NERC announced Saturday that an employee in its Atlanta office has “notified leadership of a presumptive positive test” for the COVID-19 virus.
According to a press release, the unidentified employee last visited the office on March 10. NERC said it has informed FERC of the possible infection, along with building management at the Atlanta Financial Center, the site of its headquarters. The organization is currently identifying and notifying those who have been in close contact with the employee and asking them to self-quarantine at least until March 24, in addition to disinfecting its offices.
NERC issued a Level 2 Alert on March 10 in connection with the COVID-19 outbreak and has been shifting its upcoming meetings to conference calls or video conferences in light of safety recommendations from global health authorities and travel restrictions by many stakeholders. Last week, the organization announced the second quarter meetings of its Board of Trustees and Member Representatives Committee, scheduled for May 14, would also be conducted online.
“This case shows us the importance of self-reporting and self-quarantining,” said CEO Jim Robb. “When the outbreak began, NERC activated its business continuity plan and instituted a work-from-home policy to better safeguard the health and well-being of our workforce and their families … We wish a full and speedy recovery to our valued team member.”
FERC and NERC also announced last week that, during the pandemic, they would use regulatory discretion to relax compliance actions relating to some reliability standards. The regulatory easing so far is limited to delays in obtaining and maintaining personnel certification, failure to perform required period actions and postponing on-site activities such as audits and certifications. However, additional measures may follow depending on the trajectory of the outbreak. (See FERC, NERC Relax Compliance in Light of COVID-19.)
The World Health Organization’s latest situation report indicates nearly 333,000 cases of COVID-19 have been recorded worldwide since the disease was first identified in Wuhan, China. More than 14,500 deaths have been attributed to the virus globally.
Pacific Gas and Electric said Monday it will plead guilty to 85 felonies stemming from the Camp Fire in November 2018, including 84 charges of involuntary manslaughter, a subset of homicide involving criminally negligent behavior.
“Today’s charges underscore the reality of all that was lost, and we hope that accepting those charges helps bring more certainty to the path forward so we can get victims paid fairly and quickly,” CEO Bill Johnson said in a statement.
The plea deal comes days after California Gov. Gavin Newsom agreed to drop his objections to PG&E’s reorganization plan with the caveat that the utility could be put up for sale if a federal bankruptcy judge doesn’t approve the plan by June 30. (See PG&E Deal with Gov. Allows for Utility’s Sale.)
The Camp Fire tore through Paradise, Calif., on Nov. 8, 2018, killing 86 people. | Tanner Hembree/USDA Forest Service
The Camp Fire was the deadliest and most destructive in state history. It started when a worn C-hook on a transmission tower broke, releasing a high-voltage line that ignited dry vegetation, according to the California Department of Forestry and Fire Protection (Cal Fire).
PG&E’s faulty maintenance of its century-old Caribou-Palermo line was cited as the cause of the equipment failure. (See Cal Fire Pins Deadly Camp Fire on PG&E.)
Within hours after ignition, flames raced through the rugged forested countryside of the Sierra Nevada foothills and into the town of Paradise, with a population of 27,000. It destroyed more than 14,000 homes and 500 businesses. The death toll from the fire was 86, Cal Fire said.
One person committed suicide as flames approached, and another died from a heart attack while fleeing the blaze, law enforcement officials have said. PG&E was not charged in those deaths.
PG&E will also plead guilty to a felony count of unlawfully starting a fire with enhancements for causing great bodily injury to multiple people, for injuring firefighters and for burning numerous structures, according to the plea agreement filed by the Butte County District Attorney’s Office.
The utility agreed to pay the maximum fine of nearly $3.5 million and to reimburse the prosecutor’s office $500,000 for its investigation, which resulted in a grand jury indictment of PG&E, the DA’s office said. PG&E has cooperated with law enforcement and accepted criminal responsibility, prosecutors said.
Nothing prevents crime victims from seeking restitution from PG&E, but the utility told the federal bankruptcy judge overseeing its Chapter 11 case that it hopes any payments will come from the $13.5 billion trust it already plans to establish to compensate wildfire victims. (See Federal Judge to Review PG&E’s Wildfire Plan.)
PG&E filed for bankruptcy protection in January 2019 as it faced an estimated in $30 billion in liabilities from the Camp Fire and a series of devastating blazes in Northern California wine country in October 2017.
Butte County District Attorney Michael Ramsey cited PG&E’s reorganization plan, which the utility is trying to have approved by the end of June, as a motivating factor for the plea deal. (See Judge OKs PG&E’s $23B Plan to Exit Bankruptcy.)
There is a “significant risk that a further criminal prosecution of the company at this time could jeopardize the company’s ability to pay victims,” Ramsey wrote in his court filing. PG&E has also committed to paying local governments and agencies $1 billion, including $270 million to the town of Paradise and $252 million to Butte County, the prosecutor said.
Prior Felonies and Probation
The plea deal is still subject to approval by state and federal courts. If that occurs, PG&E will have been found guilty of 101 felonies in the past four years.
