MISO and SPP last week concluded their first joint study process, saying the exercise was a valuable learning experience even though it failed to produce a single interregional project.
Meeting in Dallas on Dec. 2, the MISO-SPP Interregional Planning Stakeholder Advisory Committee (IPSAC) reviewed stakeholder feedback and its next steps after a year in which it considered and ultimately rejected 67 potential transmission upgrades. Under the current stakeholder-designed process, the two RTOs conduct a coordinated study that can last up to 18 months, followed by two separate regional analyses.
“The process itself did what [it] intended to do,” said David Kelley, SPP’s director of interregional relations. “Unfortunately, we couldn’t get any projects across the goal line. We have to find a way to get those done.”
Eric Thoms, MISO’s manager of planning coordination and strategy and Kelley’s counterpart on IPSAC, said the session was an opportunity to collaborate with stakeholders to improve the process “so we can set ourselves up for success next time.”
One of the sticking points is the so-called “triple hurdle,” created by necessary approvals from the joint-study process and each RTO’s board. SPP and MISO initially identified three congestion-relieving upgrades that would qualify as interregional projects, but SPP recommended moving forward with only one, an 11-mile, 138-kV rebuild between South Shreveport, La., and Wallace Lake.
MISO declined to pursue any of the three.
The RTO had said in October it may revisit its decision on the Shreveport-Wallace Lake project, but this week it said that it no longer intends to pursue the project. The project is described in MISO’s 2015 Transmission Expansion Plan, which will be submitted at Thursday’s MISO board meeting, but not listed among the approved projects in Appendix A.
Kip Fox, American Electric Power’s director of transmission strategy and grid development in the southwest, called the Louisiana project’s failure “very disheartening.” He said AEP will eventually rebuild the 11-mile segment as a reliability project for SPP, “even though it provides significant economic value to MISO South.”
“It’s the right thing to do for ratepayers along the seam, even though MISO will not provide financial support for the project in the MTEP15,” Fox said.
Among the suggestions stakeholders provided to IPSAC was the idea to include task teams with stakeholder representation in the process for “specific topics and detailed discussions.” However, the concept met with resistance over concerns it would create another level of approvals and diminish the IPSAC’s transparency efforts.
Stakeholders suggested eliminating the “triple hurdle” by creating an interregional evaluation process that does not require separate regional reviews. Another suggestion was a cyclical 18-month process that aligns with the RTOs’ transmission planning processes.
Both staffs agreed the interregional process had improved coordination between the two RTOs and increased the knowledge of each other’s regional processes and stakeholders.
Staff will update the MISO-SPP Coordinated System Plan to include a report on the regional reviews by year-end. The IPSAC will next meet in the first quarter of 2016, focusing on potential improvements to interregional procedures.
The region will once again rely on the RTO’s Winter Reliability Program to incentivize oil-fired power plants and natural gas generators that can access liquefied natural gas to procure sufficient backup fuel before winter begins. “The program has been a key factor in our ability to keep the lights on the last two winters,” said Vamsi Chadalavada, executive vice president and chief operating officer of ISO-NE.
More than 45% of the total generating capacity in New England — about 13,650 MW — uses natural gas as its primary fuel. Natural gas generated 44% of the region’s power in 2014, up from 15% in 2000.
The Department of Energy and Environmental Protection has issued the permits necessary for the 805-MW CPV Towantic Energy power plant to be built in Oxford.
DEEP officials said in a statement that the plant “will comply with some of the most stringent air pollution control requirements in the country and meet emissions limits designed to protect human health and the environment.” The CPV Towantic Energy power plant will operate primarily on natural gas, with the capability to use oil as a backup fuel.
The town of Middlebury and several property owners near the proposed site have challenged in court the Siting Council’s approval of the plant in May.
Palmco Power CT, a third-party electricity supplier for more than 3,500 residents, is being investigated by the Public Utilities Regulatory Authority for alleged deceptive marketing practices, according to Consumer Counsel Elin Swanson Katz. PURA is scheduled to hold public hearings on the allegations next week, and Katz is encouraging customers who feel they were subjected to Palmco’s alleged intimidating marketing tactics to come speak.
Palmco has come under fire for charging some of the highest electricity rates in the state. The company has also been investigated by New York and New Jersey authorities for alleged improper practices. Katz said one New York settlement resulted in Palmco and its partners agreeing to pay more than $2 million in refunds to consumers in that state, plus a $200,000 state penalty.
“In aggregate, Palmco customers in Connecticut paid over $412,000 more than the standard service rate … in September alone,” Katz said. Palmco recently stopped marketing to new customers in Connecticut after the state outlawed variable-rate contracts for residential customers.
Officials to Probe Steep Cost of Chicago Gas Mains
State regulators are taking a deeper look at the escalating price tag on a gas main replacement program for Peoples Gas, an Integrys Energy Group subsidiary based in Chicago.
The Commerce Commission will formally investigate whether Wisconsin Energy Corp. and Integrys conspired to conceal the escalating costs in order to win approval of their merger into WEC Energy Group. In November, Attorney General Lisa Madigan accused the companies of withholding details on the cost of the gas main replacement program, which is now estimated to cost $8 billion.
