Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be at the PJM Conference and Training Center in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report. (Note: The meetings were delayed by a week because of the pope’s visit to Philadelphia and relocated to the CTC because facilities were not available in Wilmington on the new date.)
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Manual 40: Certification and Training Requirements. Makes miscellaneous edits; clarifies concepts, roles and responsibilities related to PJM’s systematic approach to training; updates the process for member training and PJM certification and reflects changes in terminology of operator titles.
Manual M10: Pre-Scheduling Operations. Adds procedures for maintenance outages under Capacity Performance rules: the requirement for PJM members to provide estimated “early return time” for planned outages; ensures that PJM will coordinate rescheduling if it withdraws or withholds approval of a planned outage; references PJM’s authority to withhold or withdraw approval of maintenance outages with at least 72 hours’ notice; adds requirement that maintenance outages be submitted at least three days prior to the operating day of their commencement.
Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. The proposal, hammered out by Direct Energy, Old Dominion Electric Cooperative, the Independent Market Monitor and the PJM Power Providers Group (P3), would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments. (See related story, Consensus Near on Energy Market Offer Cap?)
Members Committee
CONSENT AGENDA (1:20-1:25)
B. The committee will be asked to endorse Reliability Assurance Agreement revisions regarding external capacity rights. The rule change allows load-serving entities to meet their internal capacity requirements using historic resources under certain conditions: The percentage internal resource requirement is enforced only if the locational deliverability area has been separately modeled due to certain triggers; a fixed resource requirement entity is permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and first-time elections of the FRR alternative are due four months prior to a Base Residual Auction instead of the current two-month deadline. (See IMEA Reaps Limited Relief from Capacity Rule Change.)
C. New Tariff language reflects the switch from eMkt to Markets Gateway.
ENDORSEMENT (1:25-2:25)
Members will be asked to vote on a proposal to change the $1,000/MWh energy market offer cap. (See MRC agenda item 3, above.)
SARATOGA SPRINGS, N.Y. — New York Power Authority CEO Gil Quiniones says the state-run company will be the “most innovative and advanced utility in the U.S. in a very short period” due to massive investments and its commitment to facilitate the remaking of the industry in the state.
Quiniones
Addressing the fall conference of the Independent Power Producers of New York, Quiniones said NYPA expects to spend $3 billion to $4 billion on infrastructure over the next decade, with nearly half of that total — $1.5 billion — in smart grid generation and transmission assets.
New York has embarked on the Reforming the Energy Vision initiative to transition to cleaner and more distributed generation. NYPA’s five-year strategic plan was written in the context of REV, he said.
That means a revamping of operating procedures and technologies that can accommodate distributed resources. “As we move into this REV world, we have to be sure that all this generation and transmission infrastructure works in synchronicity with the advent of distributed resources,” Quiniones said. “… Our grid has to be connected and smart and optimized and the only way to do that is to digitize it and use big-data analytics.”
NYPA has 16 power plants and 1,400 circuit miles of transmission, including one-third of the state’s high voltage system. It serves 51 small municipal and rural cooperatives.
One project now underway is the retrofit of the Massena substation, which Quiniones said will result in “the most advanced substation of its size in this country. It will be microprocessor-based, fiber optic-based; it will provide unparalleled situational awareness and operational flexibility.”
Last year, NYPA built a 15-MW microgrid on Rikers Island in New York City, which captures waste heat from the facility and runs parallel and synchronous to the utility system. It can island in the event of another city-wide power interruption, such as during Superstorm Sandy. This is intended to be the first of several microgrids NYPA will build.
NYPA is acting as a facilitator with vendors SolarCity and SunEdison to install solar panels at the 698 school districts in the state. “I predict there will be a very fast ramp up of solar in our public schools,” Quiniones said.
In October, six drones from different vendors will be tested to monitor the condition of power lines. The authority also is beginning to monitor power line conditions and operations with a robotic device from Hydro-Quebec.
Much of the innovation is taking place in the North Country, home to most of the state’s wind farms, whose variability stresses the system.
Other initiatives include:
Installing dynamic line rating technology sensors and intelligence so the system can know exactly how much power is being carried through its lines. This aids efficiency by acting as a “fast switch” as it can transfer as much as 300 MW from one line to another in milliseconds to prevent system overload;
Condition-based monitoring that would base equipment replacement on the condition of the asset rather than on manufacturers’ recommendations;
Transformer-testing software to prevent catastrophic events.
The authors of four competing proposals to change the $1,000/MWh energy market offer cap have agreed to put forward one plan for consideration by the PJM Markets and Reliability Committee on Thursday — the last chance stakeholders will have to come to consensus before the Board of Managers takes the issue into its own hands.
