specific reference level.”
Seven of the eight stakeholder-originated project proposals evaluated by MISO and PJM are not expected to pass the RTOs’ benefit threshold.
The sole project left standing is Northern Indiana Public Service Co.’s proposed new line section between its Thayer and Morrison 138-kV substations in northwestern Indiana, near the Illinois border. The greenfield project would be in service by 2022 at a $42.5 million cost, RTO stakeholders learned at an Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting Aug. 18.
MISO would reap the lion’s share of expected benefits at $75 million, while PJM would see $7.3 million in benefits; the costs would be split 91.1% and 8.9%, respectively. Staff said the project will now be evaluated in each regional process based on interregional cost allocation. PJM engineer Alex Worcester said the RTOs still plan to return to an October IPSAC meeting to discuss all eight projects and their final benefit-cost ratios, however dismal.
In May, the RTOs revealed three upgrade and five greenfield proposals from stakeholders, ranging from $1 million to $198 million, for three congested flowgates around the borders of Michigan, Indiana and Ohio.
Most proposals’ effectiveness was undercut by American Electric Power’s recently announced plans for a supplemental project for the Olive–Bosserman constraint near the western Indiana-Michigan border. AEP plans to remedy the problem by increasing voltage and rerouting nearby PJM circuits dating back to the 1930s with two new 138/120-kV distribution stations. (See MISO, PJM Weighing 8 Interregional Tx Proposals.)
All but two of the project proposals concentrated on the Olive–Bosserman constraint. Another NIPSCO proposal — an $8 million plan to reconductor a NIPSCO line between AEP’s Bosserman and Olive 138-kV substations and reconductor a NIPSCO line between Bosserman and AEP’s New Carlisle 138-kV substation — was found to benefit neither PJM nor MISO after the AEP proposal was factored in.
| MISO and PJM
NIPSCO’s Clark Gloyeske asked if PJM had plans to refund the project submission fees the RTO charged to consider the proposals. “The supplemental came along and wiped out all of these proposals,” he said.
PJM Manager of Interregional Planning Chuck Liebold said it may conduct additional analysis to explore the possibility, but he did not elaborate on an expected timeline.
Meanwhile, MISO engineer Adam Solomon said the RTOs still have five targeted market efficiency projects (TMEPs) at the ready should FERC approve the regional cost allocations for the new category. MISO filed for regional allocation Aug. 4 (ER17-2246), and PJM filed its allocation on April 11 (ER17-1406).
Commission staff tentatively approved the TMEP category in a delegated order in June but said the decision was subject to review by the commission once it regained the quorum it lost in February (ER17-721). (See FERC Tentatively OKs New MISO-PJM Project Type.)
“Pending FERC approval, we are still ready to recommend the five TMEPs that we’ve had on our hands for a while now,” Solomon said.
The RTOs will not conduct a new TMEP study this year. The TMEP process was originally intended to be performed annually, but Solomon said MISO and PJM are still undecided if they will undergo a study even in 2018.
“Closer to the end of the year is when we’d try to make that decision,” Solomon said.
MISO’s rejection last week of the last possible transmission project resulting from a coordinated study with SPP surprised the latter RTO and left officials wondering whether the neighbors will ever build an interregional project.
MISO staff told its Planning Advisory Committee on Aug. 16 that it was no longer recommending the $5.2 million Split Rock-Lawrence initiative in South Dakota, which would have been the RTOs’ first-ever interregional project.
MISO now says an analysis of the project shows that congestion on the line can be managed for now and that another alternative project could provide the RTO with at least the same benefit at a lower cost.
SPP COO Carl Monroe told RTO Insider Friday that the RTO only discovered MISO’s recommendation through posted meeting materials and the ensuing coverage. “We’re disappointed we can’t find any of these types of projects,” Monroe said. “We go through the Order 1000 process, which, from the joint study, seems to have some benefits. But it just doesn’t seem like when we go to the individual [RTOs’] studies, it shows that type of benefits.”
The project was halted before it could clear the Joint RTO Planning Committee — composed of staff with ultimate say over interregional issues — and before it would have been recommended for inclusion in MISO’s 2017 Transmission Expansion Plan. The coordinated study was meant to focus on needs along the border of SPP’s Integrated System in North Dakota, South Dakota and Iowa. Some MISO stakeholders expressed doubt at the beginning of the study that any projects would materialize.
