PJM confirmed last week that it will seek to move the deadline for submitting day-ahead offers up 90 minutes, from noon to 10:30 a.m. ET.
Adam Keech, director of wholesale market operations, told the Operating Committee that the RTO will post day-ahead results as soon as they are complete — but no sooner than 12:30 p.m. — up from the current 4 p.m. The reliability assessment and commitment (RAC) run rebid window will be open until 2:15 p.m., up from the current 6 p.m.
Keech said PJM will seek to complete the RAC run assignments before the 3 p.m. deadline for the second intraday gas nomination cycle.
“We’re going to commit as much as we can by 3 p.m., recognizing that if system conditions change we’re going to need to make supplemental commitments,” Keech said.
The RTO’s explanation last week clarified the changes it outlined to the Markets and Reliability Committee on June 25. PJM officials acknowledged the lack of consensus among stakeholders on the changes but said they were necessitated by the Federal Energy Regulatory Commission’s April order moving the timely nomination cycle deadline for gas to 2 p.m. ET from 12:30 p.m. and adding a third intraday nomination cycle. (See PJM Moving on Day-Ahead Schedule Changes.)
Keech said PJM officials are considering changes to their algorithms as well as faster computer servers as a way to meet their goal of reducing the market-clearing time to three hours from four. He said FERC’s requirement that the RTO allow hourly pricing updates means it will have to process more data during the clearing process. (See “PJM Won’t Be Ready for Flexible Generator Offers by November” in PJM Markets and Reliability Committee Briefs.)
PJM told FERC in a report last week that it will implement hourly offers by Nov. 1, following consultations with stakeholders (EL15-73).
Uncertainty over renewable tax credits and competition from low-priced natural gas may be discouraging some wind power investors — but not SunEdison’s TerraForm Power.
Established by SunEdison to own and operate its solar farms, TerraForm has since expanded its focus to wind and other clean-power assets, seeking long-term contracts that generate steady revenues for additional investments.
In the year since its July 2014 initial public offering, TerraForm has added 2 GW of wind assets to its portfolio. Last week, TerraForm made its biggest splash yet, joining with SunEdison to acquire a 930-MW energy portfolio for $2 billion from Invenergy Wind.
Just the week before, TerraForm and SunEdison announced they had finalized the acquisition of another 521-MW portfolio of operating wind farms in Idaho and Oklahoma from Atlantic Power. In January, the two companies closed a similar 521-MW package of wind and solar assets from First Wind Holdings.
The Deal
TerraForm said it intends to acquire net ownership of 460 MW of Invenergy’s wind plants, with the remaining 470 MW to be acquired by a “warehouse” facility, a financing mechanism that will be sponsored by SunEdison and third-party equity investors.
The initial acquisition includes the 187-MW Rattlesnake farm in Texas, the 196-MW California Ridge project in Illinois and the 78-MW Raleigh wind farm in Ontario. The warehouse facility includes the three Prairie Breeze wind farms totaling 279 MW in Nebraska and the 190-MW Bishop Hill, Ill., facility.
The deal is expected to close in the fourth quarter, subject to the approval of the Federal Energy Regulatory Commission and the Public Utility Commission of Texas.
Bucking a Trend
The companies are upping their stake in wind at a time in which other developers have scaled back.
Second-quarter investments in U.S. wind projects were $9.4 billion, down 4% from the first quarter and 21% from 2014’s second quarter, according to the American Wind Energy Association. Bloomberg New Energy Finance reported that global clean energy investment dropped 28% in the second quarter versus a year earlier. The U.S. entered 2015 with 65.9 GW of installed wind, AWEA says.
Yieldco Strategy
TerraForm is seeking value by “aggregat[ing] a highly fragmented industry,” CEO Carlos Domenech said.
The company’s strategy is based on the use of “yieldcos,” an increasingly popular method of holding renewable energy assets. Yieldcos allow developers to raise capital at lower costs by selling — or dropping — completed projects to the yieldco and using the proceeds to fund new projects.
