LITTLE ROCK, Ark. — SPP stakeholders last week directed the Seams Steering Committee to stop work on proposed Tariff changes that would have granted a waiver from charges for unreserved transmission use across the seams.
The Market and Operations Policy Committee’s action during its Oct. 16-17 meeting means SPP’s current practices for unreserved use will continue. They have resulted in about $23,000 in service charges since 2016, but only when that unreserved use is reported to the RTO.
The revision request (RR308) would have granted transmission customers a four-hour grace period for unreserved service during an unplanned transmission outage. SPP’s Tariff and its business practices do not allow exemptions for transmission customers using the RTO’s system to take transmission service because of outages, whether planned or unplanned.
The SSC was unable to reach a consensus during its monthslong discussions, with some members saying temporary use of interconnected systems should be a benefit and others calling for transmission owners to be compensated. The four-hour grace period was a compromise position.
“Several members thought the four-hour grace period was at least some justification to take this to FERC and stakeholders,” American Electric Power’s Jim Jacoby, chair of the SSC, told the MOPC. “It seemed to have at least some backing. From an AEP perspective, that’s a benefit of interconnected systems. We ought to give customers some time [to arrange service during an unplanned outage].”
RR308 received little support from SPP’s legal department. Associate General Counsel Mike Riley pointed to excerpts from FERC Orders 890 and 890-A, which address situations where a customer is unaware of changing conditions that result in additional service requirements. Riley said FERC’s language does not exempt “any class of transmission customer from the potential assessment of unreserved use penalties” and refers to entities “serving native load in multiple control areas.”
“Not being a FERC commissioner, it’s hard to say what the [language] is intended to cover, but when I read words like ‘multiple control areas,’ that seems applicable to us,” said SPP’s David Kelley, director of seams and market design.
“If SPP and the stakeholders have a basis for filing and justifying this four-hour window, or grace period, we’ll absolutely file it,” Riley said. “But based on 890’s provisions, where FERC appears not to make a distinction between reserved use and unreserved use, we’ve got an uphill battle.”
Riley agreed with the concept of a grace period before assessing penalties, saying it should be a business practice in the Tariff.
“We just haven’t seen or found a justification that would get us over the 890/890-A hurdle, but it’s up to FERC,” he said.
Several members suggested SPP could conform its practices with those of MISO — which Southwestern Public Service’s Bill Grant said MISO does not apply unreserved charges in similar situations — through their joint operating agreement. But Kelley pointed out, “Even if we address this issue through the JOA, we’ll still have to make a filing at the commission. We still have to get around the hurdles of what we’re arguing.”
“This is not being applied consistently,” Grant said. “Only when SPP knows about it.”
“What we’re trying to do is address the unfortunate bystander that doesn’t know what’s going on, and only finds out about it when they get a bill,” AEP’s Richard Ross said.
On the sidelines, some members referred to the TOs who reported unreserved use as “tattletales.”
The MOPC’s motion passed over 10 opposing votes and five abstentions.
LITTLE ROCK, Ark. — SPP members last week approved one of two Generator Interconnection Improvement Task Force recommendations but took no action on the second and agreed to disband the group.
The task force was formed last year to identify improvements in the RTO’s transmission study process, which is backlogged with more than 62 GW of interconnection requests. Its work will be carried on by various working groups.
The Market and Operations Policy Committee approved the GIITF’s suggestion to address generator interconnection studies in regions where the amounts of new generation being requested exceed load during spring and other light load periods.
SPP currently divides its footprint into cluster groups for individual study. In the high variable energy resource case, all VERs inside the cluster are set to 100% of capacity while external VERs are set to 20% to simulate counterflow to the internal generation.
With the increase in VERs, the amount of counterflow contained in the Integrated Transmission Planning models is high enough that the simulation is no longer needed, and the 20% setting has resulted in situations with insufficient load to absorb all the generation being requested. Under the new rules, the external VERs remain at the base reliability dispatch setting used in the ITP process.
“The changes here allow the energy to flow a further distance to a neighboring zone, which should identify [needed] transmission upgrades,” said Tradewind Energy’s Derek Sunderman.
