NEW YORK — Scott Weiner, the New York Public Service Commission’s deputy for markets and innovation, discussed the state’s Reforming the Energy Vision initiative.
“REV distinguishes itself not by its specific proposals but by its comprehensiveness. If you take a look at the specific components of REV, most, if not all, are being tested or applied somewhere else in North America. What we’ve tried to do is pull them all together at one time in a holistically, comprehensively approach to reform.”
Kerry Stroup, manager of state legislative and regulatory affairs for PJM, discussed the challenges of introducing any systemwide programs to the RTO, which operates in 13 states and D.C.
“Innovation is something that happens in a different way in a multi-jurisdictional entity like PJM as opposed to a single unit like New York or Ontario. … PJM is a market maker and doesn’t implement policy. So that can be a challenge at times because those state retail regulatory frameworks range from vertically integrated utilities to hybrid models to entire fully restructured retail markets.”
Peter Fraser, vice president of industry operations and performance for the Ontario Energy Board, said previous market models are inadequate to address customer preferences for cleaner energy and the increased integration of newer technologies.
“We’re changing the way electricity is priced to consumers in a number of ways, with residential rates going to a fixed monthly charge for their electric distribution rates. [We’re] studying reforms to nonresidential rates, and we issued a discussion paper this spring that recognizes the changes that are ongoing in the electric distribution market.”
Aleck Dadson, vice president of consultant StrategyCorp and former COO of the Ontario Energy Board, said the board embarked on a redesign of its market in advance of REV that was influenced by regulatory changes in Europe, particularly the U.K. It included a wide deployment of smart meters and increased renewable energy penetration.
“There is a really strong emphasis on performance measurement. We established scorecards that are customer-focused, with customer service metrics, operational effectiveness, safety, reliability, public policy responsiveness,” he said. “And the board every year publishes a scorecard to compare the distribution companies, to see who’s doing well and who isn’t.”
FERC on Friday approved an amendment to SPP’s bylaws clarifying that the RTO should not credit assessments for transmission service over and above the amount of members’ monthly administrative fee.
But the commission said the RTO improperly clawed back overpayments last year based on its reinterpretation of its bylaws before the rules were officially changed, ordering the RTO to pay $1.6 million in refunds (ER16-829).
SPP collects its administrative costs through a monthly assessment applied to load eligible to take network service under its Tariff (Schedule 1-A fees). Members receive a credit against the monthly assessment for fees paid for serving their load with network or point-to-point transmission service.
Between 2003 and 2015, the RTO had been making credits that sometimes exceeded the 1-A fees, with the RTO providing credits against other portions of the customers’ transmission settlement statements. The excessive credits resulted in a 1% undercollection of its administrative fees annually, forcing SPP to charge a higher administrative rate in the subsequent years.
In March 2015, SPP staff reinterpreted its bylaws and capped the credits. In December, the Board of Directors approved a revision of section 8.4 of the bylaws to clarify the new practice.
FERC approved the new crediting policy effective March 30, 2016, but denied SPP’s request for a waiver allowing the RTO to apply it retroactively.
As a result, the commission ordered SPP to provide refunds within 30 days for credits it denied last year under its new interpretation. The ruling was a victory for 13 SPP members who received credits in excess of their monthly assessments during 2014. Two members who filed protests, Kansas City Power and Light and Nebraska Public Power District, will receive the majority of the refunds, a combined $1.2 million as of December.
DETROIT — Four industry executives and a state regulator shared their views on distributed generation, resource adequacy and aging infrastructure during a stakeholder panel at the MISO Annual Meeting last week.
Robert Gee, of Gee Strategies Group, moderated.
Melody Birmingham-Byrd of Duke Energy Indiana called distributed energy resources an “inevitability” and said her company is embracing the change with “heavy involvement” in research and projects.
However, she said designing a DER rate structure remains a concern. “We want to make sure those who can afford distributed resources aren’t doing it on the backs of those that can’t,” she said.
Teresa Mogensen, senior vice president of transmission at Xcel Energy, said the grid “is a long, long way from being dead” and will continue to play a role even with greater use of distributed generation.