The proposal outlined during a special MRC meeting last week would cap cost-based offers at $2,000/MWh and allow them to set LMPs, with market-based offers allowed to equal cost-based. Generators with approved fuel-cost policies claiming costs above $2,000/MWh would be compensated through make-whole payments.
There would be no change to the treatment of the 10% adder, shortage penalty factors and start-up or no-load compensation. Cost-based offers would be considered to include the 10% adder.
The framework was hammered out during a conference call last week attended by Direct Energy, Old Dominion Electric Cooperative, PJM Power Providers Group (P3), the Independent Market Monitor — jokingly dubbed “the four horsemen”— and PJM staff.
“I think it’s fair to say that none of the four proposers who participated in the call felt it was their home run,” said committee secretary Dave Anders. “But it was something they looked at as a bridge that, should the stakeholders come to consensus on it or something close to it, it could work for this winter and until FERC” takes action.
Stakeholders already had been rushing to reach consensus after being told in July at the Liaison Committee meeting that the Board of Managers planned to take up the issue in time for winter.
Then, on Sept. 17, FERC announced its intention to take action on offer caps and other price formation issues. The commission made the statement as it issued a proposed rule requiring RTOs and ISOs to align their settlement and dispatch intervals (RM15-24). It gave no timeline for future action. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)
PJM Approves
PJM’s Adrien Ford said the new framework “is something PJM staff can fully support” to the board.
Absent consensus, she said, staff is prepared to recommend a Tariff change similar to the waiver it filed last year, which allowed prices to rise as high as $1,800/MWh. PJM made it through the winter without having to invoke it.
Staff would recommend, however, that the increased cap remain beyond the winter and would clarify in its transmittal note that any FERC action would supersede the new language, Ford said. “We view it as an interim solution for a winter or two,” she said.
PJM staff hasn’t finalized exactly what it would recommend if consensus can’t be reached, she said. One outstanding issue is whether to eliminate the cap altogether. Any solution supported by PJM would allow generators full cost recovery, she said.
Supporters of an increase in the cap say it is necessary to ensure that gas-fired generators can recover their costs when fuel prices spike during extreme conditions such as the 2014 polar vortex.
On Thursday, ODEC, Direct Energy and the Market Monitor said they would withdraw their proposals to support the new framework. David “Scarp” Scarpignato of Calpine, which is a member of P3, said he hadn’t had time to canvass the group to guarantee they would do the same, but he said initial feedback from the P3 members he reached during a break in the meeting pointed in that direction. (See PJM Stakeholders Weigh 4 Options on Offer Cap; No Agreement in Sight.)
“We see there are some areas we’re not going to come to agreement in the time we have to do so,” said Steve Lieberman of ODEC. “But we’re probably not as far apart as we may have thought. Is it perfect? Absolutely not. We shouldn’t let that get in the way of an incremental improvement.
“It’s hard to argue that this is not an improvement. It does allow generators to recover their costs. It does offer load the security blanket of a cap, albeit higher than we otherwise would wish to support.”
Susan Bruce, representing the PJM Industrial Customer Coalition, agreed.
While noting that she had not reviewed the proposal with her clients, Bruce called it “a good-faith effort at compromise.”
She said she was pleased that market-based bids above $1,000/MWh must be below the cost-capped bids and that a hard cap will remain at $2,000/MWh.
“It addresses — maybe not ideally, but practically — many of the concerns that have been raised. While there are areas of this that would give customers pause, I think it’s hard to view this as anything but a good workable framework around consensus,” she said.
“It addresses my clients’ particular concerns about our aggregate market power. … The 10% adder is problematic, but if we’re looking for consensus, it will necessarily involve compromise.”
Exelon, Maryland Balk
Not everyone was on board, however.
“It falls woefully short of correct market principles that PJM should be endorsing and has endorsed in the past,” said Exelon’s Jason Barker. Payments to individual units, recovered in uplift, fail to send clear market signals, he said.
Walter Hall of the Maryland Public Service Commission said that the state would be unlikely to support an offer cap as high as $2,000.
“We have not been persuaded that there is a need at this time [for] a raising of the offer cap; however, we do agree that generator cost recoveries are important and would be willing to see some mechanism added to the PJM Tariff that would provide that, but without setting [LMPs],” he said. “We’re willing to discuss some alternative to that, some higher level of offer cap, but unlikely to be willing to go as far as $2,000.”
Hall also asked for more information regarding the generators most likely to be on the margin and setting the highest costs.
