NYISO’s Business Issues Committee on Wednesday approved revisions to the Installed Capacity (ICAP) Manual to reflect new capacity values for the upcoming 2019/20 capability year, particularly the amount of import capacity allowed from neighboring control areas.
Hoël Wiesner, ICAP market operations analyst, told the BIC that GE Multi-Area Reliability Simulation program (MARS) simulations were performed on the locational minimum installed capacity requirements (LCR) MARS database to determine the volume of capacity imports allowed without violating the loss-of-load expectation (LOLE) criterion.
The Business Issues Committee approved ICAP manual revisions that specifically address capacity imported from NYISO’s neighboring control areas. | NYISO
The analysis excluded interface facilities having unforced capacity deliverability rights, the controllable lines from PJM into New York and the Northport-Norwalk Harbor intertie 1385 line.
The methodology took the initial 2019/20 final installed reserve margin (IRM) database as updated for the LCR study and modeled grandfathered imports consistent with the IRM study, then determined the imports for each control area individually by increasing imports on ties until the LOLE levels in the base case were met, Wiesner said.
“Once we have these individual limits set, we perform a simultaneous run by increasing the ICAP imports based on the individual limits, beyond the grandfathered imports, until the LOLE levels in the base case are met,” he said.
“These ICAP imports, added to the grandfathered imports, determine the final limits on each control area interface,” Wiesner said.
The final values for the capability year are 1,112 MW for PJM; 279 MW for New England; 1,114 MW for Hydro-Quebec; and 128 MW for Ontario — for a total import limit of 2,633 MW.
The next steps are finalizing the values and publishing them to the automated market system by March 1, emailing the marketplace when those values are finalized, and beginning the first-come, first-serve import rights process March 6, he said.
Broader Regional Markets Report
NYISO on Jan. 27 implemented software to resolve technical issues related to offer caps under FERC Order 831, precluding the need for a requested waiver.
The ISO had implemented software to comply with Order 831 in December, while requesting a limited waiver to resolve an outstanding implementation issue, Rana Mukerji, senior vice president for market structures, told the BIC in presenting the monthly Broader Regional Markets report.
The ISO will continue discussions on the issue at future working group meetings, while targeting to seek stakeholder approval from the BIC and Management Committee by the end of the first quarter, Mukerji said.
Natural Gas Prices Spike 50% in January
NYISO locational-based marginal prices averaged $50.93/MWh in January, up by about 25% from December and down around 50% from the same month a year ago when natural gas prices surged during a severe cold snap, Mukerji said in delivering the monthly operations report. Day-ahead and real-time load-weighted LBMPs came in higher compared to December.
Year-to-date monthly energy prices averaged $52.99/MWh, a 48% decrease from a year ago. January’s average sendout was 449 GWh/day, compared with 425 GWh/day in December and 463 GWh/day a year earlier.
Transco Z6 hub natural gas prices averaged $6.11/MMBtu for the month, up 50% compared with December but down nearly 66% from a year ago.
Distillate prices rose compared to the previous month but were down 9.7% year-over-year. Jet Kerosene Gulf Coast averaged $13.25/MMBtu, up from $12.54/MMBtu in December. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.20/MMBtu, up from $12.84/MMBtu.
January uplift increased to -25 cents/MWh from -29 cents in December, while total uplift costs, excluding the ISO’s cost of operations, came in higher than December.
The ISO’s local reliability share jumped to 32 cents/MWh in January from 23 cents the previous month, while the statewide share dropped to -57 cents/MWh from -52 cents.
The Thunderstorm Alert cost in New York City was $0, unchanged from December.
CARMEL, Ind. — MISO on Tuesday said it will explore whether to alter its long-term planning models to factor in expectations for an increased number of outages.
The RTO initiated a review of outage assumptions in those models after its research showed that outages are more prevalent than represented, stakeholders learned at a Feb. 12 Planning Subcommittee meeting. The current approach to outage modeling may result in long-term reliability planning models that permanently underestimate the actual volume of outages, it found.
MISO Senior Manager of Expansion Planning Edin Habibovic said the RTO could summarize its experience over the last few years as one in which it faces an aging fleet with generation retirements, which amplify the effects of the outages among remaining generators.
“The question we’re trying to answer here is to assess historical generation and transmission outages and see if they line up with the current planning assumptions,” Habibovic said.
The grid operator’s existing long-term models only consider historical planned outages lasting longer than six months, resulting in “few planned outages being embedded in the models.” Only one planned transmission outage and no generation outages were applied to the two- and five-year out models in the 2018 MISO Transmission Expansion Plan.
For forced outages, MISO’s annual MTEP assessment simulates the removal of approximately 2.8 GW for a P3 NERC contingency event and 5.1 GW for extreme events. In reality, the historical outage average varies from 2 to 9 GW of unavailable generation throughout the year.
MISO also said the frequency and duration of forced and planned outages are usually higher and longer than expected. As a result, planning models “may be overstating” the future ability to import generation and reliably serve load in some areas where generation and transmission outages occur more often than planned.
Director of Planning Jeff Webb said long-term planning models are analyzed against NERC planning standards that test system reliability for one or two outages, when in real time there are actually “tens” of concurrent outages throughout the footprint. He added that he wasn’t sure how a more realistic set of outage assumptions would affect long-term reliability planning, and said the new effort was meant to examine that question.