“We do have customers that have disconnected from the grid, and if they’ve done that, more power to them,” said DTE Electric President and COO Trevor Lauer. He said his company will be aided in its transition to DER by new, younger workers: DTE Energy will turn over 50% of its workforce over the next seven years, he said.
Jennifer Vosburg, senior vice president of NRG Energy’s Gulf Coast region, said customers “aren’t waiting around: The utility of the future is here. Our concern is, can the markets keep up, can the regulation keep up, can it be integrated into the market system?”
Michigan Public Service Commission Chairman Sally Talberg said she didn’t know how soon distributed resources would permeate the grid. “I have a National Geographic from 1983 that says solar is the way of the future,” she joked.
Resource Adequacy Concerns
All of the speakers expressed concerns over MISO’s ability to attract new generation to replace retiring plants.
“Right now, it’s hard to see how an independent power producer [without] a power purchase agreement could build new generation,” Lauer said.
Vosburg said MISO hasn’t implemented anything to “trigger new investment.”
The panel also addressed the growth of natural gas and its history of price volatility.
“Who would have thought seven years ago that there would be such a fundamental change in electric generation with fracking and natural gas use?” Lauer said. “I think price volatility is going to be there, but I think the larger concern is infrastructure and gas storage.”
Talberg agreed and said pumping gas through pipelines in Michigan can be “high-risk” since some pipelines are “vintage.”
The panel generally agreed that the Clean Power Plan stay isn’t going to slow progress on emission reductions.
“Our concern is the rate and pace of carbon emission [reductions], not that we’re going down that path,” Birmingham-Byrd said. “What Duke Energy is trying to do while [we] retire coal plants is to have a more diverse generation portfolio.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
PJM Manuals (9:10-10:00)
Members will be asked to endorse the following manual changes:
Manual 7: Protection Standards. Clarifications were recommended by the Relay Subcommittee as part of its biennial review of the manual.
Manual 10: Pre-Scheduling Operations. Changes make clear that reporting rules for all outages apply to both capacity and energy resources.
Manual 14B: PJM Region Transmission Planning Process. Updates light load and winter peak reliability analyses to align with current practices, among other updates.
Manual 15: Cost Development Guidelines. Clarifications are the result of a periodic review. Adds Tariff-approved language regarding pumped storage hydro units.
Manual 18: PJM Capacity Market. Changes are the result of a periodic review; conforming changes relate to Capacity Performance and the “deploy all resources” action.
The committee will be asked to endorse changes to make the parameter-limited schedule exception process more flexible. (See “More Flexible Parameter Limited Exception Process Approved,” PJM Market Implementation Committee Briefs.)
Members will be asked to elect Gary Greiner of Public Service Enterprise Group as a Transmission Owner sector representative. He will take the place of PSEG’s Frank Czigler, who has left the company.
AUSTIN, Texas — To address the Defense Department’s frustrations over Texas’ lack of regulation for siting new generation, the governor’s office is working with ERCOT to require notifying the department of proposed projects that might impact military operations.
DeAnn Walker, a senior policy adviser in Gov. Greg Abbott’s administration, told a Gulf Coast Power Association luncheon audience that she’s been working on the issue for nine months. Military issues are a top priority for Abbott, she said.
The Pentagon’s main concerns have been wind turbines disrupting radar signals and solar panels causing glare for pilots. Used to working with states who have control over siting facilities, military officials have been frustrated with Texas’ system, which lacks any state-level oversight. “The military claimed there were times when the first time they knew about a wind turbine farm going up near their facility was when they started seeing the turbines built,” she said.
Walker said concerns have been raised over projects planned around naval air stations in Corpus Christi and Kingsville. She knew of only one generation project canceled because of a conflict with military operations.
Walker worked with ERCOT to develop PGRR 47, which was presented in May. The change to ERCOT’s Planning Guide would require developers seeking interconnection approval to report on the status of reviews by the Pentagon and the Federal Aviation Administration.
A luncheon attendee pointed out that the military already receives notification about projects from FAA, which can occur much sooner than the interconnection application.