Jurors in August 2016 convicted the utility of six felonies related to the San Bruno gas pipeline explosion in 2010, including pipeline safety violations and obstructing a federal investigator. The disaster killed eight people and burned down part of a suburban San Francisco neighborhood.
The company remains on criminal probation in the case, and new convictions could violate the terms of that probation. Federal Judge William Alsup has been a vocal critic of the utility at its probation hearings; whether he will impose new measures remains a question.
Satellite imaging showed damage from the Camp Fire. on Nov. 16, 2018. | NASA
Stanford University law Professor Robert Weisberg, an expert in white collar crime and sentencing, said Alsup could levee additional fines or place the company in receivership, but he doubts that will happen.
“This is an unusual situation,” Weisberg said. “PG&E is already in so much trouble and involved in so many legal entanglements [that] the incremental effect of additional criminal convictions may not be so significant.”
PG&E is already facing huge financial liabilities in its nearly $60 billion bankruptcy case and has agreed to stricter oversight by the California Public Utilities Commission, including the possibility of losing its electric monopoly.
The number of manslaughter counts may be the most homicides an American corporation has ever been charged with, Weisberg said.
Another corporation might be so stigmatized by lesser criminal convictions that it would go out of business, he said. He cited the Arthur Andersen accounting firm, brought down by its wrongdoing connected to the Enron scandal in the early 2000s, including a conviction for obstruction of justice.
PG&E is different, Weisberg said. California’s largest utility is notorious for its wrongdoing over the years yet remains in business.
“Everybody now thinks of PG&E as such a feckless, pathetic entity,” he said. “This may not have as much of a punch.”
MISO’s effort to implement a new cost allocation method for large economic transmission projects was dealt a major blow last week when FERC rejected the plan for a second time (ER20-857).
At the heart of the issue was the same new local economic project category, meant for smaller, economically driven transmission projects between 100 kV and 230 kV, where 100% of costs would be allocated to the local transmission pricing zone containing the line.
MISO altered its original filing so that local economic projects had to pass only a local benefits test, no longer requiring them to demonstrate a regional 1.25:1 benefit-to-cost ratio while only allocating their costs to the local transmission pricing zone where they are located.
But FERC pointed out that MISO’s latest proposal would have still effectively measured the value of a local economic project on a regional basis through use of three benefit metrics used on regionally allocated projects — with the project costs shared at only the local level.
| MISO
“[T]he proposed cost allocation method inappropriately relies on a benefits metric, the MISO-SPP Settlement Agreement metric, that determines benefits outside of the local transmission pricing zone where the local economic project is located, but then disregards these benefits by allocating costs for the project solely within that transmission pricing zone,” FERC said. ” … [T]he proposed local economic project local benefits analysis will likely require MISO to disregard regional transmission benefits that it will necessarily uncover when applying the MISO-SPP Settlement Agreement costs benefit metric.”
MISO’s proposal would have lowered the voltage threshold for its market efficiency projects from 345 kV to 230 kV, eliminated the current 20% postage stamp allocation and added new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path. The proposal also would have provided limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability. As it did with the first rejection, FERC again said it had no problems with the other aspects of the plan.
Some stakeholders had previously argued that MISO’s revised proposal still wrongly presumed that all sub-230 kV projects cannot deliver regional benefits. They said the projects shouldn’t be excluded from a regional allocation when appropriate. (See MISO Makes U-turn on Cost Allocation Policy.)
FERC seemed to agree, saying MISO’s proposal to use the adjusted production cost savings metric would have required RTO staff to be willfully blind to some benefits of the smaller projects for purposes of cost allocation.
“It is incongruous to state that a metric is the most reliable measure of benefits, and then to ignore that measure for purposes of cost allocation for local economic projects,” the commission said.
Interregional Filing Also Rejected
In a separate order, FERC similarly ruled out MISO’s companion filing to update its cost allocation for interregional projects with PJM over the same deviation from the cost-causation principle. (ER20-862).
The commission ordered MISO to instead use a design based on adjusted production costs for economic interregional projects 100 kV and above with PJM, exercising its authority to ensure just and reasonable rates.
FERC said MISO should use its existing adjusted production cost savings metric to allocate its share of the cost of MISO-PJM interregional economic transmission projects.
Using MISO’s own words, FERC said the adjusted production cost savings metric “has been regarded as one of the most reliable measures of the net economic impact of a planning decision on energy cost in MISO.”
A new cost allocation for MISO’s share of interregional projects with PJM was necessary under a six-year-old FERC compliance directive requiring MISO to lower its interregional market efficiency project voltage threshold to 100 kV. MISO and PJM were ordered by FERC in 2013 to lower thresholds after the Northern Indiana Public Service Company complained about shortfalls in the RTOs’ interregional planning process.
“While we recognize the complexity of the issues underlying MISO’s proposal, we also recognize the need for MISO to come into compliance with the NIPSCO compliance order’s directive in a timely manner,” FERC said.
