PJM is opening its second competitive project proposal window of the year this week.
Its scope consists of a year 2021 analysis of N-1 and N-1-1 thermal and voltage contingencies; generation deliverability and common mode outages; and load deliverability thermal and voltage.
The window will be open 30 calendar days, PJM said. Those offering proposals during that time will be permitted 15 additional days to submit detailed greenfield reports.
This is the second window for which a new proposal fee will apply for upgrades and greenfield projects. There is no fee for proposed projects costing less than $20 million. A $5,000 fee will be assessed for projects of up to $100 million. Proposals with a projected cost of more than $100 million must be accompanied by a $30,000 fee.
Details on registering were presented at the January Planning Committee meeting.
SPP said last week it is seeking industry experts to serve on a second independent panel to review Order 1000 transmission proposals in 2017.
The panel will review and score proposals for competitive projects approved for construction by SPP’s Board of Directors. The RTO’s first independent expert panel earlier this year awarded a 22.6-mile transmission project to Mid-Kansas Electric. (See SPP Awards First Order 1000 Project — But it May Not be Needed.)
“We are proud of our initial [industry expert panel] process, having now seen it all the way through for the first time,” said Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel. He said the process will be refined based on lessons learned and stakeholder feedback.
SPP said interested candidates must have expertise in at least one of five areas “as it relates to electric transmission”: engineering design, project management and construction, operations, rate design and analysis, and finance.
Applications will be accepted through Sept. 1. Panelists will be selected based on a recommendation by the RTO’s Oversight Committee and approved by the board later this year. Those serving on the panel will be considered contractors and will be compensated through a monthly retainer and hourly rate.
More information on the panel’s application process can be found here.
DETROIT — MISO and its Independent Market Monitor have reconciled their differences and reached a compromise on a redesign of the capacity auction, CEO John Bear told stakeholders at the RTO’s Annual Meeting last week.
Bear made his remarks at Wednesday’s Advisory Committee meeting, which was originally planned to feature a presentation on the new competitive retail solution (CRS), a proposal to create a separate, three-year forward auction for retail-choice areas in the RTO’s footprint.
The delay gives MISO officials and the Monitor, which have disagreed on core aspects of the CRS, more time to work on their “hybrid” proposal. (See MISO: Auction Design July Filing Doubtful.)
Bear refused to give any details on the compromise, saying he preferred discussion to take place at the next Resource Adequacy Subcommittee meeting June 29-30, when the proposal will be officially unveiled. He also said further discussion would take place at a meeting in mid-July.
“If we need more time, we’ll take it. We’re not going to release something that’s half-baked,” Bear said.
MISO stakeholders, however, predicted a tough road to implementation regardless of what is released. Resource Adequacy Subcommittee Chair Gary Mathis told the board that “there’s a very big rift between those that think we shouldn’t be doing this, if ever,” and those in favor of varied approaches to redesigning the auction.
“It makes it hard to work through those issues,” Mathis said. He said he anticipates a “big stress level from stakeholders” as they sift through the revised proposal.
Board member Baljit Dail asked if it would be stalled to the point where it would still be under development in a year.
“No, I think we’ll have a big discussion, and then FERC will have to sort it out just like MISO has had to sort it out,” replied Mathis, who predicted challenges to whatever the RTO files.
Despite the predicted challenges in FERC, MISO board members put pressure on stakeholders to come up with a solution as quickly as possible. Board member Judy Walsh said she hoped MISO would come up with a filing in “some sort of short timeline.”
“The search for absolute consensus is going to lead us to endless delay,” board member Paul Bonavia agreed.
However, Kevin Murray, of the End-Use Customers sector, said any attempt from MISO to implement a hybrid solution in time for the 2017/18 planning year would be too hurried and “circumvent stakeholder process.”
Board Troubled by Forecast Generation Shortfall
At the Board of Directors meeting Thursday, board members said they were troubled by the possible generation shortfall in 2018, as predicted in this year’s MISO-Organization of MISO States Survey. (See OMS-MISO Survey: Generation Shortfall Possible.)
MISO Executive Vice President of Transmission and Technology Clair Moeller told the board that a redesigned capacity auction that sends better price signals could curb the rate of retirements.
“That’s why we continue to push the competitive retail solution and be aggressive, to solve this decline [in generation] before it becomes a reliability problem,” Moeller said.
OMS President Sally Talberg urged implementation of the CRS in time for the 2017/18 planning year.
In the survey, MISO identified 2.5 GW worth of planned retirements and 1.8 GW worth of potential closures in 2017.
Board member Michael Evans asked Moeller if he could provide reassurance that adequate reliability exists in the near future.
“We don’t anticipate significant problems in the local area as long as there is sufficient transfer capability. I am cautiously optimistic that things will be OK,” Moeller said. “In the construction world, we’d say that we used up all our ‘float.’ So we need to get to work, but there’s enough time.”
Evans also asked how many coal and nuclear plants that recently threatened to retire have actually filed for retirement study requests.