“Our commissioners and staff believe the scope of this investigation is broad enough to ensure all instances of misrepresentations on this matter are properly adjudicated,” ICC Chairman Brien Sheahan said in a statement. He said the commission would aggressively oversee reforms of the gas main replacement program “and will ensure that customers do not bear any costs of program mismanagement.”
Utility Seeking Developer for State’s Largest Solar Project
Madison Electric Works, a municipal utility, is seeking proposals for a 4-MW solar project to be located in the Madison Business Park. The company would buy power from the bid winner at a fixed price for between 20 and 30 years and eventually purchase the facility.
The utility, which provides electricity to about 2,300 customers in the town about 40 miles north of Augusta, says the project would cost about $8 million and would be located on about 15 acres. It would be the largest solar project in the state after Bowdoin College’s 1.2-MW solar farm.
A proposed $100 million wind project lost its final appeal before the state’s highest court, ending a six-year battle over the public’s right to enjoy views unimpeded by wind turbines.
The Supreme Judicial Court upheld the Board of Environmental Protection’s rejection of the SunEdison project, consisting of 16 turbines generating 48 MW in an area designated for wind-power generation.
Regulators had to weigh two competing aspects of state law: a developer’s right to build a wind farm in a designated zone versus the public’s right to scenic vistas from nine nearby lakes.
The Public Service Commission ordered Baltimore Gas and Electric to reduce the monthly fee for residential and small commercial customers who opt out of smart meter installation from $11 to $5.50 in January. A one-time initial opt-out charge of $75 remains in effect.
The commission ruled the lower charge was more appropriate given the current opt-out levels of 4%, compared with the predicted 1% assumption.
BGE also must report quarterly on the collection of opt-out revenues and the costs for servicing customers who choose to stay with meters that must be manually read.
The state’s clean energy sector workforce grew by 12% this year to 98,900, its strongest growth since the state began tracking these jobs in 2010, according to a new report by the Clean Energy Center.
The publicly funded center that promotes clean energy says that the sector’s employment has grown consistently for five straight years, up 64% since 2010.
Employment growth occurred statewide this year, although in the western region jobs increased by only 2.7%. The sector now represents 3.3% of the state’s entire workforce, according to the report. Slightly more than half of the companies have 10 or fewer employees.
Canada’s hydropower companies and New England transmission developers are teaming up to persuade the state legislature to pass a bill to compel National Grid and Eversource Energy to enter into long-term contracts to buy Canadian hydropower.
The consortium includes Brookfield Renewable, Hydro-Quebec, Nalcor Energy, TDI New England, Emera and SunEdison.
The import contracts would likely be handed out through a competitive bidding process. However, there’s no guarantee that the price of the hydropower, including the costs of new transmission lines, would be cheaper than the market rates for electricity.
Consumers Energy’s electric rates went up on Dec. 1 after the Public Service Commission last month approved a 4.5% rate increase that will allow the utility to recover more than $130 million annually, including funding for a natural gas plant in Jackson.
Rates will retreat slightly next April after the utility retires seven coal plants. The utility originally requested an increase of $199 million.
Entergy Mississippi is poised to lower electric rates a second time this year because of falling natural gas prices, pending approval by the Public Service Commission.
Entergy collected an excess of $48 million for fuel costs in 2015, even after a $46 million rate cut went into effect in September, according to Mara Hartmann, an Entergy spokeswoman. Under state law, utilities must pass through increases or decreases of energy costs without a markup.
Under the proposal set to go into effect in February, the monthly bill of a residential customer using 1,000 kWh/month would drop from $100 to $93.
The New Hampshire Community Rights Network, formed largely in reaction to major energy projects proposed in the state, has convinced a group of lawmakers to introduce a constitutional amendment that would grant cities and towns veto power over large-scale infrastructure projects.
The coalition consists mostly of communities that would host a portion of the Northern Pass hydroelectric project, the Kinder Morgan natural gas pipeline or industrial-scale wind turbines.
Constitutional amendments are a long shot under any circumstances, and this one faces an uphill battle, according to New Hampshire Union Leader columnist Dave Solomon.
Several top state politicians have lined up against a proposed Kinder Morgan natural gas pipeline, which would deliver Appalachian shale gas to New England. The list now includes the state’s Republican U.S. senator, both representatives in Congress and the Democratic governor.
Sen. Kelly Ayotte sent a letter to local officials in towns potentially affected by the Northeast Energy Direct proposal, telling them she will oppose the project before FERC. Gov. Maggie Hassan and U.S. Reps. Ann McLane Kuster, a Democrat, and Frank Guinta, a Republican, have also expressed opposition.
The 36-inch diameter pipeline would pass through about 80 miles of the state. Kinder Morgan re-routed the pipeline through the state after opposition formed along its original path through Massachusetts. (See Northeast Energy Direct Files for FERC Certificate.)
