FERC last week approved a designated entity agreement (DEA) for Transource Energy to construct the AP South Congestion Improvement Project, subject to the outcome of a formula rate case the company has submitted to the commission (ER17-349).
PJM last year approved a $340.6 million proposal by Transource and Dominion High Voltage to address the congestion issue along the border of southwestern Pennsylvania and northwestern Maryland, despite criticism from other stakeholders. FERC noted in its approval that Transource has submitted security of $5.55 million for its $197.1 million portion of the project. (See “Planners to Recommend $340.6M Solution to Congestion in AP South,” PJM Planning Committee & TEAC Briefs.)
The commission’s approval lists Transource’s project requirements, including the installation of a 230-kV double-circuit line between the Ringgold substation and the new Rice substation and one between the Conastone substation and the new Furnace Run substation.
Old Dominion Electric Cooperative objected to the DEA, saying that it included cost recovery items that the commission should consider individually. American Electric Power responded that the agreement instead provides better transparency into Transource’s cost-containment commitments. (Transource is a joint venture of AEP and Great Plains Energy.)
FERC acknowledged both points, ruling that its acceptance of the DEA is subject to the outcome of the rate case (ER17-419).
Solar photovoltaic resources can provide ancillary services in a way comparable to — or better than — conventional generating resources, according to a study released by CAISO last week.
That finding was based on testing conducted last August in collaboration with the National Renewable Energy Laboratory (NREL), First Solar and Southern Co. using a 300-MW solar facility within the CAISO footprint.
“These test results demonstrated how smart inverter technology can leverage PV technology from simply generating as a variable energy resource to providing ancillary services, such as spinning reserves, load following, voltage support, ramping, frequency response and regulation, and power quality,” the ISO said.
| First Solar
The tests were performed to address industry concerns about transmission reliability as a growing amount of renewable resources interconnect with the grid — the result of both state renewable energy mandates and the increasing cost-competitiveness of wind and solar generation.
Unlike conventional generators that have the ability to automatically vary their turbines’ rotational speed and output based on the pull of load, nonconventional technologies typically have little or no inertial response to momentary changes on the grid.
That built-in capability of conventional resources functions as a kind of damper for frequency excursions. It also leaves those resources better equipped than renewable generation to offer key grid services such as frequency response and voltage support.
The CAISO findings could undermine that conventional wisdom and expand market options for renewable resources, as the ISO develops and refines market mechanisms intended to compensate resources equipped to rapidly react to automatic signals to respond to grid disturbances — both of which are increasingly likely to occur because of increased penetration by variable renewable resources. (See CAISO Seeks Primary Frequency Response Market.)
The results also demonstrate that renewables can, within certain limits, provide the fast-ramping capability needed to respond to variable output from renewable generation located in other areas of the grid — in effect using renewables to integrate renewables.
“These findings mean renewable energy in the ISO footprint — and beyond — could be integrated into power grids at a much higher level and faster pace than once believed, giving a glimpse at the future green and sustainable electric networks,” Clyde Loutan, the ISO’s senior advisor for renewable energy integration, said in a statement. “With these results, the electric industry can expect one day to realize ambitious goals of using primarily renewable sources to power our economy.”
The report notes that a key aspect of the “grid-friendly” nature of First Solar’s solar power plant is a plant-level controller, or PPC, developed by the company to regulate the plant’s real and reactive power output and ensure that the PV arrays collectively function as a single generator.
“Although the plant is comprised of individual inverters, with each inverter performing its own energy production based on local solar array conditions, the function of the plant controller is to coordinate the power output to provide typical large power plant features, such as [advanced process control] and voltage regulation through reactive power regulation,” the report said.
As a result, the PPC, and the facility as a whole, are capable of providing such functions as output curtailment in order to avoid an operator-specified limit, ramp-rate control to ensure that the plant ramps up or down as directed, and frequency response service.
Improvements in inverter technology can allow a solar plant to provide “essential reliability services” and enable renewable resources to help further integrate additional renewable resources, the ISO said.
“These tests demonstrated how controls can leverage the value of solar photovoltaic plants from being simply a variable energy resource to providing services that range from spinning reserves, load following, voltage support, ramping, frequency response and regulation, to power quality,” said Vahan Gevorgian, chief engineer at NREL’s Power Systems Engineering Center.