MISO legal counsel Stephen Kozey answered that the RTO could provide the total capacity that has filed for retirement but couldn’t name the individual plants.
“It is true that not everything [mentioned] in the press has gone through a [retirement study] request,” Kozey said.
“We may end up with a retirement queue,” Moeller added.
“It might be worthwhile to start doing some intensive ‘what-if’ studies,” Evans said.
Dail asked if the 800-MW increase in forced outages predicted in the survey would be a continuing trend. Moeller said the higher outage rates are the result of using coal plants for short cycles, for which they weren’t designed.
“Not to be an alarmist, but this makes me a bit uneasy,” board member Thomas Rainwater said.
The board then asked if MISO could simply deny generator suspensions and retirements.
“We have the ability to call resources back to maintain local reliability but not to protect resource adequacy,” Moeller answered. He said a market mechanism needs to be created to keep generators online for the sake of resource adequacy.
“So if you need them a day later, you can keep them. If you need them three years from now, you can’t keep them?” Walsh asked.
Snowpack in the Sierra Nevada mountains, depleted after four years of drought, will likely remain in deficit until 2019, according to a University of California, Los Angeles study. The research debunks the notion that the recent El Niño, which increased snowpack levels to about 85% of normal, was a “drought buster.”
Sierra snowmelt accounts for more than 70% of the region’s streamflow, 60% of the state’s water supply and much of the energy output for the state’s extensive system of hydroelectric dams, which declined by two-thirds between 2011 and 2015.
Only one previous drought in 65 years required more than a year of recovery to the snowpack. “The fact that this deficit is so much larger is where this number comes from and why we would expect it to be a multiyear recovery,” said Steve Margulis, the study’s lead.
The Department of Natural Resources will allow the builders of the Dakota Access pipeline to use horizontal drilling methods to construct the Bakken crude pipeline under historic tribal burial grounds in the Big Sioux River Wildlife Area, removing a regulatory impediment to the $3.8 billion pipeline.
The pipeline’s developers, Energy Transfer Partners, suggested the pipeline could be bored 85 feet beneath the surface as a way to resolve the dispute over the recently discovered burial ground. The drilling method would avoid surface disturbances of an open trench. “It’s obviously going to have to go deep enough so it’s not going to disturb the tribal grounds,” DNR spokesman Alan Foster said.
Native Americans said they still opposed the 1,168-mile pipeline. “It is disheartening that they have a green light to move ahead, but I feel very confident that there are a number of landowners, tribes and well-informed citizens who will be standing up to make sure that this pipeline does not get built,” said Dallas Goldtooth, an organizer for the Indigenous Environmental Network.
Westar Energy customers could see an $18 million rate reduction as a result of FERC’s approval of a settlement between Westar Energy and the Corporation Commission over transmission-delivery charges.
FERC on March 30 approved a settlement between Westar and the KCC after determining the company had collected too much money from customers. The ruling came a day before the state commission approved a $25 million increase to Westar transmission delivery charges, adding about $4 to an average customer’s bills.
As a result of those two decisions, Westar updated its transmission costs June 21, dropping the amount charged to customers by $18 million.
Upper Peninsula utilities say their customers will unfairly bear the burden of $49.7 million in MISO reliability charges to keep three coal-fired power plants operating.
The RTO filed a new cost calculation for the plants’ system support resource agreements with FERC, and the bills’ first installments are due July 8. Utilities are blaming the state’s customer choice program, which allowed all large mining customers to switch energy suppliers but capped the rest of the state at 10%.
Cloverland Electric Cooperative owes the most, at nearly $11.3 million. Cloverland CEO Dan Dasho estimated that each customer would have to pay an additional $17 to $20 a month for the next 14 months to satisfy the bill.
Ann Arbor Eyes More Solar to Combat Climate Change
Ann Arbor has unveiled a plan to cut the city’s carbon emissions 25% by 2025, aiming to add the equivalent of 2.4 MW in solar installations every year over the next decade.
The City Council unanimously approved a resolution that supports solar-friendly measures, including instructing city departments to abide by the Clean Energy Coalition’s Solar Ready Community guidelines.
Consumers Energy Contests Taxable Value of Wind Farm
Consumers Energy is challenging the tax assessment of its 111-MW Cross Winds Energy Park in Tuscola County, where several other wind farms are also seeking reductions in their property tax payments.
The utility filed petitions with the Tax Tribunal, arguing that the assessed value of the $250 million wind farm was too high and asking for refunds for overpayment.
NextEra Energy Resources has filed a similar petition regarding their Tuscola I and Tuscola II windfarms. Tuscola County Controller Mike Hoagland said the assessed values of “most, if not all” the county’s wind turbines are being challenged.
Gov. Mark Dayton said his state will ask the full panel of the 8th U.S. Circuit Court of Appeals to hear its appeal of a lower court ruling that the state’s clean energy law illegally regulates out-of-state energy companies.
A three-judge panel of the 8th Circuit upheld a ruling that the state’s law, which restricted electricity imports from power plants that increase the state’s greenhouse gases, was unconstitutional.