“We would have some concern that perhaps there are very inefficient units being maintained here that would be providing the last megawatt of electricity,” he said.
Eleven new electric vehicle charging stations have been added at five locations under a program called “Charging Up Delaware,” a partnership between the University of Delaware and the Delaware Department of Natural Resources and Environmental Control. It brings the number of charging stations in the state to 21.
“It’s 96 miles from the northern tip of New Castle County to the southern end of Sussex County,” said Mohsen Badiey, acting dean of UD’s College of Earth, Ocean and Environment. “Completing the Delaware network for electric vehicles traveling in or through the First State complements regional electric chargers clustered in metropolitan areas of the Mid-Atlantic region like Philadelphia and Baltimore.”
The Commerce Commission has granted a certificate of public convenience and necessity to the $150 million Spoon River Transmission Project. The 345-kV transmission line is being built by Ameren Transmission Company of Illinois (ATXI), a subsidiary of St. Louis-based Ameren.
The line, which will be built using single-shaft steel poles, will span 46 miles in the state between Galesburg and Peoria. Construction is expected to start in late 2016 and scheduled to be completed in 2018. The project is estimated to support about 100 construction jobs.
Duke, Consumer Groups Reach $85 Million Settlement on Edwardsport Costs
Duke Energy Indiana, in a settlement with several consumer groups, agreed not to pass on to consumers $85 million in operating costs from its 618-MW Edwardsport coal gasification power plant in Knox County. The consumer groups had charged that the utility had rushed the plant into service early in 2013 in order to count some construction costs as operating expenses.
The settlement, announced Friday, still needs the approval of the Utility Regulatory Commission. The company has agreed to commission hearings on the matter, and Duke said it expects a final decision next year. The $3.5 billion plant is the first coal-fired generation to be built in the state in two decades. It is designed to gasify coal, remove the pollutants and use the cleaner gas to generate electricity.
An earlier commission settlement capped construction costs that could be passed through to consumers at $2.595 billion. At the time, the company agreed to shoulder $900 million in construction costs.
Optimum Renewables really, really wants to build a wind farm in the state.
The Des Moines-based company’s plan for a small, three-turbine wind facility has been turned down by three counties so far — Fayette, Buchanan and most recently Black Hawk. The company is once again asking Black Hawk for permission to construct the facility on a farm near the Black Hawk-Buchanan county line.
A hearing on the proposal is scheduled for Oct. 20.
PUC Shoots Down Emera’s Bid for $15.4 Million Tx Line
Emera Maine wanted to build a $15.4 million transmission line from Monticello to New Brunswick, but the Public Utilities Commission unanimously ruled against it.
The three-member commission estimated that it would cost the average ratepayer about $34.07/year and argued that there were cheaper alternatives. The commission suggested that Emera work with Algonquin Power to upgrade a transformer on its system in Canada, which would cost customers only $1.94/year, according to commission estimates.
Southern Maryland Electric Cooperative is asking for a 4.45% increase to its distribution service rates, the first rate request in more than five years.
The additional revenue would help strengthen the grid and improve service reliability, SMECO said. If approved, the rates would take effect in March.
Saginaw Approves $1.8 Million Plan to Replace Streetlights with LEDs
The Saginaw City Council approved a plan to spend $1.2 million on LED streetlights and another $600,000 to hire a company to install them. The city said it will save about $440,000 a year on street-lighting costs after the switch.
The council said it plans to use the savings to pay down debt on the $5 million bond it is using to finance several projects. The city anticipates having $140,000 in total annual savings after the payments.
The project is scheduled to start in November and be completed next spring.
State Appeals Court Sends Sandpiper Pipeline Back for Environmental Review
The state Court of Appeals ruled that the proposed Enbridge Sandpiper oil pipeline must go back to the Public Utilities Commission for a full environmental review, after the PUC already approved the project. The ruling strips a certificate of need for the proposed $2.6 billion, 610-mile pipeline that would run from North Dakota to Wisconsin.
The court ruled that giving approval to the project constitutes a “major governmental action” and must therefore undergo a full environmental impact study before getting PUC approval, something that wasn’t done previously. Enbridge had hoped to start construction on the pipeline next year.
Enbridge has not yet indicated whether it will appeal.
Regulators May Change Rules to Help Boost Wind Development
The Public Service Commission is considering a change in regulations that could make it easier for smaller wind energy projects to get started. The change was requested by Greycliff Wind Prime, which wants to build a 25-MW project near Big Timber but has had trouble securing a contract with NorthWestern Energy, the state’s largest utility.
