The leaders of two key Maine legislative committees told Massachusetts regulators Friday that they oppose a proposed transmission project that would cross Maine to deliver a large amount of Canadian hydropower to Massachusetts.
In a letter to the Massachusetts Department of Public Utilities, the chairmen of Maine’s joint Environment and Natural Resources Committee and Energy, Utilities and Technology Committee objected to Central Maine Power’s (CMP) New England Clean Energy Connect (NECEC) project on economic and environmental grounds.
The Avangrid subsidiary is set to sign a contract this month with Massachusetts for the state’s 9.45-TWh clean energy solicitation, which was awarded to NECEC — a partnership between CMP and Hydro-Quebec — after the original winner, Eversource Energy’s Northern Pass project, was rejected by siting officials in New Hampshire. (See Mass. Picks Avangrid Project as Northern Pass Backup.)
The Maine lawmakers wrote that recent expert testimony to their state’s Public Utilities Commission “indicates that Hydro-Quebec will not produce any additional hydroelectricity for NECEC and will instead divert power it now sells to other markets, such as Ontario and New York, to Massachusetts. In fact, NECEC may result in increased greenhouse gas emissions if markets like Ontario or New York have to use dirty fuel mixes to replace the lost electricity from Hydro-Quebec.”
The lawmakers also faulted NECEC for planning to build its line across the Kennebec Gorge, a “world renowned” whitewater rafting and fishing area.
New England Clean Energy Connect (NECEC) shown in orange | Central Maine Power
“It has not proposed burying any portion of the 53 miles of new transmission line, even at this iconic spot that is critical for Maine’s tourism economy,” said Republican Sens. Tom Saviello and David Woodsome, and Democratic Reps. Ralph Tucker and Seth Berry.
AC Better than DC
Among those testifying to the Maine PUC on April 30 was Stephen Whitley, former NYISO CEO and ISO-NE COO, who appeared on behalf of NextEra Energy Resources.
Whitley said that, unlike other proposed HVDC transmission lines in the region, CMP’s project is completely overhead, and that it would be much more useful to build an AC line “that can be looped, serve load and interconnect other renewable generators.” A DC line would not support interconnecting multiple generators located at different points of interconnection along its route, he said.
In addition, Whitley said, NECEC is not traditional utility transmission, but a merchant project dependent on the market. If contracted by Massachusetts, it will execute only a 15- to 20-year power purchase agreement with the electric distribution companies for a DC transmission line that has at least a 40-year life.
“Thus, even if one accepts the purported needs and benefits CMP attributes to the transmission line for Maine and Massachusetts, there is a cliff on those needs and benefits once the PPA expires,” Whitley said.
Fair and Equal
The Maine lawmakers also faulted CMP for offering “far less to Maine than Eversource offered New Hampshire during the Northern Pass process.”
Maine State House
New Hampshire would have received more than $210 million in benefits from Northern Pass, they said, while the TDI New England Clean Power “project would have resulted in direct payments of $372 million to Vermont for clean water, habitat conservation and clean energy development. CMP has not offered comparable mitigation for Maine.”
They cited other testimony before the PUC that the NECEC project “will suppress existing and future renewable energy generation in Maine due in part to increased congestion on the transmission system.”
The lawmakers concluded: “We are unwilling to sacrifice future development of Maine’s solar and offshore wind industries, which would provide real greenhouse gas benefits and more jobs for Maine citizens, just to provide Hydro-Quebec the ability to market its electricity in Massachusetts.”
Hydro-Quebec partnered separately with Eversource, Avangrid and TDI-NE on three different transmission projects for the MA 83D clean energy solicitation last summer.
California could return to the conditions preceding the energy crisis of the early 2000s if the transition to fragmented decision-making and electricity procurement is not managed correctly, the Public Utilities Commission said in a report issued last week.
The report on California retail electricity choice, entitled “An Evaluation of Regulatory Framework Options for an Evolving Electricity Market,” is meant to guide the discussion as the CPUC, state lawmakers and other entities work to manage the disaggregation of energy procurement from traditional utilities to an environment with much more residential rooftop solar, community choice aggregators (CCAs) and private electricity sellers through the state’s Direct Access program, which allows nonresidential customers to purchase directly from a competitive supplier.
According to the paper, decision-making around reliability, affordability and safety is splintering from central authorities such as the CPUC to multiple entities.