“The thinking with warehouse assets is that as you drop or acquire assets into the warehouse, you’ll be tranching those assets,” SunEdison CFO Brian Wuebbels explained in a conference call last week. “Equity investors, debt investors, us … we all want to know the quality of the assets we’re putting into the warehouse. Getting an investor to put down $2 billion into an empty warehouse without having an idea of the particular asset’s performance would be creating [higher] costs. … By having definitive, high-quality assets, we can drive down the cost of capital.”
The assets being acquired from Invenergy have a weighted average remaining contract life of 19 years.
UBS Securities noted only 93 MW will be under construction upon the deal’s close, easing concerns about developmental risk. The deal also diversifies the portfolio of SunEdison, the world’s largest renewable energy development company.
Invenergy
For Invenergy, a privately held company, the sale will provide capital to invest in more projects, CEO Michael Polsky told Bloomberg. “It’s a new phenomenon. It’s helped to proliferate renewable energy.”
SunEdison’s TerraForm Power is acquiring 930 MW of wind capacity from Invenergy, including the Prairie Breeze (top) and under-construction Prairie Breeze II farms (bottom), both in Nebraska.
Domenech said he expects that TerraForm’s “ongoing partnership” with Invenergy will result in additional acquisitions in the future.
Invenergy bills itself as North America’s largest independent wind power generation company, with 51 wind farms in the U.S., Canada and Europe totaling more than 4.4 GW.
The company, which is selling 10% of its total contracted portfolio to TerraForm, will retain a 9.9% stake in the U.S. assets being sold, providing operation and maintenance services for the facilities.
Cash Flow
TerraForm and SunEdison say the assets they are purchasing should generate average unlevered cash available for distribution (CAFD) of $141 million annually over the next 10 years, a levered cash-on-cash return of about 8.4%.
Private equity investors have expressed “a lot of interest in the warehouse,” Wuebbels said.
In announcing the deal, TerraForm raised its 2016 dividend target 26% to $1.70/share from $1.53 and projected a 20% compound annual growth rate from its current first-quarter dividend “driven by the increased visibility and growth provided by this transaction.”
Market Reaction
Shares in both SunEdison and TerraForm stock rose following the sale announcement Monday, with TerraForm shares up 4.4% for the week.
Travis Hoium, a columnist for The Motley Fool, was less impressed, warning that yieldcos’ appeal could fade if they turn out to be based on overly aggressive assumptions.
“Adding $141 million in cash available for distribution may sound like a lot, but the $2 billion price tag is steep for that kind of return. Remember that the cash flow from projects has to cover the depreciating value of a wind turbine over time as well as pay for debt that will be used to acquire the assets, so the return for shareholders may not be as attractive as it seems. … Unless TerraForm Power can re-up contracts for equal or greater electricity prices well beyond the current contracts, the company may not even earn its cost of capital back.”
Seven projects proposed by transmission developers for the mid-Hudson region have cleared an initial screening by the staff of the New York Public Service Commission.
Those projects scored well enough on staff’s efficiency and environmental ratings to warrant further study, according to an interim report filed on July 6 (12-T-502, et al).
The PSC has sought to jump-start transmission development in the counties north of New York City to alleviate congestion and deliver power from underutilized upstate generation resources to the higher demand areas of the state. (See Tx Plan to Open NY Choke Points Without New ROWs.)
The staff scored 21 proposed projects from four developers. Incumbent transmission owners that formed New York Transco — Central Hudson Gas & Electric, Consolidated Edison, New York Power Authority, New York State Electric & Gas, Niagara Mohawk Power, Orange and Rockland Utilities and Rochester Gas & Electric — have four projects on the list. NextEra Energy Transmission New York has one project and Boundless Energy NE has two.
One developer, North American Transmission Corp., did not receive any favorable recommendations.