Greycliff said a Public Utilities Commission rule that requires a competitive bidding process for any renewable project larger than 3 MW is making it harder for smaller projects to get a contract, because NorthWestern has few bidding events. FERC ruled last year that that particular requirement poses an “unreasonable obligation obstacle.”
The PSC voted 3-2 to review the rule and possibly change it. “I’m committed to solving the problem in some way, shape or form,” Commissioner Travis Kavulla said.
Opposition is heating up against renewing a permit allowing PSEG’s Salem nuclear plant to continue to draw 3 billion gallons per day from the Delaware River to meet its cooling-water demands.
Delaware Riverkeeper, an environmental advocacy group, submitted a detailed critique of the practice to the Department of Environmental Protection on the final day of the public response period. “Salem is surpassed in its impingement and entrainment impacts on fish by only one other facility in the nation,” a power plant in Florida, said Maya van Rossum, the Riverkeeper’s director.
Salem’s permit expired in 2006, but the plant has been allowed to operate pending a decision on the “best available technology” to mitigate its environmental impact.
Gov. Susana Martinez unveiled a broad “all-of-the-above” plan Sept. 14 to develop the state’s energy resources, the first such comprehensive policy outline for the state in 25 years.
The governor recommended a broad array of strategies and policies that include traditional fossil fuels such as oil, natural gas and coal; renewables like wind and solar; and new technologies, such as “small modular reactors” to harness nuclear energy.
Responses to the plan are likely to be varied, given the broad range of policies it promotes. Environmental organizations could take issue with some fossil fuel development strategies, such as a recommendation to export coal from mines to sustain that industry as coal consumption by local utilities declines. Potential future deployment of small modular reactors, an emerging technology that must still be approved by the federal Nuclear Regulatory Commission, also could prove controversial.
Brattle Group says Nuclear Power Brings $2.47 Billion to State
A recent report by the nuclear industry-sponsored Brattle Group says that the state’s six nuclear generating reactors bring $2.47 billion to its gross domestic product. A report released by the group in July tagged the national contribution at $60 billion.
The Brattle Group said the six reactors — Entergy’s FitzPatrick and Indian Point 2 and 3, and Exelon’s R.E. Ginna and Nine Mile Point 1 and 2 — provide 5,000 MW of generation and nearly 42 million MWh of annual generation. It said the industry supports 18,000 jobs in the state, contributing $113 million in state tax revenue a year.
Regulators to Consider Approving Turkey Poop-to-Energy Project
Prestage AgEnergy is preparing a proposed project to turn turkey droppings into a combustible fuel for a 1.6-MW plant.
The plant, if approved by the Utilities Commission, would be the first to convert poultry manure to a gas, rather than burning the droppings and litter. If approved, it would help the state reach its renewable energy mandate, a goal set in 2007.
Prestage proposes to gasify turkey waste from more than 50 farms in eastern North Carolina. It has yet to reach an agreement with Duke Energy Progress to purchase the plant’s energy.
PUCO Staff Opposes FirstEnergy Guaranteed Income Plan
The Public Utilities Commission staff said Friday that FirstEnergy’s request to shift the risk of some of their costly power plants to ratepayers is not in the public’s best interest. FirstEnergy wants a 15-year contract to buy the output of a coal and nuclear plant from FirstEnergy Solutions, its unregulated subsidiary.
A PUC staffer submitted testimony Friday that said the proposal isn’t acceptable in its present form. The recommendation has implications for a similar request by American Electric Power, which wants an income guarantee for some coal plants. AEP case’s hearing is set to begin on Sept. 28.
Hearings in the FE case started in late August. The five-member commission is not bound by the staff ruling, but it must take it into consideration.
Siting Board Authorizes 800-MW Combined-Cycle Plant in Lordstown
The Power Siting Board approved Clean Energy Future’s plan to build an 800-MW natural gas-fired combined-cycle plant in the Lordstown Industrial Park, northwest of Youngstown. Clean Energy Future said the plant will connect to the American Transmission Systems grid.
Construction is set to begin this year, and the $850 million plant is scheduled to be operational by May 2018. The Public Utilities Commission has already approved the plant.
The state held its first “listening session” last week about implementation of the Clean Power Plan. The three-hour meeting was the first of 14 scheduled throughout the state, where interest groups and private citizens will get a chance to have the ear of the Department of Environmental Protection.
DEP is seeking input on such issues as how to measure compliance, whether the state should join an emissions-trading program and how it can best use energy efficiency and renewables in meeting the goals of the carbon-cutting plan.
DEP is accepting public comments, including written submissions to its website, until Nov. 12.