“As we see more and more data that shows this gap, the question is ‘Boy, what does the performance of the grid look like if we matched it with reality?’ It could be that something changes; it could be that nothing changes,” Webb said. “There are many lines out, many generators out in every single hour of the year. Shouldn’t we look at a model that mimics that day?”
MISO said it can use its historic forced outage rate to exclude poor performing generators from redispatch in the models then assess system performance in the five-year and 10-year cases. Habibovic said the RTO would study those cases against those the current process produces to see if long-term reliability needs are affected by real-world outage numbers. He also said it would be helpful to identify potential reliability risks to the transmission system as early as possible.
Habibovic said if MISO modeled its poor performing generators as unavailable, it would have resulted in about 19 GW and 22 GW of systemwide unavailable generation in the 10-year base case model and the five-year sensitivity base case models in MTEP 18, respectively.
MISO will look into excluding the worst-performing generators from long-term modeling in MTEP 2020, Habibovic said. He asked for stakeholders’ comments on the approach by Feb. 28.
The RTO will also perform data analysis on transmission outages to see if it should change transmission availability assumptions in long-term planning models, MISO adviser Matt Tackett said.
Meanwhile, in last year’s annual NERC-required extreme event assessment, MISO found that two simultaneous facility outages are likely the most common cause of cascading events, with the most severe scenario occurring when two local generation plants go offline simultaneously.
This week, the Independent Market Monitor said it continues to monitor short-notice outages in MISO South, including planned outage extensions and unreported outages and derates. The Monitor said in January that short-notice and unreported outages continue to be “significant” in the region.
Vineyard Wind on Thursday announced it has partnered with Anbaric Development Partners in proposing up to 1,200 MW of offshore wind in response to a solicitation by the New York State Energy Research and Development Authority in consultation with the New York Power Authority and the Long Island Power Authority.
The joint venture, Liberty Wind, submitted three different proposals sized at 400, 800 and 1,200 MW — each of which couples energy generation with transmission components.
| 123rf
New York’s Public Service Commission last July authorized state agencies to procure 800 MW of offshore wind energy by the end of this year after Gov. Andrew Cuomo set a target of 2,400 MW by 2030. Last month, he dramatically upped that goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
Vineyard, a 50/50 partnership between Copenhagen Infrastructure Partners and Avangrid Renewables, last May won a contract from Massachusetts for a 1,200-MW offshore wind project off Martha’s Vineyard. Anbaric helped build the 660-MW Neptune HVDC cable linking PJM to Long Island, and also contributed to the 660-MW Hudson project connecting midtown Manhattan to the RTO.
Anbaric also has several interconnection requests and slots with NYISO, including for a 500-MW HVDC line and 800-MW AC line connecting into Ruland Road on Long Island, as well as a 1,200-MW HVDC line and additional 800-MW AC connection into the Farragut substation in Brooklyn. (See Anbaric Pushes Offshore Grid Plans.)
The Liberty Wind proposal includes fabricating foundation components at a port facility near Albany and transporting them down the Hudson River to the project site in the Atlantic Ocean.
“Our team’s extensive offshore wind experience from around the world and nearby in New England, where we are building the nation’s first utility-scale offshore wind project, allows us to deliver the best project for New York,” Vineyard CEO Lars Thaaning Pedersen said in a joint statement with Anbaric CEO Ed Krapels.
“This is the first leg of a well-designed New York ocean grid for offshore wind that will help achieve Gov. Cuomo’s goal of building a planned offshore grid,” Krapels said.
NYSERDA issued the request for proposals for the projects in November (ORECRFP18-1).
Federal regulators Tuesday approved PJM’s revisions to its market efficiency planning rules, despite protests from transmission developers that the changes will underestimate future generation needs and associated costs.
The FERC order, effective Feb. 13, approves the RTO’s updates to Section 1.5.7 of its Operating Agreement that would exclude from market efficiency planning — with exceptions — generation either with only an executed facilities study agreement (FSA) or with an executed interconnection service agreement (ISA) under suspension (ER19-562).
Change Late in RTEP Submission Cycle
The rule change comes near the tail-end of the long-term transmission planning window opened in November, which accepts proposals capable of reducing future congestion. (See PJM Market Efficiency Rules Could Slip Deadline.) Developers can submit projects through the end of February.
Under previous market efficiency rules, PJM included in-service generation and generation with either an executed ISA, an executed interim ISA for which an ISA is expected to be executed or an executed FSA. Excluding generation with executed FSAs only occurred on a case-by-case basis after review with the Transmission Expansion Advisory Committee.
West Penn Power linemen check a new 138-kV line. | FirstEnergy
The 15-year scope also projected levels of new generation and retirements. If models anticipated PJM would fall short of its reserve requirement in any of the proceeding years, the analysis would suggest transmission enhancements addressing potential congestion.
PJM said its robust capacity market, however, means the likelihood of missing reserve requirements over the next 15 years remains slim, leading to a “vast overstatement” of future generation needs and cost. The RTO’s internal analysis encompassing 1999 through 2018 concluded only 36% of generation projects with executed FSAs or ISAs under suspension reached commercial operation, compared with 70% of projects with executed ISAs or wholesale market participation agreements.