“These remaining scenarios are the most promising from an electric system benefit perspective and are significantly more environmentally compatible primarily because they are all designed to use existing rights-of-way,” the report said.
One late development will further impact the proposals. Competitive Power Ventures said on June 12 that it has closed financing for its proposed 720-MW combined-cycle plant in Orange County. Because CPV had not been included in the commission’s original analysis, staff will need to remodel power flows.
“The study is also to include an analysis of alternatives to a transmission facility and to address the issue of whether there is sufficient public need for a transmission facility as a matter of public policy,” the report said.
Federal regulators ordered a Florida energy trader to pay $15 million in penalties and repay almost $1.3 million in profits for making riskless up-to-congestion trades in PJM to cash in on line-loss rebates.
The Federal Energy Regulatory Commission imposed the penalty July 2 against City Power Marketing, of Fort Lauderdale, Fla., and its founder K. Stephen Tsingas (IN15-5), ruling that they were guilty of market manipulation and making false and misleading statements to commission investigators.
The commission ordered City Power to pay $14 million and Tsingas to pay $1 million in civil penalties and disgorgement of $1,278,358 in unjust profits, plus interest.
Chairman Norman Bay, who headed the Office of Enforcement during the City Power investigation, did not participate in the order.
The commission said City Power cashed in on line-loss rebates — or marginal loss surplus allocations (MLSA) — through three types of UTC transactions: “round-trip” trades that canceled each other out; trades between import and export pricing points of the same PJM interface with equivalent prices (SOUTHIMP-SOUTHEXP); and trades between two PJM nodes that historically had a very small price spreads (NCMPAIMP-NCMPAEXP).
The commission concluded that City Power created the false impression that it was trading to arbitrage price differences “when, in fact, it was engaging in trades solely to collect MLSA payments to the detriment of other market participants.”
“As we have noted, trades that are pre-arranged to cancel each other out and involve no economic risk are wash trades, which are inherently fraudulent,” the commission said.
The order also concluded that Tsingas attempted to mislead investigators by denying the existence of incriminating instant messages between him and a business partner, Timothy Jurco.
The allegations against City Power are virtually identical to those FERC made in its case against Rich and Kevin Gates and their Powhatan Energy Fund.
On May 29, the commission ordered the Gates brothers and their associates to pay $34.5 million in penalties and disgorged profits. If the Gates brothers don’t pay up within 60 days, as they insist they won’t, FERC will have to file a complaint in U.S. District Court to force payment. (See FERC Orders Gates, Powhatan to Pay $34.5 Million; Next Stop, Federal Court?)
FERC also may face challenges collecting from Tsingas and his company, which said in April that FERC’s investigation forced Tsingas to lay off all of his employees and “destroyed” the company. (See UTC Trader: Firm was Ruined by ‘Unfair’ FERC Prosecution.)
FERC investigators contend Tsingas’ net worth is at least $10 million, including “a waterfront mansion” in Fort Lauderdale worth $3 million, a yacht, a house in Greece and several autos.
Tsingas told FERC his net worth is “roughly $1 million” and that his “yacht” is a nine-year-old, 32-foot outboard boat “without a cabin or a shower” and that his “mansion” is a simple three-bedroom house.
Attorneys for Tsingas and City Power did not respond to a request for comment.
The New England Power Pool Participants Committee urged federal regulators last week not to short circuit its stakeholder process in ordering zonal sloped demand curves for the next Forward Capacity Auction.
NEPOOL joined ISO-NE in asking the Federal Energy Regulatory Commission to reject a request by generators to force the RTO to develop a zonal sloped demand curve design for FCA 10 in February (ER14-1639).
The New England Power Generators Association made the request June 22 after ISO-NE backed off from its commitment to introduce a new curve for FCA 10, saying that making a change now would create reliability concerns. The generators asked FERC to reiterate a previous order that directed the RTO to continue efforts to eliminate administrative pricing in zones that are short of generation resources or suffer from transmission constraints. (See NEPGA: Order Sloped Demand Curve in FCA 10.)