Entergy Forced to Shut Down Indian Point Because of Leak
A week after it came back into service following a three-month outage, Entergy once again shut down Unit 2 at its Indian Point nuclear plant so workers could repair a leaking water intake pipe.
The leak in the cooling-water intake was unrelated to the problem that Entergy encountered with damaged baffle bolts, which required the recent protracted outage to repair. But Gov. Andrew Cuomo slammed the plant’s operators for the latest in a series of problems at the twin-reactor complex.
“This is yet another sign that the aging and wearing away of important components at the facility are having a direct and unacceptable impact on safety and is further proof that the plant is not a reliable generation resource,” Cuomo said.
The Senate passed a bill that will prohibit wind turbines from being erected in the central and eastern portions of the state, threating two proposed wind farms with a combined output of 400 MW.
Sen. Harry Brown (R-Onslow County), the bill’s sponsor, said the wind turbines present a danger to low-flying aircraft, especially military jets and helicopters operating out of the several large bases, including Fort Bragg and Cherry Point Marine Air Station. “Anything we can do to protect them is important,” he said.
A Department of Defense spokesman, however, said Brown’s legislative effort was done without any consultation from the military. “We have not officially been engaged or involved with North Carolina regarding the latest proposed revisions to state law,” Lt. Col. James B. Brindle said.
Duke Energy Progress has proposed to cut rates for its 1.35 million customers to reflect lower energy costs.
The proposal, made last week to the Utilities Commission, includes some rate increases and some decreases on various components of its service.
Overall, residential customers would see a 4.9% drop; industrial consumers, 5.7%; and commercial customers, 6.3%. The rates would go into effect on Dec. 1.
The Public Service Commission last week approved a proposed $153 million wind farm and associated electric transmission line in Oliver and Morton counties. The three-member panel unanimously approved the project’s siting application, clearing the way for construction to start.
A NextEra Energy subsidiary is developing the wind farm, which will include up to 48 turbines and produce up to 100 MW of power. The project also includes a 4.5-mile, $11.4 million transmission line to connect the wind farm to the grid.
The Public Service Commission may vote as early as next month on the 72-turbine Brady Wind Energy Center II project. The PSC has meetings scheduled for July 6 and July 20.
Commissioner Brian Kalk said the commission did not have many additional questions for representatives of Brady Wind, a subsidiary of NextEra Energy.
The PSC has already approved Brady Wind I, the first phase of the project, which consists of 87 turbines and a 19-mile transmission line.
Gov. John Kasich has nominated energy industry attorney Howard Petricoff to fill a vacant seat on the Public Utilities Commission, which spurred Senate President Keith Faber, a Republican, to call for hearings into the Democratic nominee’s record.
Petricoff recently retired as head of the energy section of a large Columbus law firm and had many competitive retail energy suppliers as clients. Faber said Petricoff’s legal work “raised questions about his ability to make neutral decisions given his past activism.”
If Petricoff is confirmed by the Senate, PUCO would have two Republicans, two independents and one Democrat. State law mandates that no party can have more than three of the five seats on the commission, but it does not require at least one member of each party.
An overflow audience of nearly 300 residents turned out to debate a zoning proposal by a subsidiary of Iberdrola Renewables to build 37 wind turbines on 266 acres in Penn Forest Township, Carbon County.
The crowd, mostly hostile to the proposal, jeered representatives of Iberdrola and the Sierra Club, which supports the wind project. The 525-foot-high turbines and blades would be built on land leased from the Bethlehem Authority, the financial arm of the town’s water business. It would be located less than a mile of several homes.
Bills aimed to block a natural gas power plant and to shift a wind project’s interconnection costs to ratepayers failed in the legislative session, but other proposals favored by clean energy advocates moved forward, including an extension of the state’s renewable portfolio standard from 14.5% by 2019 to 38.5% by 2035.
The legislature also extended the Renewable Energy Fund to 2022, which provides grants and loans to install renewable-energy systems.
The sponsors of a federally funded experiment to explore deep underground storage of nuclear waste will have to search for a new site.
Spink County turned away technology development company Battelle from conducting experiments that involve drilling as much as 3 miles deep into bedrock to test storing waste in boreholes. The experiment wouldn’t involve any radioactive waste, but wary residents expressed fear the tests would increase the chances their area would eventually be chosen for a waste well.
“It was a good spot to try and do our science experiment, so we’re disappointed we couldn’t work something out with them,” a Battelle spokesman said. “But we understand.”
Lubbock Power & Light’s Electric Utility Board has proposed a 2% increase in customer bills and $70.9 million in infrastructure improvements. The budget will be presented this summer to the Lubbock City Council for final approval.
The rate increase would pay for the projected $333 million worth of capital improvements LP&L plans in the next six years, largely in preparation for the switch to ERCOT in 2019, when the city’s wholesale contract with Xcel Energy expires.
The inner transmission loop will be upgraded to 69 kV and the outer loop to 115 kV as part of the infrastructure improvements.