“In the last deregulation, we had a plan, however flawed,” the report says. “Now, we are deregulating electric markets through dozens of different decisions and legislative actions, but we do not have a plan. If we are not careful, we can drift into another crisis.”
The paper examines how electric delivery can remain reliable as the market fragments, particularly from the growth of CCAs. It expresses concerns about reliability, affordability and ability to decarbonize the electric system if the transition is not managed effectively.
| California PUC
During the energy crisis, market design flaws, insufficient monitoring and “gaming” by market participants caused price spikes, collapse of competitive suppliers and rolling outages. The state became the model for how not to manage electricity restructuring and received much attention, particularly regarding the artificial shortages created by the Enron energy trading firm.
Splintering Model
The current model was developed after the crisis, with load-serving entities required to demonstrate each year that they have contracted for adequate energy supply. The paper poses the question of whether there needs to be a single entity responsible for policymaking, implementation and enforcement.
It also explores how new technologies could be financed, how to reduce the use of fossil fuels such as natural gas and how to properly compensate utilities. It also asks whether there should be a state entity to manage “behind-the-meter” generation and other entities that are not under the jurisdiction of the CPUC, as well as evaluating other regulatory models that evolved in New York, Illinois, Texas and Great Britain.
“I think there are solutions to a lot of the potential problems, although there is not a single or a dominant design to target them,” CPUC President Michael Picker told RTO Insider last week. He added that some customer choice models are built around a particular technology such as rooftop solar, battery storage, demand response or natural gas fuel cells that can be obtained through small generator incentive programs.
“We have to do something to address the disaggregation of supply and the splintering of decision-making,” Picker said. About 13% of load across the state is provided through the Direct Access program to commercial and industrial customers.
It’s not the CPUC’s job to get in the way of CCA growth, Picker said, but “we do have to do something to respond to the growing disaggregation.”
CCAs Respond
The CPUC got pushback from CCAs in February when it approved an order implementing a registration process for them along with other changes to the regulatory structure. (See CCAs Oppose CPUC Decision, Process.)
In a statement Thursday, the California Community Choice Association said the CPUC report “wrongly asserts today’s energy system lacks regulation and adequate planning.”
“Highly regulated locally controlled CCAs were designed to help correct the problems from the energy crisis, and they are performing as intended — delivering reliable, affordable and clean energy to local customers, while exceeding the state’s [greenhouse gas] goals,” Executive Director Beth Vaughan said. “It is important to recognize in this report that other states use energy-choice program models that differ widely from those used by CCAs in California.” She said CCAs are committed to “reliability, affordability, decarbonization and social equity.”
The CPUC said the report is not meant to advocate specific policy actions but seeks instead to “jumpstart a conversation.” Comments on the report are due on June 4, which can be filed at customerchoice@cpuc.ca.gov, and the commission has also set up a webpage for the initiative.
NRG Energy is transforming itself by “right-sizing” its generation fleet, reducing costs and expanding its retail business, the company’s chief executive said during an earnings call Thursday.
NRG earned $233 million in the first quarter, compared with a loss of $169 million in the same period last year.
CEO Mauricio Gutierrez said the improved results were driven by $80 million in cost savings and higher energy prices caused by cold weather in Texas and the Northeast.
NRG continued to reduce its generation fleet last quarter, closing on the $42 million sale of its 154-MW Buckthorn Solar project to NRG Yield. The company also announced the sale of its Canal 3 peaking plant in Sandwich, Mass., for approximately $130 million, with the deal expected to close in the third quarter. It expects to close $3 billion in asset sales this year.
NRG last quarter also spent $210 million acquiring supplier XOOM Energy, expanding the company’s retail sales capabilities and presence in the East.
Texas Shines
While the company has in recent years highlighted the significant risk of retirements and the slowdown in new builds in ERCOT given persistently low power prices, Gutierrez pointed out the situation is showing signs of reversal.
“Last year, we finally saw the retirement of about 4,200 MW of uneconomic coal generation, which tightened reserve margins,” Gutierrez said. “As a result, we are entering this summer with the lowest reserve margin on record at around 10%. Prices have responded accordingly with summer on-peak prices currently trading at about $150/MWh.”
NRG Headquarters in Princeton, NJ. | NRG
Asked whether he expects Texas to see an increase in either new gas-fired generation or more utility-scale solar coming online in response to the high peak prices, Gutierrez said one season does not mean much when deciding on a 25-year investment.