“PJM adds that including all projects either with only an executed FSA or with an executed ISA that is under suspension skews the market efficiency models towards including too much generation, which results in an unrealistic estimation of congestion,” FERC said in its ruling.
The new rules exclude such projects from the market efficiency analysis, unless a generator’s specific circumstances or forecasted system reserve margins require staff to reconsider. PJM said it will invoke this unit-by-unit process “rarely,” but always “in an open, transparent process in consultation with the TEAC, and will identify the specific generation projects based on articulable factors that justify their addition.”
Stakeholder Objections
The revisions prompted interventions from developers and the Independent Market Monitor, all of whom argue excluding the projects will underestimate generation needs and mask related costs, skewing what is considered “the best picture of generation to be added” in the eyes of all market participants, stakeholders and state commissions.
The Monitor said eliminating all the early-stage generation from the analyses threatens PJM’s even-handed approach in managing competition between transmission and generation. It also criticized the RTO for not incorporating such uncertainty into forecasts of future congestion, expected fuel costs and construction of transmission projects.
FERC dismissed the Monitor’s concerns over competition, saying that improving the accuracy of PJM’s market efficiency analysis outweighs any possible advantage the new rules may give transmission projects over generation. It also disagreed with developers who argued under-representation of generation will bias the analyses, agreeing with PJM that such changes will lead to more accurate modeling.
“While it may be worthwhile for PJM to work with its stakeholders to undertake some of the suggested analysis, the issue here is limited to whether PJM’s proposed Operating Agreement revision is just and reasonable,” FERC said. “We find that it is.”
PJM’s Brian Chmielewski will lead a special meeting of the TEAC at 10 a.m. Feb. 20 to discuss the rule changes with stakeholders.
Pacific Gas and Electric proposed spending up to $2.3 billion this year on grid hardening and increased line inspections and vegetation management to prevent the ignition of wildfires.
The utility would also expand the scope of its public safety power shut-off (PSPS) program — the “de-energization” of lines during high-threat periods — to include its entire service territory of 5.4 million customers (16 million residents), meaning that even those living in low-risk areas could face shut-offs.
The Witch Fire, sparked by power lines and driven by Santa Ana winds, tore through San Diego County in 2007. | State Farm
PG&E and California’s other investor-owned utilities presented their wildfire mitigation plans (WMPs) in person to the state Public Utilities Commission during an all-day session in San Francisco on Wednesday.
The IOUs filed written plans Feb. 6 in accordance with SB 901, which required more detailed fire prevention strategies after two years of catastrophic wildfires in Northern and Southern California. (See Federal Judge to Review PG&E’s Wildfire Plan.)
PG&E’s wildfire plan drew the most interest — and scrutiny — from state officials and members of the public attending the relatively subdued hearing.
California fire investigators last year determined the utility’s equipment sparked at least 17 of the fires that swept through the state’s wine country in 2017, and the company is under suspicion for causing last November’s Camp Fire in Butte County, the deadliest and most destructive in state history.
Facing more than $30 billion in potential wildfire claims, PG&E last month filed for Chapter 11 bankruptcy protection.
‘Paradigm Shift’
Sumeet Singh, Pacific Gas and Electric | PG&E
In opening his presentation, Sumeet Singh, vice president in charge of PG&E’s community wildfire safety program, spoke about the “unprecedented level of risk we’re facing in the state of California” from wildfires.
“When you look at the last three years, nine of the 20 most destructive wildfires happened since 2015. And when you look at the associated damage, nearly 72% of the structure damage occurred within that time frame,” Singh said. He added that the volume of vegetation “plays a key role” in wildfire risk, and that vegetation “becomes more pronounced” in the forested regions of Northern California that constitute a large swath of PG&E’s territory.
Expected to cost between $1.7 billion and $2.3 billion in 2019 alone, PG&E’s plan focuses on preventing ignition and “rapid detection and situational awareness” after fires are sparked, Singh said.
He laid out a dizzying array of measures the utility expects to undertake, including identifying and removing hazardous trees along its 81,000 miles of overhead transmission and distribution corridors; clearing overhang from “the wire to the sky” in high-risk areas; examining the condition of transmission assets in fire-prone areas, including inspecting 685,000 poles; performing “enhanced” line inspections using drones; and adding 400 weather stations to the 200 it installed last year.
“It’s a fairly significant effort that we’ve undertaken,” Singh said.
In its “system hardening” effort, PG&E will seek alternatives for serving people in high-fire districts, including microgrids and battery storage; targeted undergrounding of lines; and rebuilding existing infrastructure with covered conductors and hardened poles — as Singh said the utility is already doing in devastated areas.
Singh also explained that PG&E will expand the scope of the power lines subject to its PSPS from the 7,100 miles in “extreme risk” areas to an additional 25,200 miles in “elevated risk” areas, leaving all the utility’s customers at risk for potential shut-offs — an outcome Singh said was highly unlikely.
CPUC President Michael Picker pointed out that San Diego Gas & Electric has developed tools for a more “granular” threat index to avoid the potential for such widespread shutoffs.
“We’re trying to get there faster and sooner, and that is the reason why we’ve doubled the weather station program,” Singh said. “We’d love to be able to get there this year, but I’m not sure that’s going to be achievable.”