ISO-NE withdrew its support for the change just before NEPOOL was scheduled to vote on it. At NEPOOL’s June Planning Committee meeting, only 42% of stakeholders backed the sloped curve.
NEPOOL told FERC that although some of its members feel “frustration” with ISO-NE for reversing course despite “substantial progress,” it wants any changes to result from the stakeholder process.
“NEPOOL takes no position under these circumstances on whether an order to implement sloped zonal demand curves generally is appropriate or justified,” it wrote. NEPOOL’s preference is to develop consensus in its own stakeholder process for “many interrelated issues,” it said.
The Electric Power Supply Association also weighed in on the issue last week, expressing support for NEPGA and chastising the RTO for its reversal. “EPSA does not believe that the commission intended the ISO-NE to receive a free pass on this issue,” it wrote.
In its reply to NEPGA, filed July 2, ISO-NE said the generators’ motion should be dismissed on procedural and substantive grounds.
“NEPGA’s proposed zonal demand curve design using potential FCA 10 capacity zone boundaries shows dramatically worse performance,” it said.
NEPGA had asked for a Section 206 proceeding, but the RTO said “it falls far short of what is required under the commission’s rules to initiate a proceeding.”
SPP’s Markets and Operations Policy Committee will vote this week on a recommendation to move the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT.
The proposal, which has cleared four lower stakeholder groups, would have day-ahead results posted at 2 p.m. CT, up from 4 p.m. It also shortens the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 and results posted by 5:15.
The changes to SPP’s operating tariff are intended to comply with the Federal Energy Regulatory Commission’s Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle. The commission ordered RTOs to adjust the posting of their day-ahead energy market and reliability unit commitment process results “sufficiently in advance” of the revised gas cycles, or explain why it is not suitable for their markets. (See SPP Trying to ‘Balance the Risk’ on Gas-Electric Schedules.)
‘Incremental’ Improvement
The revised timeline would not provide day-ahead market results before the 1 p.m. CT nomination deadline, but it would provide 30 minutes before the Intraday 2 nomination. RUC results would be available 45 minutes before the 6 p.m. evening gas nomination.
The proposal has already been endorsed by majorities in the Gas Electric Coordination Task Force (4-2 with two abstentions); the Market Working Group (7-5-5); Regional Tariff Working Group (14-2-3); and Operating Reliability Working Group (9-1-1).
The task force’s recommendation termed the changes “an incremental improvement over the existing timeline for improving coordination between the market results and the Timely and Evening nominations.” The group also said the changes will allow for day-ahead market and reliability unit commitments to be provided before the evening nomination and sufficient time in the morning for “price formation” before the day-ahead market closes.
SPP estimates it will take approximately $1.5 million and 14 months to implement the current changes, which would require FERC’s approval of the tariff changes and new software implementation. RTO officials’ long-term goal is to post day-ahead market results before the timely gas nomination.
Opposition in the North
The change was opposed by several members in SPP’s north, where cold weather affects natural gas supplies during critical time frames, including Lincoln Electric and the Omaha and Nebraska public power districts.
In stating its opposition, Nebraska Public Power District said SPP and its members should have taken their timeline concerns to FERC before developing a revision request. “Spending $1.5 million and not [getting] what we need … actually could make it worse for the market overall,” NPPD said.
NPPD and City Utilities of Springfield also said the change would hurt forecast accuracy, particularly for wind generation.
Springfield noted that SPP has a large share of intermittent wind generation — making forecasts especially important —while experiencing fewer gas constraints than eastern RTOs.
“The greatest benefits of [the change] impact less than 10 days a year (3%) at the detriment of the remaining 355 days,” Springfield said. “SPP has a relatively small percentage of gas generation in their average stack and a ~40% capacity benefit margin, which provides needed cushion in the current construct.”