“So far, what we have seen is only the expectation on one summer of high prices,” Gutierrez said, adding that in an energy-only market such as ERCOT, “price is everything,” providing the “right signal and incentive” for developers to invest capital in the market. “So, you need to see two things: You need to see them high enough and you need to see them long enough to attract this capital investment.”
PJM Capacity Auction
Gutierrez also highlighted the PJM capacity auction for planning year 2021/22 being held this month, with results scheduled to be posted May 23.
“Last auction saw a slowdown in new builds and over 7 GW of announced retirements added to the PJM deactivation list this year,” he said. “But there is still uncertainty on how these will play out in terms of market tightening. As you are aware, some generators are seeking compensation for plants that are not needed for reliability and not economically viable.
“While some entities are grasping a bailout in the short run, we see capacity rationalization as a necessary first step towards a healthy market,” Gutierrez said. “And we are confident that there will be continued support for the competitive market value proposition. Beyond PJM, our risk portfolio is well-positioned given our fuel diversity and location near load pockets.”
Gutierrez referred to the “uncertain” effect of “all these out-of-market conversations that are happening today.”
But, he said, “I am encouraged by seeing FERC and the different ISOs take a very specific stance in terms of the protection of competitive markets and making sure that they don’t negatively impact those markets.”
Consolidated Edison’s first-quarter earnings jumped more than 10% on an increased rate base and a weather-related boost in steam revenues, but the company noted Thursday that it faces regulatory scrutiny for its role in subway power outages, its tax accounting and its storm response preparedness.
The company earned $428 million in the first quarter, compared with $388 million in the same period a year ago.
“While we continue to face challenging weather events, we remain focused on our long-term strategy of providing customers with the technology and options they need to live and work today,” CEO John McAvoy said in a statement accompanying Con Ed’s May 3 earnings release.
Regulatory Update
A company presentation pointed out that, in a proceeding investigating a New York City subway power outage last April, the New York Public Service Commission last year issued orders requiring Consolidated Edison Company of New York (CECONY) to upgrade the electrical equipment that serves the subway system. The utility plans to complete the required actions this year.
The PSC in January also initiated an audit of the income tax accounting of certain state utilities, including CECONY and sister utility Orange and Rockland Utilities (O&R), which serves customers in southeastern New York and northern New Jersey (18-M-0013).
ConEd plant on the East River at 15th Street in New York City
Con Ed noted that two storms in March damaged its utilities’ electric distribution systems, interrupting service to approximately 209,000 CECONY customers, 93,000 O&R customers and 44,000 Rockland Electric customers. Con Ed said the recovery of $106 million in storm-related costs is subject to review by the PSC and the New Jersey Board of Public Utilities, both of which are investigating utilities preparation and response to the storms, and may penalize them.
O&R last month updated its January rate filing with New York PSC, asking to increase its electric rates from $20.3 million to $22.5 million.
Tax Cuts and Rates
Con Ed expects the federal Tax Cuts and Jobs Act of 2017 to result in customer rates likely being reduced to reflect the reduction in the corporate tax rate from 35% to 21%, elimination of bonus depreciation and the amortization of excess deferred federal income taxes the utilities collected from their customers that will not need to be paid.
The PSC opened a proceeding on the new law (17-M-0815), and commission staff on March 29 recommended that most utilities be required to begin to credit their customers’ bills with the net benefits of the tax cuts on Oct. 1.
The company expects a commission decision after the 90-day comment period expires in late June.
Coal plant retirements have not caused a shortage of black start resources, but grid operators should consider expanded testing, FERC and NERC said last week.
NERC, its eight Regional Entities and the commission released a study May 2 based on information from a representative sample of nine volunteer registered entities, a follow-up to a 2016 joint report. (See Utilities’ Restoration Plans Pass FERC, NERC Review.)
“Although some participants have experienced a decrease in the availability of black start resources due to retirement of black start-capable units over the past decade, the joint study team found that the participants have verified they currently have sufficient black start resources in their system restoration plans, as well as comprehensive strategies for mitigating against loss of any additional black start resources going forward,” the new report says. “The joint study team also found that participants that have performed expanded testing of black start capability, including testing energization of the next-start generating unit, gained valuable knowledge that was used to modify, update and improve their system restoration plans.”