MISO said the congested line in South Dakota is now operating as an open circuit under an operations guide proposed by Xcel Energy in May, which shifts some congestion to the nearby Sioux Falls–Split Rock 230-kV line. Had the project — which would have looped Xcel’s existing Split Rock-Lawrence 115-kV circuit into the Western Area Power Administration’s Sioux Falls station, crossing SPP territory — proceeded, Xcel would have been at risk of incurring SPP penalties for unreserved use of non-firm point-to-point transmission service, the RTO said.
| MISO and SPP
MISO recommends maintaining the status quo and operating the Lawrence–Sioux Falls line in an open state to relieve the congestion for now, Davey Lopez, the RTO’s adviser of planning coordination and strategy, told the PAC. He added that the open state operation “provides MISO nearly the same adjusted production cost savings” as the interregional project at little to no cost.
However, MISO said it would continue to pursue upgrades to terminal equipment on the Lawrence–Sioux Falls line through joint efforts between MISO, Xcel, SPP and WAPA. The terminal upgrades would still represent a savings over the originally proposed loop project, MISO said.
Questions on Open Circuit
Monroe questioned MISO’s use of an open circuit, which can reduce reliability when congestion is shifted from one line to another. “Normally, we don’t run the system with open lines,” he said. “In some regards, it increases the risk you’re taking.”
Monroe said SPP has offered to go beyond FERC’s Order 1000 process to find “mechanisms and ways to share costs” to ensure both RTOs benefit from interregional projects, “but we haven’t found one of those.”
“It’s hard to say whether it’s the process or stakeholders or something,” Monroe said, “but we just haven’t been able to get across the goal line from the perspective of their regional review.”
SPP stakeholders have questioned the desire of MISO to develop interregional projects with its western neighbor. The two RTOs have now conducted two coordinated joint studies and failed to agree upon a single interregional project.
Adam McKinnie, utility economist for the Missouri Public Service Commission, said he had “severe concerns” that MISO was allowing a temporary operations plan to become a long-term solution for congestion.
“We couldn’t justify subjecting our customers to a $5 million project when there’s a no-cost solution available,” Lopez explained.
Seeking a ‘Willing Partner’
McKinnie also questioned if the SPP-MISO seam is receiving the same level of interregional coordination as the MISO-PJM seam. “I’m kind of tired of refereeing fights between MISO and SPP because my ratepayers pay for those fights,” he said, adding that SPP officials seem more receptive to interregional planning than those at MISO.
MISO staff countered that the RTO is looking for the most economic and efficient solution to the congestion.
MISO’s interregional project cost and voltage thresholds with SPP remain unchanged at $5 million and 345 kV, respectively. FERC ruled at the beginning of the year that MISO and SPP were not bound by its directive to PJM and MISO to remove identical thresholds. SPP had asked FERC last year to apply the same directive to the MISO-SPP seam.
Had the 115-kV Split Rock-Lawrence project won approval, MISO would have had to designate its portion of the project as “miscellaneous,” unable to qualify for cost allocation, because it does not meet the 345-kV voltage threshold required of its market efficiency projects.
“We just haven’t seen that ability, whether it’s because they don’t want to do it, or they don’t feel like they can do it, or the stakeholders don’t want it,” Monroe said. “I just don’t know where the resistance is. If you feel like these [projects] are good to do and you want to get them done, you can work through these issues, hopefully, and even demonstrate the rigidness of the problems that Order 1000 creates. We just haven’t found a willing partner on the other side to negotiate those issues.”
SPP’s Seams Steering Committee was to present the South Dakota project to the Markets and Operations Policy Committee in October, but that is unlikely to happen now, Monroe said. “You could probably believe we don’t have much hope that our members want to go ahead with this either, if MISO doesn’t want to,” he said.
It’s unclear how soon the RTOs will embark on another joint study. Last spring, MISO staff originally decided against a coordinated study, explaining that it was hoping to improve the process behind coordinated studies before taking up another one. Staff later reversed course and agreed to the 2016 coordinated study. A 2014-15 MISO-SPP coordinated study ran over deadline by three months and left both RTO staffs frustrated and empty-handed. (See SPP, MISO Try to Bridge Joint Study Scope Differences.)
