ERCOT’s Technical Advisory Committee has canceled its June meeting because of a lack of voting items.
The TAC’s next scheduled meeting is July 27. The Board of Directors does not meet again until Aug. 8.
TAC Chair Adrianne Brandt, of San Antonio’s CPS Energy, asked committee members to vote by email on a pair of revision requests, setting a 5 p.m. deadline Wednesday for responses:
NOGRR170: Revises the Nodal Operating Guide to be consistent with NPRR824 language related to NERC Reliability Standards EOP-011-1 (Emergency Operations) and BAL-001-2 (Real Power Balancing Control Performance).
RRGRR014: Conforms the Resource Registration glossary to the as-built release, which captured baseline updates before the approvals of RRGRR006 and RRGRR007. The RRGRR adds solar resource registration inputs omitted from the greybox tab for RRGRR009.
New Hampshire regulators on Friday took the first step toward an overhaul of their net metering rules, reducing compensation for rooftop solar owners while ordering a study of the value of distributed generation that will inform long-term changes.
Solar Panels at Exeter High School
The Public Utilities Commission ordered utilities to implement a new alternative net metering tariff that retains monthly netting for small distributed generation system owners while moving to instantaneous netting for non-bypassable charges. The rules, “to be in effect for a period of several years,” will begin Sept. 1 (Order 26,029).
The commission chose a quasi-adjudicative process to reconcile two settlement proposals on how to develop and implement a new alternative net metering tariff, as directed by the state legislature last year in House Bill 1116.
Two Proposals
One settlement proposal came from a coalition of utilities and consumer parties (UCC), including Eversource Energy, Liberty Utilities, Unitil Energy Systems, the state Office of Consumer Advocate, the New England Ratepayers Association, Consumer Energy Alliance and Standard Power of America.
The other proposal was filed the same day by a coalition of distributed generation industry advocates and environmental organizations known as the Energy Future Coalition (EFC), which included the Acadia Center, The Alliance for Solar Choice, the Conservation Law Foundation and eight other organizations and companies (docket DE 16-576).
In its unanimous 74-page order, the commission ruled that:
Small customer-generators with renewable energy systems of 100 kW or less will continue to net meter their DG resources monthly. Those customer-generators will receive monthly net export credits equal to the monetary value of kilowatt-hour charges for energy service and transmission service at 100% and distribution service at 25% — a 75% reduction — while paying the full amount of non-bypassable charges, such as the system benefits charge, stranded cost recovery charge, other similar surcharges and the state electricity consumption tax. Previously, they received kilowatt-hour credits.
Large customer-generators will continue to be net-metered as they are currently but will also receive monetary credits rather than kilowatt-hour credits on a monthly basis. To qualify for alternative net metering, large customers must consume at least 20% of their actual or estimated annual distributed generation system electric production behind the meter.
DG systems installed or queued during the period the new net metering tariff is in effect will have their net metering rate structure grandfathered until Dec. 31, 2040.
Pilot projects will be proposed and a value of DER study will be designed and completed to “inform the development of the next version of net metering or another alternative regulatory mechanism.”
“As the penetration level of DG in the state is quite low in both absolute and relative terms, there is little evidence of significant cost-shifting from DG customers to customers without DG,” the commission said. “Payment of non-bypassable charges by all net-metered customers and a reduction in the distribution credit for net exports should serve to mitigate the potential for such cost-shifting, even if DG penetration levels increase significantly above their low levels.”
The commission said it accepted common elements in the two settlement proposals and resolved differences between them based on the legislative purposes of HB 1116. The bill called for “the continuance of reasonable opportunities for electric customers to invest in and interconnect customer-generator facilities and receive fair compensation for such locally produced power while ensuring costs and benefits are fairly and transparently allocated among all customers.”
The order requires Eversource, Liberty (Granite State Electric) and Unitil to file revised tariffs within 30 days. The commission also approved an automatic rate adjustment mechanism for the companies to recover lost revenue, under the process approved for Unitil in February (Order No. 25,991).
Value of DER Study
The order provides that the alternative net metering tariff take effect while the utilities and stakeholders collect further data, implement pilot programs and conduct a study on the value of DERs.