A next-start unit is the first generator in the cranking path to be energized using power from the black start generator.
The report recommends that:
The report emphasized that its recommendations — while “appropriate for all registered entities responsible for system restoration” — are voluntary and “not subject to mandatory compliance with the recommendations, separate and apart from any obligations of mandatory reliability standards.”
The report also noted “beneficial practices” used by some that may not be universally appropriate. “The joint study team recommends that registered entities consider incorporating these practices, or variations thereof, as appropriate,” it said.
FERC on Friday approved the dissolution of the SPP Regional Entity (RE) and the transfer of its members to the Midwest Reliability Organization and SERC Reliability Corp., ending a reliability oversight role that had been a source of concern at the commission and NERC (RR18-3).
The commission found that a proposal submitted by NERC, MRO and SERC in March “reflects the transfers of registered entities will ‘promote effective and administration of bulk power system reliability’” in accordance with the Federal Power Act.
The order terminates the amended and revised delegation agreement between NERC and SPP, effective Aug. 31, and revises the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints. The transfer is effective July 1.
FERC said it was “satisfied” that the petitioners and SPP “have considered and established mechanisms to mitigate against the risk of material gaps in oversight of compliance and enforcement activities due to the transfer of registered entities.”
Most of the RE’s 122 registered entities have been reassigned to the MRO, with the remainder joining SERC. NERC will assume the compliance monitoring and enforcement of the SPP RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.
SPP was appointed by NERC as an RE in 2007. The RTO said last July it had reached an agreement to dissolve the RE, citing a mismatch between the RE’s footprint and SPP’s. FERC and NERC had both expressed concerns that SPP failed to ensure the RE’s independence from the RTO.
NERC, MRO and SERC filed the joint petition with FERC in March.
The RE said it will address transitional and wind-down costs using its approved 2018 statutory assessment funding. Any funds left over will be transferred to MRO and SERC, allocated according to the transferred load-serving entities’ relative net energy for load.
Preliminary results from a biennial NYISO study show high congestion in three areas of the New York bulk power system, mainly in the eastern part of the state, ISO officials said Tuesday.
The 2017 Congestion Assessment and Resource Integration Study (CARIS) found congestion on the Central East interface, through the line eastward to Albany, and from the capital down the Hudson River Valley toward New York City.
“These are not necessarily surprising, being consistent with what we’ve seen in past studies,” said Timothy Duffy, the ISO’s manager of economic planning. “We also did find one interesting piece, which was a small line, referred to as Edic-Marcy, which we have found in the past year or so to have some significant contribution to congestion on the system.”
The Edic-Marcy line is located in the central part of the state.
Location of congested transmission | NYISO
The CARIS process requires planners to identify the top congestion elements on the system. “That’s obviously a key indicator of where developers ought to be thinking in terms of building additional transmission to provide value in terms of reduced congestion,” Duffy said.
The ISO’s Tariff calls for the CARIS to identify four solutions for each case study. Planners start with a generic solution such as transmission, demand response, energy efficiency and generation, then model those solutions and develop specific costs associated with them, calculating high-level cost-effectiveness tests and benefit-to-cost ratios.
The only benefit the CARIS process factors into its benefit-to-cost calculation is a reduction in statewide system production costs. While the study reports other benefits such as reductions in emissions, capacity market payments and consumer energy payments, it does not reflect them in the benefit-to-cost ratios.
“In terms of Phase I, there’s a whole host of data that’s presented,” Duffy said. “We look at historic, we look at its projected congestion on the system, we identify what the key drivers are, and we look at a number of different scenarios in terms of gas prices; for example, other load forecasts, other big macro changes on the system and how they affect system congestion.”
Six Studies
The ISO studied the three congested areas under six scenarios:
Study 1: Central East-Edic-Marcy
Study 2: Central East
Study 3: Central East- New Scotland- Pleasant Valley
Study 4: Study 3 with Edic- Marcy relaxed
Study 5: Study 3 under the System Resource Shift Case
Study 6: Study 5 with Edic-Marcy relaxed
Planners began with a “business as usual” (BAU) case consistent with past practices. In most such cases, the ISO is very constrained in terms of what it can model and assume, so the BAU results are of limited value, Duffy said.
