FERC last week upheld its decision requiring Northern States Power to continue purchasing electricity from a small hydroelectric plant, maintaining that the plant does not have access to MISO’s capacity market (QM15-2-001).
In its June request for rehearing, Northern States argued that FERC erred in requiring that the company show that Twin Cities Hydro, an 18-MW qualifying facility on the Mississippi River in Minnesota, had access to MISO’s markets. The Public Utility Regulatory Policies Act allows for the termination of the mandatory purchase of electricity from a QF if the generator has “nondiscriminatory” access to the markets.
FERC presumes that any QF with capacity less than 20 MW does not have access to the markets and requires utilities seeking to eliminate QF obligations to prove otherwise. In its May 14 order, FERC ruled that while Twin Cities had been selling power in MISO’s energy markets, it could not access the RTO’s capacity market. (See Ruling Denies Northern States’ Request to Halt Hydro Purchases.)
In its rehearing request, Northern States said the law “does not require a showing that the QF currently has met the requirements to sell its capacity into a market or a showing that the QF has had a history of sales. It simply requires a showing that the QF is on a level playing field with other facilities to establish nondiscriminatory access.”
It said FERC’s May 14 order allows Twin Cities, which is owned by Brookfield Renewable Power, to “sit on its hands and then be allowed to take advantage of the purchase requirement through its inaction.”
FERC was not persuaded by the arguments.
Northern States “has acknowledged that the Twin Cities QF cannot, at present, access the MISO capacity market,” FERC said. “The evidence presented by [Northern States’] own witness explained that, if Twin Cities were to submit a network resource interconnection service request, MISO would likely grant Twin Cities only conditional service, pending completion of several transmission network upgrades.”
The commission said the law requires that Twin Cities have “access to the specified markets and not merely that the Twin Cities QF is no more disadvantaged than any other sellers seeking to sell in such markets.”
Northern States also argued that FERC erred when it said that the company had to show access to an organized market, rather than merely a wholesale market.
The commission said no such thing, FERC said. Northern States’ “strawman argument that the May 14 order made such a finding — when, in fact, it did not — is thus without merit.”
Portland General Electric said Friday it will explore joining CAISO’s Energy Imbalance Market (EIM).
The EIM currently provides least-cost dispatch in California and parts of Oregon, Washington, Utah, Idaho and Wyoming, with Nevada-based NV Energy scheduled to join Nov. 1. Puget Sound Energy in Washington and Arizona Public Service plan to join in October 2016.
Also last week, the CAISO Board of Governors approved a proposed governance structure for the EIM. The governing body would have five members charged with representing real-time market participants’ interests, regardless of location. Changes in EIM market rules would have to be approved by the governing body and the ISO board before being filed with FERC.
Atlantic Coast Pipeline Files for Construction Permit with FERC
The owners of the Atlantic Coast Pipeline filed a formal request to FERC to construct the $5.1 billion, 564-mile pipeline to transport natural gas from the shale region of West Virginia to the Virginia and North Carolina coasts.
The owners, led by Dominion Resources and including AGL Resources and Piedmont Natural Gas, pre-filed the application about a year ago. Dominion, the operator, said it hopes to begin construction by the second half of 2016 and to complete it by the end of 2018.
The 30,000-page application asks FERC to declare the pipeline as a public benefit and necessity, which would allow the project to use eminent domain to obtain rights of way. Dominion says it has completed about 85% of the surveying for the project.
A look at the 99 operating nuclear generating stations in the U.S. in the first half of 2015 showed that 75 were operating at high levels and within all security and safety parameters, according to the Nuclear Regulatory Commission. A further 21 needed to resolve one or two low-significance safety items and will need an additional inspection, according to the commission.
But Arkansas Nuclear One Units 1 and 2 and Pilgrim nuclear plant were ranked substantially lower, on the commission’s “Multiple/Degraded Cornerstone Column,” or Column IV. Column V is “Unacceptable Performance Column” and calls for a plant to be shut down.
Pilgrim was marked down because of long-standing low-to-moderate safety findings. The plant’s operators are considering whether they can afford the costly upgrades and repairs required. If not, they say, they may shut down the plant.
Entergy, owner of Arkansas One, is set to brief the commission on steps it has taken to prepare for a major inspection of the plant. An NRC spokesman said about two dozen inspectors are expected to work “many weeks” to perform the full inspection.
NRC issued the poor rating for the plant after a fatal accident in March 2013, when a 500-ton generator part fell and crushed a worker and injured others. The incident also resulted in flooding in some parts of the plant.
Obama Administration Pledges $120 Million for Solar, Renewables
The Obama administration has pledged $120 million in funding to advance solar and other renewable energy technologies. The Department of Energy will oversee most of the programs, which are aimed at boosting solar in 24 states.