Picker asked about PG&E’s expected timeline for implementing its mitigation plan.
“Do you think of it as three-, five- or 10-year plan?” Picker asked.
“Less than three years. Look at this as a short-term plan,” Singh replied.
Elizaveta Malashenko, CPUC deputy executive director for safety and enforcement policy, questioned the utility’s ability to meet that time frame.
“The plan is very aggressive, but it’s a plan we put together and have a line of sight into,” Singh said. “We have dedicated teams, dedicated individuals focusing on this work.”
Gabe Petlin, CPUC supervisor of grid planning and reliability, pointed out that PG&E currently has only 43 open positions advertised on its website, just two of which were for the more than 700 arborists that Singh said would be needed for the company’s increased vegetation management efforts.
Singh said PG&E is working with “contractor partners” to obtain the expertise. “It’s a model we’ve used for many years,” he said.
During the public comment period on the plan, Robin McCollum, a former tree clearing supervisor for Butte County, called vegetation removal “low-hanging fruit” for PG&E, saying that trees are “a valuable public resource that shouldn’t be squandered.” He also characterized PG&E’s plan for an additional 32 feet of ground clearance around corridors as “very extreme.”
“I think we’re at a point where we should have a paradigm shift in our thinking,” McCollum said. “It’s not the vegetation that causes the problem. It’s not the vegetation that’s the enemy or the target. It’s the wires, the bare wires, that are the hazard. … What we need to do, however long it takes, and at whatever expense … we should insulate those wires.”
SDG&E’s ‘Model’
SDG&E was the first of the three big IOUs to lay out its fire prevention strategy on Wednesday. State officials often cite the utility as a role model for PG&E and Southern California Edison to follow in preventing wildfires.
David Geier, San Diego Gas & Electric | SDG&E
After a series of devastating blazes last decade — including the Cedar Fire in 2005 and the Witch and Harris fires in 2007 — SDG&E’s service area hasn’t experienced fires of that magnitude since, said David Geier, the utility’s senior vice president for electric operations. The CEO of SDG&E’s parent company, Sempra Energy, vowed 12 years ago that “we are not going to have any wildfires caused by [our] equipment ever again,” Geier said.
SDG&E embarked on a program to install hundreds of weather monitoring stations and cameras across its mountain-to-ocean service territory. The weather stations revealed wind gusts up to 101 mph in some locations when the majority of the utility’s grid was built for 60-mph winds, Geier said.
The utility is installing transmission towers constructed to 85-mph wind standards. It has undergrounded or covered many lines, and it inspects all of the 465,000 trees each year, he said.
“We probably know as much about trees as we know about any other asset in our system,” he said.
SDG&E also installed “sensitive ground fault detection” that can cut current by 67% on downed lines, he said.
“That’s the spark that causes the fire,” Geier said.
San Diego Gas & Electric credits its intensive weather monitoring with preventing major wildfires since 2007. | SDG&E
The company has tried to instill its safety culture company-wide, with every employee part of the mission, and consumers have been continually included in the effort through public meetings and outreach, he said.
“One thing is certain,” Geier said. “There’s going to be another fire season.”
SDG&E’s plan is being partially adopted by SCE, which is installing weather stations and cameras across its high-risk fire areas. The utility also has a program of emergency power shutdowns in extreme fire conditions.
Phil Herrington, Southern California Edison | Southern California Edison
SCE will spend about $582 million on fire prevention measures this year, but Phil Herrington, vice president for transmission and distribution, said there’s only so much utilities can do in the face of climate change.
“I think we all recognize this is not a utility issue. It’s a statewide issue,” Herrington told the commission.
SCE will deploy more than 800 weather stations and will have camera coverage of 80 to 90% of its service area by 2020, he said. It inspects about 900,000 out of its 1 million trees annually, and the utility established a central command post to monitor for emergencies “24/7,” he said.
“How far off are you from SDG&E?” Malashenko asked Herrington. Regarding SCE’s mitigation plan, she asked, “How much closer is it going to get you?”
Herrington replied, “We’re looking at making rapid catch-up.”
Stakeholders representing load interests minced no words in a letter to PJM’s Board of Managers that criticized staff for rebuffing manual revisions they argue would increase transparency on transmission owners’ supplemental projects.
Signed by more than a dozen utility companies and state agencies — including American Municipal Power, Old Dominion Electric Cooperative, Kentucky’s Office of the Attorney General, the Delaware Department of Justice and the D.C. Office of the People’s Counsel, among others — the Feb. 8 letter accuses PJM of shirking its responsibility as an independent regional planner. It says the RTO failed to thoroughly vet the necessity of supplemental projects, which are managed by TOs and not deemed necessary for compliance under the RTO’s reliability, operational performance or economic criteria.
According to an AMP analysis, TO-requested projects totaled $7.2 billion in 2018, with nearly 80% classified as supplemental — a 219% increase over 2017. Meanwhile, PJM identified $560 million in baseline projects, which are those needed to solve future reliability and congestion issues.
“To be clear, the process as PJM staff is currently implementing it is not providing an adequate level of transparency,” the letter reads. “PJM is falling short of its requirements.”