Appalachian Power Seeks Approval for $50 Million Transmission Line
Appalachian Power says it will ask the State Corporation Commission for permission to upgrade and expand a $50 million transmission line near Abingdon. The project would upgrade six substations, as well as add 11 miles of new transmission line.
The company said the upgrades are needed to meet growing power demand in the region. “The electric needs of the town of Abingdon and Washington County are growing,” said Mary Begley, Appalachian Power external affairs manager. “Work that Appalachian is planning will address those needs and provide a transmission grid capable of handling future growth. This investment in our system provides Abingdon and Washington County with a network that can help attract new businesses to the area while allowing existing companies to compete and expand.”
Bradley C. Jones joined ERCOT little more than two years ago from Energy Future Holdings as the grid operator’s vice president of commercial operations. The job gave him responsibility for market operations, design and development, settlements, retail operations and client relations.
He wouldn’t stay long.
In January, ERCOT appointed him senior vice president and chief operating officer, putting him in line to potentially succeed CEO H.B. “Trip” Doggett, who announced in June that he will retire in 2016.
In August, however, ERCOT named General Counsel Bill Magness as Doggett’s successor. So last week, after less than nine months in his new job, Jones announced he would succeed Stephen C. Whitley as CEO of NYISO.
Jones (left), Whitley (right) (Source: NYISO)
Jones will take over Oct. 12, as the New York power market faces a proposed overhaul led by the state’s governor and utility regulators.
In January, Gov. Andrew Cuomo called for the Public Service Commission to review the ISO, saying its market design is at odds with his administration’s Reforming the Energy Vision initiative, which seeks increased deployment of distributed resources and clean energy. Cuomo also called for more public and consumer representation on the ISO’s Board of Directors. (See NYISO: We’ll Cooperate with PSC Review.)
The ISO’s other challenges include the continuing shift to natural gas generation; reliability concerns caused by coal retirements and above-market contracts needed to keep some generators operating; transmission constraints into New York City; and discussions to change the capacity market that have not reached consensus.
Three Decades
Those who know him at ERCOT say Jones’ nearly three decades of experience in the industry have prepared him for the challenges.
“Brad was integral in the creation of the successful ERCOT market,” said Theresa Gage, ERCOT’s vice president of external affairs and corporate communications. “We are sad to see him go, but we are proud that NYISO recognizes the excellence in Brad that benefited the ERCOT market for so long.”
His new bosses in New York say Jones’ experience in the private sector and with the Texas grid is what made him the best candidate.
“The board gave serious consideration to a number of highly qualified and impressive candidates — both internal and external — and ultimately selected Mr. Jones because of his long and distinguished career in the electric sector,” NYISO spokesman David C. Flanagan. “His diverse background — with experience in grid operations, power plant operations, generation development, project finance, market design, and regulatory and legislative affairs — was the best fit for the NYISO at this point in its history.”
Whitley announced in January he would step down after more than seven years as the ISO’s head. He will remain with NYISO during a transition period and will become an adviser to the Board of Directors.
Jones last week declined an interview request, saying he is not yet ready to talk publicly. In a statement, he said he was “excited about the opportunity to work with the NYISO’s employees and stakeholders, as well as with government officials.”
Florida Native, Texas Career
Though born in Florida, Jones has spent most of his time in Texas, where he and his wife raised their six children.
He earned a bachelor’s degree in mechanical engineering from Texas Tech University and a master’s degree in finance from The University of Texas at Arlington. He is a registered professional engineer in Texas.
Last Coal Plant
He joined TXU Corp. as a plant engineer, rising through the ranks and various executive positions in retail, generation, investor relations, government relations and regulatory affairs. He led the development of TXU’s Oak Grove Project, a 1,634-MW coal-fired generating station located near College Station, Texas, and the last coal plant to be built in the state.
He remained with TXU after Energy Future Holdings (EFH) acquired the utility and its subsidiaries in a 2008 leveraged buyout. When he was tapped by ERCOT, Jones was serving as vice president of government relations for EFH’s competitive businesses.
While with TXU and EFH, Jones chaired ERCOT’s Technical Advisory Committee, which is comprised of stakeholders that make recommendations on operating guides and market protocols to the ISO’s Board of Directors.
Texas Market
“With his deep knowledge of the industry, Brad was always such a great resource for me,” said Pat Nichols, a senior communication strategist with TXU and EFH. “I was sorry to see Brad leave EFH but glad for his success.”
During the 1999 legislative session, Jones worked with the Texas Legislature to restructure the electric industry and allow customers to choose their electric suppliers. Then, as the Texas electric market prepared for retail competition, he led several ERCOT workgroups and committees that created the state’s competitive electricity market.