Xcel Energy on Dec. 1 dedicated the first section of a new 42-mile transmission line that it says will improve the state’s power system. Xcel said the 230-kV line is the first step in a major expansion of the area’s new bulk electricity transmission network.
Xcel has also recently completed a 20-mile, 115-kV project in Lea County. Both projects include more than 250 miles of transmission and distribution lines and seven new substations.
NYISO said the state’s electric system has the capacity to meet demand for power and the necessary operating reserves during extreme cold weather conditions through the 2015-2016 winter season.
NYISO anticipates a peak load demand of 24,515 MW for the winter season, comparable to last winter’s peak of 24,648 MW. The state’s record winter peak was set in 2014, during polar vortex conditions that pushed load to 25,738 MW.
Installed generation capacity in New York state this winter amounts to 41,312 MW. Net external capacity purchases, plus projected demand response, guarantees that sufficient electricity is available in the event of unanticipated power plant outages, transmission outages or unexpected increases in power consumption, NYISO said. (See Diversity Helps NYISO, but Gas Still Rules.)
The upstate town of Nassau has formed a committee to explore ways the town can install its own distributed power systems to disconnect municipal facilities from the area’s electric utility.
Supervisor David Fleming said the town suffers frequent outages during storms because of aging utility equipment. The initiative would not affect residential or commercial services, just municipal operations such as the highway garage and the transfer station. Fleming said the goal is to have all town services operate independent of the grid by 2020.
National Grid spokesman Patrick Stella said this was the first that the utility had heard that the town was contemplating removing itself from the electric grid. “We will be reaching out to the town to find out exactly what their needs are and how we can best meet them,” he said.
Solar advocates are criticizing Oklahoma Gas and Electric’s proposal to assess a demand charge on customers with rooftop solar installations as a way for the utility to protect its business model and to suppress the state’s fledgling solar market.
At a hearing before the Corporation Commission, a former Ohio regulator testifying on behalf of OG&E said the proposed tariff for new distributed generation customers was an attempt to make billing more transparent. He said it would ensure those customers pay the right amount of grid-connection costs.
The proposed tariff would affect 15 current customers. The utility proposes to charge distributed generation customers $2.68/kW of peak demand. Most households have peak usage of 6 to 8 kW, meaning the monthly charge would be $16 to $21 for a typical residential solar customer.
Commission Rejects OG&E Environmental Compliance Plan
After five months of deliberation, the Corporation Commission voted 2-1 to reject Oklahoma Gas and Electric’s application for preapproval of $1.1 billion in environmental compliance and replacement generation costs. The proposal would have increased residential customer bills 15 to 19% by 2019.
The commissioners voting against the proposal said OG&E hadn’t provided enough information to allow preapproval of its application.
OG&E wanted permission to begin charging customers for $700 million in upgrades needed to meet federal Regional Haze and Mercury and Air Toxics Standards. It also wanted preapproval to spend about $400 million to replace its aging Mustang natural gas plant in western Oklahoma City.
HIKO Energy must issue $2 million in customer refunds, pay a $1.8 million civil penalty, give $25,000 to electric distribution companies’ Hardship Fund and modify its marketing practices, the Public Utility Commission has ordered.
The penalties stem from “deceptive actions” following the polar vortex in the winter of 2013-14.
The company previously refunded $159,000 to customers it had overcharged after having promised to give them rates lower than their utility’s standard offer.
In response to public concerns about a proposed solar project, Cranston local officials have proposed an ordinance that would create “performance standards” for large-scale solar projects that would regulate noise, soil removal and decommissioning after the project’s useful life ends.
The developer of a proposed project, RES America Development, has promised that the solar farm will meet all of the conditions spelled out in the ordinance, although the legislation has not yet been enacted. RES proposes to lease land now mostly planted for corn to erect the solar farm.
Lawsuit Seeks Decision on Power Plant, Refinery Permits
Four environmental groups are suing the state to force it to approve or deny long-delayed air pollution permit applications at five refineries and three power plants. By failing to issue permits, the Commission on Environmental Quality is keeping the public from knowing how much pollution the companies are putting into the air, said Ilan Levin, spokesman for the Environmental Integrity Project.
The lawsuit says TCEQ is supposed to rule on permits within 18 months, but the commission has failed to approve permits submitted as long as six years ago. The Environmental Integrity Project is joined in the lawsuit by the Sierra Club, Air Alliance Houston and the Texas Campaign for the Environment.
Three coal-fired power generators were listed as defendants in the lawsuit: American Electric Power’s Welsh plant in East Texas, Luminant’s Oak Grove plant in Central Texas and the Sand Creek plant near Waco.
Dominion’s Plan for James River Transmission Towers Criticized
Concerned over a dwindling sturgeon population, environmentalists are opposing Dominion Resources’ plan to erect 17 transmission towers in the James River.
Dominion says the transmission line and the towers are needed because new federal emissions restrictions are forcing the company to close two coal-fired plants in Yorktown. Without the transmission line, the utility says it may have to conduct rolling blackouts during usage spikes.
The Army Corps of Engineers is in the final phase of deciding whether the proposal should move forward.