Supplemental projects have consistently outpaced baseline projects in PJM’s Regional Transmission Expansion Plan, according to AMP. | AMP
Manual 14B Dispute
At last month’s Markets and Reliability Committee meeting, PJM rejected two paragraphs in a set of revisions that stakeholders approved for inclusion in Manual 14B: PJM Region Transmission Planning Process. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
The paragraphs came from an AMP proposal — designed to address load interests’ concerns — that said supplemental projects “should be based on written articulable criteria, models and guidelines that are measurable and, to the extent available, quantifiable (e.g., asset replacement prioritization) so stakeholders can replicate TO planning decisions and validate their proposed solutions.” AMP cited the transparency principles in FERC Order 890, saying TOs should disclose asset-specific condition assessments and the criteria and models supporting supplemental projects.
Aaron Berner, PJM’s manager of transmission planning, called the disputed text an “overreach” of the RTO’s Regional Transmission Expansion Plan, which he said is limited to studies of load flows, short circuits and stability.
PJM Vice President of Planning Steve Herling later confirmed the RTO would not implement the proposed changes because they were “not consistent” with FERC rulings. “We don’t do this often, but we’re going to have to not implement what the members have approved,” he said immediately after the MRC approved the changes in a sector-weighted vote of 3.46 out of 5.
AMP’s proposal won unanimous support from the Electric Distributors and End-Use Customers sectors, 80% of Other Suppliers and 58% of Generation Owners. It was opposed by all but one member of the Transmission Owners sector.
‘Paradigm Shift’
In the letter, load interests insist PJM incorrectly interpreted federal guidance on regional transmission planning rules, describing its refusal to implement the AMP language as a “paradigm shift.”
“In light of the billions of dollars in supplemental projects proposed in recent years, it is untenable to hear that PJM believes that language such as ‘should’ and ‘to the extent possible’ is an ‘overreach’ by stakeholders,” the letter concludes. “It is equally untenable that PJM staff has no problem with disregarding the supermajority vote of the PJM stakeholders.”
PJM spokesman Jeff Shields said Wednesday the RTO remains committed to working with all stakeholders to maintain transparency and accountability. He cited its decision to clarify the term “useful life” in the manual as “not intended to indicate that facilities might be replaced solely based on them being fully depreciated.”
“The [other] manual changes forwarded to PJM are simply inconsistent with FERC’s description of PJM’s role in transmission planning,” Shields said. “PJM has exclusive purview over its manuals and is not required to introduce changes requested by stakeholders.”
In a separate letter to the board Feb. 11, the American Public Power Association (APPA) and the Transmission Access Policy Study Group (TAPS) said PJM’s refusal lacks “compelling justification.”
“The recently rejected Manual 14B revisions would have afforded stakeholders additional transparency concerning the basis, cost, timing and need for proposed supplemental projects,” wrote APPA CEO Susan Kelly and TAPS Executive Director John Twitty. “Transparency and opportunity for meaningful stakeholder participation in supplemental project planning help ensure that these projects will be cost-effective and beneficial to customers.”
The groups argued that PJM should not reject “broadly supported” manual changes designed to increase transparency around supplemental projects without “a compelling justification.”
“We urge the board to carefully consider the load group’s arguments that such a justification was lacking in the case of the rejected changes to Manual 14B,” the groups said.
The PJM Board of Managers agreed to submit staff’s revised energy price formation proposal for FERC approval, CEO Andy Ott said Wednesday.
“PJM will review the agreement language with stakeholders prior to filing, and we look forward to that opportunity,” he said in an email to members the day after the board’s meeting Tuesday. “The board thanks stakeholders for their engagement and their ongoing support on this important matter.”
He said the Federal Power Act Section 206 filing will happen within the next few weeks.
The plan, advanced at the recommendation of the board’s Competitive Markets Committee — with input from both the Independent Market Monitor and members’ Liaison Committee — includes the following from PJM’s proposal:
Consolidation of Tier 1 and Tier 2 synchronized reserve products;
Improved utilization of existing capability for locational reserve needs;
Alignment of market-based reserve products in day-ahead and real-time markets;
Downward sloping operating reserve demand curves (ORDCs) for all reserve products; and
Increased penalty factors to ORDCs to ensure utilization of all supply prior to a reserve shortage.
2 Changes
The board recommended two changes after lengthy discussions with stakeholders, including a Liaison Committee meeting Feb. 11.
The board directed PJM to adjust its assumptions regarding generator forced outage rates based on feedback from the Monitor, which said staff were being overly conservative. The board also ordered the RTO to increase the cap on demand response that may be assigned as synchronized reserves to 50% of the requirement.
PJM’s proposal replaces the current stepped ORDC with a sloped curve; the first horizontal segment would represent the minimum reserve requirement, with the downward sloping curve based on the probability of reserves falling below the minimum reserve requirement (PBMRR) in real time based on uncertainties. The PJM proposal also increases the price for the initial horizontal segment of the curve to $2,000/MWh, up from the current $850.
The filing will not include a transitional adjustment to the energy and ancillary services offset in the capacity auction.
During a special session of the Members Committee on Feb. 6, PJM’s Stu Bresler said the FERC filing will likely come in early to mid-March, with a June 1, 2020, “reasonable target” date for implementation.