HARTFORD, Conn. — Connecticut regulators got an earful at a public comment session Thursday on the future of Dominion Energy’s Millstone nuclear plant, with multiple speakers opposing a state subsidy such as those adopted by New York and Illinois.
Instead, the speakers urged that any efforts to preserve the plant be part of a regional initiative that also includes other emission-free generation. Others questioned whether Millstone needed financial support in addition to its revenue from ISO-NE’s energy and capacity markets.
The Aug. 17 hearing was in response to Gov. Dannel Malloy’s executive order requiring state officials to assess the economic viability of Millstone and determine whether the state should provide it financial support. The governor also directed the Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority to assess the viability of all forms of renewable energy and to report their findings by Feb. 1. (See CT Gov Orders Financial Analysis of Millstone Plant.)
Free to Solicit
PURA Chair Katie Dykes, who led the public meeting, reminded participants that they were not only to look at nuclear, but also at “large-scale hydropower, demand reduction, energy efficiency measures, energy storage and emissions-free renewable energy — all those different resources together — and how they could help Connecticut meet interim and long-term carbon and other emission targets. So there is a larger scope here.”
The Connecticut General Assembly in June failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state procurement process (S.B. 106). Dominion had sought the legislation to boost the plant’s revenues, which have suffered from low-priced natural gas, which often sets LMPs in New England.
Dominion has until Aug. 29 to respond to PURA’s request for the company’s financial records on Millstone, which supplies approximately 45% of Connecticut’s electricity.
Tom Swan, executive director of the Connecticut Citizen Action Group, characterized Dominion’s pleas of economic hardship as “BS” and said the regulators should also look at additional legislative remedies if the company wants to leave the business. While the state may need Millstone to meet its emissions reduction goals, “that doesn’t say it has to be Dominion,” he said.
State regulators have been given leeway to act by a 2nd U.S. Circuit Court of Appeals ruling in June that rejected claims that Connecticut’s renewable energy procurement law intruded on FERC’s authority. The court on Aug. 17 declined to revisit its decision.
The ruling affirmed a lower court decision on the law, which requires the state to solicit proposals for renewable energy projects and for utilities to sign contracts with the winners. Renewable energy developer Allco Finance challenged the law’s implementation as discriminatory (16-2946, 16-2949). (See Second Circuit Upholds Conn. Renewable Procurement Law.)
Despite the court’s support for state’s rights, Peter Fuller, vice president of market and regulatory policy for NRG Energy, said, “We need to keep everything in the context of the regional context, the regional structure. ISO-NE and the New England markets are specifically tasked with maintaining reliability of the grid, are structured to achieve those reliability goals at lowest cost.”
Connecticut’s agencies need not “start from whole cloth” and worry about those issues, Fuller said. “We have those structures in place. Hopefully ISO-NE will be involved in assessing the various scenarios and so forth and assuring the various agencies on what is reliable.”
Michael Cuzzi, senior director of government relations for Brookfield Renewable, recommended that the study consider all hydropower resources in ISO-NE and adjacent control areas, not simply large-scale hydropower as stated in the governor’s order and as currently defined under Connecticut statutes.
“The existing statutory definition — which contains both size and geographic limitations — prevents Connecticut from accessing existing, interconnected hydropower resources from both Canada and New York that can help Connecticut meet its energy needs and that are not currently accounted for in the state’s greenhouse gas emissions inventory,” Cuzzi said.
If the “hydro resources in New York and Canada aren’t currently counted toward their renewable goals, are they currently counted towards other jurisdictions’ goals?” Dykes asked him.
“It depends,” Cuzzi replied. “As you know, in New York, the initial Clean Energy Standard did not incorporate existing clean energy resources, so I think there’s a bit of a first-mover opportunity here to frankly claim those attributes and lock them into one jurisdiction or another.”
Pricing Carbon
Fuller said that any targeted subsidy will distort markets, produce less-efficient outcomes and potentially increase risk to consumers.
He urged the regulators to “think about the multistate issues, think about the legislative proposal from a few months ago to place a broad, economy-wide carbon tax — those are the kinds of solutions either within the IMAPP [Integrating Markets and Public Policy] or within the broader economy we feel are going to be far more effective at getting the right answer.”