The Public Service Commission will allow Xcel Energy to increase its fixed monthly customer charge from $8 to $14. Xcel had sought an $18 monthly charge.
The moves comes a year after the PSC approved similar increases for We Energies, Madison Gas and Electric and Wisconsin Public Service, and just a month after the commission boosted the monthly fixed-rate fee for WPS customers from $19 to $21.
More than 500 commenters filed objections to the rate hike with the commission. The state is approving increases in utility fixed-rate charges at “exceptionally higher” rate than the regulatory agencies of other states, Tyler Huebner, executive director of the advocacy group RENEW Wisconsin, said in a statement.
An SPP task force preparing for EPA’s Clean Power Plan suspended its work last week, having done all it can for the time being.
The task force spent what may have been its final face-to-face meeting Friday in Dallas discussing proposed comments to EPA and a staff-developed white paper assessing rate-based and mass-based compliance. The group will present the white paper — and its comments to EPA — to the SPP Board of Directors/Members Committee on Tuesday. The comments are due to EPA on Jan. 21.
The group agreed it had met its original charge. “I think we’re done,” said Golden Spread Electric Cooperative’s Mike Wise, the task force’s chair.
“There’s not a whole lot left for this task force to do,” agreed SPP Chief Compliance and Administrative Officer Michael Desselle, the task force’s secretary.
The group determined it was too soon to address the implications of a proposed carbon-trading market or the RTO’s role in it.
The draft white paper focuses on how best to determine the supply of allowances and credits and their monitoring, verification and tracking; allocation issues; leakage under mass-based plans; and reliability implications.
SPP Vice President of Engineering Lanny Nickell has taken the point in meeting with member legislative representatives and state air regulators. He told the task force he has been involved in “broad stakeholder discussions” in every state in SPP’s footprint, with the exception of the Dakotas, Montana, Texas and Wyoming.
Left to right: Lanny Nickell, SPP; Governor Mary Fallin; Mike Ross, SPP (Source: SPP)
Nickell spoke most recently at Oklahoma Gov. Mary Fallin’s energy conference in November. Nickell said he encouraged the state to develop a compliance plan despite Fallin’s executive order in August directing state agencies not to do so.
Nickell also said he is often asked when SPP will do an analysis on the final CPP in addition to the three studies it performed based on the draft rule. Dale Niezwaag, a senior legislative representative for Basin Electric Power Cooperative, said he would welcome such a study.
However, the task force decided against an additional study.
“There are too many unknowns to do a study,” Desselle said. “With the number of unknowns and the assumptions we would have to make, it would be too expensive.”
But Wise cautioned the group, “That’s not to say we can’t change that view.”
When discussion shifted to other actions SPP might take, its associate general counsel, Matt Morais, reminded the group the RTO is also working with its peers on the ISO/RTO Council to solidify its positions and determine further actions.
“To the extent there is agreement on these issues with other ISOs, that carries a lot more weight than doing it on our own,” Morais said.
SPP Moves Closer to Making First International Transactions
SPP is preparing to conduct its first international transactions through a joint operating agreement with SaskPower, the principal electric utility in Saskatchewan. SaskPower became an SPP seams neighbor with the Oct. 1 addition of the Integrated System. (See Integrated System to Join SPP Market Oct. 1.)
Staff told the Seams Steering Committee on Thursday that the JOA is pending execution of a billing agreement for emergency energy with NorthPoint Energy, SaskPower’s marketing and billing agent. Once that agreement is executed, SPP will file with the Department of Energy for the necessary permits for international transactions.
With the recent resignations of Richard Ross (American Electric Power) and Roy Boyer (Xcel Energy), the committee has seven open positions.
SPP Sets Seventh Wind Peak in Fall
SPP, which has already set six wind-peak records this fall, established another mark Nov. 23 when it recorded 9,564 MW of wind generation at 9:45 p.m., just the second time it has eclipsed the 9,000-MW level. The RTO generated about a third of its electricity from wind at the time, below its record penetration level of 38.3%.
WASHINGTON — FERC, which faces monthly protests by global warming activists for approving natural gas pipelines and LNG terminals, was summoned to Capitol Hill last week to answer Republican criticism that it commission isn’t clearing infrastructure permits fast enough.
It fell not on Chairman Norman Bay but on the panel’s lone Republican, Tony Clark, to defend FERC’s record on natural gas before the House Energy and Power Subcommittee.
FERC Commissioner Tony Clark
Clark said that the commission had completed 92% of all applications within 12 months for the last decade. But that percentage is bound to fall, he said, because of the crushing volume of pending applications.
Since August 2014, Clark said, pending applications have spiked from 1,000 miles of pipeline with a capacity of 24 BCF/d to 4,600 miles and 50 Bcf/d. “I think it is going to be very difficult to maintain that high average when you have this volume of [applications],” said Clark, now the senior Republican on the commission with the departure in October of Philip Moeller.
While Clark talked of infrastructure, Bay focused his prepared testimony on his priorities as chairman. Commissioner Cheryl LaFleur addressed reliability and competitive markets, while Commissioner Colette Honorable spoke about FERC’s role under the Clean Power Plan.