The ISO plans to perform similar testing on a large wind farm, which it expects will also be positioned to provide reliability services based on the use of similar technology.
The use of solar and wind resources to provide such services will enable the ISO to move more emissions-free power into its system during periods of high renewable production, an “essential” development for California to meet its statutory mandate of generating half of its electricity from renewables by 2030, according to the ISO.
“The next steps are to identify regulatory and operational barriers to the feasibility of renewables providing essential reliability services and explore economic and contractual incentives to maximize the potential for renewables to provide these services,” the ISO said.
VALLEY FORGE, Pa. — PJM has developed a load forecasting process that has improved the grid operator’s prediction accuracy, staff meteorologist Elizabeth Anastasio told stakeholders at a Jan. 11 Operating Committee meeting.
PJM purchases three weather forecasts from different vendors, Anastasio explained. Load forecasts based solely on the most accurate of the three created an average error of 1.91% in 2016.
Using its own, more comprehensive forecast process, PJM achieved an average 1.79% error rate during the same period.
Each day, PJM produces a forecast for the current day and the week ahead for 22 zones within its footprint, as well as for several aggregates and the entire RTO. Dispatchers can update forecasts at any time, and updates are published twice hourly at 15 minutes and 45 minutes past the start of the hour.
Initial forecasts are posted by 10 a.m. ET, before the close of the day-ahead market at 10:30 a.m. At 6 p.m., the current forecast update becomes the “original” forecast for the next day in members’ Data Viewer portal.
Dispatchers combine the weather forecasts with information about the day — such as the season or whether the day is a holiday — and historical load information to develop eight models. Several of them perform best on days with normal conditions, while others are most useful under specific circumstances.
“On average, the ensemble models are our best performers,” Anastasio said. “On holidays, a lot of these models are going to give you trouble.”
Unusual weather conditions, daylight saving time and a lack of information on load sources and likely human behavior can also contribute to forecast errors, Anastasio said. Dispatchers minimize those discrepancies in several ways, including by “backcasting” — a process used to determine what factors would have produced a perfect forecast and compare them with the factors that were actually used.
PJM is improving the process, she said, by combining the forecasts into a “smart mix,” creating better models, implementing a solar forecast, developing a load forecast analysis team and participating in industry forums on the topic.
“There’s a lot of things going on behind the scenes to make this better,” she said.
Manual 40 Revisions Approved with Exelon’s Addendum
Members endorsed PJM’s proposed Manual 40 changes that will reduce the grace period for completing operator training. The proposal had been updated from previous versions to include a phrase proposed by Exelon.
Exelon asked for language clarifying that the clock for the grace period begin only after the operator is “deemed qualified” by the employing company. PJM has proposed cutting the grace period in half to six months. (See “PJM Moves to Cut Operator-Training Grace Period in Half,” PJM Operating Committee Briefs.)
PJM plans for the new requirement to apply to anyone who begins training on Feb. 1 or later. Trainees who begin earlier than that date will remain subject to the 12-month grace period.
PJM Moves to Relax Refresh-Rate Standards
PJM plans to relax its telemetry scan rate requirements for internal special cases and transformer tie lines from four seconds to 10 seconds in proposed changes to Manual 1, PJM’s Ryan Nice explained.
However, he noted that if more than one regulation is involved, the more stringent standard still applies.
Emergency Procedure Messages Added
Two potential message types have been added as emergency procedure events: Conservative Operations and Synchronized Reserve Events, PJM’s Dave Hislop explained.
Conservative Operations might be declared when the RTO (or a portion of it) is undergoing, or has the potential to face, adverse impacts from a weather or environmental event and requires enhanced RTO reliability efforts, or if it enters an unknown operating state, such as an outage to its Energy Management System. PJM added this message type to any facilities that receive hot or cold weather alerts.
PJM has consistently exceeded its frequency response obligation based on criteria set by NERC.