It directs stakeholders to convene working groups within 60 days to develop proposals on the commission’s mandates. It also requires them to file quarterly progress reports with the PUC. The order also gives concerned parties 30 days to submit written briefs or comments on grandfathering issues, such as the clause that “customer-generators that receive a net metering capacity allocation while the new alternative net metering tariff is in effect to be ‘grandfathered’ at the applicable net metering design and structure then in effect through Dec. 31, 2040.”
Reaction
“The ruling is a mixed bag,” CLF attorney Melissa E. Birchard said.
While the order is an overall win for the state because it sets a path forward to value the broad benefits of clean energy resources and accelerates grid modernization, Birchard said she was dismayed by the cut in the distribution credit.
“It is disturbing to see cuts to an important program like net metering at the same time that New Hampshire is lagging behind the rest of the region on solar penetration and energy efficiency,” Birchard said. “If we’re not careful, other states in the region are going to reap the financial benefits of strong solar and energy efficiency programs while Granite Staters pay more on their electric bill for a disproportionate share of the costs.”
Nashua, New Hampshire Dam
While the distribution portion of the credit is only one piece of the overall credit, “this cut is arbitrary in the sense that there was no real data in the docket to support it, and it will affect the pace of clean energy investments,” Birchard said.
Gradual Change
The commission said that an abrupt change from monthly netting to instantaneous netting would likely confuse customers and send potentially inefficient price signals.
“For example, instantaneous netting may be confusing to customers who lack real-time data about their electricity usage,” said the order. “It may also provide financial incentives for maximum on-site electric consumption during periods when the benefits of DG exports to the system may be greatest, such as at the time of late afternoon system peaks, thereby decreasing the potential system-wide benefits of those energy exports.”
Birchard believes the cuts in net metering will be temporary.
“There should be a new rate established after the commission carries out a value of distributed energy resources study, particularly distributed solar and hydro, and after that study it’s going to open a proceeding to revalue it,” said Birchard. “So the credits that those resources receive will be based on the broad benefits, potentially including climate change and health benefits. That kind of value-based rate can make clean energy innovation more competitive in an open market way so that different kinds of resources can compete with each other based on their value.”
California regulators last week advanced on a plan to study the potential for eliminating the Aliso Canyon natural gas storage facility.
The move came as Southern California Gas reiterated warnings about the impact of gas shortages on grid reliability this summer.
The state’s Public Utilities Commission issued a draft request for proposals to develop an “Aliso Canyon Reliability and Economic Analyses.” The central question to be answered, according to the draft: “should the commission reduce or eliminate the use of the Aliso Canyon storage facility, and if so, under what conditions and parameters, and in what time frame?”
The commission seeks public comment on the draft by June 29 and expects to issue the RFP on July 6. It is considering what elements of the proposal work or could be improved, if any important questions are missing and whether instructions are clear.
Location of Gas Leak at Aliso Canyon Natural Gas Storage Facility | SoCalGas
Injections into the 86 Bcf facility near Los Angeles have been halted since the leak was discovered in October 2015. The restriction was kept in place even after the leaking well was finally plugged in February 2016.
State Senate Bill 380 prohibited reinjection of gas into Aliso until completion of a safety review and required the PUC to determine whether use of the facility can be reduced or eliminated while still maintaining electric and gas reliability.
Winning bidders on the RFP will be required to hold stakeholder workshops and public hearings, as well as perform hydraulic model analysis of the reliability of the Aliso system under a variety of scenarios, using forecasted electricity demand and contribution of renewables to the generation mix.
The PUC is looking for bidders experienced with Synergi Gas software — or an equivalent — and working on gas-electric coordination. Also desired is a background running community forums and “developing models to assess the market, consumer and economic impact of significant changes to the natural gas or related markets.”
Bidders’ proposals are due on Aug. 24, and the contract award date is tentatively set for Sept. 29.
“From our perspective, we are cautiously optimistic that, based upon the CAISO forecast, we will be able to meet the demands on our system. Of course, this is dependent on there being no unplanned outages on either the electric or gas systems,” SoCalGas CEO Bret Lane said in a June 16 letter.