Oversight Ritual
Congressional oversight hearings are a ritual of Washington. Each member of the committee gets five minutes to ask questions. While many members use their time to make policy statements, the best questions have often been picked clean by the time those with less seniority get their turn.
Clark faced much the same dilemma after becoming the junior member of the commission in 2012. “I don’t have any questions,” he would often tell staff presenters at the monthly meetings with a sheepish smile. “But thank you for your report.”
But with the departures of Moeller, Jon Wellinghoff and John Norris, and the arrival of Bay and Honorable, Clark is now second in seniority only to LaFleur.
At the Nov. 19 commission meeting, he settled for the first time into what had been Moeller’s seat, to the left of Bay at the head of the semi-circular table. “I’ve never been accused of being to the left of anyone on this commission,” he said to laughter. He has become increasingly assertive in the last year, both at commission meetings and in speeches around the country. (See FERC’s Clark: Energy Markets Need Tweaks, not Overhaul.)
In their opening statements last Tuesday, Energy and Commerce Chairman Fred Upton (R-Mich.) and Power Subcommittee Chairman Ed Whitfield (R-Ky.) chided FERC over what Upton called “problems with the timeliness of FERC approvals.”
They also criticized the Clean Power Plan, with Whitfield saying he is concerned “that FERC is allowing itself to become a helpless bystander as EPA increasingly dominates the electricity sector and does so in ways that serve to exacerbate the very problems FERC is supposed to protect consumers against.”
In keeping with the bipartisan ethos that has governed FERC since at least the Pat Wood era, the commission has taken pains not to get embroiled in the partisan fight over climate change and the CPP.
“Thank you for your question, congressman,” the commissioners prefaced their responses to even the most uninformed or repetitive questions.
Clark’s even-handed responses left little policy daylight between himself and his Democratic colleagues.
‘Punitive’ Target for North Dakota
But things got personal when he talked about the impact of the CPP on his home state of North Dakota.
Between the draft and final rules, Clark said, the state’s emissions reduction target quadrupled from 11% to 45%.
This, he said, even though carbon emissions dropped 11% between 2005 and 2014 and even though the state is one of only a few meeting EPA’s National Ambient Air Quality Standards.
“Utilities during that timeframe built a significant amount of wind power, in part as a hedge against carbon regulatory risk,” said Clark, whose term expires in 2016 and is rumored to have interest in running for Congress himself. “Unfortunately, it turned out to be a hedge for which they will receive no credit. Additionally, the state’s coal fleet is still relatively young, and has thus incurred recent investments for environmental compliance.”
Clark said the state’s CPP target is “so punitive that I struggle to conceive of a way it can meet it in an affordable manner,” citing a state estimate that compliance through emissions trading could exceed $400 million annually. It is, he said, “a staggering figure for a state of less than 750,000 people.”
NYISO last week asked for FERC approval to change its scarcity pricing logic, saying the proposed rules will more closely reflect the real-time value of demand response (ER16-425).
Scarcity pricing determines the value of energy and certain ancillary services when DR resources are called upon to maintain system reliability. The purpose is to ensure that real-time prices reflect the costs associated with deploying DR, the filing says.
NYISO said the filing was prompted by New York transmission owners’ concerns that its current methodology could result in uplift because of inconsistencies between prices and resource schedules.
NYISO is also proposing to increase the value of 30-minute reserves in the Southeast New York region from $25/MW to $500/MW, effective at all times. “This increase appropriately recognizes that [emergency demand response program] resources and [special case resources] have historically been called upon to protect reserves in SENY,” the ISO wrote.
NYISO is asking FERC to accept the revisions by Jan. 29, 2016, to give it enough time to develop and deploy software changes. The proposed revisions would become effective on or before June 30.
NYISO implemented its current, ex-post scarcity pricing logic in 2013. The logic allows it to adjust real-time energy prices after resource schedules have already been established in the load zones in which DR resources are used.
Generators are protesting the way in which ISO-NE calculated its installed capacity requirement for the 10th Forward Capacity Auction, saying the RTO hasn’t sufficiently vetted the way it reflects behind-the-meter solar.
In anticipation of its 2019/20 auction scheduled for February, ISO-NE filed its ICR with FERC on Nov. 12 (ER16-307).
The RTO said the only change in its assumptions from prior auctions was the inclusion of behind-the-meter solar resources that are not yet reflected in historical loads, which resulted in a 390-MW reduction in the load forecast.
In a protest filed last week, the New England Power Generators Association said the calculation should be determined by a Section 205 proceeding before FERC, after a more complete examination by the New England Power Pool.
NEPGA and Dominion Resources, which owns nuclear and gas-fired generation in the region, said that the RTO had discussed with NEPOOL stakeholders how the new methodology would be implemented but had not adequately examined related market and operational issues.
The ICR value failed to win endorsement by the NEPOOL Participants Committee, garnering a bare majority of 53%.
“A number of members expressed their opposition to those ICR values because of their view that the values were overstated because behind-the-meter PV was not properly and fully accounted for in the load forecast,” the committee said in its comments.