The commission said it rejected the filing without prejudice because the interregional allocation proposal referred to and relied on provisions in MISO’s regional cost allocation filing. The RTO also filed in January to create a cost allocation for its share of some interregional projects with PJM and had also proposed that its share of interregional economic projects with voltages below 230 kV — but at or above 100 kV — be allocated 100% to the transmission pricing zones where the project is located.
UPDATED March 24: PJM announced it has canceled its annual meeting in Chicago on May 4-5 but will hold a Members Committee meeting via WebEx on May 4. The RTO also said it has extended the WebEx-only stakeholder meetings and its employee work-from-home policy until at least April 10.
By Rich Heidorn Jr. and Michael Yoder
PJM announced Monday it will hold a weekly call beginning Friday to update stakeholders on operational impacts from the COVID-19 pandemic. The calls, from 11 a.m. to noon, will continue until further notice.
The RTO said data from March 17 to 19 show the normal 8 a.m. morning peak has shifted to 9-10 a.m., and the evening peak is about 5% lower than expected. “The load curve also is flatter, without the same fluctuations usually shown by morning and evening peaks and valleys, when people are preparing for work in the morning or dinner at night,” PJM said. “The impact so far has been noticeable, but not severe,” said Michael Bryson, senior vice president of operations. “This is similar to patterns we typically see on a snow day.”
PJM said telecommuters may be getting up later without having to commute. While commercial use of electricity is down with schools and businesses closed or operating remotely, the reductions will be partially offset by an increase in residential use.
PJM actual load on March 17 compared to a similar day model pre-coronavirus | PJM
On Monday, March 16, when PJM would normally have expected about 100,000 MW of load, it lowered its forecast to 94,500 MW. Load came in at about 95,500 MW.
PJM has implemented a work-from-home policy through April 10 for employees, with the exception of system operators and other shift personnel. Employees are also working longer shifts to minimize shift changes. The RTO said it successfully tested its work-from-home capabilities on March 13. PJM markets, planning, stakeholder meetings and member relations can all be operated remotely, it said.
On Friday, PJM opened a survey of its generation operators to identify operational risks resulting from the COVID-19 pandemic. PJM said the survey, in the eDART application, will remain open indefinitely to allow updated responses as conditions change.
PJM’s eDART application | PJM
The survey includes both company- and unit-level questions to identify potential delays or restrictions on fuel and consumable item deliveries and contractor and staff health concerns that may impact scheduled outages.
Are you currently experiencing any workforce impacts (either plant personnel or contractors) that could impact the unit’s availability or reliability in any way?
Regarding outages that are currently active, do you foresee any chance of needing to extend the duration of the outage to complete the work to return the unit to service?
Regarding outages currently scheduled over the next 12 weeks but not yet started, do you foresee the need to cancel or postpone these due to contractor or resource limitations?
Are you aware of any staffing limitations on any of your fuel suppliers, including gas pipeline operators?
Do you anticipate any changes to any of your unit’s operational parameters (e.g., emergency minimums, minimum down time etc.)?
Is there anything PJM can do to help support any specific needs of this unit during this period?
The survey asks for ideas on best practices. “Examples could include: Segregating MOC dispatchers to multiple locations; limiting interactions between shift personnel (MOC or Plant) as much as possible; implementation of enhanced cleaning processes; evaluation of upcoming outages to determine the feasibility of deferral.”
Lower natural gas prices and increased renewable penetration pushed wholesale power prices down sharply in most of the country last year, FERC reported last week.
The commission’s 2019 State of the Markets report noted that prices dropped 20% to 30% in MISO, PJM, NYISO and ISO-NE compared with 2018. Prices in northern CAISO were down 10%, and those in southern CAISO down 20%.
SPP’s prices were the lowest of the organized markets, averaging $30.43/MWh, unchanged from a year before, according to the report by the Office of Energy Policy and Innovation’s Division of Energy Market Assessments (DEMA).
Only ERCOT saw an increase, as record-high demand in summer pushed prices for the year to $49.65/MWh, up 20%.
Natural Gas
Although natural gas demand hit new highs, record-high production and relatively mild weather resulted in price declines of 35% to 41% at hubs in the Mid-Atlantic, New England and New York City. The biggest drops were in the Southwest, where hubs traded at negative prices at times because of pipeline takeaway capacity constraints.
U.S. natural gas production rose to 92.2 billion cubic feet per day (Bcfd) in 2019, up 8.4 Bcfd, the second-largest increase since the advent of shale exploration. Net gas exports averaged 5.1 Bcfd through November 2019, up from 1.9 Bcfd in 2018.
U.S. natural gas pipeline in-service capacity additions by region (Bcfd) | FERC Office of Energy Projects
Natural gas shippers added nearly 5 Bcfd (17 miles) of commission-jurisdictional pipeline capacity in 2019, down from the 13 Bcfd added in 2018.
Overall natural gas demand increased 2.6 Bcfd to 84.9 Bcfd in 2019, a 3% jump. Demand for electric generation averaged 30.9 Bcfd, up 7%, with a 12% increase in the Midwest.