Lane’s letter was accompanied by another June 13 letter from a group of municipal utilities to State Sen. Henry Stern, saying that they have serious concerns with the continuing moratorium on injections that the legislature required until a root cause of the leak is identified. The analysis is not needed because the wells have been retrofitted and gas no longer flows into outer casings, the practice that led to the gas leak, the utilities said.
“We are concerned that the bill constrains the transmission of natural gas, which could limit local electric supply, resulting in electric outages,” says the letter from Burbank Water and Power, Pasadena Water and Power, and Vernon Public Utilities.
The utilities also said that the legislation failed to define a process for emergency gas injections, “suggesting that a response to a blackout might come too late.” They backed SoCalGas’ recommendation that the current gas inventory at Aliso Canyon be increased to prevent blackouts.
The utilities caution that temperatures were moderate last year, which has so far not been the case this year. A heat wave last week swept areas of California, cutting electricity to about 190,000 Pacific Gas and Electric customers and prompting CAISO to issue a conservation alert. (See California Heat Wave Prompts CAISO Flex Alert.)
BRANSON, Mo. — Energy industry veterans mused on the state of energy innovation and the future of the sector during a panel discussion at MISO’s annual stakeholders’ meeting last week.
Thomas Voss, retired chairman of Ameren and a self-proclaimed devotee of innovation, said microgrids and rooftop solar are gaining traction.
“In California, it’s completely changed the planning process. Lines that they thought would be overloaded were fine because of rooftop solar,” Voss said during the June 21 panel. “Now there’s winner and losers, and it might not be as fair as it should be, but hopefully we can come together and solve that.”
William Mohl, a former Entergy executive, said MISO has the luxury of studying what the RTOs on the coasts are doing with renewables and storage and waiting until it becomes economic to implement the results.
James Jura, former CEO of Associated Electric Cooperative Inc., recounted how he used to ask industry participants if they had heard of Elon Musk before he was a household name: “I said, ‘You have to look him up because he’s going to get between you and your member-owners.’”
Libby Jacobs, former chair of the Iowa Utilities Board and former Organization of MISO States president, said FERC will need to address the public appetite for renewables with orders or possible rulemaking.
“I do see energy storage as one of the coming-together points of what regional, state and national entities can do,” she said. MISO has tentatively scheduled a July 24 common issue meeting to discuss how storage might fit into its market and could convene a task team to craft new rules. (See MISO’s Next Step on Storage: ‘Common Issues’; Task Team?)
Voss said with load growth flat nearly nationwide, it’s time for state regulators to determine whether current energy policies will still make sense when demand eventually rises again.
Mohl agreed. “Slow load growth hides a lot of sins,” he said, adding that baseload resources are no longer being tested regularly for reliability.
Capacity is still not properly priced for merchant generation, Voss said, maintaining that suppliers have no incentive to build any new generation — especially in Southern Illinois. “I don’t think the capacity problem has been solved anywhere in the country. There’s no drive to build anything new,” he said.
Mohl added that low margins and low gas prices are pricing some longtime generators out of the market.
“There are some that say, ‘Well, they should just leave the market,’ but we don’t want all of them to leave the market,” he said, adding that capacity needs to be priced properly.
As the industry moves away from coal — and even nuclear — generation, RTO leaders, regulators and utilities will require more defined plans for upgrading natural gas infrastructure and pipelines, Mohl said.
“I think a lot of times people hope and pray that it’s there when they need it, but what I don’t see is a more intentional plan. … If you get down to renewables and natural gas and remove baseload generators, there’s inadequate infrastructure,” he said.
“There’s a big disconnect there,” Voss agreed. “There hasn’t been enough attention on, ‘Is the firm supply of gas really firm?’”
“Right now, it really doesn’t matter. But it will,” Mohl added.
Jacobs predicted increased difficulty in siting new pipelines and transmission alike because of a surge in environmental activism. “I think 10 years ago, regulators would have asked, ‘Why are there police, bomb-sniffing dogs at your meetings?’” she said.
VALLEY FORGE, Pa. — The plethora of data PJM provides is only useful if the grid operator also explains what it all means, stakeholders told RTO staff last week at a special session of the Market Implementation Committee on providing transparency in how market prices are developed.
John Horstmann of Dayton Power and Light said that stakeholders are not always as informed as staff about what is significant in the numbers and what is not.