Less than a week after obtaining its air permit from the Air Pollution Control Board, Dominion Virginia Power began construction on its 1,588-MW Greensville County Power Station. The company said it expects the $1.3 billion plant to go into service by 2019.
Dominion says the power station will be a major boost for the region’s economy, with up to $8 million in property taxes paid to Greensville County in its first year of operation. The company also said its customers will save about $2 billion over the plant’s expected 36-year life, as the company will not need to purchase power on the market.
“The air board has approved and the Virginia Department of Environmental Quality has issued a very strict permit, which will require that our station be one of the most efficient and environmentally protective natural-gas fueled power stations in the world,” Dominion’s Pamela F. Faggert said.
DETROIT — The MISO Advisory Committee’s five priorities in 2016 have been finalized, but now the committee’s leadership would like them extended into 2017.
Chair Audrey Penner said the priorities process and priorities themselves would be subject to revision during an October strategy session, but they could carry into 2017. (See “Committee Endorses 5 Final Priorities,” MISO Advisory Committee Briefs.)
Paul Kelley, representing the Transmission Owners sector, said he wanted an opportunity to revisit priorities in 2017.
CEO John Bear said the committee’s agreed-upon priorities closely aligned with MISO’s. “I feel like we’re closer than ever with what [MISO] and the parent entities want,” Bear said.
Stakeholder Redesign Completed
Committee Vice Chair Tia Elliott said the stakeholder redesign organization chart has been fully implemented since June 1.
She also said this update at would likely be her last.
Elliott said the redesign’s benefits and possible shortfalls would be the subject of December’s Hot Topic discussion.
“I think it’s phenomenal that a very large group of stakeholders could coalesce and get this done. Kudos to you,” board member Judy Walsh said.
Elliott quoted Henry Ford to sum up the redesign work: “Coming together is a beginning; keeping together is progress; working together is success.”
WILLIAMSBURG, Va. — Two former Ohio regulators debated FirstEnergy’s and American Electric Power’s controversial power purchase agreements in the opening session of the Mid-Atlantic Conference of Regulatory Utilities Commissioners Annual Education Conference last week.
Steven Lesser, who served on the Public Utilities Commission of Ohio from 2010 to 2015, defended the commission’s decision to award the eight-year PPAs for the companies’ merchant generation, saying it was consistent with state policy since 1999. “The first thing I want to do is dispel this myth that Ohio has been on this clear trajectory toward deregulation,” he said.
Lesser’s opponent in the debate was former PUCO Chairman Todd Snitchler (2011-2014), who conceded that the state has moved in “fits and starts” toward competition. But he said consumers have indicated their preference for choice, with more than 80% of industrial and commercial customers in most areas of the state choosing alternate suppliers, along with more than 50% of residential customers.
After FERC said April 27 that the PPAs would be subject to its affiliate abuse review, the companies asked to replace the agreements with different proposals crafted to avoid FERC jurisdiction (14-1297-EL-SSO, 14-1693-EL-RDR, 14-1694-EL-AAM). Opponents of the deals have kept up the pressure in filings with FERC. (See FirstEnergy Foes Ask FERC to Step in Again in Ohio Dispute.)
Avoiding Risk
Lesser said PUCO was correct to adopt the PPAs as price hedges given natural gas’ history of price volatility. The commission’s role is to be “risk averse,” he said.
“As regulators … we have to look to the future. Are we one large injection-well earthquake from some moratorium on gas [development]? Has gas ended its long history of being a boom-bust industry?”
He also cited the solar and wind development the utilities promised in return for the PPAs, and PUCO’s conclusion — based on an assumption that gas prices will rise — that the PPAs will produce net benefits of $500 million versus market prices.
Ohio “should not have to choose between being a totally vertically integrated state or a fully deregulated state,” he said. “States should be allowed to choose wherever in that paradigm they want to be.”
Snitchler, now a principal with Vorys Advisors, said state restrictions on utility ownership of generation mean that the promised renewables “may not actually come to fruition.”
“So they sounded terrific, but the deliverables are at some point in the future, to be paid for by a party yet to be determined at a cost that is unknown and unknowable,” he said. He cited testimony that the PPAs could cost customers $3.5 billion to $5.5 billion “for nothing that ratepayers aren’t already receiving.”
Snitchler also acknowledged that gas prices have been volatile in the past. “But no commodity has zero fluctuation,” he said. “And the last time we were concerned about the price of gas, the Marcellus and the Utica [shale plays] were not developed,” he said.
Plant Closures
Lesser said the PPAs allowed regulators to balance the benefits of restructuring with reliability concerns and the state’s “economic development needs,” a reference, in part, to job losses that would result from plant closures.
“Ohio is just looking for some narrow flexibility between the fully deregulated” and fully regulated models, he said. “Regulators have the responsibility to ensure reliability — not hope for it, not wish it, but ensure it. … They need to be very risk-averse. Sometimes that might cost a couple extra dollars. … But being risk-averse is what they have been named to these positions to do.”