Synchronized Reserve Event notifications were removed from the system in 2012 because the events are usually of such a short nature that operators often posted the notification after the event had already been canceled. Members have asked them to be reinstated now that notifications are system-automated and posted immediately. The notifications will be sent for the reserve capability of generation units that can be converted into energy or demand response resources able to respond within 10 minutes. PJM added this message type to any facilities that receive primary reserve alerts.
PJM Satisfying Frequency Response Obligation
PJM’s field trial performance has exceeded its expected frequency response obligation (FRO) every year since NERC’s BAL-003 standard went into effect in 2011, PJM’s Danielle Croop said.
“We are well above our obligation in our performance measure,” she said.
The performance is measured as the median of all NERC-selected events. Of 28 events selected in 2016, PJM met or exceeded its obligation on all but five. PJM’s FRO for the 2017 operating year is -258.31 MW/0.1 Hz.
“Coordination is an important part of MISO’s ongoing strategy, but it has a lot of different time horizons as our reliance on gas grows,” said MISO adviser Scott Wright at a Jan. 11 subcommittee meeting.
The RTO’s foremost priority is ensuring grid reliability while “analyzing and vetting” resource adequacy risks under increased gas reliance, according to Wright.
“We’re very well positioned in MISO with a good gas pipeline system,” Wright said. “Our 15-state footprint has about 20 to 30 pipeline systems.”
MISO will this year pilot a program that sends hourly gas usage profiles to a handful of selected pipeline operators. RTO staff will update stakeholders on the project later in the quarter. (See MISO to Continue Gas-Electric Coordination Efforts in 2017.)
Wright repeated assurances that the RTO will not try to influence generator behavior with the use of hourly profiles and expanded contingency planning: “For us, it’s knowing what is going on. It’s a way to be proactive in real time so operators know what kind of headroom they have.”
Preliminary Load Forecast Released
Preliminary data from MISO’s independent load forecast for the 2017/18 planning year indicates the RTO expects coincident peak demand of 122 GW during the period and a 135-GW planning reserve margin requirement.
Other details from the preliminary forecast:
Zone 1, covering Minnesota, North Dakota and western Wisconsin, shows a 16,307-MW coincident peak forecast and a 18,246-MW planning reserve margin requirement;
Zone 2, covering eastern Wisconsin and upper Michigan, should register 12,184 MW in coincident peak demand and will require a 13,410-MW planning reserve margin;
The collective coincident peak forecast for Iowa’s Zone 3, Missouri’s Zone 5 and Michigan’s Zone 7 comes in at 36,673 MW, with the planning reserve margin requirement expected to be 40,667 MW;
Zone 4 in Illinois should peak at 8,975 MW and have a 9,920-MW planning reserve margin requirement; and
Zone 6, covering Indiana and Kentucky, should register a 16,577-MW coincident peak and hold a 18,512-MW planning reserve margin.
MISO South — which includes Arkansas’s Zone 8, Zone 9 covering Louisiana and Texas and Mississippi’s Zone 10 — together have a 36,673-MW coincident peak forecast and a 34,081-MW planning reserve margin requirement.
Consumers Energy’s Jeff Beattie contended that data should not be combined for Michigan’s Zone 7, Iowa’s Zone 3 and Missouri’s Zone 5 because Consumers and DTE Energy are required to report their own load data to Michigan. He said the combined data is concealing trends that the company could otherwise identify and use.
“It’s putting us at a disadvantage,” Beattie said.
DTE’s Nick Griffin said he also supported more data transparency among zones.
RASC Chair Gary Mathis said the item would be taken up at the March meeting, when MISO plans to post more up-to-date values and host a discussion on the issue.
In a final rule issued Jan. 9, FERC has increased its maximum civil penalties by 1.6% to reflect inflation.
The rule revised commission fines for violations of FERC-jurisdictional statutes, rules and orders imposed under the Federal Power Act, the Interstate Commerce Act, the Natural Gas Act and the Natural Gas Policy Act of 1978. FERC is required to make the annual update under the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (RM17-9).
Inflation was calculated using the U.S. Department of Labor’s Consumer Price Index for all urban consumers, comparing October 2016 figures with those from October 2015.
The new set of maximum fines range from $1,270 per offense, per day for violating the Interstate Commerce Act to $1,213,503 per violation, per day for violating sections of the Federal Power Act, the Natural Gas Act or the Natural Gas Policy Act.