“I think we’re looking for more than just raw data,” Calpine’s David “Scarp” Scarpignato said. “We’re looking for some kind of meaning.”
Staff acknowledged the need for explanation. The meeting adjourned early, with Rami Dirani, PJM’s facilitator of sessions on the topic, agreeing to develop a presentation on what data the RTO can provide and some ideas regarding the best way to provide them. The presentation, scheduled for the committee’s next meeting July 11, will also address confidentiality and critical energy infrastructure information (CEII) considerations, he said.
Gary Greiner of Public Service Electric and Gas said that he wants to go beyond price spikes and trends and “get a seat alongside of the dispatcher as they’re making their reliability decisions” to know why units are dispatched out of market, why those units weren’t economic and why that isn’t anticipated. PJM’s current practice of reviewing the past month’s results loses the advantages of instantaneous feedback, he said.
“I don’t know that that’s a good model for price formation,” he said.
Acknowledging confidentiality and competitive concerns, Greiner urged PJM to provide the most granularity possible to help market participants understand system dynamics, such as where circumstances are changing and what’s causing it. And while he also acknowledged the importance of not making dispatchers so preoccupied with how their actions will be perceived that they hesitate to make the right decisions, he cautioned against relying on a dispatcher’s “experience and intuition” to dictate a “significant portion” of dispatch.
“As much of that as we can push into the algorithms embedded in the models, the better we are — and we won’t know that unless we can see it,” he said.
The goal for PSE&G, he said, is to make decisions as predictable as possible so market participants can anticipate situations and act on them as quickly as possible.
“I don’t have a sense of what’s going on there,” he said. “When dispatchers are taking out-of-market actions, I’d like to know what they are and why they’re taking them … to get closer to a more transparent dispatch that we all understand.”
Joe Ciabattoni, who manages PJM’s market coordination, said MISO’s forecast reports offer more granularity, which PJM is studying and plans to include in its reporting. PJM’s security-constrained economic dispatch engine provides forecasts of various intervals, including “very short-term,” “short-term,” “intermediate-term” and “real-time,” he said, adding that staff will consider what data from each category could provide meaningful information for stakeholders.
“Historically, we’ve always reported on the overall forecast because years ago, before we had sophisticated applications, that’s all that really mattered,” he said.
Dirani said he would begin compiling information in response to the group’s interests. He asked stakeholders to provide, as soon as possible, any additional issues PJM should examine and be prepared to fully evaluate all of them for the next meeting.
BRANSON, Mo. — MISO will have adequate generation over the next five years to address its changing resource mix and the adoption of new technologies, planning staff told RTO leaders last week.
Low electricity demand plays a big part in the brighter forecasts and more optimistic tone adopted by MISO when discussing future resource adequacy, staff say.
“Energy efficiency has made our load essentially flat since 2008,” Clair Moeller, MISO executive vice president of operations, said during a June 20 meeting of the Board of Directors’ System Planning Committee.
The RTO’s annual resource adequacy survey published jointly with the Organization of MISO States earlier this month found that low demand will leave its footprint flush with capacity through at least 2022. The survey showed a 2.7- to 4.8-GW regional surplus over the next five years, while last year’s survey predicted a 0.4-GW shortfall by 2018 if no new generation came online. (See Capacity Survey Shows MISO in the Black.) MISO expects peak loads of more than 130 GW by 2032. Current summer peak is expected to hit about 125 GW.
Director Phyllis Currie asked what MISO is receiving from states in terms of resource planning.
Jennifer Curran, MISO vice president of system planning, pointed to a new level of fuel diversity in states’ integrated resource plans, which typically chart a resource mix that is one-third each coal, natural gas and either wind or nuclear generation.
“The old days were a preponderance of coal; the new days are a preponderance of gas,” Moeller said.
Wind projects still occupy about a 67% share of the current 32 GW of new generation in the RTO’s interconnection queue. Moeller expects fewer wind projects to enter the queue as federal production tax credits are phased out.
Planners think batteries do not yet make financial sense in the MISO footprint. “We think we have some time to work through how to do the math to optimize storage,” Moeller said.