Fuel Mix
Natural gas was responsible for 42% of generation nationwide between January and November 2019, according to the Energy Information Administration (EIA), with 26% from coal, 22% from nuclear, 4% from wind and 1% from solar.
MISO and SPP were most dependent on coal, which accounted for 43% of the regions’ generation. Solar and wind were big contributors in CAISO and SPP, respectively.
As in recent years, most new generation was natural gas or renewables and most retirements were coal plants.
Generation by fuel type | ABB Velocity Suite
The biggest retirements were the 670-MW Pilgrim Nuclear Power plant in ISO-NE (May 2019) and the 980-MW Three Mile Island nuclear power plant in PJM (September 2019).
PJM added 356 MW of natural gas-fired capacity, mostly combined cycle units. MISO saw a net decrease of 852 MW as it lost 2.9 GW of coal-fired capacity and gained 969 MW of natural gas and 997 MW of wind capacity.
SPP added 1.8 GW of wind capacity and had no retirements in 2019.
CAISO’s capacity dropped by 21 MW, losing 600 MW of natural gas capacity and adding 561 MW of solar.
Storage, DERs
Battery storage capacity increased by 174 MW in 2019, down from a 202-MW boost in 2018. But EIA forecasts about 400 MW of new battery storage will be added in 2020 and 1,816 MW in 2021.
“While it is unlikely all planned facilities will be operational by the end of 2021, the large increase represents a sea change in the role that battery storage plays in the bulk power system,” FERC said.
Battery storage capacity additions in recent years | EIA Form 860M
Battery storage additions have been clustered in a few states, led by California with 38% percent of planned capacity through 2023.
Capacity from distributed energy resources using net metering rose 4 GW to a record 23 GW in 2019, most of it in California, New Jersey, Massachusetts, Arizona and New York. The five states represent 70% of the net-metered capacity in the country, including California’s 40% share.
All but 6% of net metered capacity is solar PV. Solar PV’s price dropped 37% between 2013 and 2017, FERC said.
Transmission
Order 1000 transmission planning regions had 309 transmission projects go into service during the year, led by MISO (104) and PJM (101). In 2019, PJM, ISO-NE and NYISO each announced, or awarded to developers, new transmission projects using the competitive bidding processes in Order 1000.
Transmission additions by transmission planning region | C Three Group
FERC on Friday rejected rehearing requests by American Municipal Power and Illinois Municipal Electric Agency over the commission’s November 2017 order approving PJM’s tougher requirements for pseudo-tied generators. The commission also approved PJM’s December 2017 compliance filing required by the order (ER17-1138).
“The commission found that PJM’s new pseudo-tie requirements would help ensure that external resources bidding into the PJM capacity auctions are comparable to internal resources in assuring that they will be deliverable to PJM’s system when needed,” FERC said last week. “With this principle in mind, we continue to find that PJM’s proposed treatment of pseudo-tied resources is just and reasonable.”
AMP’s Challenge
AMP’s rehearing request alleged five errors by the commission, including a challenge to PJM’s decision to set the electrical distance requirement at 0.065 per-unit impedance. AMP said the commission “failed to weigh and substantiate the impact of the proposed electrical distance requirement with the level of reliability assurance” and “failed to address the relationship between the value selected as the electrical distance requirement and the impact on PJM’s state estimator.”
| PJM
PJM said the 0.065 threshold was based on a distribution factor analysis (DFAX) to identify the external facilities that would be impacted by PJM’s dispatch of external resources. PJM said the distance requirement made at least 130 GW of existing external resources in the Eastern and Midwestern U.S. eligible for pseudo-ties. The commission accepted PJM’s threshold, saying it was the “result of significant analysis and requiring PJM to rely on an external resource with a higher impedance value would increase the risk to PJM’s state estimator.”
The commission reiterated its previous finding that the electrical distance requirement was just and reasonable “because establishing a bright-line test for external participation strikes an appropriate balance between allowing external resources to participate in PJM’s capacity auctions, while providing PJM with a level of reliability assurances.”
IMEA’s Arguments
IMEA questioned FERC’s interpretation of Section 217(b) of the Federal Power Act and whether the commission’s decision “violated the sanctity of contracts.”
The agency argued that the commission’s determination that Section 217(b) of the FPA only applies to the energy markets and not capacity markets “effectively destroys the self-supply rights of load serving entities (LSEs).”
It said that if Section 217(b) does not apply to capacity markets, then PJM and other RTOs could make filings through Section 205 of the FPA to eliminate all “self-supply options” based on a finding that having control of all resources and planning would ensure better reliability.
FERC was unmoved. “Unlike energy markets, RTOs implement capacity markets to ensure long-term reliability and resource adequacy and, therefore, different requirements for using generation may be applied to capacity and energy markets,” the commission said.
FERC last week accepted Tri-State Generation and Transmission Association’s petition for a declaratory order that recognizes the cooperative as jurisdictional to the commission when it added its first non-utility member last year (EL20-16).