ISO-NE said it developed the 390-MW solar forecast with stakeholders, including state regulators, over a 10-month period.
“In order to determine the load reduction impact of [behind-the-meter] PV resources, the ISO used solar PV production data of currently installed behind-the-meter PV resources provided by the states and distribution utilities. The ISO calculated the PV already embedded in load and then adjusted the load forecast by the forecasted” resources, the RTO wrote.
The New England States Committee on Electricity, which last year challenged the exclusion of distributed solar resources from the ICR calculations, supports ISO-NE’s current ICR filing.
“The ICR … must consider in a timely manner the rapid development of solar PV resources that are affecting system demand,” it said in its comments. “New England consumers are increasingly investing in clean, distributed energy resources in furtherance of state energy programs and policies. The ICR cannot be divorced from these significant investments in solar PV resources.”
With transmission bottlenecks and aging and unprofitable legacy generation, New York presents a host of challenges for any experienced energy executive, let alone a newcomer. But a path-breaking initiative to transform the state’s power business that has the whole nation watching and an established wholesale market proved an irresistible combination for Bradley Jones.
“This is a fantastic opportunity,” Jones, who took over as president of NYISO in October, told RTO Insider last week. “It’s a great state, it’s a great market and I’ve enjoyed Albany quite a bit. It’s a wonderful opportunity and it’s the right place for me.”
‘The One I Wanted’
Jones, 53, came to New York from ERCOT, where he was senior vice president and chief operating officer — presumably in line to contend for the top spot next year, when current CEO H.B. “Trip” Doggett retires.
In August, however, ERCOT named General Counsel Bill Magness as Doggett’s successor. Thus, after spending his entire, near-three-decade professional life in the Southwest, Jones moved cross country to replace the retiring Stephen C. Whitley, who headed New York’s power grid for seven years. (See New NYISO Head Brings Broad Experience.)
Bradley Jones (NYISO)
“I did have many opportunities, but this is the one I wanted,” he said. “One of the things is the market changes I was trying to make happen at ERCOT I have found that New York had already done.”
One of those is NYISO’s look-ahead capability, which allows its operators to identify upcoming changes in conditions, such as equipment outages or changes in renewable energy output, and prepare the system to most efficiently respond.
“I was amazed to find that NYISO already had that in place and had already been applying those tools,” Jones said.
Adding Transmission
Jones has extensive experience in what New York policymakers want — namely building infrastructure and integrating wind. “I hope my experience at ERCOT will show how to manage these things,” he said. “My three initiatives, without joking, have always been transmission, transmission, transmission.”
He said he was amazed that the ISO has had to curtail low-cost hydroelectricity because of the lack of transmission to move it west to east. But he’s encouraged by the New York Public Service Commission’s recent initiative to eliminate bottlenecks for downstate load centers.
The PSC is expected to vote this month on two transmission projects totaling an estimated $1.2 billion. The proposed routes would satisfy Gov. Andrew Cuomo’s Energy Highway goal to bring 1,000 MW of power generated upstate to areas of high demand in southeastern New York and New York City. (See NYPSC Staff Recommends $1.2B in Transmission Projects.)
There are also transmission proposals to access wind resources in northern New York to help the state meet Cuomo’s goal of 50% renewable electricity by 2030. “We can increase wind or renewables capacity by 50%, somewhere around 17.5 million MWh a year, from west and north to the rest of the state,” Jones said.
Jones said the state’s Reforming the Energy Vision will mostly affect change at the distribution network. “We expect we will be able to develop very quickly a platform for how that will work. We will be able to interconnect very quickly,” he said.
Gas-electric coordination: “The reliability of the bulk power system is increasingly linked to the performance of the natural gas pipeline infrastructure, raising reliability concerns related to fuel delivery during periods of peak demand.” The plan vows to improve coordination with the gas industry and develop market designs that promote fuel assurance among generators.
Integration of distributed energy resources: The plan anticipates that DER will grow due to improving economics and public policies, influencing the design of the grid. “The NYISO will work to integrate such resources into its markets in a manner that enhances system efficiencies through increased demand elasticity while deploying new planning and operational tools to ensure visibility into system conditions and future needs as distributed energy resources proliferate.”
Federal and state policies: The ISO’s markets and planning functions will have to respond with more complex market designs to accommodate the growing role of renewables and DER under the EPA Clean Power Plan and the New York State Energy Plan.
Shaking Hands with 500
Jones said he will implement the plan by engaging every employee. He started on his first day, standing at the entrance of a welcome barbeque to shake everyone’s hand. NYISO employs more than 500.
[Editor’s Note: An earlier version of this article mistakenly suggested that ERCOT had not yet chosen a successor for retiring CEO H.B. “Trip” Doggett.]
VALLEY FORGE, Pa. — PJM will use the default economic capacity base load (CBL) to measure the non-summer response of Capacity Performance demand response under manual and Tariff revisions endorsed by the Market Implementation Committee last week.