However, MISO is hedging bets this year by introducing a fourth 2018 Transmission Expansion Plan 15-year future scenario that envisions a surge in rooftop solar, localized storage devices and electric vehicle use. (See “MISO Tweaks 4th and Newest MTEP Future,” MISO Planning Advisory Committee Briefs.)
“Now the electric vehicle folks are sure this is going to happen, and the solar collector folks are sure this is going to happen,” Moeller joked. “We’ll see. What we need to ensure is that we have the grid for the future when the future gets here.”
| MISO
MISO still expects emerging technology like solar to increase the complexity of transmission planning and noted that demand-side programs have the potential to “fundamentally change load levels and shapes.”
Moeller noted that the Department of Energy forecasts even higher future solar penetration than MISO’s highest predictions.
“We’re not quite sure where their optimism comes from, but that’s where it is,” Moeller said.
An Energy Information Administration report released early this year projects that the U.S. will add nearly 70 GW of new wind and solar photovoltaic capacity from 2017 to 2021. Solar will be one of the “most competitive sources of new generation” by 2022 and will represent more than 50% of new capacity additions between 2030 and 2040, according to the agency.
WASHINGTON — In their closing remarks at Thursday’s annual technical conference on reliability, acting FERC Chair Cheryl LaFleur and Commissioner Colette Honorable talked as if the event would be Honorable’s last public appearance as a commissioner.
It was indeed.
“Parting is such sweet sorrow! My last day as a FERC commissioner will be this Friday. It has been an honor. Thank you!” Honorable tweeted late Monday night.
“When we sat in this [commission meeting] room last month, I said, ‘I hope this won’t be the last time we’re in this room together,’” LaFleur began.
“And I equally hope that today, but I’m less sanguine that there’ll be a lot of other times,” LaFleur continued. “I think you’ve brought so much … to the commission, particularly with your focus on customers and your constant reminders about the need to work with our state colleagues. … I will really miss having you here.”
Honorable thanked FERC staff at length and told LaFleur that “It’s been an honor to work with you.
“This has been the highest honor of my professional career,” she concluded. “And it’s so much so because of the men and women I’ve done it with. So thank you so much.”
BRANSON, Mo. — MISO staff and the Independent Market Monitor agreed that the RTO’s markets performed as they should have this spring, but both found a surge in MISO South outages troubling.
MISO reported an average 69.2 GW of load March through May, up 1.3% from 68.3 GW in spring 2016. Executive Director of Strategy Shawn McFarlane said hotter-than-normal spring temperatures contributed to the load increase. The RTO hit a 92.2-GW spring peak on May 16.
The average spring real-time energy price was $29.96/MWh (the Monitor reported an average $29.90/MWh), a 39% increase from spring 2016, driven by a sharp increase in gas prices, MISO said. Market Monitor David Patton said natural gas prices rose 57 to 65% year-over-year, with the highest price spikes in Texas and Louisiana.
McFarlane said the higher load, combined with forced outages, caused high real-time congestion on multiple days, particularly in the South and Central regions.
MISO racked up $467 million in congestion during the quarter, Patton said during his quarterly report delivered on the first day of summer to the Markets Committee of the Board of Directors. He cited higher gas prices as a contributor to the rise in congestion, saying “gas-fired units are often marginal when generation is redispatched to manage network flows.”
“MISO experienced the most congestion of any other RTO in the country … almost half a billion dollars,” Patton said. He repeated his proposal for relieving congestion: that MISO and its neighbors transfer the control of border constraints when one RTO has more relief on a flowgate than the other.
“A good reminder that there is always work to be done at the seams to improve things for our constituents,” Director Paul Bonavia said.
The congestion was also because of high planned outages in MISO South, Patton said, adding that the RTO should seek additional authority to approve and coordinate outages. Expanding the authority of the RTO, which is currently limited to a “reliability review,” will be one of the recommendations in his annual State of the Market Report this month.
Under its Business Practices Manual, MISO can only “recommend [an outage] schedule that maintains system security and minimizes adverse impacts.” Owners and operators submit planned maintenance outage schedules for generators 10 MW and above to MISO for a minimum rolling 24-month period. The RTO studies the impact of all transmission and generator outages and works with owners to reschedule when an “outage analysis indicates unacceptable system conditions” or when a zonal maintenance margin is reached. “We have to not schedule ourselves into emergency situations. The ability to schedule them to minimize their effects will be a significant savings,” Patton said.