The commission agreed with Tri-State’s contention that the admission last September of Mieco, a wholesale energy services company that provides natural gas to Tri-State and other purchasers, made the cooperative a non-exempt jurisdictional public utility for purposes under the Federal Power Act (FPA).
FERC found that since Sept. 3, Mieco has “continuously been earning patronage capital through its sales of natural gas below index prices” and that Mieco and Tri-State have engaged in transactions that generated patronage capital — or the difference between a cooperative’s yearly operating income and expenses. It said Mieco has a vote in Tri-State’s operations “tailored to its status as a non-utility member,” noting that although the natural gas marketer holds voting rights different from those held by utility members, the commission has not found that the FPA “requires that owners have equal levels of control to demonstrate ownership.”
It said because no party provided evidence countering Tri-State’s claim that Mieco is not an exempt entity under the FPA, Tri-State “has demonstrated that Mieco’s rights are sufficient … to establish that Tri-State has not been wholly owned by entities exempt under [the FPA] since Sept. 3.
“Tri-State is grateful to FERC for its actions today and looks forward to working with FERC in a constructive manner for the benefit of Tri-State’s members,” Tri-State CEO Duane Highley said in a statement.
Tri-State G&T’s service territory spans much of the Rockies. | Tri-State
The company noted that it advances member flexibility for more self-supply and local renewable energy development. As part of Tri-State’s Responsible Energy Plan, members have additional flexibility for the self-supply of power and more local renewable energy development.
Partial requirements contracts address the concerns of some members that desire self-supply above the 5% provisions in their current contracts.
Tri-State also requested relief to terminate controversy and remove uncertainty due to pending complaints filed in November before the Colorado Public Utilities Commission by members La Plata Electric Association and United Power. The cooperative said the utilities asked the PUC to “establish an exit charge [for the Member to be relieved of its obligations under its Wholesale Service Contract and exit Tri-State] that is just, reasonable, and nondiscriminatory.”
FERC said that while it had jurisdiction over Tri-State’s exit charges, it declined to rule that the jurisdiction is exclusive, recognizing that no federal court has found the commission has exclusive jurisdiction over “rules or practices that directly affect a jurisdictional rate.
“We find that the Colorado PUC’s jurisdiction over complaints before it regarding Tri-State’s exit charges is not currently preempted,” FERC wrote. “A ruling by the Colorado PUC on those complaints would not be preempted unless and until such ruling conflicts with a commission-approved Tariff or agreement that establishes how Tri-State’s exit charges will be calculated.”
Tri-State is a generation and transmission cooperative that provides wholesale electricity to 43 member electric distribution cooperatives and public power districts in Colorado, Nebraska, New Mexico and Wyoming.
Other Tri-State Requests Accepted
The commission also issued four other orders related to Tri-State’s request for FERC jurisdiction that the cooperative said ensure “consistent wholesale rate regulation” for its member distribution utilities. Those orders:
Granted Tri-State’s and Thermo Cogeneration Partnership’s request for market-based rate authorization. FERC denied Tri-State’s request for certain waivers and blanket authorization and granted Thermo Cogen’s request for waivers commonly granted to market-based rate sellers (ER20-681).
Found that Tri-State and Thermo Cogen had rebutted the presumption of market power in the Western Area Power Administration’s Colorado-Missouri balancing authority area and that they met the criteria for Category 2 sellers in the Northwest, Southwest and SPP regions and Category 1 sellers in the Southeast, Northeast and Central regions.
Denied Tri-State’s request for regulatory waivers and blanket authorizations, saying it does not typically grant waivers where the seller makes sales at cost-based rates.
Accepted Tri-State’s stated rate Tariff and wholesale electric service contracts and instituted a Section 206 proceeding under the FPA to determine whether the cooperative’s Tariff and electric service contracts are just and reasonable. The order establishes a refund effective date, as well as hearing and settlement judge procedures (20–676).
Found that Tri-State’s filings raised issues of material fact that could not be resolved based on the record before it, saying they would be more appropriately addressed through hearings. It accepted the cooperative’s state rate Tariff and wholesale contracts to be effective Feb. 22 and Feb. 25.
Accepted Tri-State’s Tariff and instituted a Section 206 proceeding and hearing and settlement judge proceedings (ER20-686).
FERC’s 206 investigation will determine whether Tri-State’s proposed formula rate, base return on equity (ROE), formula rate implementation protocols, reactive supply and voltage control service rates and real power loss factor are just and reasonable.
The commission also accepted Tri-State’s proposed service agreements and a notice of cancellation for filing. It held two contested cancellation notices in abeyance. It rejected without prejudice a board policy that describes members’ option to use self-owned or -controlled distributed or renewable generation resources to serve up to 5% of that members’ requirement (ER20–689).
FERC also found the cooperative’s board policy and generation contracts are deficient without another board policy on file that comprises specific rate mechanisms, terms and conditions that significantly affect the rates utility members must pay if they produce energy in excess of the 5% allowance. It directed Tri-State to refile the rate schedules. The commission did accept the cooperative’s bylaws and other rate schedules for filing.