In 2001, Jones became one of only four recipients of the Public Utility Commission of Texas Commissioner’s Award for his leadership in preparing the state’s electric market for competition. He is well connected within the industry, having served on the boards of the Gulf Coast Power Association and FutureGen Industrial Alliance, chaired an Edison Electric Institute advisory committee and participated on a Texas Reliability Entity committee.
[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.]
PJM is prepared to meet this winter’s load — even if it’s a bit higher than the record peak seen last season, COO Mike Kormos told FERC last week.
PJM’s winter preparedness study considered a peak load of 135,350 MW (not including demand response), below the record winter peak of 143,086 set Feb. 20.
“We did not identify any reliability problems,” he said. “Our margins are fairly sufficient as well. We do not see anything at this point that is problematic to us.”
PJM is responding to generation retirements (blue circles) with new generation (orange circles) and transmission (yellow lines).
PJM officials are feeling more comfortable, in part, because of the improved generator performance last winter.
Generator outage rates, which exceeded 20% during the 2014 polar vortex, were generally less than 15% last winter. Officials plan to repeat the winter preparation checklist and a testing program for seldom-run units that were credited with improving performance. (See Why Did PJM Grid Fare Better This Winter?)
Kormos noted that about 10,000 MW of generation has retired since last winter, only about 3,000 MW of which has been replaced. Although the RTO feels confident it can make up the losses, in part due to new transmission, “it is a 7,000-MW difference,” Kormos said.
In addition to making enhancements to the grid, PJM has been working on its relations with the gas industry. “We have spent a lot of effort since last winter continuing coordination,” Kormos said.
Beginning Nov. 1 until March, PJM will be holding weekly calls with the pipelines to talk about upcoming maintenance on either side, projected peak loads and forecasting conditions, he said.
Kormos said he was encouraged by one pipeline’s recent announcement that it is considering offering firm service customized for generators’ needs.
“Generators are not [local distribution companies]. They don’t draw gas every hour, seven days a week, 365 days [a year] like an LDC does. They don’t have storage contracts in place like LDCs do,” Kormos said. “They need a different service.
“We feel we are in a much better situation after the past two winters,” he continued. “We believe we’re doing a better job coordinating.”
SPP’s Clean Power Plan (CPP) Task Force was given an advance look last week at a webinar that will open the dialogue with state and utility officials charged with implementing the Environmental Protection Agency’s CO2 emission rule.
SPP is hosting the webinar Tuesday for air quality regulators, utility commissions and government contacts at its member utilities in each of the RTO’s 14 states. More than 70 had registered to attend as of last week.
SPP met its goal of having each state represented by at least one registrant, said SPP Vice President for Engineering Lanny Nickell, the RTO’s point person on the CPP.
“We want to introduce ourselves as an RTO, particularly to the air quality and environmental regulators,” Nickell said. “We haven’t done that before in a programmatic approach. They don’t all know who SPP is and how it works.”
Southern States Slower to Embrace Regional Compliance
The webinar attendees will hear from SPP that state-by-state compliance with EPA’s final CPP rule will be more costly than regional compliance, and that more new generation and transmission infrastructure will likely be needed. In addition to being more expensive, SPP says state-by-state compliance would be more difficult for the RTO to manage.
Asked about the SPP states’ early plans, Nickell said, “The states in our north have expressed the most interest in working with each other.” Pausing, he said, “I don’t get that same sense from the states in the South.”
Several of SPP’s states — Arkansas, Kansas, Louisiana, Nebraska, Oklahoma and Texas — are led by Republican governors and legislatures that have pledged to battle EPA’s final rules rather than comply.
SPP’s Sam Ellis, who led a staff team that “pored over” the final rules, said states have flexibility under the regulations, but “they would lose it if they don’t implement their own plan.” EPA says it will implement a federal plan in the states that do not submit an “approvable” plan of their own.
Trading Framework
The final rule provides a framework for trading of CO2 allowances. Nickell is expected to tell the webinar attendees that there are merits to developing regional carbon trading markets and will encourage states to develop their own plans.
Ellis told the task force EPA will consult with “planning authorities” in developing the federal plan and accept comments on whether to include allowances for reliability emergencies. He said the agency believes its rate-based and mass-based approaches contain sufficient flexibility to mitigate reliability issues without having to seek extensions under the reliability safety valve.
“The EPA may not have considered interactions between the federal plan and potential state plans for a given region,” Ellis said.