SPP used social media recently to announce its membership had hit 90 with the addition of three cooperatives and an investor-owned utility that joined the RTO as part of the Integrated System.
East River Electric Power Cooperative is a wholesale supply cooperative serving 24 rural electric co-ops and one municipally owned electric system with a total of more than 92,000 homes and businesses. The cooperative has a 40,000-square-mile service area covering 63 primarily rural counties in eastern South Dakota and western Minnesota.
Northwest Iowa Power Cooperative is a generation and transmission cooperative supplying wholesale power to seven distribution co-ops serving more than 30,000 members and consumers. It covers 6,500 square miles in western Iowa.
Corn Belt Power Cooperative, another G&T cooperative, provides energy to nine distribution co-ops and a municipal co-op in 41 counties in northern Iowa.
NorthWestern Energy is an investor-owned utility providing electricity and natural gas to about 692,600 customers in Montana, South Dakota and Nebraska. It owns and operates wind, water, natural gas and coal-fired generation and delivers electricity to more than 416,100 customers.
SPP began coordinating transmission for the Integrated System on June 1. Full membership is expected in October. SPP has members from 14 states and 48,537 miles of transmission; the newest members will give SPP approximately 60,000 miles of transmission, stretching from northwest Louisiana, across the Great Plains to western Montana.
The amount of coal mined using the controversial mountaintop removal method has plummeted 62% in the past six years, according to the US. Energy Information Administration.
All coal production has decreased 15% because of lower natural gas prices and a decreasing demand for coal, according to EIA. But the drop has been more acute for coal recovered by mountaintop removal, which involves clearing rock and soil overburden to expose a coal seam. The method, used mostly in central Appalachia, and decried by environmentalists, sometimes results in valleys being filled in by the waste material.
Obama Administration Wants more Americans Getting Solar Energy
The Obama administration is introducing measures that will triple the capacity of solar and other renewable energy installed in subsidized housing to bring green energy to lower- and middle-income Americans.
The administration’s climate change initiative includes backing efforts to make it easier for homeowners to borrow money for renewable energy installations, primarily solar. Charities and investors also have committed to spending more than $520 million for solar and energy efficiency projects.
Senate Republicans Call for Revocation of NRDC’s Status
The National Republican Senatorial Committee is calling for federal authorities to revoke the tax-exempt status of the Natural Resources Defense Council because of its “partisan” campaign against Sen. Mark Kirk of Illinois.
The Republican committee said the NRDC’s campaign criticizing Kirk violates its nonprofit status, which prohibits it from engaging in political activity. Kirk is up for re-election in 2016.
The environmental group says the ads are purely educational. The NRDC’s campaign followed major campaigns by the League of Conservation Voters and the Sierra Club against Kirk.
DOE Providing $18 Million in Biofuels Research Projects
The Department of Energy is investing $18 million in six projects that aim to produce biofuels that would come to market for less than $5/gallon by 2019.
The projects, which seek to produce fuels or fuel additives from algal biomass, are underway at the Colorado School of Mines, Duke University’s Marine Algae Industrialization Consortium, Global Algae Innovations, Arizona State University, University of California/San Diego and Lawrence Livermore National Laboratory.
Energy Companies, Utilities Seek Last-Minute White House Meetings
Utility groups and energy companies are lobbying the White House before new carbon emissions regulations for power plants are released in August.
The White House has hosted at least eight meetings with industry groups in the past three weeks, including Duke Energy, manufacturer Honeywell and the National Mining Association. Opponents argue that the regulations imposed on states are too stringent, and the timetable is too short, to be reasonable.
“The point we left them was that in the Clean Power Plan, EPA is offering governors a basket of rotting carp,” said the NMA’s Luke Popovich.