A second set of results is more forward-looking, the product of the ISO “taking a step further, beyond the confines of the Tariff, in terms of the minimal amount of work required by the tariff,” Duffy said. “We created this system resource shift case, which essentially allowed us to use our judgment to identify a set of assumptions so that the results of the study would provide additional meaning.”
In including the system resource shift case, Studies 5 and 6 differed from the first four by modeling the Indian Point nuclear plant and all New York coal units as retired by 2020/21. In addition, the studies forecast that the state would meet its Clean Energy Standard 2030 goal of 50% renewable resources by 2026.
The study’s model included 4.6 GW of onshore wind, 10.8 GW of utility-scale solar and 250 MW of offshore wind in service by 2026, annually producing 28.5 TWh of renewable energy. ISO planners supplemented this with annual energy reductions of 10.5 TWh from energy efficiency.
| NYISO
Phase II of the CARIS process invites developers to propose specific transmission projects to address congestion on the system. The ISO will perform a benefit-to-cost analysis for each proposed transmission project to assess eligibility for regulated cost recovery.
While estimates of production cost savings will still dictate project eligibility, Phase 2 will examine zonal locational-based marginal pricing (LBMP) load savings to identify beneficiaries and determine cost allocation. The LBMP value used is net of transmission congestion contract (TCC) revenues and bilateral contracts.
To qualify for cost recovery under the ISO’s Tariff, a transmission project must have a capital cost of at least $25 million, benefits that outweigh costs over the first 10 years of operation and received approval to proceed from 80% or more of the actual votes cast by beneficiaries on a weighted basis.
Having met these conditions, the developer must also file with FERC for approval of the project costs and rate treatment.
Public Policy Tx
Switching gears from discussion about the CARIS process, Zach Smith, NYISO vice president for system and resource planning, said the ISO’s planning process has three core pieces: reliability, economic and public policy.
Among the steps taken so far on the public policy front, the ISO “last year selected the Western New York Public Policy Transmission project, and we’re currently going through stakeholder discussions on the AC transmission public policy, and we anticipate a selection of those projects in July this year,” Smith said. (See MC Approves Western New York Tx Proposal; NYISO Management Committee Briefs: Sept. 27, 2017.)
The proposed AC projects include the $1 billion Edic-Pleasant Valley 345-kV line and the $246 million Oakdale-Fraser 345-kV line, which are intended to relieve downstate congestion by upgrading the AC transmission systems north and west of New York City. (See Downstate NY to Pay 90% of AC Tx Projects.)
Smith highlighted one change in the ISO’s planning process, noting that under FERC Order 1000, “an interregional transmission project can be proposed under any of our planning processes.”
An interregional project is one physically located in two regions, such as transmission that ties PJM to New York.
“That project could then get a joint cost allocation, where customers within the PJM system might bear some costs, and New York might bear some cost,” Smith said. “To date we have not had an interregional project, but there is that potential there.”
New York faces increasing penetration of intermittent distributed energy resources, declining load, all-time low energy prices and the need to replace aging generation as the state moves toward achieving its Clean Energy Standard goal of producing 50% of its electricity from renewables by 2030, according to a NYISO report.
“Compared to other regions in the U.S., New York enjoys a fairly diverse fuel mix, but we’ve identified a real disparity between the upstate and downstate regions … with upstate [being] where just about all the hydro and renewable resources are located,” NYISO Executive Vice President Richard Dewey said Thursday while presenting Power Trends 2018, an annual report covering how technology, economics and public policy are influencing the state’s wholesale electricity markets.
| NYISO
The state’s imbalance of renewable energy supplies means the downstate region (consisting of the Hudson River Valley and New York City area) will become increasingly reliant on natural gas-fired generation, the report said.
Low Capacity Factors
The operational challenge for the ISO is to keep the lights on 100% of the time when the capacity factors for onshore wind and solar are just 26% and 14%, respectively — compared to 89% for nuclear, Dewey said.
| NYISO
“We need to think about having the right type of generation capacity available so that we can meet the load requirement at the grid and provide the right kind of incentives so that generators are available,” he said.
Offshore wind differs from onshore in that it gives higher output during the daytime hours, which is more consistent with New York’s load profile. Offshore wind also operates at a higher capacity factor, sometimes in the 40% range or higher, Dewey said, adding that the ISO is modeling how that higher capacity factor might affect grid and market operations.