Task force Chair Al Tamimi, of Sunflower Electric Power, said the change “might help us move forward with [definitive system impact studies].” Staff is working on study requests that date back to 2015.
“That should tell us something,” Oklahoma Gas & Electric’s Greg McAuley said. “We’re dancing around the problem. We have too much generation coming in, and we have no place to put it.”
McAuley pointed out that the Holistic Integrated Tariff Team is also working on the problem. “We don’t know where they’re going to land,” he said.
The measure passed with six opposing votes, mostly from transmission owners, and 14 abstentions.
Members declined to take a vote on the GIITF’s recommendation to change the criteria for allocating network upgrade costs to interconnection customers by adding a new energy resource interconnection service (ERIS) criterion.
Under the proposal, SPP would have first allocated cost responsibility to requests with 20% or more of the generator’s output flowing across a constrained element, as under current practice.
After applying the 20% transfer distribution factor (TDF) test, the proposal would have added a second screening to determine which requests have at least a 5% TDF. If the number of such requests resulted in a cumulative TDF of 20% or more, a mitigation would be assigned to the cluster, with the cost allocated to those requests with at least a 5% TDF.
SPP said the change would have resulted in the identification of four additional constraints in the DISIS-2016-001 study.
But several members said the recommendation didn’t go far enough in identifying constraints caused by interconnection requests. Staff agreed the current process doesn’t catch enough constraints.
The committee also accepted a storage white paper for incorporation into SPP’s generator interconnection processes. The document describes proposed rules for processing and evaluating storage interconnection requests. Two members opposed the motion and three abstained.
WASHINGTON — Infocast’s inaugural Storage East summit drew policymakers, grid operators, utilities and companies looking to break into energy storage to the Washington Plaza Hotel last week. Panelists discussed the optimism surrounding the industry, as well as strategies for locating resources and optimizing their services for maximizing returns.
FERC Commissioner Neil Chatterjee kicked things off by recalling actions the commission has taken on storage since he joined in August 2017. The highlight of these was the February issuance of Order 841, which directed RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets. (See FERC Rules to Boost Storage Role in Markets.)
When Chatterjee joined FERC as chairman, he restored the commission’s quorum, which it had been without for six months. He said he had expected to be able to vote on a final version of the commission’s November 2016 Notice of Proposed Rulemaking as soon as he walked in, but he found that staff were still working on “a number of complex, legal and technical issues.”
“Understanding the importance of what was at stake, during my tenure as chairman, I worked closely with staff to push that final rule forward,” he said proudly. “I believe in the potential for storage to be a transformative technology for our grid. Storage is a game-changer. I’ll admit it’s a bit cliche, but there’s truth to it.”
He also noted the importance of Order 845, which revised the commission’s pro forma large generator interconnection procedures and interconnection agreement. One of the 11 changes the commission approved was to include storage in the definition of “generating facility.” (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)
Another change allows generators to sell their surplus interconnection capacity to other resources. Storage owners can purchase surplus capacity for their resources so they can interconnect without having to go through the full queue, Chatterjee said.
“While this change in policy sounds very wonky — and it is — I think it’s a subtle but important action we’ve taken to improve opportunities for storage development.”
Chatterjee also noted the challenges storage still faces. RTOs and ISOs face a Dec. 3 deadline for their Order 841 compliance filings. FERC is “likely to take several months” to review them, and any deficiencies it finds will delay implementation further, Chatterjee said.
He also said grid operators have been slow to develop new products to compensate storage resources for their different services.
“With the exception of PJM’s RegD product, there’s been little momentum toward expanding the traditional set of ancillary services in the past few years,” Chatterjee said. “The increasing penetration of renewables might provide additional momentum for such products, but in any event, whether and how these products come to fruition could have a significant effect on the opportunities for storage.”
Siting and Co-location
Multiple panelists discussed the best strategies for deciding where to develop storage resources.