The rule becomes effective upon publication in the Federal Register. FERC submitted the rule to the Senate, House of Representatives and Government Accountability Office and posted it without notice and comment period because it did not exercise discretion over the inflation calculation.
ERCOT rang in the new year by breaking an 18-day-old record for winter electricity demand six times within 14 hours, thanks to an early-January Arctic front that brought sub-freezing temperatures to Central Texas.
Demand reached 59,650 MW during the 6 p.m. interval on Jan. 6, smashing the previous winter record of 57,924 MW set Dec. 19. The record was topped five more times before 9 a.m. the following morning.
ERCOT had forecast a winter peak of 58,591 MW.
The new winter peak easily surpassed the previous January record of 57,256 MW recorded in 2014.
December peak demand was up 29% year over year, with the short-lived record far exceeding the 44,934-MW monthly peak seen a year earlier.
Last month marked the fifth straight month the Texas grid operator set a new record for monthly peak demand, dating back to August. Electricity consumption was up 11.2% in November, while the previous three months were all up less than 4%.
Overall, the ERCOT system produced 351.5 million MWh of electricity in 2016, just above the forecast of 350.6 million MWh.
VALLEY FORGE, Pa. — When Dominion Resources argued that failing to build a 500-kV line across the James River could result in blackouts, opponents of the plan didn’t believe it.
It turns out the company wasn’t bluffing.
Ronnie Bailey, a transmission planner for Dominion, presented the company’s alternative plan at PJM committee meetings this week, saying that the closure of its two coal-fired Yorktown plants in April will create a “long list” of N-1-1 contingencies that could result in voltage collapse and thermal overloads on the Virginia Peninsula.
An N-1-1 contingency represents the consecutive loss of two elements in a power system but with intervening time for operator adjustments.
The plan — the North Hampton remedial action scheme (RAS) — would be armed at PJM’s discretion. If the RTO detects the loss of certain facilities, it would trip the remaining feeds to the Yorktown area and drop service to approximately 150,000 customers, preventing voltage collapse. Rotating outages would follow until the facilities are repaired. Bailey confirmed the RAS has been approved by the SERC Reliability Corporation.
The blue circle depicts the area that will be affected by blackouts if Dominion’s RAS for North Hampton is utilized.
The Surry-Skiffes Creek line was proposed to maintain grid reliability on Virginia’s Lower Peninsula after Dominion shutters the Yorktown units. Increased environmental regulations have made the units impractical to run, and the isolated peninsula has few other power stations. With the local load projected to grow 8% by 2020, Dominion saw increasing the area’s connection to the grid as the only viable solution.
The project has attracted opponents, who are concerned that the transmission line would ruin the view at Jamestown and other historic sites nearby and believe the blackout warning is a scare tactic. A study conducted on behalf of the National Parks Conservation Association concluded that Dominion overestimated projected power growth and called for consideration of other alternatives, including underwater lines and converting the Yorktown plants to natural gas.
Approved by the PJM Board of Managers in 2012, the transmission project remains stalled pending permit approval from the U.S. Army Corps of Engineers. Bailey estimated that construction of the line would take at least a year after all permits are approved.
At a Jan. 11 Market Implementation Committee meeting, PJM Independent Market Monitor Joe Bowring asked Bailey if he was “100% certain” the Yorktown units would close. Bailey would only say that they’re required to close by law.
The region is home to numerous large electricity customers, including Newport News Shipbuilding, Joint Base Langley-Eustis, the Yorktown Naval Weapons Station, NASA, Historic Jamestowne, Colonial Williamsburg and the College of William and Mary.
Bailey assured the committee that the RAS “is only a stopgap measure,” noting that PJM’s regulations require those schemes to be temporary responses.
New York Gov. Andrew Cuomo has proposed the development of 2,400 MW of offshore wind generation off Long Island by 2030, the largest commitment to that energy source in the U.S.
Cuomo said the roadmap for developing offshore wind projects will be laid out in a master plan to be completed by the end of the year.
New York last year adopted a Clean Energy Standard that commits the state to generating 50% of its electricity from renewables by 2030.