Snitchler said the reliability concern is a “red herring,” noting that the “plants in question that were threatened to be closed were committed [as PJM capacity resources] through the end of May 2019.”
“The concerns about jobs are real, because jobs do matter. But all jobs matter,” he continued, citing the construction jobs created by five new natural gas facilities being built in the state.
No Takers
The quick-witted Snitchler has been a crowd favorite at MACRUC gatherings in the past. But it was Lesser who drew the biggest laugh of the session when he responded to former New Jersey regulator Fred Butler, who asked whether politics influenced PUCO’s approval of the PPAs.
“Todd and I both support our families by practicing before the commission,” said Lesser, now senior counsel in the government relations and legislation group at Calfee, Halter & Griswold. “You expect us to answer that question?”
The Debate Continues
PUCO Chairman Asim Haque and Commissioner Thomas Johnson, who voted to approve the PPAs, had to leave the conference room for the debate because of ex parte concerns. “We’re going to get a couple’s massage,” Haque joked.
But Haque was present for a later session at which PJM CEO Andy Ott, Maryland Public Service Commission Chairman Kevin Hughes, former U.S. Energy Secretary Spencer Abraham and former Pennsylvania regulator Glen Thomas discussed the benefits and limits of restructuring and PJM’s capacity market.
Haque asked Thomas, now head of the PJM Power Providers Group (P3), whether the markets “got lucky” because of the cheap gas brought by the shale revolution. “Markets could be working but prices could be high,” Haque said.
“Maybe,” Thomas conceded. “But the bigger point is, because the markets were in place, consumers were able to benefit more than they would have otherwise.
“If you look at last 20 years of electric prices in PJM, there have been some [price] upticks. The polar vortex happened two years ago. There was Hurricane Katrina in [2005]. But if you look at the … overall trend over the long term, whenever there are [price] increases, the market responds, supply comes on and prices go down. … The market always responds to whatever is thrown at it.”
In 2015, he noted, wholesale energy prices were about the same as they were in 1999.
Thomas said when Pennsylvania approved restructuring two decades ago, “the single biggest concern … was ‘Could a competitive market build new resources?’ Twenty years later … the answer is a resounding ‘yes.’ We’re going into this summer with a 28% reserve margin.”
At the same time, he said, NOX, SOx and CO2 emissions are “all dramatically down.”
Support from Maryland
Hughes said PJM’s capacity market has recently resulted in new gas-fired generation in Maryland.
That was not the case in 2012, when the PSC ordered the state’s utilities to enter into contracts-for-differences with Competitive Power Ventures to build a gas-fired plant in the state.
At the time, Hughes recalled, policymakers believed the state was overly dependent on imported power. No new baseload generation had been built in the state since the mid-1990s. As coal plants began to retire, the commission feared the lack of in-state replacement capacity could cause reliability problems, Hughes said.
But CPV found financing to build the plant anyway and now it is one of three gas-fired plants under construction in the state; the PSC recently granted a certificate of public convenience and necessity for a fourth. “So I do think … we are seeing some signs now that capacity markets are working and are incentivizing some new generation,” Hughes said.
He said the state will seek additional in-state generation to comply with its Greenhouse Gas Reduction Act, enacted in April, which mandates a 40% reduction in emissions from 2006 levels by 2030.
But he added, “I do not think we are going to need to look at incentivizing new baseload generation. I think we have some good news there.”
Ott acknowledged that the majority of new capacity in the RTO has been gas-fired, which he said raised the question, “How much gas is too much?”
But that, he said, is a long-term concern. For now, he noted, PJM’s capacity is growing more diverse. Gas was the real-time marginal fuel in 35% of hours in 2015, up from 26% in 2011, while coal has dropped to 52% in 2015 from 69% in 2011, according to the Independent Market Monitor. Meanwhile, demand response clearing the capacity market has increased from less than 2,000 MW for delivery year 2011/12 to more than 10,000 MW for 2019/20.
“The good news is some of these gas units coming on … sit right on wellheads. … Some have dual-fuel capabilities. So the point is they are not all created equal from an operational perspective,” Ott said.
“What are the operational implications of being 70% gas?” he continued. “Certainly there are areas of the country that are at that level today so it’s not unprecedented.”
Ott also addressed Exelon’s threat to retire its Clinton and Quad Cities nuclear plants in Illinois, saying he hoped an “in-market solution” would be reached. The goal, he said, should not be to save every nuclear unit. (See Exelon to Close Quad Cities, Clinton Nuclear Plants.)
“Not every nuclear plant is created equal,” he said, noting the higher operating costs faced by small, single-unit plants. “Not everyone is run the best. So there is some benefit to having a market-based solution.”
The Society for the Protection of New Hampshire Forests has appealed the dismissal of its complaint against the Northern Pass transmission project to the New Hampshire Supreme Court.
The Coos County Superior Court last month dismissed the group’s suit, which sought to prevent the burial of lines in a highway right of way. The society said its property rights allowed it to deny access, even though it had granted rights of way for above-ground construction. (See Court Dismisses Complaint vs. Northern Pass.)