Opposition Likely
PJM’s filing is certain to be opposed by load interests concerned about the cost of the changes. The proposal received only 31% support in a sector-weighted vote at the MRC, with no ‘yes’ votes from End-Use Customers and only one vote out of 28 from Electric Distributors. It was supported by 60% of Transmission Owners and almost half of Generation Owners and Other Suppliers.
A PJM white paper published in December projected that staff’s plan — before the two changes ordered by the board — would boost energy and reserve market revenues by $1.92 billion annually, with energy revenues up $1.8 billion (increasing average LMPs by $2.27/MWh) and reserves increasing by $190 million. Uplift was projected to drop by $70 million.
The RTO expects the additional costs will be at least partially offset by reduced capacity costs. It said the most optimistic case would result in annual cost savings to consumers of $350 million.
“A potentially more realistic outcome is that these changes will increase costs to loads in the range of $700 million,” the RTO said. “PJM believes these changes are justified because much of the reserve capability PJM has today is either undercompensated or not compensated at all.”
“PJM has detailed its concerns with current energy and operating reserve pricing mechanisms but has not justified the urgency of resolving these concerns, established the operational and cost effectiveness of its solutions, or adequately evaluated the risks and rewards of its proposed reforms,” said Michael Richard, president of the Organization of PJM States Inc. (OPSI) in a letter dated Jan. 29. “It seeks to institute new market structures under an unnecessarily rushed timeline, allowing little opportunity for its staff to generate the analyses necessary for stakeholders to fully understand the potential impacts these proposals will have on market sellers and consumers, gauge the reasonableness of the proposals or develop alternatives.”
The Sustainable FERC Project, meanwhile, filed a letter of opposition Feb. 4 on behalf of the Sierra Club Environmental Law Program, the Union of Concerned Scientists and the Clean Energy Program that said proposals by PJM and others “neither consider the existing demand response reserves committed on the system, nor provide a mechanism to compensate those demand resources for the reserve services they are providing.”
“PJM’s energy reserve reform package would unacceptably delay fully and efficiently utilizing the capabilities of clean energy technologies to serve system needs,” the letter reads. “Over 68% of load served in PJM is located in states that have clean or renewable energy targets that become increasingly ambitious in coming years. It is no longer acceptable for consideration of clean energy technologies to be relegated to an afterthought.”
The board also heard earlier from executives of FirstEnergy, Exelon, Duke Energy and Public Service Enterprise Group, who criticized the RTO for failing to implement energy and capacity market rule changes despite a decade of stakeholder discussions. (See Utility CEOs Urge PJM Board to Act on Price Formation.)
Nearly 40 people braved a snowstorm Tuesday to testify on a bill that aims to put some of New York’s ambitious decarbonization goals into the statute books.
The testimony over the draft Climate and Community Protection Act (S7971A) was part of the New York State Senate’s first-ever hearing on climate change, held by the Committee on Environmental Conservation and chaired by Sen. Todd Kaminsky (D). Control of the Senate this year passed to Democrats from Republicans who had declined to take up the issue.
NYSERDA CEO Alicia Barton testifies at the New York State Senate hearing on climate change on Feb. 12, 2019. | NYSERDA
Last month, Gov. Andrew M. Cuomo vaulted the state ahead of all others in renewable energy targets by pledging to erase the state’s carbon footprint by 2040 and nearly quadrupling its offshore wind energy goal to 9 GW by 2035. (See New York Boosts Zero-carbon, Renewable Goals.)
Alicia Barton
“Here in New York, public policy is informed by science, and we are collectively committed to taking action to address the climate crisis,” Alicia Barton, CEO of the New York State Energy Research and Development Authority, said at the hearing. “The discussion today is not about whether to act, but how best to act.”
Todd Kaminsky
The proposed bill specifically targets sectors other than the electric generation sector, Kaminsky pointed out. He asked Barton whether lawmakers should place emission caps on transportation and buildings, for example.
“Our efforts are much more mature in the electric sector,” Barton said, adding that similar work and analysis would be needed in other sectors, including “pushing the markets to advance more quickly… in building decarbonization and electrification and emissions reduction in the transportation sector.”
70% Renewable by 2030
The cornerstone of the new state goal: to increase of the state’s Clean Energy Standard mandate from 50% to 70% renewable electricity by 2030.
The governor’s proposal “sets the 100% clean electricity standard by 2040 but also directs the Climate Action Council to develop a roadmap to a carbon-neutral economy,” Barton said.
Last fall’s report by the U.N.’s Intergovernmental Panel on Climate Change “stated that there is no historic precedent for the magnitude of changes that are necessary,” Barton said. “The good news is that we have been making progress faster than we thought just a few years ago … technology has been breaking our way and costs have been breaking our way.” (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
Brian Kavanagh
She said nobody foresaw the incredible cost declines in technologies such as offshore wind even a few years ago, “and I think we have every reason to hope that we will see those same transformations take place in transportation and in the building sector.”
Sen. Brian P. Kavanagh (D) asked Barton whether the administration would think it “imprudent to try to develop legislation” while the state agencies are working out their plans to achieve the state’s energy goals.
Barton declined to speak for the governor but said “given where we are today, doubling down and accelerating quickly in the electric sector is something that we believe is technologically reasonable” and cost-effective.