The White House noted that 734,000 homes now have solar panels, compared to 66,000 when President Obama came into office.
“President Obama and Vice President Biden are committed to promoting smart, simple, low-cost technologies to help America transition to cleaner and more distributed energy sources, help households save on their energy bills and to address climate change,” the White House said in a fact sheet outlining the efforts.
Nevadans Show up to Question NRC Report on Yucca Mountain
Nearly 100 people turned out at a public meeting to dispute a recently released Nuclear Regulatory Commission report that concluded that there would be “a negligible increase” in health risks if the Yucca Mountain underground nuclear waste repository were completed.
Richard Bryan, chairman of the Nevada Commission on Nuclear Projects, said the state was “steamrolled” into accepting the site, and said he’s not ready “to gamble on the health and safety of Nevadans” when it comes to Yucca Mountain.
The project is at a standstill, after the Obama administration cut off its funding in 2010.
FERC and the Nuclear Regulatory Commission are holding a joint meeting Oct. 21 at FERC headquarters in Washington. The two sets of commissioners will hold discussions during the first portion of the meeting, followed by staff presentations.
Representatives of the North American Electric Reliability Corp. are also expected to participate.
The Nuclear Regulatory Commission said that it is satisfied that PSEG Nuclear had addressed the issues that caused a series of unplanned shutdowns at the company’s Salem 1 station in Lower Alloways Creek Township, N.J., which prompted a higher level of attention from the regulatory agency.
NRC regulations call for a full review if a plant has more than three unplanned shutdowns in 7,000 hours of operation. Salem 1 had a fourth shutdown on Oct. 19. NRC said the company added new employee training to address the issues. The level of NRC oversight at the plant has dropped back down to normal levels.
Nation’s Utilities Perform Well After Fed Interest Rate Ruling
The stock prices of the nation’s electric utilities outperformed every other industrial sector following the Federal Reserve’s decision not to raise interest rates on Thursday.
The industry and investors were watching for the decision because utility stocks historically perform poorly when interest rates increase. The industry is capital-intensive, and utilities typically have to wait for rate increases to catch up with any interest rate increases.
“Interest rate increases are historically negative for utility stocks,” said Kit Konolige, a Bloomberg Intelligence senior utility analyst. “They react a lot like the way the bond market does when interest rates rise, which is negative.”
Sunflower Electric Power lost a second time last week in its bid to recover $5 million it claims it is owed for “backstopping” a power-supply arrangement between Kansas Municipal Energy Agency and Garden City, Kan.
FERC denied Sunflower’s request for a rehearing of a July 2014 order that rejected its complaint (EL14-38-001).
The Kansas-based cooperative had charged the arrangement was unfair and violated FERC and SPP rules, and SPP’s Tariff. Sunflower alleged Kansas Municipal’s firm capacity and firm transmission were insufficient to supply Garden City during January and February 2014 and that delivering wind energy to Garden City did not meet SPP’s dynamic scheduling rules governing the transfer of energy from one control area to another.
By failing to comply with dynamic scheduling requirements, Sunflower said, Kansas Municipal violated North American Electric Reliability Corp. standards.
Sunflower said it was entitled to $5.1 million in compensation for backstopping Kansas Municipal with imbalance energy, ancillary services and firm capacity and for Kansas Municipal’s reliance on the energy imbalance services (EIS) market. Sunflower also asked FERC to eliminate Kansas Municipal’s “unfair marketing advantages” and practices it said threatened grid reliability.
Sunflower was the balancing authority for the area before SPP launched its Integrated Marketplace in March 2014. The dispute arose after Garden City dropped its supply contract with Wheatland Electric Cooperative, a Sunflower member, and switched to Kansas Municipal to supply its 71.5-MW load in January 2014.
FERC denied Sunflower’s complaint in July 2014, saying the cooperative failed to meet its burden of proof.
The commission noted there was no network integration transmission service agreement (NITSA) violation because the wind resources were short-term and, therefore, not part of the NITSA. FERC also pointed out SPP’s Market Monitoring Unit found no violation of the Tariff or evidence that Kansas Municipal negatively affected SPP’s EIS market.
The commission held that neither Kansas Municipal nor SPP could violate the NERC standard in question, “because neither entity was registered as a balancing authority with NERC during the relevant time period,” and that neither Kansas Municipal nor SPP “had any obligation with regard to dynamic scheduling.”
In Sunflower’s rehearing request, it charged that FERC erred in finding Sunflower failed to meet its burden of proof and determining that the supply arrangement did not violate the Tariff.
In denying Sunflower’s request for a rehearing and clarification of the July 2014 order, FERC said the cooperative’s request fell outside the order’s holdings.
“The complaint order principally rested on Sunflower failing to meet its burden of proof,” FERC said. “In contrast, Sunflower’s requests for clarification are general questions regarding the operation of the SPP Tariff. The requests are not specific to the instant proceeding and are inappropriate to raise at this late stage of the proceeding.”