Commission Partially Accepts GridLiance Filing
The commission found that GridLiance High Plains’ amendments to FERC’s pro forma large generator interconnection agreement (LGIA) and pro forma large generator interconnection procedures partially comply with requirements of orders 845 and 845-A, requiring a further compliance filing within 120 days (ER19–1961).
The commissioners said GridLiance’s proposed revisions regarding the option to build transmission partially comply with the orders’ requirements because they incorporate most of their language without modification. However, FERC found that GridLiance had not justified its proposal to retain language of its pro forma LGIA that the commission removed from FERC’s pro forma LGIA in the revisions set forth in the orders.
The language at issue provides that the “interconnection customer shall so notify transmission provider within 30 calendar days” as required by orders 845 and 845-A.
FERC on Thursday approved a new MISO Tariff provision that allows transmission owners to recover interconnection facility operations and maintenance costs from interconnection customers.
The decision allows MISO to include a new rate schedule — Schedule 50 — to allow TOs to recoup costs from interconnection customers for “reasonable expenses, including overheads, associated with operation and maintenance, and repair” of TO-owned interconnection facilities (ER20-170).
MISO TOs filed in October for the new rate schedule.
“While relevant provisions of a MISO generator interconnection agreement … already explicitly provide that interconnection customers ‘shall be responsible’ for all reasonable [operations and maintenance] expenses, there is presently no mechanism in the Tariff to enable the calculation and recovery of such expenses from interconnection customers,” the TOs explained to FERC.
MISO joined the filing as administrator of its Tariff but took no stance on the proposed revisions.
The TOs plan to allocate O&M annual charges based on a calculation involving the interconnection facilities’ installed costs as a share of a total annual transmission gross plant. When installed costs aren’t available for calculation, TOs will have to submit filings so FERC can review the alternate calculations.
In accepting the new schedule, FERC disagreed with renewable energy proponents that the Schedule 50 approach would “unduly” shift costs to interconnection customers. Some had argued that a process including transmission facilities didn’t translate well for interconnection facilities because they’re newer and less prone to maintenance charges. But the commission said the average useful life or O&M costs of an interconnection facility aren’t much different than the average useful life or O&M costs “of other similar transmission facilities.”
Other clean energy advocates said O&M costs should be assigned directly to interconnection customers instead of using a calculation. FERC again disagreed.
” … [E]ven in the instances where transmission owners utilize direct billing, not all costs are able to be directly assigned, some are assigned based on various allocators, and some costs are not even recovered,” the commission explained.
FERC on Thursday accepted changes to the New England Transmission Owners’ (NETOs) interconnection study deadlines and the scope of their feasibility studies (ER19-1952).
However, the commission only partially accepted a separate Order 845/845-A compliance filing by ISO-NE and NETOs to reflect the orders’ changes to the commission’s pro forma large generator interconnection agreement (LGIA) and large generator interconnection procedures (LGIP), ordering a further compliance filing within 120 days (ER19-1951).
Renewable developers EDF Renewables, E.ON Climate & Renewables N.A. and Enel Green Power N.A. had argued that the revised deadlines — extending the feasibility study from 45 to 90 days and the system impact study (SIS) from 90 to 270 days — are unreasonably ambitious. They noted ISO-NE’s severe backlog, with feasibility studies averaging 229 days and SIS averaging 443 days.
But the commission said it expects “that the average study lengths will drop due to the reduced scope of the feasibility study and due to the other interconnection process improvements,” citing expanded use of consultants and a streamlined approach for managing SIS models and data.
EDF Renewables’ Williston solar project in Vermont became operational in 2016. | EDF Renewables
Under the previous rules, many interconnection customers that chose the separate feasibility study later modified their projects before the SIS, reducing the time savings from conducting the feasibility study first. The new rules eliminate the option to integrate the feasibility study within the SIS and allow customers to forgo the feasibility study. Feasibility studies will be reduced to a limited power flow analysis, instead of the full power flow analysis allowed previously.
Regarding the LGIP filing, the commission found that it proposed, “without justification, language that differs in one respect from the commission’s requirements related to the process for analyzing surplus interconnection service requests.”
The filing parties explained in their transmittal letter (but did not specify in proposed Tariff revisions) that ISO-NE would limit the analysis it performs to its existing 10-business-day material modification framework for accommodating technological changes. The commission said it “may be inadequate to complete the evaluation required under Order No. 845.”
The commission required a further compliance filing to address the stand-alone network upgrades definition; interconnection customers’ ability to exercise the option to build; NETOs’ proposal to recover actual costs rather than a negotiated amount for oversight costs related to the option to build; the method for determining contingent facilities; requests for interconnection service below generating facility capacity; provisional interconnection service; and both the process and definition for surplus interconnection service.
FERC Partially Accepts Emera Maine Filing
FERC on Thursday also accepted amendments to Emera Maine’s LGIA and LGIP but ordered a further compliance filing within 120 days (ER19-1887).