Offshore wind also has the added advantage of being located closer to demand centers in Long Island and New York City, he said.
According to data compiled from the Danish Energy Agency and Denmark’s state-owned utility, the Anholt 1 wind farm, which only opened in 2013, reached an average capacity factor of 53.7% for the full year 2017.
Asked whether New York could expect such higher capacity from its offshore installations, Dewey said, “A lot of that depends on the local environmental studies. I can’t comment on the wind currents off Long Island as opposed to what the Danish have experienced, but I will say that technology is continuing to work to our advantage where some of the newer turbines are both in terms of the height, turbine design and some of the technology around how they place and manage them. Increasingly, the industry is learning lessons from some of the existing installations.”
Low Market Prices
Dewey noted the impact that historically low wholesale electricity prices — largely correlated to falling natural gas costs — are having on the state’s generating fleet.
“When you talk about wholesale markets that really are at the all-time lows, this is great for consumers, from the standpoint of energy prices, but it creates some concerns when you start thinking about the viability of the generation fleet and the willingness of suppliers to make investments to some of those assets,” he said. “We really need to think about the revenue adequacy of some of those plants to the extent that natural gas prices are projected to be at or near these levels for the foreseeable future.”
Changing Demand
New York’s electricity demand experienced steady growth for many decades, but it has now flattened out and in many respects is starting to decline, Dewey said.
Energy usage is expected to decline over the next decade at a rate of 0.14% per year, and peak demand — a critical element to reliable system planning — is expected to fall by 0.13% per year through 2028, the report said.
| NYISO
“Increasingly our demand is impacted by the weather,” said Dewey. “We’re a summer peaking system that relies heavily on the load of air conditioning in the summer, and when we have a cool summer like we had last year, that has significant impacts on the overall consumption.”
The proliferation of rooftop solar and demand response is flattening that load, resulting in “substantive impacts on our planning and our markets,” he said.
“The impact solar has on energy demand is actually quite a bit different than the impact it has on the peak,” Dewey said.
Solar production fades just at 4 to 5 p.m., when the electric system is hitting its peak, “so what we end up getting is high ramp periods in the afternoon when we’ve got to get response from our suppliers to meet that high electric peak when the solar production is dropping off,” Dewey said.
The ISO expects the problem to grow as solar installations increase and extend throughout the state, he said. In addition, energy efficiency efforts continue to displace the amount of energy supplied by the grid, with the New York State Energy Research and Development Authority last month outlining plans to accelerate the state’s energy efficiency goal by 40%. (See NY Sets 40% Hike in EE Goal.)
“DERs hold tremendous value in that, if sited properly, they could address some of the resiliency issues at both the retail and the wholesale level, and provide a whole lot of options for both distribution companies and grid operators, but [they] do add a whole lot of complexity to the grid,” Dewey said.
As a wholesale market administrator, NYISO is working with the state and utilities to come up with market incentives to appropriately price the resilience attributes DERs bring to distribution companies and ensure those costs are incurred by the retail system. And to the extent that DERs provide value to the wholesale market, the ISO will make sure those revenues are appropriately allocated, he said.
The report notes that over the past year, the ISO has received proposals to connect more than 400 MW of battery storage to the grid.
SPP’s Seams Steering Committee on Wednesday endorsed a staff-proposed Tariff change that would grant some transmission customers a four-hour exception from taking SPP transmission service in the case of an unplanned transmission outage that leaves them reliant on the RTO’s system.
The proposal encountered minor turbulence from members who wanted an exception exceeding four hours. It eventually passed by an 8-3 margin, with Kansas City Power & Light and Sunflower Electric Power abstaining.
| ACES
Staff drafted the proposal to address the committee’s concerns about the current requirement that transmission customers along the SPP seams obtain service from the RTO during an unplanned outage, even if the customer may not normally be required to take the service. Customers that do not prearrange for the service from SPP are charged for unreserved use, and the Tariff does not currently allow the RTO to waive those charges even when a customer unknowingly takes transmission service immediately after an outage.
The proposed change would allow SPP to waive the unreserved use charges during the first four hours of an unplanned outage. Staff said the revision will avoid burdening customers with having to arrange for transmission service during the initial moments of an unplanned outage, while still allowing transmission owners to be compensated.
Staff will now take the proposed change through SPP’s revision-request process. The Regional Tariff Working Group will be responsible for the measure’s progress.