In exchange for its cooperation, the state has asked the Defense Department to provide color-coded maps that show where developers might run afoul of military siting restrictions, Walker said. The maps would be of all military operating areas in the state and be marked green (where there are no restrictions), yellow (where they could work together toward a solution) and red (where the military would oppose any development). Another attendee said the maps already exist on FAA’s website.
Walker said Abbott is adamant about winning approval of the change and asked that anyone with concerns address them with her directly.
Although the lack of siting regulation has caused tensions in Texas, the Defense Department has worked cooperatively with the power industry, becoming early advocates of renewables and microgrids.
At a FERC technical conference on reliability earlier this month, Chris Murray of the Navy’s Renewable Energy Program Office invited transmission and generation projects onto naval facilities. “If there is land on our base that you think makes sense, let us know. And more often than not, that land is going to be behind a secure perimeter with guards, which also can be good for a critical asset,” he said.
DETROIT — MISO expects the use of technologies such as energy storage, synchrophasors and HVDC lines to increase, Executive Vice President of Transmission and Technology Clair Moeller told the Board of Directors at its System Planning Committee meeting last week.
“As we do modeling into the out years … we see a substantial shift in the footprint away from coal — and that’s expected. But how the rest of the mix [develops] plays an important role,” Moeller said. “It’s a pretty interesting time in terms of how the portfolio might shift.”
Synchrophasors, which provide real-time transmission data, can answer whether “you can safely take the system to its physical limits to completely squeeze all you can out of the grid.” Moeller said. “This is the electric system’s introduction into big data.”
“How much [capacity] is in [the transmission system]? Because you know it’s there,” board member Paul Bonavia said. “This is a lot of food for thought.”
Board member Michael Evans asked if MISO could commission a technology company “that’s already slogging through the big data” to analyze the RTO’s information.
HVDC
MISO has found that DC transmission, which is ideal for transporting large amounts of power over long distances, only becomes as cost effective as AC for lines longer than 600 miles.
Moeller said DC technology could connect MISO resources to ERCOT and the Western Interconnection.
“If there are technologies available to us to move power from Denver to Des Moines, direct current is the way to go,” he said.
Clean Line Energy is MISO’s largest DC merchant, with three interconnection projects in the queue: the Grain Belt Express (which could carry 4,000 MW of wind power from western Kansas to Missouri, Illinois and Indiana), the Rock Island line (3,500 MW of capacity from northwest Iowa to Illinois) and the Plains & Eastern line (4,000 MW of capacity from the Oklahoma Panhandle to Tennessee and Arkansas). The Plains & Eastern project faces opposition from Arkansas’ congressional delegation. (See House Panel OKs Bill Targeting Clean Line Project.) MISO has just three DC lines to date: one in Manitoba and two transferring power from North Dakota into Minnesota.
“They’re substantially faster and more flexible,” Moeller said.
Storage
MISO’s treatment of battery storage as generation will have to change, Moeller said. It cannot be “force fitted” into a generation market definition, he said.
Although energy storage is evolving rapidly, and utilities are beginning to experiment with it, it is not yet competitive in MISO, Moeller said. He said there is no an independent source that has identified when storage will become economically viable.
Moeller also said MISO believes storage’s competitiveness has been hurt by the low cost of gas. While storage technology becomes cheaper and MISO shifts from its dependence on coal, Moeller said the RTO has discussed strategies to more precisely model price volatility, including securing grants for Ph.D.s in university mathematics departments for a more complex algorithm for gas prices and renewables. MISO currently uses U.S. Department of Energy data and simple inflation to forecast gas prices.
MISO Vice President of System Planning and Seams Coordination Jennifer Curran said the RTO expects installed gas capacity to increase in the near future, with 2,700 MW of gas-fired generation projects in advanced stages of study in the generator interconnection queue.
By 2030, MISO expects gas penetration to reach 35%, almost equal to coal’s current 36% share.
MISO said the substantial shifts in generation mix is justification for the RTO to begin making its own independent load forecasts.
Two generation owners on Friday petitioned FERC to block New England states’ efforts to have electric ratepayers underwrite the cost of expanded natural gas pipelines (EL16-93).