Storage can receive the federal investment tax credit when added to existing qualifying resources, mainly solar facilities. But Michael Harrington, of Consolidated Edison’s Utility of the Future department, pointed out that the New York State Energy Storage Roadmap, issued in June, predicted that more than half of the 1,500 MW of storage the state aims to procure by 2025 would be downstate, close to New York City’s load.
“We do think there’s opportunity with upstate renewables, but certainly we recognize that storage is going to follow where the economics are the best,” he said.
Ascend Analytics CEO Gary Dorris explained why being near the city is so attractive for storage. The best way to determine where to site storage resources, he said, is finding where prices are most volatile: where congestion on the grid is most persistent.
Price spikes occur very infrequently on a typical New York node — only 1.5% of a 24-hour day — but they represent 22% of the average real-time energy price, according to Dorris. “So storage can be a wonderful physical hedge against price spikes, and that’s a real opportunity to mitigate uncertainty in supply by having that physical hedge in attacking those price spikes.”
“Co-located storage with renewables certainly has benefits, but is co-locating renewables with storage going to become standard practice?” Chatterjee posited. “The answer to that question could have major implications for storage. We have evidence that the cost-benefit ratio of co-located storage is tipping in favor of adding storage.”
Prices in New York state are highest near the New York City metro area, where there is persistent transmission congestion. This presents the best economic opportunity for storage resources. | Ascend Analytics
He pointed to a 2017 resource solicitation by Xcel Energy’s Public Service Company of Colorado. While individual wind and solar resources received median offers of $18/MWh and $29 MWh, respectively (“amazing numbers in their own right”), wind and solar resources co-located with storage received a $3 and $7 premium.
“When you consider market incentives like … capacity constructs in PJM and ISO-NE, co-location could be extremely beneficial in allowing renewables to avoid performance penalties and take advantage of high prices,” he said.
Wish List from States, RTOs
Several speakers said grid operators and states could be doing more to value storage’s services.
In introducing a panel on innovative business models for storage, Dorris suggested that states should lower their property taxes for storage. Taxes are particularly high in the Northeast, where storage is most in demand. “That’s probably not being talked about as much as perhaps it could be given the nature of these projects,” he said.
The panelists focused on the lack of a “T&D benefit” in RTOs and ISOs, saying storage should be compensated for its congestion-reducing benefits as energy efficiency programs are. Such programs are valued in part for reducing the voltage levels on transmission and distribution lines, allowing transmission owners and utilities to defer costly upgrades.
“Just level the playing field between how you treat conservation and how you treat storage,” Dorris urged.
“As a developer, we need to have certainty, and we need to have predictability going forward,” said Thomas Leyden of EDF Renewables. “That’s not easy in a market-based system, but there are things that can be done to help our investors become more comfortable.”
Adam Rousselle, CEO of Renewable Energy Aggregators, went further. He noted that transmission owners get paid fixed rates of returns based on the value of their assets. “If we can not align the development of storage with the transmission owner, we won’t be building storage any time soon in PJM,” he said. “And if your solution delays their transmission investment, they’re competing with you, make no mistake about it.”
PHILADELPHIA — Fugitive methane emissions might be reduced throughout the natural gas supply chain by making accidental leaks and routine venting part of the carbon markets being considered for the power industry, panelists told attendees Wednesday at a policy forum hosted by The Kleinman Center for Energy Policy at the University of Pennsylvania.
The key would be developing a market that taxes emitters but also pays those who capture emissions, as the technologies would also be useful for reducing methane emitted by nature — either as part of natural processes or negative feedback loops exacerbated by global climate change.
“If you can price greenhouse gas emissions and you put in that financial incentive for capturing it, and then whatever brilliant technology gets developed, it faces the right incentives and it has a financial ability to move forward,” said Catherine Hausman, an assistant professor of public policy at the University of Michigan. “The carbon tax, the flip of that is the subsidy or whatever for what gets captured.”
She suggested a policy, which she acknowledged has legal concerns, where every potential source of methane in a region would be responsible for a share of the area’s emissions unless it can prove it wasn’t the source. That would incentivize gas producers and pipelines to monitor their operations to prove themselves innocent.
The panelists weren’t afraid to promote increased governmental regulation.