There is no need for all resources to schedule their maintenance outages in the spring and fall shoulder months, Patton continued, noting that capacity often exceeds winter load in the South by so much that it becomes “stranded” because of the limit on South-to-North transfers. “Economic opportunities likely exist to shift outages from shoulder to winter months,” he said.
Outages in MISO South removed as much as a 34% share of capacity during the spring, and outages in MISO Midwest took about 25% of capacity. Last year, spring outages took out 15% in the South and 14% in the Midwest. As a consequence, real-time congestion cost increased more than 50% over last winter and the prior spring quarter, according to the Monitor.
Patton also noted that the transmission and generation outages and extreme weather in the South led to 22 days of conservative operations in load pockets and three days with maximum generation alerts in April. An emergency maximum generation event on April 4 was spurred by the loss of a large nuclear unit, apparently Entergy’s Grand Gulf 1 in Mississippi, which the Nuclear Regulatory Commission reported going out of service because of a condensate leak.
Director Baljit Dail asked if there was a reason behind the spate of outages. “It just struck me as a massive increase. … It was two-and-a-half times what we normally have,” he said.
Staff agreed the outages were higher than the usual crop of shoulder-season outages.
“We do agree with Dr. Patton’s suggestion that a higher degree of coordination would be useful,” Chief Operating Officer Richard Doying said.
Bonavia said he once commiserated with control room operators over the challenges of handling summer heat but was told it was the shoulder months that caused the most anxiety. “They’re ready on those hot summer days when demand is screaming. … It’s those shoulder periods when the weather is volatile and the storms kick up that worry them,” Bonavia recounted.
Patton also praised the rollout of MISO’s extended locational marginal pricing (ELMP), which he said was responsible for about a 10% decrease in real-time revenue sufficiency guarantees paid out to market participants in the spring. However, Patton said he is still recommending that the RTO expand ELMP further to allow all generators with two-hour minimum run times to set prices, instead of MISO’s change, which added online resources with one-hour start-up times. MISO contends that the Monitor’s price-setting expansion would not be worth the expensive software change. (See “MISO Officially Expands ELMP,” MISO Market Subcommittee Briefs.)
WESTBOROUGH, Mass. — ISO-NE Director of Regional Planning Mike Henderson on Wednesday presented the schedule for stakeholder comments on the grid operator’s 2017 Regional System Plan, which are due July 24. The plan will be discussed at the August Planning Advisory Committee ahead of a Sept. 14 public meeting in Boston. The draft plan will be posted online by July 7.
“Our view is that the report should be viewed as a [critical energy infrastructure information] document,” Henderson told the PAC during a June 21 teleconference. “In past years, we have noted some, frankly, mistakes that the ISO made in the report where we may have inadvertently included some CEII materials, and as a draft document, that would present a major issue. … We’d hate to see something that does not reflect your [PAC members] input … put out in the public domain.”
Transmission planner Jon Breard presented an update on transmission projects and asset condition as part of the RSP drafting process. One participant asked if, based on the presentation, the growth in transmission spending was coming to an end in 2019.
“I’d be careful about ‘coming to an end,’” said Brent Oberlin, director of transmission planning. “It’s just what we have planned so far [is] really slowing down, and that’s our expectation going forward.” He added that the RTO must still complete reassessments for Maine, New Hampshire and central Massachusetts.
RTO will not Conduct Public Policy Tx Study for 2017
Oberlin presented ISO-NE’s conclusion that no federal or state public policy requirements are currently driving transmission needs, precluding the need for a special study on the subject this year. The RTO’s position aligns with a similar assessment submitted by the New England States Committee on Electricity (NESCOE) last month. (See ISO-NE: Won’t Override States on Public Policy Tx Needs.)
A May 16 letter from the Conservation Law Foundation asked the RTO to conduct the analysis despite NESCOE’s conclusion. NESCOE responded that ISO-NE should evaluate potential projects only after states have indicated transmission needs resulting from their policies.
Paul Dumas of Avangrid asked when the Tariff stipulates that the RTO must start another public policy process.