She added that New York also has “the most aggressive energy storage targets in the country” and that many projects should start to come online in the second half of the year.
Julia Salazar
Sen. Julia Salazar (D) asked what the state is doing to protect people of color and low-income residents, who tend to be impacted most by higher electricity rates. Barton said NYSERDA is working on a number of programs “across the board to make sure that low-income New Yorkers have access to solar energy and other new renewable energy resources.”
Brad Hoylman
Bill sponsor Sen. Brad Hoylman said the draft legislation “aims to build up those communities through direct targets in terms of prevailing wage, apprenticeship utilization and the like.”
“Does the governor’s plan have those kinds of good job-making targets?” he asked Barton.
“Already today NYSERDA has taken the step of requiring prevailing wage under our large-scale renewable energy solicitations,” Barton said. “The state’s request for proposals for offshore wind energy was the first in the country to require a negotiation of project labor agreements, and the agency has allocated $70 million for workforce training.” (See New York Plans for Wind Energy, Related Jobs.)
No Rolling Blackouts
Peter Iwanowicz
Peter Iwanowicz, director of the Environmental Advocates of New York, advised legislators not to be swayed by naysayers.
Iwanowicz recounted how New York’s power companies provided three warnings before the state joined in creating the Regional Greenhouse Gas Initiative: “First, RGGI was going to drive prices through the roof. Second, there’d be blackouts in New York City. Third, and this is really unbelievable, but I was told this directly, power companies were going to shut down in New York and move to Pennsylvania just to avoid RGGI.”
Darren Suarez
Darren Suarez of the Business Council of New York State said that its members oppose the legislation and that if measures taken “in New York result in increased emissions elsewhere in the world, we’ve done nothing to solve the problem.”
“The European experience demonstrates that well-intentioned environmental policies can result in higher energy production costs, driving carbon leakage and output leakage,” Suarez said. “To those who say the legislation is aspirational … this is not a goal, it’s a law, and the law will require that emissions be 50% below 1990 levels by next year.”
Roger Downs
“The pace at which we should make these changes has been hotly debated,” said Roger Downs of the Sierra Club. “In some ways it is not unlike evacuating people from a burning theater. Moving too fast in a panic has the same dire consequences as moving too slowly.”
Sam Wade
The committee heard from foresters, forest product makers, bird lovers, and also from a Californian who supports running heavy industrial vehicles on renewable gas.
Sam Wade of the Coalition for Renewable Natural Gas, who ran California’s low-carbon fuel standard program for the past 10 years, testified that “taking one big diesel rig off I-87 today is the carbon emissions equivalent of taking 119 gasoline-powered cars off the road.”
American Electric Power will buy Sempra Energy’s renewable business in a $1.056 billion deal that will triple AEP’s renewable portfolio, the companies announced Tuesday.
Sempra’s Sempra Renewables subsidiary owns all or part of seven wind farms and one battery installation in seven states, with a total capacity of 724 MW. Five of the wind farms are jointly owned with BP Wind Energy, which will retain its ownership share.
Sempra Renewables owns the Apple Blossom Wind project in Michigan and the Black Oak Getty Wind project in Minnesota. It holds interests with BP in Colorado (Cedar Creek 2 Wind), Hawaii (Auwahi Wind, which also includes battery storage), Indiana (Fowler Ridge 2 Wind), Kansas (Flat Ridge 2 Wind) and Pennsylvania (Mehoopany Wind).
The facilities have an average capacity factor of 37%. The energy is contracted out through long-term, power-purchase agreements with investor-owned utilities, municipal utilities and electric cooperatives, with an average remaining life of 16 years.
AEP will also acquire all Sempra Renewables wind projects in development.
AEP Renewables, AEP’s competitive renewable subsidiary, owns 351 MW of contracted renewable generation. It has wind and solar projects in Texas (261 MW wind), California (20 MW solar), Nevada (50 MW solar) and Utah (20 MW solar).
AEP Renewables also recently signed an agreement to purchase a 75% interest, worth 227 MW of capacity, in Invenergy’s Santa Rita East Wind Project under construction west of San Angelo, Texas. AEP will acquire its share of the project upon completion later this year. Invenergy will retain the remaining 25%.
With 1,302 MW of renewable generation in 11 states, AEP will become the seventh largest utility owner of competitive wind generation in the United States upon the completion of the Sempra transaction and Santa Rita construction.
Sempra Renewables’ Apple Blossom Wind Farm | Sempra Renewables
Following the 2018 collapse of its $4.5 billion, 2-GW Wind Catcher project, AEP said it would focus on smaller renewable projects as part of its plan to reduce carbon dioxide emissions 80% from 2000 levels by 2050. (See AEP to Focus on Smaller Renewable Projects.)
“Our long-term strategy is focused on diversifying our generation portfolio, including expanding our ownership of renewable generation,” said AEP CEO Nick Akins in a statement.
AEP’s generation capacity in 2005 was 70% coal-fueled, 19% natural gas and 4% renewable. After the Sempra transaction’s closure, the mix will be 46% coal, 27% gas and 16% renewable.
The deal includes $551 million in cash, assumption of $343 million in existing project debt and $162 million in tax equity obligation. It is part of the company’s planned $2.2 billion investment in contracted renewables by 2023.