NextEra Energy and Public Service Enterprise Group said the proposals by state regulators to release natural gas capacity to electric distribution companies “will render ISO-NE markets unjust, unreasonable and unduly discriminatory, and result in manipulation of the ISO-NE market.”
The generators asked FERC to rule by Aug. 23 and order ISO-NE to draft a “prophylactic tariff fix” within 90 days. They also seek a technical conference and “final” FERC order by the end of January 2017, before the next Forward Capacity Auction in February.
“State regulators in Massachusetts, New Hampshire, Connecticut and Rhode Island are on the verge of implementing a scheme expressly intended to artificially suppress prices in wholesale energy markets in New England,” the companies wrote.
“Having no use for the pipeline capacity, the EDCs would release the capacity at below-market rates — first to gas-fired generators … and then whatever is left will be released to the marketplace,” the complaint continued. “This transportation subsidy would artificially flood ISO-NE markets with gas, thereby unreasonably suppressing gas prices and wholesale power prices.”
The proposal by the EDCs, endorsed in varying stages in proceedings by state regulators, would allow the distributors to recover from their ratepayers the cost of access to expanded pipelines.
EDCs Eversource Energy and National Grid favored the capacity release proposal at a FERC technical conference held last month. (See Utilities Seek OK for Gas Releases to Generators at Technical Conference.) The two are partners in the proposed Access Northeast pipeline at the center of the dispute. It would bring shale gas from the Marcellus region of Pennsylvania into New York and New England.
The Massachusetts Department of Public Utilities, which is the furthest along among the regulators, has ruled such a contract is legal under state law. It is considering a proposal for a 20-year gas supply contract that could be approved as early as October. (See More Pipelines for New England: ‘Gold-plating’ or Necessity?)
Massachusetts Attorney General Maura Healey has supported a lawsuit filed by ENGIE and the Conservation Law Foundation that challenged the legality of such contracts. A ruling by the state’s Supreme Judicial Court is expected soon.
Another proposed pipeline that could have benefited from ratepayer subsidies, Kinder Morgan’s Northeast Energy Direct, was scuttled earlier this year, in part because of the lack of commitments for firm capacity customers. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)
PJM is opening its second competitive project proposal window of the year this week.
Its scope consists of a year 2021 analysis of N-1 and N-1-1 thermal and voltage contingencies; generation deliverability and common mode outages; and load deliverability thermal and voltage.
The window will be open 30 calendar days, PJM said. Those offering proposals during that time will be permitted 15 additional days to submit detailed greenfield reports.
This is the second window for which a new proposal fee will apply for upgrades and greenfield projects. There is no fee for proposed projects costing less than $20 million. A $5,000 fee will be assessed for projects of up to $100 million. Proposals with a projected cost of more than $100 million must be accompanied by a $30,000 fee.
Details on registering were presented at the January Planning Committee meeting.
SPP said last week it is seeking industry experts to serve on a second independent panel to review Order 1000 transmission proposals in 2017.
The panel will review and score proposals for competitive projects approved for construction by SPP’s Board of Directors. The RTO’s first independent expert panel earlier this year awarded a 22.6-mile transmission project to Mid-Kansas Electric. (See SPP Awards First Order 1000 Project — But it May Not be Needed.)
“We are proud of our initial [industry expert panel] process, having now seen it all the way through for the first time,” said Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel. He said the process will be refined based on lessons learned and stakeholder feedback.
SPP said interested candidates must have expertise in at least one of five areas “as it relates to electric transmission”: engineering design, project management and construction, operations, rate design and analysis, and finance.
Applications will be accepted through Sept. 1. Panelists will be selected based on a recommendation by the RTO’s Oversight Committee and approved by the board later this year. Those serving on the panel will be considered contractors and will be compensated through a monthly retainer and hourly rate.
More information on the panel’s application process can be found here.
DETROIT — MISO and its Independent Market Monitor have reconciled their differences and reached a compromise on a redesign of the capacity auction, CEO John Bear told stakeholders at the RTO’s Annual Meeting last week.
Bear made his remarks at Wednesday’s Advisory Committee meeting, which was originally planned to feature a presentation on the new competitive retail solution (CRS), a proposal to create a separate, three-year forward auction for retail-choice areas in the RTO’s footprint.