The method will allow PJM to bypass the more labor-intensive relative root mean square error (RRMSE) test. Extensive analysis has determined that the process would deliver accurate CBLs for most customers, PJM’s Pete Langbein said.
Market Monitor Joe Bowring reiterated his objection to the method.
“We think that the proposed measurement verification for DR for the winter … would permit double-counting, and that’s not appropriate,” he said. “The simple fact that it may be administratively difficult to do [the mean square test] is not a reason not to do it.”
Problem Statement to Define Operating Parameters Approved
Members endorsed a problem statement to develop standardized definitions of operating parameters under Capacity Performance.
PJM proposed the initiative after discovering that market sellers and PJM had different interpretations of various parameters for CP and base capacity resources.
PJM wants to expedite the work of defining the terms before June 1, when the CP rules take effect for delivery year 2016/17.
The definitions are expected to impact Manuals 11, 15 and 28 and include such terms as soak time, start-up time, start-up cost and no-load cost.
Several stakeholders expressed concern over rushing through defining such important terms, and many agreed that the MIC is not the appropriate committee to handle the task.
Market Monitor Joe Bowring took issue with the idea that the work is time-sensitive.
“There is no urgency. The issues, to the extent that any exist, have been around for a long time,” he said.
PJM Provides Update on Line-Loss Refunds
PJM CFO Suzanne Daugherty provided an update on marginal loss surplus allocation billing adjustments, responding to a recent FERC order regarding the seven-year-old issue.
“Everyone who was owed a recoupment credit got it in full the summer of 2012,” she said. If there is any money left to be refunded, it will only be going to members who paid default allocation assessments that summer, she said.
“There is no more charging related to this topic that I expect to occur,” she said.
ITC Midwest is overcharging its customers for network upgrades because it isn’t applying for tax breaks to which it is entitled, customers and Iowa officials told FERC last week.
Among the projects affected is Wisconsin Power and Light’s 201-MW Bent Tree Wind Farm in southern Minnesota.
In an unexecuted facilities services agreement filed with FERC, ITC said it needs $38.8 million in network upgrades to support Bent Tree’s generation. It sought to bill WPL $418,020 monthly over 25 years.
WPL asked FERC last week to reject the rates, claiming the charges are excessive because they fail to reflect the “bonus” depreciation that ITC could claim on its federal taxes (ER16-206).
WPL’s sister company, Interstate Power and Light in Iowa, filed a motion to intervene on Nov. 24, saying it could face an identical situation over its Marshalltown Generating Station, which is interconnecting into ITC’s transmission system in Iowa.
“IPL has estimated that ITC Midwest’s annual revenue requirement is roughly $18 million higher in 2015 than it would have been had ITC Midwest taken available bonus depreciation in prior years in which it was eligible to do so. This results in an ITC Midwest transmission rate which is approximately 5% higher, unnecessarily increasing charges to ITC Midwest’s customers — including IPL and its customers,” IPL stated in its motion.
The Iowa Office of Consumer Advocate, Iowa Consumers Coalition, Iowa Utilities Board and Resale Power Group of Iowa have all filed to intervene in the matter.
“The IUB also understands that when bonus depreciation is utilized, it is done so on all capital investments within a given class of assets in a given year, not just selected projects. Thus, ITC Midwest’s choice to not utilize bonus depreciation will affect not only the Bent Tree or Marshall Generating Station network upgrades, but could affect all capital investments in the asset class, including investments elsewhere in the ITC Midwest transmission system, which could directly affect Interstate Power and Light’s customer costs of transmission service,” the Iowa Utilities Board said.
Likewise, the Iowa Consumers Coalition said ITC should “articulate a sound rationale for not electing to take bonus depreciation.”
In recent policy disputes over capacity markets and energy price caps, FirstEnergy and the independent power producers of the Electric Power Supply Association have usually been on the same side.
When EPSA won a federal appeals court ruling voiding FERC’s authority over demand response last year, FirstEnergy asked the commission the same day to prevent DR from being included in PJM’s capacity auction.
But when the Akron-based utility announced last week that it had reached a settlement with the staff of the Public Utilities Commission of Ohio to secure guaranteed rates for several of its merchant plants, the company found itself under attack by many of its former allies.
By Thursday, EPSA had corralled Dynegy, Talen Energy, the PJM Power Providers Group (P3), the Sierra Club of Ohio, AARP and others in a coalition blasting the deal. Dynegy and Talen threatened to sue.
“The fault of FirstEnergy’s inability to compete in Ohio lies with FirstEnergy and it should not be dependent on the citizens and businesses of Ohio to provide a bailout,” said Robert C. Flexon, CEO of Dynegy, which increased its stake in PJM with its purchase of 12,500 MW of generation from Duke Energy and Energy Capital Partners earlier this year. (See Dynegy Wins FERC OK for $6.25B Duke, Energy Capital Partners Generation Deals.)
“Dynegy will pursue all available avenues, including litigation, to prohibit the power purchase agreement from being enacted so as not to compromise the competitive market design, and we strongly encourage the PUCO commissioners to oppose and vote down this adverse anti-market public policy.”