WASHINGTON — As the Sept. 28 deadline approaches for Exelon and Pepco Holdings Inc. to appeal D.C. regulators’ rejection of their merger, Mayor Muriel Bowser is saying little to indicate how she feels about a second try by the companies to close the deal.
On Thursday, local officials and advocates rallied in front of the mayor’s office to urge Bowser to “stand firm” against Exelon and Pepco, amid talk that the companies are lobbying her administration with extra concessions designed to secure her support before they request that the D.C. Public Service Commission reconsider the deal.
Councilwoman Mary Cheh said that the companies want to be able to go before the PSC with the mayor and city’s attorney general saying that additional ratepayer credits — “or whatever little kind of trinket they’re going to throw our way” — now make the deal in the public benefit.
“Right now, believe me, sort of slithering around the district building and other parts of our government are Exelon and Pepco representatives trying to work out some deal that will steal from us the victory that we won on the merits before the Public Service Commission,” Cheh said.
Last week, Exelon placed full-page ads in The Washington Post proclaiming that the “merger is too important to fail,” which opponents at the rally held up as evidence that the companies have not given up.
But even as The Post reported Friday that administration officials are internally discussing whether a revamped deal is possible and that Pepco has warned the administration that rates would go up if the deal was not approved, Bowser has remained taciturn. Cheh told RTO Insider that the council has been “left in the dark” by the mayor.
Speaking on the Kojo Nnamdi radio show Friday, Bowser declined to say whether she’s had any discussions with Exelon, only saying that she agreed with the PSC’s decision last month that the deal, as proposed, was not in the public interest. (See DC Halts Exelon’s Acquisition of Pepco Holdings.)
Bowser also declined to say whether she wanted to support the merger. Noting that other states have approved the deal with concessions, she said, “We’re not them. And it’s always been my position that they have to have in front of us something specific to the District of Columbia that addresses my concerns.”
But ultimately, Bowser said, “whether I think they come to terms or not, the Public Service Commission has to approve or disapprove the merger and then it would follow the legal course beyond that.”
The PSC would have 30 days after the companies file an appeal to make a decision. The companies could turn to the courts as a final recourse, Bowser acknowledged.
“We continue to hear from both sides and our position hasn’t changed — any merger has to be in the best interest of district residents and taxpayers,” Bowser spokesman Michael Czin said in a statement.
“Today we just have two words for Mayor Bowser: Madame Mayor, stand firm,” said the Rev. Earl D. Trent, pastor of the Florida Avenue Baptist Church, at Thursday’s rally. “Stand firm; do not settle for the quick fix. Stand firm against the blistering winds of compromise that Exelon is surely offering. … Stand firm and back the PSC’s decision. Your constituents have clearly spoken.”
FERC last week approved MISO’s rate schedules for the system support resource agreements at three aging power plants on Michigan’s Upper Peninsula but directed the RTO to revisit its general cost allocation methodology to address concerns over how it might be applied to future SSR units.
The order conditionally approved the allocation of SSR costs at Presque Isle, Escanaba and White Pines (ER14-2952-003). The commission had rejected a prior cost allocation plan in an order in February.
FERC found that MISO’s proposed cost allocation methodology “generally complies” with the February order “in that it assigns SSR costs directly to load-serving entities (LSEs) serving loads that would contribute to thermal or voltage reliability violations in the absence of the Presque Isle, Escanaba and White Pine SSR units under conditions that are representative of actual manual and/or automatic responses taken during reliability events.”
But it rejected MISO’s filing as a generally applicable rate schedule, instructing the RTO to address the commission’s remaining concerns in a compliance filing.
FERC said the proposed methodology does not explain how MISO will calculate load distribution factors and does not justify how it selects load buses in identifying SSR beneficiaries.
The commission also said MISO did not provide an adequate explanation of the terms “daily load weighting factor” and “aggregate distribution factor” and failed to justify its proposal to allocate SSR costs at commercial pricing nodes based on their non-coincident monthly peak volumes.
“We find that this approach does not represent the actual conditions studied that caused the constraints, because MISO’s Attachment Y study identifies constraints during the coincident system peak volume, as this is when the SSR unit is most likely needed for reliability purposes,” the commission said.
In last week’s order, FERC dismissed the Michigan commission’s “generic criticism” that MISO’s new methodology is based only on how load contributes to thermal constraints and voltage violations in the absence of the SSR unit. The PSC said MISO failed to consider other factors that could be used to identify LSEs that require the SSR units.
“The Michigan commission has not made a showing that these two factors are insufficient to identify LSEs that benefit from the operation of the SSR units, nor has it identified other factors that MISO should have considered,” FERC 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.”