Revised path for Northern Pass shows buried sections in yellow.
“We believe strongly that the Superior Court erred by not getting to the root of the private property rights issue in its decision,” Forest Society attorney Tom Masland said.
He said the Superior Court ruling that dismissed the suit sidestepped legal questions about the property rights of the Forest Society by deferring to transportation officials.
“The N.H. Department of Transportation does not have the authority to determine the property rights of landowners affected by a project like Northern Pass,” Masland said. “By failing to address that issue now — nor allowing the issue to be litigated — landowners like the Forest Society would be left with no remedy. This is a complex case, and important issues remain unresolved, including the complexities and ramifications of declaring DOT the sole authority to resolve all matters involving the use of roads.”
Project developer Eversource Energy said it was confident it will prevail in the appeal.
“The New Hampshire Superior Court spoke clearly and decisively on May 25 when it dismissed the Forest Society’s lawsuit that claimed that the Northern Pass project does not have the right to bury the project under public roads in the North Country,” the company said in a statement. “The court’s summary judgment decision was based on over a century of New Hampshire law. We are confident that the state Supreme Court will uphold the Superior Court’s ruling.”
Eversource and its partner Hydro-Quebec have proposed to bury 60 miles of the 192-mile route. The project is being reviewed by the New Hampshire Site Evaluation Committee. (See Northern Pass Decision Delayed Nine Months.)
WILLIAMSBURG, Va. — As of last year, 17 states had smart meter penetration of 50% or more. Yet only seven states — Maryland, Delaware, Arizona, Oklahoma, Ohio, Arkansas and Louisiana — have more than 5% of their residential customers enrolled in time-varying rate plans, according to the Energy Information Administration.
The reason for states’ halting progress was the subject of a session moderated by Maryland Public Service Commissioner Anne Hoskins at the Mid-Atlantic Conference of Regulatory Utilities Commissioners Education Conference last week.
Leah Gibbons, director of regulatory affairs for NRG Retail Northeast, said consumers’ wariness of time-of-use rates and the speed of technological changes are arguments for retail competition.
“The real reason for relying on retail markets … is because consumer needs and desires are a very quickly evolving thing. People change their minds on what they want and what they need all the time. And the best way to meet those needs is through the innovation of competitive markets. … The regulated model simply is not equipped to deal with that pace and keep up.
“We still don’t know what are customers really going to want. What are they going to go for?” she asked, citing the experience in Texas and some experiments in the Northeast. “Customers really do not like big price spreads that you get in a time-of-use rate. … They’re kind of afraid of it. But you really need to have a decent price spread between on- and off-peak to get customers to change their behavior and actually shift their load. So … we’re going to have to figure out: How do you get customers to choose those kinds of products? Or does it make sense to think more about demand response products?”
Gladys Brown, chair of the Pennsylvania Public Utility Commission, said many of the state’s industrial customers are already on TOU rates and that the commission is now focused on expanding the option to residential ratepayers to take advantage of its 2008 law mandating smart meters. The PUC says about 40% of its 5.7 million residential customers now have advanced meters.
A PPL Energy pilot program that began in 2011 was suspended after less than a year after an unexpected increase in spot market prices resulted in both on-peak and off-peak prices being below the fixed-price default service, resulting in undercollections (P-2013-2389572). When prices rose above the default rate, customers fled the program.
“It started out slowly,” Brown said. But she said regulators hope that with “full deployment of smart meters that we’ll have a lot of different programs.”
Rich Sedano, director of U.S. programs for the Regulatory Assistance Project, said that in addition to reducing peak demand, TOU rates can influence customers’ willingness to add solar panels or a high-efficiency water heater. “The marginal costs of the system are something that customers are typically not aware of if they are in a flat-rate situation, but with time-varying rates they can be made aware of that. And their investments can actually be replacing utility investments,” he said.
William Fields, senior assistant for the Maryland Office of People’s Counsel, questioned whether TOU rates are compelling enough to motivate consumers, citing Pepco’s current TOU rates: 9.6 cents/kWh on-peak; 7.7 cents/kWh off-peak; and 8.2 cents/kWh intermediate.
“In this low-gas-cost, relatively high-capacity-cost … environment, is there really a big difference there?” he asked. “We just want to express some caution that we take a very close look at whether there’s value there to make it worth it.”
The first step is to obtain better data, he said. “One of the frustrations I’ve had … is the limited amount of really good customer data — usage for residential customers, different size houses, apartments,” he said. “I think the [advanced metering infrastructure] that we have should be looked at as an opportunity to collect some better data on things like how does overall usage correlate to [peak] demand? … Do smaller-usage customers have small demand and large-usage customers have large demand?”
WILLIAMSBURG, Va. — More than 300 regulators, PJM officials and industry stakeholders attended the Mid-Atlantic Conference of Regulatory Utilities Commissioners’ 21st Annual Education Conference last week. Here are some highlights.