The commission found that the revised dispute resolution procedures in the company’s LGIP comply with Orders 845/845-A and that the variations are “consistent with or superior” to them. “However, the deadlines in Emera Maine’s proposed dispute resolution timeline contain an apparent incongruity,” the commission said, ordering a further compliance filing to address a five-day discrepancy in stated terms.
The commission found that the LGIP’s method for determining contingent facilities is in partial compliance but that proposed criteria for identifying contingent facilities “lack the requisite transparency.” It ordered the company to describe the specific technical screens, analyses, triggering thresholds or criteria it will use to identify such facilities.
The commission also ordered further compliance filings to incorporate pro forma revisions to section 3.1 of its LGIP; to revise section 4.4.6 to clarify how it will assess changes to a generating facility’s technical specifications; to clarify the deposit amount the interconnection customer is required to tender; and to specify that Emera Maine will complete its assessment and determination of whether a proposed technological change is a material modification within 30 days of an interconnection customer submitting a technological change request.
Wednesday’s Planning Advisory Committee meeting opened with stakeholders asking for information on proposals generated by ISO-NE’s first competitive transmission solicitation in December.
The RFP seeks to address reliability concerns over the planned retirement of the Mystic Generating Station near Boston. (See ISO-NE Issues First Competitive Tx RFP.)
The RTO “received 36 Phase One proposals prior to the submission deadline of March 4, with costs ranging from about $49 million to $745 million,” said ISO-NE Director of Transmission Planning Brent Oberlin. In-service dates ranged “roughly” from mid-2023 to 2026, he said.
“Right now, the ISO is weeding its way through all the proposals … and we have received a number of requests to publish them,” Oberlin said. “Our current policy is that we want to release that information together with the ISO’s draft determination.”
Oberlin noted that eight qualified transmission project sponsors submitted bids. Among them was Anbaric, which on Thursday announced details of its proposed 900-1,200 MW Mystic Reliability Wind Link project, including an option for an additional 1,200 MW.
In response to a question from Sebastian Libonatti, of Avangrid Networks, Oberlin said ISO-NE would not immediately release executive summaries of the various proposals. In a Thursday memo, the RTO explained it would wait 175 calendar days to divulge proposal details because of concerns over inadequate or inaccurate information in some of the proposals.
ISO-NE’s memo said that some proposals do not meet the identified needs, or violate the Tariff, and that due to the two-phase solicitation process, some of the initial proposals’ life-cycle costs are misleading.
“Posting a list of the Phase One Proposals with these potential serious flaws without noting them will not facilitate meaningful stakeholder discussion or review and will result in wasted effort as non-compliant proposals are evaluated,” the memo said.
During Wednesday’s meeting, Phelps Turner, a senior attorney for the Conservation Law Foundation in Maine, said, “We also want to flag that we have due process concerns with the proposed schedule, which should be expedited to ensure openness and transparency, planning principles that were clearly outlined in [FERC] Order 1000, and we also want to make sure we set a good precedent with this first competitive procurement [in New England].”
Turner told RTO Insider that the CLF was concerned about the evaluation process for all proposals, not just for any single bid.
“Order 1000 says that stakeholders must be provided an opportunity to participate in the process in a timely and meaningful manner,” Turner said, comparing the 175 days the RTO is taking to the week or so its solicitation schedule provides for stakeholders to see the proposals and submit comments.
“It’s standard practice in the legal community to share redacted versions, and while we would prefer the unredacted proposals be published, redacted ones are better than nothing,” he said.
Modeling More Offshore Wind, Slowly
ISO-NE presented the PAC preliminary results of the Anbaric 2019 Economic Study for scenarios adding from 8,000 to 12,000 MW of offshore wind in southern New England, which it found causes export interface congestion in the Southeastern Massachusetts/Rhode Island (SEMA/RI) interface.
The assumptions include retirements of nearly 4,500 MW.
The RTO’s lead engineer for system planning, Haizhen Wang, led discussion of the study, which compared the Anbaric results to those presented at last month’s PAC from a similar study requested by the New England States Committee on Electricity (NESCOE). (See ISO-NE Planning Advisory Committee Briefs: Feb. 20, 2020.)
NESCOE, Anbaric and RENEW Northeast had requested separate analyses at the April 2019 PAC meeting.
The new analysis found that interconnecting more OSW close to load centers outside of the SEMA/RI areas (such as the Mystic and Millstone substations) would reduce the congestion hours of the SEMA/RI export interface.
Total renewable spillage in the Anbaric_8000 scenario, primarily OSW and hydro, decreases approximately 50% compared to the NESCOE scenario. This is because the assumed nuclear retirements decrease the energy oversupply in the Anbaric scenario. | ISO-NE
Retirement of large baseload must-run nuclear generation would lower spillage associated with over generation, the report said.
Theodore Paradise, Anbaric senior vice president for transmission strategy and counsel, asked about a rise in natural gas energy production under both constrained and unconstrained scenarios for 8,000 MW OSW, which assumes new OSW insufficient to cover the retired nuclear generation.
Peter Wong, ISO-NE manager for resource adequacy, said that more assumed nuclear retirements means fewer hours of oversupply, during which the RTO would otherwise spill the offshore wind.