Dynegy said that FirstEnergy is already enjoying the benefits of the wholesale market and shouldn’t need any further assistance.
“Recent market awards indicate that FirstEnergy is already set to receive significant revenue for capacity at all of their Ohio plants for the next three years,” Dynegy said. “According to FirstEnergy’s own data from their recent investor presentation at the Edison Electric Institute’s Financial Conference, FirstEnergy’s fleet has been awarded more than $2.3 billion in revenues over the next three planning years from the PJM capacity auction with all of their generating plants clearing the most recent capacity auctions, which is significantly more than the amount expected at the time of FirstEnergy’s original subsidy request. As part of the award, FirstEnergy’s plants are now obligated to run through May 31, 2019, without the PPAs.”
Reliability Threat
FirstEnergy has said that it needs the income guarantees, in the form of PPAs for its Davis-Besse Nuclear Power Station, the W.H. Sammis coal-fired plant and its share of Ohio Valley Electric Corp.’s generation output, to keep them profitable.
American Electric Power has a similar proposal pending before the Ohio commission. Without the guarantees, the companies say, they might have to retire their plants, threatening system reliability.
Sixteen parties, including PUCO staff and civic groups, signed on to the proposed settlement filed with the commission last Tuesday (14-1297-EL-SSO). Several other organizations, including the Office of the Ohio Consumers’ Counsel, rejected the deal and joined in a motion to reopen the record.
FirstEnergy’s first proposal, which PUCO staff rejected earlier this fall, called for income guarantees for 15 years. The settlement seeks income guarantees for eight years. Ratepayers would make FirstEnergy whole if its generators were not profitable based on their capacity and energy sales in the competitive market.
Although PUCO staff approved the settlement, it still needs approval of the commission. FirstEnergy said it expects the commission to hold hearings on the proposal early next year.
Picking Winners and Losers
Talen joined Dynegy in promising to contest the deal in court if it is approved by the commission.
“As you are aware [PPL, one of Talen’s predecessors] led successful legal challenges in the federal courts against generation subsidy initiatives in New Jersey and Maryland,” Talen spokesman Todd Martin said Thursday. Before PPL’s generation assets were spun off to form Talen, the company won court rulings voiding PPAs obtained by Competitive Power Ventures for two merchant plants. (See CPV Md. Plant Goes Forward Despite FERC Ruling.)
“We believe states with competitive electricity markets must let those markets operate without interference or subsidies, and should not in effect be picking winners and losers,” Martin said.
P3 President Glen Thomas said PUCO staff’s “about face” represents “corporate welfare at its worst.”
“Forcing customers to buy overpriced electricity from uncompetitive plants to deliver windfall profits to FirstEnergy is a holiday offering that only the Grinch could support,” said Trey Addison of AARP Ohio.
“This bailout would leave Ohio locked into outdated and costly coal and nuclear plants, when we should instead be working to transition to a cleaner and more competitive energy system,” said Shannon Fisk, managing attorney with Earthjustice. Fisk was involved in settlement negotiations on behalf of the Sierra Club but withdrew in protest just before Thanksgiving.
Also weighing in was anti-nuclear group Beyond Nuclear, which blasted any deal that would result in the continued operations of FirstEnergy’s Davis-Besse nuclear plant. “The ratepayers of Ohio would be gouged additional billions of dollars on their electricity bills to prop up the uncompetitive Davis-Besse atomic reactor, effectively being forced to fund 20 more years of radioactive Russian roulette at the problem-plagued atomic reactor,” Beyond Nuclear spokesman Kevin Kamps.
$20/MWh Premium
Despite the opposition, UBS analysts predicted last week that the commission will approve the PPAs, which the analysts valued at $68/MWh.
That would be $20 MWh above market prices, based on Ohio’s most recent auction for default service. PUCO in November accepted the results of AEP Ohio’s third wholesale auction to determine the default price through May 2018, at $48.29/MWh. That price will be blended in with result from other auctions to determine the price-to-compare for June 1, 2016, to May 31, 2018. The $48.29 price was the result of a 13-round auction with six competitive suppliers participating.
On Monday, UBS upgraded AEP to “buy” on the expectation that it will win PUCO approval of its deal.
FE: Looking out for Ratepayers
For its part, FirstEnergy said it wasn’t surprised to see the blowback from competitors.
It said it alone is looking out for Ohio’s ratepayers. Although residential ratepayers would pay an extra $3.25 to $3.50 a month during the first year of the deal, the company claims it will produce overall savings of about $560 million. FirstEnergy’s projections, which assume sharply higher natural gas prices in the latter years of the deal, have been widely disputed.
“FirstEnergy has stated from the outset that customers will likely see a monthly charge in the first three years under this arrangement, with the charges converting to credits for customers for the remainder of the eight-year term,” FirstEnergy spokesman Doug Colafella said Friday.
“Out-of-state power producers opposing our plan are betting on sharply higher power prices in Ohio down the road, so naturally they would oppose putting safeguards in place to protect our customers,” Colafella said. “Our proposal is that safeguard.”