MISO M2M Payments to SPP Exceed $50M
MISO’s market-to-market (M2M) payments to SPP surpassed $50 million in March when the Midwest RTO incurred $3.4 million in charges, increasing its total to $51.4 million since the two neighbors began the process in March 2015.
It was the eighth straight month and 16th of the last 18 that MISO has paid SPP.
| SPP
SPP’s Nashua-Hawthorn and Riverton-Neosho-Blackberry flowgates — in Kansas and Missouri, respectively — were once again the main culprits, binding for a combined 267 hours and racking up $2.2 million in charges. The flowgates have accounted for more than $32 million in M2M payments to SPP, with the Riverton-Neosho-Blackberry flowgate responsible for $26.5 million.
A shadow-price override was put in place in early April to mitigate that flowgate’s power swings.
SPP, MISO Evaluating Feedback on Joint Studies
SPP and MISO staff are evaluating feedback gathered from their members on how best to improve their interregional planning process. Staff recommendations based on the feedback will be shared with members in May and June, before any tariff changes or joint operating agreement revisions are made.
The RTOs agreed in February to develop a new process for their coordinated system plan. SPP and MISO have conducted two joint studies, but have yet to approve any joint projects. (See MISO, SPP Look to Ease Interregional Project Criteria.)
WASHINGTON — FERC Commissioner Robert Powelson on Wednesday reiterated his defense of organized markets but said he sees an “erosion of confidence” in RTO stakeholder processes.
Powelson, who made the observation in a speech at a PJM issues workshop sponsored by the Great Plains Institute and Duke University’s Nicholas Institute for Environmental Policy Solutions, elaborated afterward in an interview with reporters.
He cited concerns over escalating transmission rates and PJM’s February “jump ball” filing of two competing proposals for insulating its capacity market from state-subsidized generation. (See PJM Board Punts Capacity Market Proposals to FERC.)
“You talk to certain state commissioners; you talk to consumer advocates; there’s a concern that voices are not being heard,” he said. “I think PJM — [CEO] Andy [Ott] has heard me say this — has to do a better job with their state outreach. … A lot of states right now are not happy.”
Illinois Commerce Commissioner John Rosales, and Pennsylvania Public Utility Commission Vice Chairman Andrew Place, who also spoke at the workshop, agreed with Powelson’s characterization. “PJM is swimming and drowning in capacity. … And capacity repricing only worsens that,” Place said.
PJM spokeswoman Susan Buehler said Powelson’s “concern about our stakeholder process … is valid and has been recently discussed with members.”
Regarding complaints about the “jump ball” filing, Buehler said: “PJM believes this is a policy question and that FERC should make policy calls. Based on the recent New England ruling, it appears evident that commissioners are divided.” (See Split FERC Approves ISO-NE CASPR Plan.)
‘Awkward Position’
Powelson said PJM’s decision to file both the two-tier capacity repricing proposal RTO staff prefer and the Independent Market Monitor’s proposal to extend the minimum offer price rule (MOPR) to all units indefinitely “puts us in an awkward position.”
The former Pennsylvania regulator contrasted the filing with the RTO’s Capacity Performance proposal, which was supported by his state as a response to the 22% generator forced outage rate during the 2014 polar vortex. “I want to see more of that synchronization as these constructs come down [to FERC]. It makes the commission’s job a lot easier if there’s those kind of alignments.
“It’s hard to build consensus, and that’s a concern too,” he added. “I don’t know how to change that, but I’d like to see us at least look at it more.”
Adam Keech, PJM executive director of market operations, who spoke after Powelson, also addressed his comments.
“I think the stakeholder process is a great process for getting feedback and vetting proposals and understanding the interests,” Keech said. But he acknowledged the RTO has difficulty advancing “big ticket items” and navigating some “larger issues.”
“And so, are there are ways we can make the process more efficient? I’m sure there are, but there’s value to the process nonetheless. … We need to not throw the baby out with the bath water,” he said.
The challenge of reaching stakeholder consensus was highlighted in a May 2017 paper on PJM’s governance by Christina Simeone, director of policy and external affairs at the University of Pennsylvania’s Kleinman Center for Energy Policy.
“For these high controversy issues, it seems the stakeholder process is falling short at exactly the time when stakeholder collaboration and joint problem solving is critical to informing profound questions about market design and the future of competitive markets,” Simeone wrote.