“As [OSW] increases to 10,000 MW and 12,000 MW, does the natural gas run in terms of amount decrease?” Paradise asked.
“As we add more offshore wind to the system, the need for other generating resources would decrease when the offshore wind is not constrained by export limits,” Wong said. “That’s why the natural gas generation keeps decreasing as we add additional offshore wind to the system.”
The RTO plans to present additional spillage and marginal emissions results from the NESCOE study in April, complete ancillary service analysis by May and publish the final report by June 1, Wang said.
The Anbaric study will see additional GridView results presented with 2015 load/PV/wind profiles in April, with the final report to be published in June or July. The RTO also will present NESCOE and Anbaric transmission cost estimates in March and April.
If time does not permit a presentation at the PAC, the RTO will still make the relevant information available to stakeholders, Wang said.
The RENEW GridView results with 2015 load/PV/wind profiles will be presented in April, and the final report in July.
Draft 2020 CELT Load Forecast
Jon Black, manager of load forecasting, presented an update on the annual 10-year forecasts of energy and demand that the RTO publishes as part of the capacity, energy, loads and transmission (CELT) report.
He focused on the heating and transportation electrification forecasts newly included in CELT 2020, saying that the usual topics of gross energy, summer demand and winter demand forecasts, as well as energy efficiency and solar forecasts will be discussed in more detail at the April PAC.
The 2020 heating electrification forecast focuses on the adoption of air-source heat pumps (ASHPs), currently the most prevalent heat pump technology, he said.
“Heating electrification is a nascent trend,” Black said, noting that the emergence of other technologies, such as ground-source heat pumps, may warrant consideration in future forecasts.
Final draft 2020 heating electrification forecast in terms of monthly energy (GWh) | ISO-NE
One stakeholder wondered how the RTO could estimate the effect of ASHPs on load while only using three winter months of data.
“We’re mapping it to heating degree days, which is a variable that we use in our forecast models,” Black said. “In general, when it gets cold, you use your heat pumps more, and we are mainly focusing on getting the winter demand impact as good as we can, which is why we focused on more of the colder months.
“Essentially, those colder months yield a relationship between how cold it is and how much electricity you use before and after installing a heat pump,” he said. “We apply those assumptions to all the months and days in our forecast where you have heating degree days.”
A related presentation at last month’s PAC showed that heat pumps and plug-in electric vehicles make up only 4% of projected 2030 annual net load, which spikes to about 10% during winter evening peaks. But the draft CELT shows EV load impact steadily rising from near zero today to 1.2% of load and nearly 180 GWh in terms of monthly energy in January 2030.
Final draft 2020 EV forecast in terms of monthly energy (GWh) | ISO-NE
The EV forecast in the draft CELT estimates the adoption of electrified light-duty vehicles for each state and the region over the next 10 years, both battery-electric vehicles (BEV) and plug-in hybrids (PHEV), Black said.
The RTO takes the adoption estimates and extrapolates monthly demand and energy impacts per EV based on recent historical EV charging data licensed from ChargePoint. It developed energy and demand assumptions based on an aggregate EV charging profile reflecting between 118 and 247 EV drivers across the region between June 2018 and May 2019.
The aggregate profile reflects 78% residential and 22% non-residential, he said.
Natural Gas Use Rises in NE
Tom Kiley, CEO of the Northeast Gas Association, gave a brief review of the natural gas industry in the region, as well as of what turned out to be a mild winter. He referred to a separate winter review posted that day by the RTO for stakeholders seeking greater detail on the season.
“We plan for a lot of eventualities and scenarios, but certainly this COVID-19 pandemic is quite extraordinary … and clearly emphasizes how industry coordination and communication during challenging times remain of critical importance,” Kiley said.
U.S. natural gas production in 2019 set new all-time records (92.2 Bcf/d), as did consumption (85 Bcf/d).
“The EIA reported U.S. natural gas consumption grew in the electric power sector by 2.0 Bcf/d, or 7%, but remained relatively flat in the commercial, residential and industrial sectors,” Kiley said.
New 2019 additions to gas generation capacity in New England | NGA
New gas generation capacity in New England last year included PSEG Power’s 485-MW Bridgeport Harbor Station 5 in Bridgeport, Conn.; NRG Energy’s 333-MW Canal 3 plant in Sandwich, Mass.; and Exelon’s 200-MW West Medway unit in Medway, Mass.
Two New England pipeline capacity expansion projects went into service in 2019, both part of the Portland Natural Gas Transmission System: the second phase of Portland Xpress and the first phase of Westbrook Xpress.
Projects expected to go into service this year are the second phase of Enbridge’s Atlantic Bridge Project in Weymouth, Mass., the third phase of Portland Xpress, and the Station 261 Upgrade on the Tennessee Pipeline in Agawam, Mass.
Since 2012, more than a million new households have been connected for natural gas use in the six New England states plus New Jersey, New York and Pennsylvania, he said.
“Today this represents over 12 million households in total,” Kiley said.
