The Western Area Power Administration has selected a route for the TransWest Express transmission project, a proposed 730-mile, extra-high-voltage DC line designed to deliver large volumes of renewable energy into the desert Southwest.
The announcement comes a month after the U.S. Interior Department’s approval of the project — which would cross about 440 miles of Bureau of Land Management land — after eight years of environmental studies.
TransWest Express transmission line map | TransWest Express LLC
The proposed 600-kV line would run from south-central Wyoming, passing through Colorado and Utah and ending at the Marketplace Hub substation about 25 miles south of Las Vegas. That hub functions as a major wheeling point for transmitting power from the interior West into Southern California.
WAPA’s decision will enable project developer TransWest Express to proceed with design and engineering activities, as well as position the agency “to better evaluate its options for participation in or financing of the project,” the agency said in a statement.
The federal power marketing administration is supporting the project through its Transmission Infrastructure Program, which allows transmission developers to “leverage” the agency’s development experience and provides eligible infrastructure projects with access to federal financing.
“Collaboration between WAPA and energy developers is critical to developing infrastructure capable of meeting our nation’s growing energy needs while minimizing environmental impacts,” WAPA Administrator Mark A. Gabriel said. “This decision and comprehensive study provides the foundation to further the project’s development.”
TransWest Express is a subsidiary of the Denver-based Anschutz Corp., a privately held company with extensive investments in energy and real estate.
The project will boast 3,000 MW of bidirectional capacity when completed. The line’s primary function will be to allow loads in Arizona, California and Nevada to tap the output of planned wind resources in Wyoming.
Project specifications include two 200-acre AC/DC converter stations at each terminating point, a fiber optic network communications system and two 600-acre ground electrode facilities.
The project is expected to cost about $3 billion and take three years to complete after the start of construction. WAPA and BLM were the lead agencies in preparing the environmental impact statement for the project, which is still subject to approval from additional state and federal regulatory bodies.
VALLEY FORGE, Pa. — PJM staff last week outlined a proposal to lengthen the RTO’s Regional Transmission Expansion Plan cycle for reliability projects from 12 months to 18 months.
Staff explained the plan at a special session of the Planning Committee on redesigning the Transmission Expansion Advisory Committee.
The proposal comes in response to more detailed analysis of the optimal timing for the planning cycle, a component of the TEAC redesign that began about a year ago, staff said.
The expansion of the cycle — along with the development of a flowchart for how projects will move through proposal windows — would represent a “memorialization” of existing processes that have never been specifically defined, PJM’s Mike Herman said.
The proposed change would take effect for the 2018 planning year, moving the beginning of the cycle to September 2017. The RTEP cycle for market efficiency projects would remain unchanged.
Stakeholders expressed concern about the decisional-process flowchart and asked for additional transparency around why certain projects are rejected. They also sought more opportunities to provide input.
Staff acknowledged some of the concerns but pushed back on others.
Paul McGlynn, PJM senior director of planning, said it would be challenging to rank projects against each other because of the difficulty in comparing the relative benefits of dissimilar project factors.
Vice President of Planning Steve Herling provided a hypothetical example of the challenge: “There’s no way to show how much a perceived benefit is going to wipe away the ability to get a right of way through the Gettysburg Battlefield.”
Alex Stern of Public Service Electric and Gas questioned the wisdom of trying to incorporate all project drivers into a single comprehensive manual and warned that critical pieces might get “lost in the sauce.”
PJM staff acknowledged his concerns. “Ultimately, I’m less concerned about the format of the manuals than about the content,” Herling said.
Stern also suggested that PJM include a provision to limit the potential for selling a project before or after it’s built, which attorney Steve Huntoon warned might create “unintended consequences that raise risk.”
The next meeting on the issue is scheduled for Feb. 10.
CARMEL, Ind. — MISO is poised to implement a laundry list of changes intended to improve its capacity market, some of which should take effect in time for the 2017/18 Planning Resource Auction.
The most significant — and controversial — is a proposal that would apply a 50-MW physical withholding threshold to affiliated market participants on a collective basis, rather than to each affiliated company individually.
The RTO’s Independent Market Monitor recommended the change in its 2015 State of the Market report, contending it would prevent a supplier from avoiding mitigation by creating multiple affiliates to increase its withholding threshold. (See “MISO Takes 1st Steps in Monitor Recommendations,” MISO Resource Adequacy Subcommittee Briefs.)
MISO plans to file the change with FERC on Jan. 17, MISO Manager of Resource Adequacy John Harmon said during Wednesday’s Resource Adequacy Subcommittee meeting.
In light of the change, the Monitor will this year begin to review bids made by affiliated market participants during the offer window. Monitor staff will contact affiliates once to notify them of a violation, providing an opportunity for violators to resubmit offers. Affiliates that continue to exceed the 50-MW threshold after the offer window closes will be subject to sanctions.
“It’s important to remember the offer window is a three-day window,” Harmon said. “Most offers are received on the first day, but there are three days” to submit offers.
Monitor staff member Michael Chiasson said the Monitor will not tell affiliated companies the specific volume of their collective shortfall of offers.
“It’s on or off, like any other light on the dashboard,” Chiasson said. Penalties will be identical to sanctions already detailed in Module D of the Tariff, which include fines, ineligibility for revenue sufficiency guarantee payments, bans on submitting virtual transactions or a condition that all of a company’s power requirements be scheduled in the day-ahead market.
Chiasson noted that the Monitor will notify violators of shortfalls by phone or emails and rely on contact information from the operating cost survey contact list and MISO’s official market participant registry.
“I just worry about the nightmare scenario that you’re calling and no one is picking up the phone,” said Jamie Watts, an attorney with the Long Law Firm.