“Tax the emission if you can. Absent a tax … you need regulations on the way they run. … I am totally happy with regulatory measures that are not market-based in situations where you can’t develop market-based solutions,” Hausman said. “I always teach that zero pollution is not the right answer because it stops all economic activity. Now, very aggressive action is certainly needed.”
“I would love to get to the place where methane emissions from the oil and gas industry are appropriately taxed. … Our view is we’re not there yet,” the Environmental Defense Fund’s Ben Ratner said. “Where we really want to get to over time is prevention. … There’s just no way around government action.”
From left, Environmental Defense Fund’s Ben Ratner, Catherine Hausman, assistant professor of public policy at the University of Michigan, and moderator Karen Goldberg, a chemistry professor at the University of Pennsylvania and the director of the Vagelos Institute for Energy Science and Technology. | (c) RTO Insider
Another challenge for developing a carbon market will be defining what values are used to determine payments. As hard as it is to nail down a valuation of carbon — the panelists noted suggestions from $40 to $400/ton — so too is calculating the amounts emitted. And while researchers can estimate global emissions, “knowing the precise location [of the source] is what’s hard,” Hausman said.
“You have to solve the measurement problem,” she said.
“There’s still so much uncertainty about global emissions … that we don’t know yet what [each source’s emissions limit] should be,” Ratner said.
Hausman suggested the key might be locating “super-emitters.”
The panelists also criticized the Trump administration for attempting to reverse regulations on methane emissions in the oil and gas industry. The Clean Air Act’s procedural rules barred the Obama administration from expanding its more stringent regulations for new and modified facilities to existing facilities, Ratner said.
The hope was for the next administration to make that expansion, he said. But “not only is this new administration not doing that, it seems to be intent to roll back” the Obama revisions, he said.
ARLINGTON, Va. — FERC Commissioner Neil Chatterjee and Assistant Energy Secretary Bruce Walker pledged to continue their work on grid resilience Wednesday following the apparent demise of the Trump administration’s latest plan to prop up struggling coal and nuclear plants.
The two appeared at the Department of Energy’s Electricity Advisory Committee meeting, where Walker charged the panel with reconsidering current practices on spinning reserves, calling it wasteful to have 15% of capacity “doing no work.”
Walker also did a little spinning of his own, insisting that DOE’s “leaked pre-decisional memo” calling for price supports for “fuel secure” generation was never about propping up nuclear plants or the coal industry. The memo became public at the beginning of June, after Trump — who had made saving the coal industry a signature campaign promise — directed Energy Secretary Rick Perry to “prepare immediate steps to stop the loss” of fuel-secure generators facing retirement. (See Trump Orders Coal, Nuke Bailout, Citing National Security.)
“It was not focused on coal or nuclear,” Walker said. “It was a recognition that there has been a significant change in the portfolio of generation throughout the United States … most notably a significant reliance on natural gas pipelines for electric generation.”
Talking to reporters after his speech, Walker elaborated. “The fact is, the words in the pre-decisional memo were ‘all fuel secure generation.’ Everybody misinterpreted the words for whatever political reasons they chose to,” he said. “There’s liquid natural gas that can have on-site fuel. There’s biomass conversion that has on-[site] fuel. … Pump storage, that’s fuel-secure generation. Hydro, that’s fuel-secure generation.”
Chatterjee in a Rush
The normally gregarious Chatterjee rushed with aides to an awaiting SUV immediately after his remarks from the podium, declining to take questions from the committee and refusing to talk with reporters.
Asked how the apparent failure of the Trump/Perry plan would affect FERC’s work, Chatterjee said, “We’ve got our resilience docket open.
“We’ll continue to work on it,” he said, getting into the car. FERC opened the resilience docket in January after rejecting DOE’s earlier bid to help coal and nuclear plants. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Was the demise of the DOE plan disappointing to him? “I didn’t even know what they were considering,” Chatterjee said.
McIntyre’s Future
Chatterjee’s haste may have had less to do with the coal and nuclear plan than with rumors that FERC Chairman Kevin McIntyre, who has been battling a brain tumor, may announce his resignation. Chatterjee — who had reportedly visited the White House on Oct. 16 — declined to respond to reporters’ questions about McIntyre’s status and whether he would resume as acting chairman.