NRC Approves Transfer of Nuke License to Duke Energy Progress
The Nuclear Regulatory Commission has approved the transfer of the operating licenses of the Harris Nuclear Plant and the Brunswick 1 and 2 plants from the North Carolina Eastern Municipal Power Agency to Duke Energy Progress. The transfers were part of Duke’s $1.2 billion acquisition of NCEMPA generation assets announced earlier this year. Closing of the deal is expected by the end of July.
VALLEY FORGE, Pa. — Tier 1 synchronized reserve resources would be obligated to respond in emergencies and subject to penalties if they couldn’t, under a PJM-backed proposal approved Wednesday by the Market Implementation Committee.
The proposal retains Tier 1’s ability to receive compensation outside of synch reserve events whenever the non-synch reserve market price is more than $0. Units could opt out of the performance obligation, but by doing so they would forfeit any credit they would have received outside of responding to an event.
Estimated Tier 1 megawatts would still be considered when clearing the synch reserve market so that opting out could not be used to withhold supply from the market and drive up prices.
In addition, units would be made whole for the cost of responding to a spin event. However, that would apply only to units scheduled by PJM to provide energy or self-scheduled resources that are dispatched by PJM to run above their minimum rate.
The PJM proposal was one of three presented to address a problem statement raised last fall by Independent Market Monitor Joe Bowring, who estimated that the payment scheme dating to 2012 results in about $85 million in unnecessary expenditures each year. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
The other plans were crafted by Bowring’s Monitoring Analytics and PJM’s Industrial Customer Coalition.
Bowring’s proposal would have eliminated the compensation Tier 1 resources receive when they’re not responding to an event — what he classified as an unearned “windfall” — and would not have imposed a performance obligation. It failed, garnering just 29% of the vote.
Bowring said Tier 1 resources already can offer as Tier 2. “All of the functionality that PJM wants to add through these complicated changes are already there,” under current rules, Bowring said, sparking a brief debate with Adam Keech, PJM‘s director of wholesale market operations.
Keech said it is up to PJM to decide whether to accept Tier 1 resources seeking Tier 2 status.
“No one can force PJM to buy Tier 2 it doesn’t need,” Bowring agreed.
The proposal from the ICC would have compensated Tier 1 resources outside of an event, but at the non-synchronized reserve price.
The ICC’s Susan Bruce said the proposal was a compromise between the approaches of PJM and the Monitor. “The Industrial proposal is smack dab in the middle between the two.” It was rejected with a favorable vote of just 23%.
PJM’s scarcity pricing scheme was created in 2012 to accurately price energy and reserves when reserves are short — defined as less than the largest generating unit that is on-line. The mechanism allows the market clearing price to rise, creating an incentive for resources to respond in an emergency.
PJM’s proposal, which passed with 64% approval, will be heard at the Markets and Reliability Committee next month. If approved there, it will be presented to the Members Committee in October and implemented shortly thereafter. Manual language will be presented at the August MIC.
Market participants would be able to enter replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year if the need is linked to a physical reason that would prevent a participant from meeting its commitment, according to manual changes approved last week.
To prevent the opportunity for financial arbitrage between auctions, the changes prohibit generation that is replaced early from being recommitted for the delivery year.
The motion passed with 81% support, trumping an alternate measure introduced by Tom Rutigliano on behalf of EMC Development. That proposal, which would have placed no restrictions on what capacity could be replaced or on it being re-entered into the market, received 28% support.
Under the approved changes, replacements would be permitted when the owner could show the expected final physical position of the resource at the time of the request.
Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project was canceled or delayed.
Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.
Package Calls for Notice on Pricing Interfaces
PJM would be required to provide more public notice before it creates “closed-loop” pricing interfaces under a proposal approved by the committee.
Under the changes, the RTO would announce the implementation of such interfaces at least five days before the close of the next monthly financial transmission rights auction. Currently, there are no notice requirements except for sub-zonal demand response, which is announced the previous day.