The Clean Power Plan Task Force was formed under the Strategic Planning Committee’s direction to review EPA’s federal implementation plan and recommend the role SPP should play in assisting states’ compliance. The group will also work to ensure regulators have a clear communications path to SPP.
“Our hope is SPP develops concepts and policies the states can embrace,” said Michael Desselle, SPP’s chief compliance and chief administrative officer and the task force’s staff secretary.
The webinar is the beginning of SPP’s communication effort. Besides the broad overview of SPP and its responsibilities, registrants will receive SPP’s take on the CPP and a high-level overview of the three analyses it has already performed on the CPP — though, as Nickell noted, those assessments were done on the EPA’s earlier draft rules. (See SPP: State-by-State Compliance Would Hike Costs.)
“We want to talk about what we believe our role to be, and that’s reliability,” he said. “We want to encourage the regulators in our states to talk with us, and to do so early in the process.”
PLYMOUTH MEETING, Pa. — PJM staff, stakeholders, financiers, regulators and industry leaders debated the effects of environmental rules and RTO policies on the capacity market, reliability and investments at Infocast’s PJM Market Summit 2015 last week.
Following are some highlights. (Presentations for the executive forum, “Disruptive Factors in the PJM Market,” can be found here.)
Mike Kormos, PJM executive vice president and chief operations officer, gave the keynote address, “Priorities and Future Directions for the PJM Interconnection.”
Kormos borrowed a phrase from outgoing CEO Terry Boston for his presentation: “The future ain’t what it used to be,” highlighting the differences between projections from two decades ago and the reality of today.
One of the biggest game changers is gas.
“Even as late as 2007, gas wasn’t being talked about. Gas was too volatile. People didn’t want to get into that part of the business,” he said. “Now, gas is king. It’s all we’re seeing.
“Everyone is thinking gas will remain cheap and plentiful.” But, he said, “We were wrong in 2000. Are you sure we’re right in 2015?”
Prospects for Adoption of Distributed Energy Resources
“The future is quite uncertain,” said Steve Fine, vice president at ICF International. “A lot is going to depend on how DER interacts with the wholesale market.” There, aggregators would play an important role.
He added: “We’re moving away from a net metering system and more toward a distribution resource planning process.”
There are barriers to adoption, he said, including customer pushback, the impact on rates and utility financials, policy uncertainty, metering and data transmission issues, and interconnection standards.
Reid Harvey, director of the Environmental Protection Agency’s Clean Air Markets Division, said that the agency is holding calls with states and groups of states to determine how they plan to implement the final Clean Power Plan released in August.
Joe Kerecman, director of government and regulatory affairs for Calpine, said he favors a regional approach. “Just like in PJM, scale matters to market efficiency, and we think that would be the best outcome,” he said.
Kathleen Barron, senior vice president of federal regulatory affairs and wholesale market policy for Exelon, said the Illinois energy giant will be keeping an eye on how the plan’s implementation will affect its nuclear plants, some of which are struggling.
“The CPP is really the last big unknown,” she said. “We’ll be looking very closely at how states are trending for CPP implementation and what that means for our nuclear stations. It’s too soon to know whether the CPP will be the missing link for this particular sector, but we’re keeping an eye on it.”
For his part, Asim Haque, vice chairman of the Public Utilities Commission of Ohio, said his state would be litigating the rule.
A New Day for Demand Response
Greg Poulos, manager of regulatory affairs for EnerNOC, said demand response provides an “incredible value” to consumers. “If you take demand response out of the capacity market, it would cost consumers about $10 billion annually,” he said.
Allen Jones, a consultant for the OPENADR Alliance, said the use of DR is changing, regardless of what the Supreme Court decides on the D.C. Circuit Court of Appeals ruling threatening FERC’s authority over DR.
“It’s being used for more than just, ‘Oh we have a terrible problem, we need to curtail some load,’” he said, noting that retail giant Walmart, among others, has piloted a program integrating it into its energy use plan. “Demand response is going to be something you’re going to see more and more of.”
The winners of the new capacity market construct are the consumers, said Jason Barker, director of wholesale market development for Exelon. “We’ve estimated the net benefits to consumers somewhere in the neighborhood of $1 billion to $7 billion per year,” he said.
Among the surprises for George Katsigiannakis, principal of ICF International, was the amount of new generation. “I expected a larger amount,” he said.
“The price of the base product was the biggest surprise from that auction. The amount of DR was a surprise for me, also — I was expecting less DR,” he said.
Pricing, however, was not a shock, he said. “We were expecting those levels.”