Haque Reflects on Year as MACRUC President
Public Utilities Commission of Ohio Chairman Asim Haque reflected on his year as president of MACRUC as he prepared to hand the gavel to incoming president and New Jersey Board of Public Utilities Commissioner Mary-Anna Holden.
Haque acknowledged obstacles in executing his theme for the year: “lead together, lead now.”
His tenure coincided with a bruising battle in Ohio over FirstEnergy’s and American Electric Power’s requests for financial support for their merchant generation. At the same time, Exelon’s acquisition of Pepco Holdings Inc. split commission members in D.C. and Maryland.
“What I’ve come to find this past year is that each of our states’ challenges, while possibly common, are layered in so much subtext,” Haque said. “Most often that subtext can be unique to that particular state. The subtext can be existing law, the makeup and strength of various stakeholders in the state, the political tenor, varying financial interests…
“Finding the answers that are universally acceptable to each of our states is incredibly challenging,” he continued. “If you can’t find universally acceptable answers, then most certainly you won’t be able to lead now.”
‘CEO Panel’ Compares Notes
In the “CEO Panel,” executives from AEP, Pepco and NiSource discussed their challenges in response to questions from moderators Judith Jagdmann, of the Virginia State Corporation Commission, and Richard Mroz, president of the New Jersey BPU.
Robert Powers, COO of AEP, and David Velazquez, CEO of Pepco, shared their experiences operating in multiple jurisdictions. AEP has distribution utilities in seven states in SPP, ERCOT and PJM. In March, Pepco became part of Exelon, which now has distribution operations in five states and D.C. within PJM.
Powers said AEP’s geographical diversity gives the company “opportunities to experiment” on initiatives in one location before proposing them elsewhere. AEP’s philosophy is to “put strong people locally who don’t always have to come to [AEP headquarters in] Columbus for every decision,” he said.
Velazquez said dealing with multiple commissions prevents the company from rolling out initiatives such as smart meters and smart grids in all of its territories at once because of the need to “sell” them to state regulators individually.
On the other hand, he said, “As we get feedback, it helps us … refine and make better the product we’re offering. … So there’s pluses and minuses.”
Carl Levander, executive vice president for regulatory policy and corporate affairs for NiSource, said his company faces a challenge in maintaining institutional knowledge because 23% of its workforce is eligible for retirement and another 29% has at least 20 years’ experience — while a quarter of the employees have less than three years’ tenure.
Levander said that his company, the parent of Northern Indiana Public Service Co. and Columbia Gas, is not interested in expanding into services, such as home security, that other utilities have tried. “We’ve made a decision to be a very boring company — and we have the right people running it,” he said, prompting laughter.
CAISO last week stepped up efforts to convert skeptics of a Western RTO, convening a forum in Denver to discuss a proposed set of governing principles and dispel concerns that California interests would dominate a West-wide entity.
“What we’re doing actually matters, and it has enormous upsides,” CAISO board member Ashutosh Bhagwat said of the effort.
CAISO is leading the push for an RTO in the West, in part driven by a 2015 California law requiring the grid operator and state energy agencies to explore ISO expansion to improve the state’s ability to meet its 50% renewable energy mandate.
The ISO also seeks to accommodate the timelines of PacifiCorp, which hopes to join the ISO in 2019 but must gain regulatory approval from five Western states before doing so.
Bhagwat said the diversity of resources in an expanded ISO would improve renewable integration and reduce costs for customers in California and the broader region.
EIM Experience
“Experience with the [Energy Imbalance Market] has proven this,” Bhagwat said. “We’re doing this because there is a lot to be gained.”
Contending that the West is “behind the rest of the country” in creating an RTO, Bhagwat also acknowledged “legitimate concerns” among Western industry stakeholders about how the organization would be governed.
“We’ve tried to address them,” he told the forum, referring to the ISO’s proposed principles for governance, which would seek to preserve state regulatory authority, provide all participating states the means to influence RTO policy and reshape the ISO into an entity no longer overly subject to the prerogatives of California.
Still, RTO skeptics — and some supporters — contended that an expanded ISO would be overly subject to California’s influence even with the principles in place.
They cited one major sticking point: the transition to an independent and regionally representative board of directors.
CAISO’s proposal calls for the RTO’s initial board to include the five members of the ISO’s current board and four new members selected by other RTO states through a process approved by those states. Initial board members would have terms staggered in such a way that California-appointed members would always hold a majority through a transition period.
That transition would conclude with the initial board selecting a final, independent board through a nominating process developed by a transitional committee of stakeholders. The nominating process — along with other governance elements proposed by the committee — would be subject to approval by the initial board.
A second sticking point: The transitional committee itself would be appointed by the ISO’s current board.
‘The Mother of all California-Centric Concerns’
“The proposal for the initial board is the mother of all California-centric concerns,” said Bryce Freeman, administrator of the Wyoming Office of Consumer Advocate.
Freeman pointed out that the proposal did not provide an explicit deadline for the transition period, meaning the current ISO board would constitute a majority for an unspecified amount of time. Any policies “hammered out under that arrangement would be accountable to the California political process,” he said.