The offshore wind commitment would provide enough power for 1.25 million homes and projects would be built out of view of onshore communities, according to Cuomo.
The announcement came a day after the governor took credit for the early closure of the Indian Point nuclear plant north of New York City by 2021, although plant owner Entergy cited low natural gas prices as the reason for shuttering the facility. (See Entergy to Shut Down Indian Point by 2021.)
Cuomo said a combination of transmission upgrades, energy efficiency and new renewable energy resources would replace lost generating capacity from Indian Point. Still, other clean energy sources would be needed to fill the gap before an adequate volume of offshore wind production could be put in service.
One proposed project 30 miles southeast of Montauk Point, the first phase of the massive Deepwater ONE project, would deploy about 90 MW of offshore generation by 2022.
The governor called on the Long Island Power Authority to approve that project, which has been stalled for months. State energy officials last summer requested a delay in project negotiations just as an agreement appeared to be in sight, and the agency’s board of directors failed to take up an expected vote on the project in December. (See LIPA Delays Vote on Offshore Wind Project; 90-MW Project Would be Largest in US.)
But Cuomo’s statement indicated that the project could be back on track, with the board now expected to consider a contract with the developer at its Jan. 25 meeting.
The project’s developer, Deepwater Wind, operates the nation’s first offshore wind farm off the coast of Rhode Island.
The governor’s proposal also calls on state agencies to ensure environmentally sensitive development in a 79,000-acre federally leased area capable of siting about 800 MW of offshore wind off the Rockaway Peninsula. The project area 17 miles south of the peninsula was the subject of a federal auction in December, which attracted a record $42.5 million bid by Norwegian energy company Statoil Wind US.
Cuomo said agencies should work with affected stakeholders — such as fishermen, maritime industries, coastal communities and labor groups — to ensure proper development.
He also directed the Department of Environmental Conservation and the New York State Energy Research and Development Authority to undertake a comprehensive study to determine the most rapid, cost-effective and responsible way to reach 100% renewable energy for the entire state.
“Gov. Cuomo’s plan to build 2,400 MW of offshore wind power by 2030 makes New York a national leader of this new clean energy industry,” Liz Gordon, director of the New York Offshore Wind Alliance, said in a statement. “The governor’s powerful endorsement will spur billions in investment, create thousands of skilled jobs and generate clean, affordable and reliable electricity for New York.”
She added: “The myriad benefits of offshore wind power have attracted the vocal support of a broad, diverse and growing coalition that unites business, labor, environmentalists, developers, academics, community leaders and environmental justice advocates.”
Environmental groups last month called on Cuomo to commit to developing offshore wind off Long Island.
“We applaud Gov. Cuomo for listening to New Yorkers and committing to large-scale, long-term offshore wind in New York and moving New York’s first offshore project forward,” said Lisa Dix, senior New York representative for the Sierra Club.
FERC has affirmed a previous ruling stating that evidence of price reporting deficiencies by power sellers during the Western Energy Crisis of 2000-2001 cannot constitute the sole basis for a finding of market manipulation during the event.
The commission’s Jan. 9 order clarified a key element of an October 2016 decision that gave credence to California’s contention that a failure of some power sellers to file compliant price reports with FERC may have helped conceal market manipulation, which in turn created a “pricing umbrella” under which California’s Department of Water Resources was compelled to sign overpriced contracts near the conclusion of the crisis (EL02-71). (See FERC to Consider Western Energy Crisis ‘Umbrella Pricing’ Theory.)
That decision opened the door for the California parties to the ongoing proceeding — which include the Public Utilities Commission, the state’s attorney general’s office, Pacific Gas and Electric and Southern California Edison — to introduce evidence of reporting deficiencies as part of the examination of factors that enabled sellers to charge the state exorbitant contract rates.
The October ruling prompted Shell Energy North America, TransCanada Energy and Hafslund Energy Trading, collectively referred to as the “indicated respondents,” to ask the commission to affirm a previous finding that “evidence supporting a pricing umbrella argument cannot in and of itself establish liability” for any sellers still involved in the energy crisis proceeding.
“Out of an abundance of caution, indicated respondents respectfully seek clarification and confirmation of the commission’s ruling,” the companies said in a November 2016 filing with the commission.