The New England States Committee on Electricity (NESCOE) told the New England Power Pool in April that the states opposed “a FERC-jurisdictional tariff reflecting carbon pricing.” (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
Cuzzi similarly recommended that the study “examine a uniform ISO-NE-wide carbon price.”
On Aug. 11, NYISO and the New York Department of Public Service released a report that said a $40/ton carbon charge in the state would have “a relatively small impact” on customer costs, with bills dropping by 1% or rising no more than 2%. The analysis from the Brattle Group was prompted by the Public Service Commission’s decision to subsidize upstate nuclear plants through zero-emission credits (ZECs) and penalize fossil fuel generators based on their level of carbon emissions. (See NYISO Study Sees Little Cost Impact from Carbon Charge.)
“The question of carbon pricing has come up a lot in the IMAPP context,” Dykes said. “The executive order does highlight that we should consider best mechanisms, including potentially collaborating with other states, but we also have to consider how they would work [and] what the impact would be if Connecticut could not entice other New England states to participate with us: so as a one-state option versus how it would work if there was a multistate option.”
Dykes added that “in an IMAPP context, the New England states’ comments provided to NESCOE were not supportive of carbon adders, but I just wanted to highlight that this is one of the variables we’ll be looking at as we assess mechanisms, one state versus regional implementation.”
James Shuckerow, director of electric supply for Eversource Energy, said any recommended remedy should be least-cost and for the shortest duration possible.
“Because Millstone is a regional resource, if somehow there could be a regional remedy, I think that would be preferred by all,” Shuckerow said. “I recognize the problem in New England. We have six different states versus the situation we have in New York.”
In its written comments, Eversource said that Millstone is not a Class I, II or III renewable resource and “cannot simultaneously be a competitive merchant generator and receive state-sponsored financial support.”
The company said that “any financial remedy that is developed to address a legitimate economic need should be based on cost-of-service principles with correspondingly limited returns on equity to reflect the reduction in risk resulting from Millstone’s receipt of state financial support that is unavailable to other non-renewable merchant generators.”
“Look at the costs affecting all customers and the overall impact not only on standard service customers or large customers, but all customers throughout Connecticut,” Shuckerow said.
The cost-of-service approach would allow all types of customers through an appropriate charge to share the benefits, Shuckerow said. “Essentially, we’d sell the energy into the market, get credit for that energy and credit that against the cost of service.”
Kerry Schlichting of the Acadia Center said that because the study results could influence Connecticut’s long-term energy strategy, her organization asked DEEP and PURA to “issue a draft methodology and base case scenario sometime this fall for stakeholder review and comment” before the release of the draft report in early December. If the agencies wait too long it will be difficult to incorporate stakeholder feedback on modeling issues, she said.
Nancy Burton, director of the Connecticut Coalition Against Millstone, said “Millstone is hardly a zero-emissions facility. … Every year they pile [DEEP] up with documents about their emissions, their continuous radioactive emissions into the air and the water, as well as their toxic discharges to the Long Island Sound.”
John Erlingheuser, representing AARP, said: “How do we know what the problem is if Millstone doesn’t release actual data? … We’re not opposed to nuclear or opposed to Dominion or to keeping the plant open. What we object to is devising solutions without proper information and without determination that there’s an actual need.”
Local construction worker John Thomson spoke as a consumer on the potential economic impact of losing Millstone. “I’m concerned about the economic impact of that area of the state,” he said. “We’ve lost a lot of businesses already, so what’s that going to look like going forward for taxpayers, not just ratepayers?”
Lynne Bonnet, a member of the New Haven Energy Task Force but speaking on her own behalf, said the Cross-Sound Cable was built as a two-way conduit but that so far the energy has only flowed from Connecticut to Long Island. “Why don’t we ask Long Island now to generate power to help us to shut down Millstone?” Bonnet said. “And Long Island could also generate power to supply their own needs so they won’t have to buy power on a contracted Cross-Sound Cable.”
Bonnet also asked the regulators to be wary of the assumption that the state has already been penetrated with solar energy and energy efficiency. “If you pay attention to these situations where energy efficiency has decreased the load from residential use, New Haven is an untapped resource. It’s not saturated and not even been penetrated,” she said.