The delay gives MISO officials and the Monitor, which have disagreed on core aspects of the CRS, more time to work on their “hybrid” proposal. (See MISO: Auction Design July Filing Doubtful.)
Bear refused to give any details on the compromise, saying he preferred discussion to take place at the next Resource Adequacy Subcommittee meeting June 29-30, when the proposal will be officially unveiled. He also said further discussion would take place at a meeting in mid-July.
“If we need more time, we’ll take it. We’re not going to release something that’s half-baked,” Bear said.
MISO stakeholders, however, predicted a tough road to implementation regardless of what is released. Resource Adequacy Subcommittee Chair Gary Mathis told the board that “there’s a very big rift between those that think we shouldn’t be doing this, if ever,” and those in favor of varied approaches to redesigning the auction.
“It makes it hard to work through those issues,” Mathis said. He said he anticipates a “big stress level from stakeholders” as they sift through the revised proposal.
Board member Baljit Dail asked if it would be stalled to the point where it would still be under development in a year.
“No, I think we’ll have a big discussion, and then FERC will have to sort it out just like MISO has had to sort it out,” replied Mathis, who predicted challenges to whatever the RTO files.
Despite the predicted challenges in FERC, MISO board members put pressure on stakeholders to come up with a solution as quickly as possible. Board member Judy Walsh said she hoped MISO would come up with a filing in “some sort of short timeline.”
“The search for absolute consensus is going to lead us to endless delay,” board member Paul Bonavia agreed.
However, Kevin Murray, of the End-Use Customers sector, said any attempt from MISO to implement a hybrid solution in time for the 2017/18 planning year would be too hurried and “circumvent stakeholder process.”
Board Troubled by Forecast Generation Shortfall
At the Board of Directors meeting Thursday, board members said they were troubled by the possible generation shortfall in 2018, as predicted in this year’s MISO-Organization of MISO States Survey. (See OMS-MISO Survey: Generation Shortfall Possible.)
MISO Executive Vice President of Transmission and Technology Clair Moeller told the board that a redesigned capacity auction that sends better price signals could curb the rate of retirements.
“That’s why we continue to push the competitive retail solution and be aggressive, to solve this decline [in generation] before it becomes a reliability problem,” Moeller said.
OMS President Sally Talberg urged implementation of the CRS in time for the 2017/18 planning year.
In the survey, MISO identified 2.5 GW worth of planned retirements and 1.8 GW worth of potential closures in 2017.
Board member Michael Evans asked Moeller if he could provide reassurance that adequate reliability exists in the near future.
“We don’t anticipate significant problems in the local area as long as there is sufficient transfer capability. I am cautiously optimistic that things will be OK,” Moeller said. “In the construction world, we’d say that we used up all our ‘float.’ So we need to get to work, but there’s enough time.”
Evans also asked how many coal and nuclear plants that recently threatened to retire have actually filed for retirement study requests.
MISO legal counsel Stephen Kozey answered that the RTO could provide the total capacity that has filed for retirement but couldn’t name the individual plants.
“It is true that not everything [mentioned] in the press has gone through a [retirement study] request,” Kozey said.
“We may end up with a retirement queue,” Moeller added.
“It might be worthwhile to start doing some intensive ‘what-if’ studies,” Evans said.
Dail asked if the 800-MW increase in forced outages predicted in the survey would be a continuing trend. Moeller said the higher outage rates are the result of using coal plants for short cycles, for which they weren’t designed.
“Not to be an alarmist, but this makes me a bit uneasy,” board member Thomas Rainwater said.
The board then asked if MISO could simply deny generator suspensions and retirements.
“We have the ability to call resources back to maintain local reliability but not to protect resource adequacy,” Moeller answered. He said a market mechanism needs to be created to keep generators online for the sake of resource adequacy.
“So if you need them a day later, you can keep them. If you need them three years from now, you can’t keep them?” Walsh asked.
NextEra Energy and Public Service Enterprise Group said the proposals by state regulators to release natural gas capacity to electric distribution companies “will render ISO-NE markets unjust, unreasonable and unduly discriminatory, and result in manipulation of the ISO-NE market.”