The three companies said that they assumed the commission would only permit the introduction of pricing umbrella evidence as a means to “provide greater context and depth to actual probative respondent-specific evidence regarding the California parties’ claims for remedies against respondents.”
Pricing umbrella evidence would not in and of itself represent such probative evidence, the companies contended.
“Therefore, for example, no pricing umbrella evidence can alleviate the California parties’ burden to establish that a reporting deficiency ‘masked an exercise of market power or other overt manipulation [by a respondent] in order to demonstrate the required nexus between an unlawful act and an unjust and unreasonable rate,’” the companies said, citing the commission’s previous finding.
FERC’s Jan. 9 order confirmed the companies’ understanding of how the pricing umbrella theory will be applied in the proceeding.
The order notes that the commission will “continue to find that evidence of a third party’s conduct [in filing deficient reports] is not relevant to this showing because the focus of the Mobile-Sierra inquiry [into the contracts] is the conduct of the seller and whether that conduct directly affected contract prices.”
That language echoed the commission’s previous determination that evidence of a reporting violation alone could not overcome the Mobile-Sierra presumption of the “justness and reasonableness” of a contract. Such a finding would require evidence of an actual intent to manipulate markets.
“We clarify that, while we will permit the introduction of pricing umbrella evidence solely for the purpose of providing greater context and depth for probative, seller-specific evidence, this evidence should not be treated as evidence that can be the basis of a finding of refund liability,” the commission said. “We thus affirm that pricing umbrella evidence is not an element upon which a finding of refund liability may be based in this proceeding.”
Massachusetts legislators last week passed a bill that seeks to remove barriers to electric vehicle ownership and allows utilities to invest in charging infrastructure.
Gov. Charlie Baker is expected to sign the bill, which moved through the legislature last year but was left out of an omnibus energy bill that addressed several clean energy items. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.) The bill passed in the legislature’s informal session, a day before the start of the regular session.
| Mass
The new law prohibits charging station operators from requiring subscription fees from EV drivers and allows towns to create EV-only parking spaces. It also codifies regulations that would allow cost recovery for utilities’ EV infrastructure and promotes studies of issues such as the electrification of the state vehicle fleet.
The bill additionally requires “fair” rates for public charging, a detail that will be left to state regulators to determine.
Supporters said the final bill eliminated a provision directing the state Board of Building Regulations and Standards to amend building codes in order to require that new residential and commercial buildings be pre-wired for EV charging — instead leaving that as a recommendation.
“Massachusetts consumers want electric cars, but convenient access to charging stations is a barrier to getting more electric vehicles on the road,” said Megan Herzog, staff attorney at the Conservation Law Foundation. “This bill helps communities promote the charging infrastructure necessary to support increased electric car sales in the state.”
Herzog noted that transportation is the single largest contributor to Massachusetts greenhouse gas emissions. The sector is responsible for nearly 40% of in-state emissions, making their reduction crucial to meeting the targets of the state’s Global Warming Solutions Act.
“We must be mindful of our greenhouse gas emissions, especially those emitted by our transportation sector,” Senate President Pro Tempore Marc R. Pacheco (D), cosponsor of the bill, said in a statement. “We need to lessen our dependence on fossil fuels and make it easier for owners of electric cars to use their vehicles while incentivizing the transition to zero-emission transportation.”
Mark LeBel, a staff attorney at Acadia Center, said the bill’s provision to allow utility investment in charging station infrastructure codifies language from an existing Department of Public Utilities order.
“The specifics of utility proposals will be important to determine whether the three statutory criteria for approval are met,” LeBel said. “The proposals must be in the public interest, meet a need regarding the advancement of EVs and must not hinder the development of a competitive EV charging market.”
The Baker administration recently committed $14 million to the Massachusetts Offers Rebates for Electric Vehicles (MOR-EV) program, which offers state residents rebates of up to $2,500 for qualified vehicles.
The rule revised commission fines for violations of FERC-jurisdictional statutes, rules and orders imposed under the Federal Power Act, the Interstate Commerce Act, the Natural Gas Act and the Natural Gas Policy Act of 1978. FERC is required to make the annual update under the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015 (