McIntyre did not attend the commission’s open meeting Thursday, the second he has missed since a fall that left him visibly uncomfortable at the meeting in July. (See Ailing McIntyre Absent from FERC Open Meeting.)
Chatterjee noted McIntyre’s absence as he opened Thursday’s meeting, saying “My prayers are with him and his family.”
“I’m very sorry Chairman McIntyre is not able to be here today, and I continue to send warm wishes to him for his recovery,” Commissioner Cheryl LaFleur said.
In March, McIntyre issued a statement saying he had undergone “successful surgery” for a “relatively small” brain tumor that was discovered in summer 2017. He said he did not intend to provide further details or updates for privacy reasons.
At the July meeting, he wore a sling after disclosing he had injured his arm and suffered compression fractures in two of his vertebrae in a fall. (See “McIntyre Toughs it out,” FERC Says Farewell to Powelson.)
Although he was not present for the September meeting, McIntyre participated in its votes; he was not recorded as voting on Thursday.
Sources have told RTO Insider that the chairman is often absent from FERC headquarters and that meetings with him have been frequently rescheduled as a result. Spokeswoman Mary O’Driscoll last month declined to answer questions on the subject.
Chief of Staff Anthony Pugliese told reporters after Thursday’s meeting that the chairman would issue a statement on his status within a few days.
With the resignation of Republican Commissioner Robert Powelson in August, the commission is now split 2-2 between Republicans and Democrats. Earlier this month, President Trump nominated the Department of Energy’s Bernard McNamee as Powelson’s replacement. (See Trump Nominates DOE’s McNamee to FERC.)
Perry: Out of Our Hands
DOE’s Walker, who heads the Office of Electricity, did not explicitly confirm the numerous news reports that the White House had rejected DOE’s proposal following opposition from the National Security Council and National Economic Council. Perry told reporters in September that DOE had finished its resilience proposal and was awaiting a White House decision.
The memo outlined “one of the many possible solutions,” Walker said. “We are focused on national security. We will continue to look at what are the things that best support the infrastructure that’s needed under national security.”
ISO-NE staff made few changes to the Regional System Plan in October, although nearly $30 million were cut from the estimate for the Greater Hartford project in Connecticut by revising a 3.7-mile all-underground 115-kV line to a hybrid overhead/underground line, Director of Transmission Planning Brent Oberlin told the Planning Advisory Committee in an update Wednesday.
The RTO reported a $12 million increase in the estimated cost for the Southeast Massachusetts/Rhode Island Reliability Project, reducing the total for all projects in the plan by $18 million since the last update in June to an aggregated estimate of $1.589 billion, Oberlin said.
Investment of New England transmission reliability projects by status through 2022. | ISO-NE
The cost estimate increased because of two new projects: the West Medway 345-kV circuit breaker upgrades and Medway 115-kV circuit breaker replacements.
Twelve upgrades on the project list have been placed in service since the June 2018 update: four in southwest Connecticut; three around Hartford; and in Massachusetts, a partial rebuild of the 1779 line, a double-circuit tower separation in the Greater Boston area, a reconductor/upgrade on the 112 line, and refurbishment of the Sandy Pond Substation, along with a control house rebuild.
Three new asset condition projects are the Canal Station Project and Robinson Avenue Station Upgrades in Massachusetts, and the Railroad Corridor Transmission Line Asset Condition Upgrades in Connecticut.
Avangrid’s railroad project is the most expensive of the three at $376.3 million, “where they’re essentially getting off the catenary structures that run along the Metro North railroad corridor and moving onto separate poles,” Oberlin said.
Eversource 115-kV Structure Replacements
John Case of Eversource Energy reported the utility’s work replacing aging transmission towers in Connecticut, Massachusetts and New Hampshire.
The utility is replacing 1,585 structures, or about a third of the 4,400 structures inspected, Case said. Eversource maintains more than 20,000 115-kV structures, about two-thirds of them made of wood.