Freeman also noted that the five PacifiCorp states would be forced to jockey for just four seats on the initial board.
Governing principles for a Western RTO will initially need buy-in from the five states containing PacifiCorp’s service territories.
“Whose ox gets gored in that process?” he asked.
“When we get to the final stage of things, California still gets what I’ve been calling a veto over everything anyway,” added Abby Briggerman, an attorney representing inland industrial energy consumers in the West.
Continued reliance on the ISO’s current board is also the American Wind Energy Association’s biggest concern, said Caitlin Liotiris, a consultant representing the organization, which is a strong supporter of the expansion.
Montana Public Service Commissioner Travis Kavulla echoed Freeman’s concerns about the open-ended nature of the initial board. He said it would have more influence on governance than the final board, as governance design would actually be developed and approved during the transition period.
Market-Oriented Board
Kavulla instead suggested the establishment of a market-oriented board populated by members with expertise in electricity market operations, while the “big questions” regarding tariff design and governance would be left to another body.
“That leaves the more complex matters of market design to the people actually running the ISO,” said Kavulla, the current president of the National Association of Regulatory Utility Commissioners.
While Kavulla didn’t specify what body should have authority over the tariff and governance issues, CAISO’s proposal calls for the formation of a body of state regulators “to provide policy direction and input on matters of collective state interest.”
That body would be funded by the RTO but incorporated as a separate entity, with one regulator from each state serving as a voting member. Publicly owned utilities (POUs) within the RTO footprint would appoint one nonvoting representative to act in an advisory capacity.
CAISO intends for the body of state regulators to have “primary authority” over RTO initiatives related to matters like transmission cost allocation and “aspects” of resource adequacy — meaning the RTO would be required to seek the body’s approval for any Section 205 filing with FERC.
“It has been noted that this body has a lot of reserve authority and power,” Kavulla said, adding that it should be staffed with experts to advise its members and support that authority.
Public Power Role
Mark Gendron, Bonneville Power Administration (BPA) senior vice president of power services, suggested a full voting role for the public power representatives.
“That might be a good home for BPA as a [federal power marketing agency],” said Gendron, whose organization operates 78% of the transmission in the Northwest and markets the output from 31 hydroelectric projects.
Gendron’s suggestion received support from Marshall Empey, COO of Utah Associated Municipal Power Systems, which represents community-owned utilities throughout the West.
“The reason we want this as public power is that regulators don’t represent us,” Empey said.
Steve Beuning, director of market operations at Xcel Energy, voiced a different perspective.
“I’m concerned to think of any stakeholder that might have more of a stake than me — such as public power getting a defined role,” Beuning said.
Kavulla noted that the interests of POUs are represented on the state committees of other RTOs. None of those committees set aside a seat for POUs.
“That level of trust might not exist in the West,” he added, referring to the fact that the region’s public utility districts are not subject to state oversight and maintain an arms-length relationship with utility commissions.
Briggerman spotlighted what she considered to be yet another flaw in the design of the state body: a provision that policy changes would require not just a majority vote, but approval by members representing a majority of load in the RTO footprint. California would hold a clear majority in an RTO that includes just PacifiCorp.
“This just sort of echoes my general theme that California has too much authority in this proposal,” Briggerman said.
“At the end of the day, [a Western RTO] is going to take mutual trust between California and non-California,” Kavulla said.
Snowpack in the Sierra Nevada mountains, depleted after four years of drought, will likely remain in deficit until 2019, according to a University of California, Los Angeles 
The Department of Natural Resources will allow the builders of the Dakota Access pipeline to use horizontal drilling methods to construct the Bakken crude pipeline under historic tribal burial grounds in the Big Sioux River Wildlife Area, removing a regulatory impediment to the $3.8 billion pipeline.
Westar Energy customers could see an $18 million rate reduction as a result of FERC’s approval of a settlement between Westar Energy and the Corporation Commission over transmission-delivery charges.
Consumers Energy is challenging the tax assessment of its 111-MW Cross Winds Energy Park in Tuscola County, where several other wind farms are also seeking reductions in their property tax payments.
A week after it came back into service following a three-month outage, Entergy once again shut down Unit 2 at its Indian Point nuclear plant so workers could repair a leaking water intake pipe.
Duke Energy Progress has proposed to cut rates for its 1.35 million customers to reflect lower energy costs.
The Public Service Commission last week approved a proposed $153 million wind farm and associated electric transmission line in Oliver and Morton counties. The three-member panel unanimously approved the project’s siting application, clearing the way for construction to start.
Lubbock Power & Light’s Electric Utility Board has proposed a 2% increase in customer bills and $70.9 million in infrastructure improvements. The budget will be presented this summer to the Lubbock City Council for final approval.
Less than a week after obtaining its air permit from the Air Pollution Control Board, Dominion Virginia Power began construction on its 1,588-MW Greensville County Power Station. The company said it expects the $1.3 billion plant to go into service by 2019.