The transaction is expected to close in the second quarter of 2019 and is subject to FERC approval and Hart-Scott-Rodino clearance.
WASHINGTON — FERC Commissioner Richard Glick on Tuesday provided some insight into the “vigorous debate” over natural gas pipeline approvals that has divided the commission along party lines.
Speaking at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit, Glick said that, by failing to consider the impact of greenhouse gas emissions when licensing pipelines, “the commission is essentially ignoring” the 2017 D.C. Circuit Court of Appeals’ order that remanded FERC’s approval of an environmental impact statement for the Southeast Market Pipelines Project. (See FERC Must Consider GHG Impact of Pipelines, DC Circuit Rules.)
In its rejection last May of a rehearing request of its environmental assessment for Dominion Energy Transmission’s New Market Project, FERC ruled 3-2 along party lines that it will no longer prepare upper-bound estimates of GHG emissions when “the upstream production and downstream use of natural gas are not cumulative or indirect impacts of the proposed pipeline project.” (See FERC Narrows GHG Review forGas Pipelines.)
Glick, a Democrat, has issued several dissents in the commission’s approvals of gas infrastructure because of his opposition to that policy. “What gets me concerned about that is I think I get this kind of reputation as being against all natural gas pipelines. That’s just not true. That’s simply not true,” he told a ballroom of state regulators and their staff at the Renaissance Washington Hotel. “The fact is I think we need to do more analysis. … There are certainly pipelines that I could vote for. If we weigh the benefits of that pipeline versus the greenhouse gas emissions, I think that I could end up voting for them.”
Fellow Democratic Commissioner Cheryl LaFleur has voted for certain pipelines after considering their emissions but also partially dissented on those projects, noting the rest of the majority did not take emissions into account. (See Dem Dissents Show FERC Divide on Carbon.)
“I think the fact that the commission is not doing its job, we’re creating a lot of uncertainty, legal uncertainty in particular,” Glick said.
‘Not Enough Compromise’
With the death of Commissioner Kevin McIntyre, there is now a 2-2 partisan split, and Chairman Neil Chatterjee has been pulling gas items from the consent agenda at open meetings.
“I’m trying to figure out what the harm is. I think we can do the analysis. The numbers aren’t that hard to figure out,” Glick said. “I’m just trying to figure out what [the Republican commissioners’] real motivation is, and sometimes I worry it’s from an ideological perspective about climate change.”
He said the social cost of carbon is “a good tool for us to be able to determine whether an externality is significant, and if it’s significant, if it’s outweighed by the benefits” of a proposed project.
Idaho Public Utilities Commissioner Kristine Raper asked Glick whether he was concerned about a lack of plaintiffs to appeal FERC decisions on which he dissented. He said “there’s a reasonable chance” some of them would be overturned by the courts because “the commission didn’t do what it was supposed to do under the various statutory requirements.”
But he noted the plaintiff in the Southeast Market case declined to appeal FERC’s order on remand upholding its original decision, in part because of a lack of resources. “That is a concern. I think you’re going to see that. There’s kind of a fatigue out there, and there’s not sufficient resources sometimes to take these cases to the courts.”
Speaking to reporters, Glick said “we’re still having discussions” about the emissions dispute. He wants the commission to repeal the policy from the New Market case, “but so far they haven’t done that, so [there’s] not enough compromise at this point.”
Despite the dispute falling along party lines, Glick defended the commission against charges of politicization. “There have been a number of articles written, and I’ve read those articles [asking] are we independent anymore? Is the Trump administration telling us what to do? Are the commissioners themselves being too political, whether it’s on the left or on the right? …
“But in reality, I think FERC itself is as independent as an independent agency can get,” he said. “And even though our decisions or our votes come down on party lines, I think among the commissioners themselves, I think there’s never really a discussion of politics.”
Twitter Spat
Asked by a reporter if there were any issues every commissioner agreed on, Glick said there were plenty, highlighting Order 841, a unanimous ruling a year ago that directed RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets.
“I’d say 90-odd percent of the votes that we have” are unanimous, Glick said.
Glick also defended the statement that he and LaFleur made Feb. 5 regarding FERC’s inaction on Vineyard Wind’s request for a waiver ahead of ISO-NE’s 13th Forward Capacity Auction. (See ISO-NE Completes FCA 13 Despite Controversy.)
Glick tweeted the statement, then Chatterjee responded with his own tweet subtly chastising his colleagues. “I do not discuss the commission’s internal deliberations with the public,” Chatterjee said. “Doing so would be highly inappropriate and might undermine the commission’s process.”
Bloomberg described the incident as a “Twitter spat.”
“I don’t think that was airing any grievances at all against the other commissioners,” Glick told reporters. “We were just expressing frustration that unfortunately, we didn’t issue an order and created some uncertainty. … I had a conversation with Chairman Chatterjee after that and explained to him that before we posted that statement, we checked with the general counsel’s office [and] we checked with the ethics adviser. … I think the chairman now understands that that was not an appropriate comment.”
Commissioner Bernard McNamee also appeared at the summit in an 11-minute discussion with Virginia State Corporation Commissioner Judith Jagdmann, but he did not discuss the gas policy dispute and left without taking any questions from the audience or reporters.