“At least every three years,” Oberlin said. “So the farthest that we would go out would be initiating the process in 2020. I think we’re going to keep an eye on where the states are with [requests for proposals] and things like that and make our determination if we would go earlier.”
Eversource to Replace ‘Vintage 1950’ Equipment
Eversource Energy’s George Wegh presented CEII material on the utility’s work to modernize several outdated substation control houses in its Eastern Massachusetts service territory. Wegh apologized for informing the PAC after the work had already started. He said Eversource would fix whatever internal communications problem created the lapse in planning protocol.
Two of the control houses being refurbished are “vintage 1950” and still use some of the original equipment, including analog meters and electromechanical relays.
Woodpecker Woes on 345-kV Lines in Eastern Mass.
Woodpecker damage, pole rot and splitting | Eversource
Eversource’s Chris Soderman presented evidence of woodpecker damage and decaying support structures along a 345-kV line in Eastern Massachusetts and similar problems on the Southern Connecticut Loop, where the company will not only replace structures but install optical ground wire to enhance communications and reliability.
The company will replace with steel approximately a fifth of the 262 wooden structures along the 29-mile Northfield-to-Ludlow line in Massachusetts. The estimated $8 million cost includes installing new hardware and insulators.
Southern Connecticut Loop | Eversource
Along the Connecticut line, which runs about 38 miles, Eversource will spend an estimated $68 million to replace 258 structures, many of which have decaying, laminated wood cross arms. Soderman emphasized that the light-duty weathering steel poles being installed on both projects were not custom ordered but off-the-shelf equipment.
National Grid Implements Reliability Scheme on Tx Circuits
Jack Martin of National Grid presented the utility’s plans to install dual high-speed protection systems on 45 major transmission circuits over the next decade to meet standards set by the Northeast Power Coordinating Council.
NPCC Directory 1 mandates that all New England transmission owners meet the performance reliability requirements on Bulk Electric System elements by Sept. 10, 2025.
National Grid will pursue a five-stage rollout and estimates the cost for Phase 1 at $1.8 million. The company expects substantially higher costs for the ensuing phases, which include significant installation of optical ground wire and a number of control house rebuilds. The utility has started conceptual engineering for the other four phases and will update the PAC once it has estimated the costs.
CAISO last week proposed to eliminate from its Tariff an annual state transmission concept plan that it says is obsolete because of changes at the federal level.
The move has support from Southern California Edison and the California Office of Ratepayer Advocates (ORA).
CAISO has developed the Statewide Conceptual Plan each year since 2010 as part of its lead role in the California Transmission Planning Group (CTPG), the transmission owner and operator group once responsible for coordinating local and regional planning across the state under FERC Order 890.
But since the implementation of FERC Order 1000 — the federal process that supersedes the previous planning process — the CTPG is no longer operating, and utilities have generally stopped responding to CAISO’s conceptual plan.
“There is little if any value in the ISO alone developing the conceptual statewide plan, and it detracts limited ISO resources from focusing efforts on the extensive and important planning activities they must otherwise undertake,” CAISO said in its draft proposal.
CAISO Says the Annual Conceptual Transmission Plan is Obsolete | Berkshire Hathaway Energy
The planning process under Order 1000 now covers regional and interregional planning, and the CTPG has not held a meeting in four years, has none scheduled and has no chairperson. The ISO Tariff still requires the grid operator to develop the plan to determine transmission requirements to meet reliability, economic and public policy needs.
SCE, the state’s second largest investor-owned utility, said it “concurs with the proposal’s conclusions and the recommendation to remove the Conceptual Statewide Plan from the California ISO Tariff.”
ORA agreed that the conceptual plan “no longer serves its intended purpose” but said the impact of eliminating the plan should be evaluated after the completion of the next interregional transmission planning process. It should be determined whether the revised process adequately incorporates California’s specific transmission needs into interregional plans, the agency said.
Order 1000 identified CAISO as a planning region with Pacific Gas and Electric, SCE and San Diego Gas & Electric as members. Other participants in the conceptual plan are now associated with WestConnect as a planning region.
“Absent the active participation of all statewide planning entities in developing a conceptual statewide plan, development of the plan amounts to little more than a unilateral ISO exercise,” CAISO said.
The ISO is asking that stakeholders submit comments on the final draft proposal by June 29.