Connecticut accounts for 63%, or $245.4 million, of the $387.6 million total to be spent on the 2018/19 replacements, which cover about 10% of Eversource’s 115-kV infrastructure in the region.
The utility inspects mainly with foot patrols by experienced linemen and high-resolution aerial surveys from helicopters, but a new drone program started last year should be able to survey the whole system within three years, Case said.
Eversource manages approximately 4,000 circuit miles of overhead lines, including around 3,400 structure miles, or nearly 40% of all transmission in New England. The difference between circuit miles and structure miles arises because some structures carry multiple lines, Case said. Their working number is approximately 10 structures to the mile.
Asked whether the spate of storms last March indicated a cost savings to be achieved by putting lines underground, Case said “overheading continues to be an economical and reliable solution to most of our requirements.”
Eastern Interconnection Planning Collaborative on Track
Richard V. Kowalski, ISO-NE system planning technical director, reported that transmission planning in the Eastern Interconnection is well-coordinated among its planning authorities, ensuring NERC reliability requirements are met, according to a report released earlier this month by the Eastern Interconnection Planning Collaborative (EIPC). (See EIPC Finds Eastern Tx Planning Working Well.)
Entities currently participating in EIPC represent approximately 95% of the Eastern Interconnection load. The biggest nonparticipants are Ontario and the Maritimes provinces in Canada.
EIPC has completed an Eastern Interconnection frequency response analysis to support NERC concerns regarding the changing resource mix. ERCOT is already facing operational issues associated with the trend toward an increasing share of renewable resources generating power, he said.
Kowalski explained that one of the bigger concerns with the change in inertial behavior associated with renewable resource technologies is the increased risk of under-frequency load shedding when it shouldn’t happen.
EIPC members share costs on a net energy per load basis, and ISO-NE is not even 5% of the interconnection in terms of net energy per load, Kowalski said.
“ISO-NE’s share this year would have been around $40,000, but we’ve been so far under budget that it should be less,” he said. The only EIPC staff is a consultant serving as executive director.
FERC last week said that it will not delay its decision to shut down a Michigan hydropower dam over safety violations.
The commission ruled there was no reason to grant a stay of its order to revoke the license of the 4.8-MW Edenville Dam in northern Michigan, saying it only allows such a delay in cases of “irreparable injury” to the petitioner (P-10808-062). In this case, the commission said it found no harm other than economic loss.
FERC ordered the dam shut down in February, citing concern over a failure of owner Boyce Hydro to increase the dam’s spillway capacity. (See Michigan Dam Ordered Shut over Safety Breaches.)
Edenville Dam spillway
Boyce filed for a stay last month, along with the Sanford Lake Preservation Association, the Wixom Lake Association and the Gladwin County Board of District Commissioners, who wanted to take over dam operations. The D.C. Circuit Court of Appeals on Sept. 25 denied Boyce’s motion to stay the revocation order.
In its ruling Thursday, FERC reiterated the dam’s 14-year history of noncompliance and safety violations.
“In multiple orders, the commission has set forth a history, going back to 2004, of Boyce Hydro’s failure to comply with its license, the commission’s regulations and commission orders,” FERC wrote. “The commission’s primary concern has been Boyce Hydro’s ‘longstanding failure to address the project’s inadequate spillway capacity.’ Nevertheless, 14 years after acquiring the license for the project, the licensee has still not increased the project’s spillway capacity. The licensee has shown a pattern of delay and indifference to the potential consequences of this failure, which the commission has found must be remedied in order to protect life, limb and property.”
FERC also said it was not swayed by the argument by the lake associations and county commissioners that it would be costly and difficult to acquire a new license for the dam.
“Whether Boyce Hydro and the lake associations will reach agreement regarding the sale of the project works is speculative; these entities have not suggested that such a transaction has gone beyond the exploratory stages,” FERC said.
The shutdown is ultimately in the public interest, FERC said, observing that even the temporary state of the dam during spillway renovations would place the public at further risk: “Boyce Hydro … notes that to repair the spillways will require the installation of a cofferdam for four to six months, which will reduce the spillway capacity by approximately 50%, increasing the potential for overtopping of the dam.”