Steve Lieberman, director of RTO and regulatory affairs for Old Dominion Electric Cooperative, said he expected a much greater spread between the Capacity Performance and base products.
Now, he said, “I’m hoping we can sit on our hands and stop fussing with it. … Let the auctions run, take a step back, digest the results and take it from there.”
Iberdrola USA and UIL Holdings have agreed to clean up an abandoned power plant site in New Haven if Connecticut regulators approve their proposed $3 billion merger.
The companies on Thursday agreed to a consent order with the state’s Department of Energy and Environmental Protection that would allow the contaminated English Station site to be cleaned up for reuse.
The Connecticut Public Utilities Regulatory Authority rejected the proposed acquisition in June on other grounds, saying that the plan was not in the public interest. The companies refiled a new plan in July that they said addressed regulators’ objections. (See Iberdrola Refiles Acquisition Bid for UIL Holdings.)
The state estimates site remediation would cost under $30 million. The companies have committed to spend any amount in excess of that if necessary.
The agreement was announced in a statement by Gov. Dannel P. Malloy, Attorney General George Jepsen and DEEP Commissioner Robert Klee. “The state will strongly oppose any attempt to recover remediation costs from ratepayers. The companies will propose the scope of work to fully examine the pollution and clean it, and DEEP will review and approve the scope of work,” they said.
“This is an important settlement — to New Haven and to Connecticut. The English Station has long been a site that absolutely needed to be cleaned up and given a second life, and now it will be,” Malloy said in the statement.
The plant is situated on Ball Island in the middle of the Mill River in New Haven. It was operated by UIL unit United Illuminating for 63 years and closed in 1992. It is contaminated with polychlorinated biphenyls, heavy metals and other contaminants.
Administrative proceedings will continue against UIL to determine responsibility for cleanup of contamination in the river, according to state officials.
The acquisition, which includes natural gas distribution companies in Massachusetts, must also be approved by that state’s regulators.
Connecticut regulators will conduct hearings on the acquisition in October. A decision is expected by Dec. 4.
FERC said last week it will require the North American Electric Reliability Corp. to provide the commission access to NERC databases in what Chairman Norman Bay said is an effort to apply “Moneyball” techniques to reliability.
The commission issued a Notice of Proposed Rulemaking that would give FERC access to NERC’s transmission availability data system (TADS), generating availability data system (GADS) and protection system misoperations databases (RM15-25).
“It takes the concept of ‘Moneyball’ to our analytics on reliability,” said Bay, referring to the best-selling book on Oakland Athletics General Manager Billy Beane’s use of statistical analysis in evaluating baseball players.
The commission said access to the data “would inform the commission more quickly, directly and comprehensively about reliability trends or reliability gaps that might require the commission to direct [NERC] to develop new or modified reliability standards.”
TADS and GADS contain data on transmission and generation outages, respectively, including cause codes.
The protection system database collected information on about 2,000 misoperations in 2014, including causes. “Protection system misoperations have exacerbated the severity of most cascading power outages, having played a significant role in the Aug. 14, 2003, Northeast blackout,” FERC said.
“While the aggregated TADS, GADS and protection system misoperations data provided in NERC’s periodic reports afford the commission some insight into the reliability and adequacy trends identified by NERC, we believe that having direct access to the underlying data will assist the commission in its understanding of the periodic reports, thereby helping the commission to monitor causes of outages and detect emerging reliability issues,” FERC said.
FERC Micromanaging NERC?
Commissioner Cheryl LaFleur issued a concurring statement expressing concern that the proposal could be seen as micromanaging NERC. Although FERC has ordered NERC to initiate standards on geomagnetic disturbances and physical security, LaFleur said that authority should be used sparingly.
“It is important that we recognize the distinction between [FERC’s] oversight role and NERC’s primary responsibility to monitor reliability issues and propose standards to address them. Ultimately, I believe our efforts to sustain and improve the reliability of the bulk electric system are furthered by mutual trust and shared priorities between the commission and NERC,” she said.
“I understand that today’s proposal might be controversial within the NERC community. I therefore welcome comment on the proposal, including any potential issues or concerns not identified in the NOPR.”
Comments on the proposal are due 60 days after publication in the Federal Register.
The commission also gave final approval to two sets of reliability standards and preliminary approval to a third.
FERC approved reliability standards PRC-002-2, which specifies requirements for time-synchronized data for post-disturbance analysis (RM15-4), and PRC-005-4, adding sudden pressure relaying systems to the protection system maintenance rules (RM15-9).
It also approved a NOPR proposing to approve standard PRC-026-1, which would require that protective relay systems differentiate between faults and stable power swings (RM15-8).