`Very Disappointing’
Rosales, who is president of the Organization of PJM States Inc. (OPSI), said he agreed that state regulators don’t feel PJM is sufficiently responsive. “Absolutely. 100%. Unqualified yes,” said Rosales, who called PJM’s jump ball filing “very disappointing.”
“We were very clear,” he told RTO Insider in a brief interview. “We thought that the status quo was better than these two really poor options that they put to be filed at FERC.”
Rosales elaborated in a panel of state regulators. PJM is “trying to resolve an issue that hasn’t become an issue yet. It’s a solution to a problem that we don’t have.”
OPSI sent the PJM Board of Managers a letter in February urging it to take no action on any repricing proposal, saying that if the RTO thought rule changes are necessary, “it should reinitiate a more holistic stakeholder process.” The organization said it was not convinced that state policies undermine the RTO’s markets and that PJM’s proposal does not respect state jurisdiction and may raise capacity prices.
But Rosales said OPSI’s concerns have gone unheeded and that PJM has recently adopted a practice of effectively covering its ears and saying, “We hear you.”
“It becomes very frustrating for us because they’ll say they listen, they’ll tell us about the stakeholder process, they’ll tell us everything that they’ve done … and then they’ll just throw it out the door and say, ‘We’re going to go with this anyway.’”
OPSI is not a PJM member, so it has no means of trying to change the stakeholder process at FERC. “We as a group have decided not to be stakeholders,” Rosales said. “We try to have a relationship with PJM … [and] play nice in the sandbox. … But for the most part they’ve not had an open dialogue. … They listen, but the changes aren’t there.”
Monitor Contract
Rosales also cited the renewal of PJM’s contract with its Monitor, Monitoring Analytics. The IMM’s current contract expires in December 2019. “We have problems with getting the Market Monitor contract — again. They seem to be going not the right way,” he told RTO Insider. He did not elaborate on his concerns, which he repeated on the panel.
Monitoring Analytics President Joe Bowring, a Ph.D. economist, has served as PJM’s Monitor since 1999. In 2013, the PJM board came under fire over its proposed request for proposals for monitoring services, which OPSI and other critics said contained language that would undermine the independence and quality of the monitoring function. The board dropped the proposal and signed a contract renewal with Monitoring Analytics later that year. (See Board, OPSI Bury the Hatchet over Monitor Contract.)
OPSI Executive Director Gregory Carmean did not respond to a request for comment Wednesday on the current contract negotiations. Bowring declined to comment in detail but said he was confident in reaching agreement with the RTO.
PJM’s Buehler acknowledged PJM has received questions from OPSI about the contract negotiations. “PJM believes the discussions are productive and ongoing and we are frankly confused by any other characterization,” she said.
Not Just PJM
Powelson said his concerns over the stakeholder process are not limited to PJM, saying all RTO/ISO boards should operate under term limits and ensure diversity among their members. “I’m looking at this … from general business practices as a regulator overseeing those boards and what these RTOs do; making sure they’re synchronizing with what’s going on in the corporate world.
“In my view, you can’t have enough transparency in this [stakeholder] process,” he continued. “We’re making all these changes. People should have the ability to see it, understand it and feel comfortable with the final outcome.”
Powelson also commented on PJM’s initiative, announced Monday, to seek a market-based response to potential fuel security concerns. (See PJM Seeks to Have Market Value Fuel Security.)
Based on “the briefing I received from Andy Ott and his team, I think [PJM] is exactly where we need to be,” he said.
Powelson said “people should not read into” PJM’s announcement that it will end up paying coal and nuclear operators to provide backup for gas-fired generators subject to fuel delivery interruptions. “I think what PJM is saying is ‘we’re going to look at it and we’re going to do it in a market-based approach.’ There might be other technologies out there that have the same [fuel security] characteristics. It could be an oxidized fuel cell. It could be storage. It’s going to be a level playing field discussion. … It’s going to be done in a fuel-neutral, technology-neutral way.”
Powelson said it would be a mistake for the Trump administration to use the 68-year-old Defense Production Act to keep financially struggling coal and nuclear power plants operating, as is being considered, according to published reports. The act was used by President Harry Truman to control steel prices during the Korean War.
“I think it would lead to the unwinding of competitive markets in this country,” Powelson said. “It would be the wrong direction for us to venture down.”