FERC last week reduced the return on equity adders previously granted to ITC Holdings subsidiaries for being independent, standalone transmission providers, saying a 2016 merger affected the parent company’s autonomy.
The commission’s Thursday order said International Transmission Co., ITC Midwest and Michigan Electric Transmission Co. were no longer fully independent because ITC Holdings merged with Canadian and Singaporean companies in 2016. FERC reduced their “transco” adders to 25 basis points each effective April 20, 2018 (EL18-140).
| ITC
FERC had granted ITC and METC 100-basis-point adders in 2003 and 2005, respectively, and ITC Midwest a 50-point adder in 2015.
But in 2016, Canada-based Fortis purchased 80.1% of ITC Holdings, while Singapore government-owned investment company GIC Private Limited acquired 19.9%. As a result, FERC now says the ITC subsidiaries are indirectly owned by two entities “with affiliates that participate in Eastern Interconnection energy and capacity markets.”
Tangled Associations
Several utilities had joined the complaint against ITC’s transco adders, including Consumers Energy, Interstate Power and Light, Midwest Municipal Transmission Group, Missouri River Energy Services, Southern Minnesota Municipal Power Agency and WPPI Energy. The complainants said the change in ownership meant ITC’s companies no longer have the full independence necessary to collect the approximately $24 million in annual revenues from the adders.
The utilities pointed out that Fortis subsidiary FortisOntario uses parts of the grid affected by the loop flow around Lake Erie that is managed by phase angle regulators owned and operated by the ITC companies. Another Fortis subsidiary, Central Hudson Gas and Electric, “generates, purchases and sells electricity over the Eastern Interconnection grid, in portions of New York state that can also be affected by the operation and planning of the ITC companies’ MISO-area facilities,” they noted.
They also said GIC subsidiary Epsom Investment indirectly owns 44.4% of Duquesne Light Co. and Duquesne Power, which sells retail electricity and markets power within PJM. Another GIC subsidiary, Camborne Investment, owns a “substantial minority stake” of four generators owned by Eastern Generation. The companies also said a Wisconsin Public Service Commission proceeding shows that “senior executives of the ITC subsidiaries, FortisOntario, Central Hudson, and other Fortis operating subsidiaries meet regularly, outside the Open Access Same-time Information System transparency contemplated by Order No. 889, to ‘collaborate on initiatives that are of interest and benefit to the regulated utility subsidiaries.’”
Finally, the complainants argued that “equity infusions from Fortis to ITC Holdings or dividends from ITC Holdings to Fortis may cause generation and transmission investments to compete for capital” and that ITC’s proposed 2,000-MW Big Chino Valley pumped storage hydroelectric facility in Arizona is evidence that the company is interested in pursuing investments outside of transmission.
ITC Holdings had argued there was “no credible argument” that Fortis, GIC or their affiliates are market participants in MISO and therefore could not affect its independence. The company also contended that FERC analyzes market participation for transco adders on an RTO basis, not an interconnection-wide basis, and pointed to NextEra Energy owning more than 38 GW of generation in the Eastern Interconnection. It also said it continues to be governed by an independent board of directors and is party to a shareholders’ agreement with Fortis that restricts ITC equity securities holders from MISO market participation.
The company said “nothing has changed in ITC Holdings’ planning of, investment in or operation of its transmission systems under the ownership of Fortis and GIC.”
But FERC said ITC’s merger “has reduced, but not eliminated, the ITC companies’ independence from market participants.” The commission relied on criteria in its Order 679 to scrutinize ITC’s independence and examined investment planning, capital formation, investment processes and business structure. In several areas, FERC found ITC still demonstrated “some level” of independence.
“We acknowledge certain minor potential conflicts of interest associated with other assets owned by Fortis and GIC may exist. However, such concerns are largely attenuated by the location of such assets and the fact that they are largely subject to small ownership shares by Fortis and GIC. Moreover, ITC’s and MISO’s actions have indirect and limited effects on their other affiliates or subsidiaries,” FERC said.