The RTO also will provide notice when it begins studying a potential new interface that will be defined and able to be used, such as looking into modeling the interface. Notices will be posted on the OASIS site, triggering an email to stakeholders. The rule will allow an exception to the advance notice requirements for planned, emergency or maintenance outages of less than 10 days.
PJM uses closed-loop interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems.
The change was approved by acclamation with 10 members voting in opposition.
PJM told the Operating Committee last week it plans to poll members on whether to expand the winter preparedness testing it began last year. The testing was credited with improving generator performance during the winter of 2014/15, but it came at a cost of about $7 million to load.
Susan Bruce, of the PJM Industrial Customer Coalition, said her members had questions about whether the testing “is a good use of ratepayer dollars.”
“It’s not a slam dunk to us that this should be expanded,” she added.
Gregory Carmean, executive director of the Organization of PJM States, which represents state regulators, suggested generators — not load — should be shouldering the costs. “What’s the rationale for load paying these costs in a Capacity Performance world?” he asked.
However, Brock Ondayko of American Electric Power noted that the coming 2015/16 winter will not be subject to the Capacity Performance rules, which don’t take effect until delivery year 2016/17.
Dan Griffiths, executive director of the Consumer Advocates of PJM States, was more sympathetic to continuing the testing, calling it a “pragmatic question.” But he requested time to poll his members before voting.
“If it’s useful for identifying problems it should be done,” he said.
Members will be asked to vote on four options, which would be reflected in Section 7.5 of Manual I4D:
Option 1, with the addition that the program would end after winter 2015/16 for CP resources.
Option 1, plus the following changes: Expand the exercise period from the month of December to the months of November through January; expand the maximum temperature for the testing to 40 degrees Fahrenheit in PJM’s southern zones (from 35 F); allow testing of more than 1,000 MW/day.
Option 3, with the program terminating after winter 2015/16 for CP resources.
In a survey in June, all but three of 119 respondents said they supported continuing the testing; 93 (78%) said they preferred maintaining the current rules while 26 (22%) favored making some changes, which were not specified. (See Why Did PJM Grid Fare Better This Winter?)
PJM Seeking to Tighten Training, Certification Rules
PJM will seek OC approval next month on an initiative to improve compliance with the RTO’s training and certification requirements.
The requirements cover transmission owners, generation dispatchers, demand response providers and energy storage device operators. While transmission owners are usually in compliance, PJM said in a problem statement, non-compliance by some in the other groups “has been continuing for many months and in many cases has increased or become chronic in nature.”
Although those not in compliance are required to submit mitigation plans, most have not done so or have failed to comply with them.
In June, nine generating companies, five small generators (>75 MW) and four DR and storage providers were out of compliance with training or certification requirements. Aside from seven of the generators, none had submitted mitigation plans.
PJM said the problem could lead to operational or reliability problems as some members are unaware of their responsibilities for providing instantaneous reserves and other generator data.
Glen Boyle, manager of system operator training, said the RTO hopes to complete the work, which it is recommending be conducted by the System Operations Subcommittee, within three months. “We’ve talked internally and have some options” for solutions, he said.
PJM said it will not consider changing the existing training and certification requirements within the scope of the problem statement.
Disconnect Between PJM, Members on Meter Accuracy
A proposed update of Manual 1: Control Center Requirements has exposed a gap between PJM and some transmission owners regarding accuracy requirements for system control and monitoring meters.
As a result — at PJM’s request — members last week endorsed changes to the manual except for Section 5.
“We need more time” before changing Section 5, PJM’s Ryan Nice told the OC. “PJM needs a better overall picture of the accuracy of metering data.”
While the manual requires accuracy of ± 2% for meters supplying data to PJM’s energy management system (EMS), it’s not clear that all meters are covered by that requirement. Some TOs have meters that are only accurate to within 3%, Nice said.
The gap affects real-time meters, not billing meters.
“We need to evaluate the cost” of requiring all meters to comply with the 2% requirement, Nice said, “to make sure the operational value justifies the cost and time to members.”