Harmon said that MISO would not simply “leave a voicemail with a random individual and then shrug our shoulders.”
Some stakeholders are still wary of the change, maintaining that FERC Order 697 already prohibits affiliates from colluding to dodge withholding mitigation.
“I’d love to see what antitrust officials think of this,” said David Sapper of Customized Energy Solutions. “But that’s not relevant — or it might be.”
Tariff Clarifications
MISO will revise Module D of its Tariff to allow planning resources to request facility-specific reference levels for the auction. Offers for resources that make no such request will be set to $0/MW-day, as required by FERC. (See FERC OKs MISO Use of PJM Cost Estimates for Mitigation.)
Because a cost of new entry conduct threshold continues to apply to the auction’s initial reference level, the Monitor recommends that all resources whose competitive cost of selling capacity exceeds $26/MW-day request a facility-specific reference level. The RTO and Monitor are also proposing to exempt demand resources, energy efficiency resources and external resources from mitigation measures. The changes will be filed Jan. 17.
One stakeholder contended that resources external to the RTO should also be subject to mitigation, but MISO pointed out that external resources have no obligation to offer into the market and should not be discouraged from volunteering offers at their own prices.
The RTO has yet to establish an effective date for the changes because the filing will be made so close to auction registration, according to Jacob Krouse, MISO’s corporate counsel, but implementation could occur in time for the 2017/18 auction.
Indianapolis Power and Light’s Ted Leffler said the new reference levels were confusing. “I’m hearing zero, 10% of cost of new entry, and it all seems to be a bit of mush to me,” he said.
North-South Limit Calculation Specified
MISO will update its Tariff to specify a method for calculating transfer limits of flows between its North and South regions that cross SPP’s system, as directed by FERC late last year. (See FERC Backs MISO on Transfer Limit, Seeks Details.) The new provision will direct RTO staff to determine a megawatt limit by reviewing seams, transmission service and coordination agreements. Transmission providers will then be required to conduct a feasibility analysis to determine whether tighter limits are needed.
Harmon said MISO will submit a compliance filing by the end of the month (EL16-112), but the RTO is open to receiving stakeholder feedback up until Jan. 20.
Chiasson objected to the subtraction of all firm transmission service in determining the calculation for the limit and encouraged MISO to study the probability of actual firm transmission use to come up with a more accurate limit.
“When capacity import limits and capacity export limits are determined between [other MISO] zones, those determinations don’t use any firm transmission reservations,” Chiasson said. “We think that should also be true for limits between the North and South regions.”
The Monitor is likely to protest the filing, he added.
For the FERC directive to develop going-forward costs for facility-specific reference levels, also contained in the transfer limit order, MISO will use two years of data and a formula in which the hypothetical cost of suspension or retirement at the beginning of a planning year is subtracted from costs incurred during a 24-month period if the resource retires or suspends at the end of the planning year. MISO defines going forward costs as the sum of operations, administrative, taxes and insurance, maintenance and capital expenses.
Harmon said the calculation will become effective in time for the 2017/18 auction. While FERC did not require a specific deadline for implementation, the order did stipulate that the changes become effective in “future planning years.”
Dynegy’s Mark Volpe objected to the short gap between the filing and effective date, as many auction data collection deadlines occur on Feb. 15.
“Now you’re telling us that you’ve only got two weeks to change gears,” Volpe said. “You’ve led us to believe it was on a prospective basis for the 2018/19 Planning Resource Auction. … Now you’re saying it’s the seventh inning and we’re going to switch the rules.”
Chiasson said market participant data requirements are largely unchanged from prior years, adding that the Monitor has already asked for two years of planning data.
“I don’t think it will be work wasted,” Chiasson said. “But it would have been nice to know before the work started.”
Tim Bachus, MISO capacity market administration analyst, said the 2017/18 PRA is on schedule. He said 94% of market participants have submitted data for the Generator Verification Test Capacity reporting.
MISO is considering other improvements for the PRA — in addition to a proposal for seasonal categories and six new external resource zones — while awaiting FERC’s verdict on a request to implement a bifurcated capacity market.
Harmon said the RTO is seeking stakeholder evaluation of five potential changes, including:
Penalizing participating units that expect to be on planned or forced outages for most the planning;
Relaxing auction accreditation rules for hydroelectric assets that serve as load-serving entities, rules that MISO says might be too “onerous” and might not recognize capacity benefits;
Improving the partial unit clearing algorithm, which Harmon says clears marginal offers on a pro rata basis “that can result in resources clearing a small percentage of their unforced capacity, resulting in capacity revenue less than their costs”;
Creating a capacity accreditation formula for battery storage before widespread adoption of batteries occurs; and
Clearing up MISO rules and the Tariff with respect to treatment of behind-the-meter generation in the capacity auction.
Chris Plante of WEC Energy Group asked if any of the improvements could be implemented by the 2017/18 planning year.
With stakeholder support, improvements will be discussed throughout 2017 and implemented in the 2018/19 planning year, alongside the first separate forward capacity market for retail choice areas, Harmon replied.
MISO has sidelined the discussion of seasonal and locational auction issues until February, RASC liaison Shawn McFarlane said.
“Certainly the [Competitive Retail Solution] is the primary objective and we need to get that through before we tackle too much, but we’re looking at other resource adequacy improvements, including seasonal and locational improvements,” McFarlane said.
Leffler questioned whether seasonal constructs should continue to be a priority, given that stakeholder support has cooled since MISO revealed design specifics last year.
“I’d encourage people to provide that feedback,” Leffler said to stakeholders.
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.
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 (