The commission said a 25-basis-point adder “appropriately encourages the transco business model in these circumstances and promotes corresponding consumer benefits.”
Commissioner Richard Glick dissented, saying the ITC companies are no longer sufficiently independent to justify any ROE adder.
“Fortis, which owns 80% of the ITC companies, assesses capital expenditures on a consolidated basis, meaning that in evaluating how to allocate capital among its subsidiaries, it is directly comparing investments in transmission with investments in other aspects of its business,” Glick wrote. “Even though the ITC companies are permitted to develop their own capital and business plans, Fortis and GIC retain ultimate authority with respect to those plans.”
ITC Reaction
An ITC spokesperson said the company was disappointed in FERC’s “failure to fully recognize our independence” and is reviewing its options, including rehearing and appeal.
“While the order acknowledges value in our business model, the commission found ITC to be less independent post Fortis ownership,” the spokesperson said in an email to RTO Insider.
ITC also recognized the issue could spark a review of transmission incentives.
The “order was characterized as a compromise solution, and several of the commissioners spoke to the need for a broad review of all transmission incentives. Such a review will provide an opportunity for a more expansive review of this and other transmission incentives offered under FERC’s policy statement,” the spokesperson said. “ITC will advocate that any change to current policy should take into consideration previously approved incentives, which were relied upon by developers to construct facilities that provide ongoing benefits to customers.”
FERC on Wednesday approved National Grid’s request to add liquefaction facilities at its 600,000-barrel Fields Point LNG storage facility in Providence, R.I.
Customers currently truck LNG to the Fields Point facility for storage, with National Grid redelivering gas via truck or through use of Narragansett Electric’s distribution pipelines and Algonquin Gas Transmission’s interstate pipeline. “The proposed project would effectively reverse this flow by enabling Algonquin to transport gas that Narragansett Electric would deliver to Fields Point to be liquefied and stored,” the commission said (CP16-121).
Fields Point LNG | National Grid
National Grid said it proposed the liquefaction facilities at the request of Narragansett and a second customer, Boston Gas, which were seeking to diversify their supply sources. It will have a capacity of 20 MMcfd.
Narragansett will provide a dedicated 13-MW, 34.5-kV electric service to power the facility.
Opponents of the project disputed the need for it, saying gas trucked to Fields Point have met peak day demands. But the commission said it was persuaded by storage customers’ complaints that they have had trouble obtaining enough LNG supplies.
Commissioners Cheryl LaFleur and Richard Glick joined in the approval but wrote a concurring statement to reiterate their position that the environmental review of such projects should include greenhouse gas emissions.
“We agree with today’s finding that the liquefaction facility will not have a significant effect on the environment, particularly given the limited GHG emissions associated with the project,” they wrote. “However, we disagree with the language in the environmental assessment that dismisses the social cost of carbon as a useful tool to inform the environmental review, stating the social cost of carbon method ‘cannot meaningfully inform the commission’s decision whether and how to authorize a proposed project under the [Natural Gas Act].’ We believe the social cost of carbon provides a meaningful and informative approach for an agency to consider how its actions contribute to the harm caused by climate change.”
The ERCOT Technical Advisory Committee canceled its Oct. 24 meeting, citing a lack of items to be considered this month. It’s the fourth TAC meeting to be canceled this year, and the third in five months.
ERCOT has distributed its membership applications and agreements for 2019, recommending that entities interested in joining the grid operator do so well in advance of Nov. 9 to avoid potential processing delays.
Applicants may join as a corporate, associate or adjunct members. Corporate membership includes the right to vote on general membership matters, such as election of certain board members, election of TAC representatives and members of TAC subcommittees, and amendments to the Certificate of Formation and bylaws.
Market participants are not required to be members.
Membership terms are for no more than a year and do not renew automatically. Dues are required at the time of application; applicants can request waivers for good cause.
Confirmation of board members and TAC representatives for 2019 will take place at the annual membership meeting Dec. 11.
More Information and copies of ERCOT’s bylaws and Articles of Incorporation can be found on the grid operator’s website.
