WASHINGTON — The Nuclear Energy Institute held a conference at the National Press Club Wednesday to discuss the progress made in cleaning up and dismantling the Fukushima Daiichi nuclear power plant in Japan. The Tohoku earthquake and tsunami on March 11, 2011, caused a meltdown at the plant, forcing thousands of people to abandon their homes.
While speakers primarily focused on safety improvements made in both the U.S. and Japan as a result of the disaster, others spoke about the effect it had on the workers and residents in the area, as well as the culture and communication at Tokyo Electric Power Co. (TEPCO), which operates the plant.
Houston-based CenterPoint Energy (CNP) on Friday reported a net loss of $509 million ($-1.18/share) for the fourth quarter of 2015. The loss included a $984 million impairment charge for its Enable Midstream Partners spinoff, a joint venture with OGE Energy and private-equity firm ArcLight Capital Partners.
The transmission and consumer natural gas company reported a net loss of $692 million ($-1.61/share) for the year. It said net income would have been $465 million ($1.08/share) without impairment charges of $1.846 billion, compared to $611 million ($1.42/share) in net income in 2014.
CenterPoint CEO Scott Prochazka told analysts Feb. 26 he expects 2016 earnings in the range of $1.12 to $1.20/ share.
“We expect continued strong financial performance from utility operations in 2016, which is incorporated in our guidance,” he said in a statement.
Shares of CenterPoint stock finished down 61 cents Friday, or 3.19%, closing at $18.53.
PJM last week joined more than a dozen other parties in calling for a FERC review of power purchase agreements that would provide FirstEnergy and American Electric Power a guaranteed return for their struggling generating stations in Ohio.
“If approved, the [PPAs] will create incentives that will likely lead to these generation units being offered, unless checked, in a manner that could harm the overall competitiveness of the PJM markets,” PJM said in comments supporting complaints by the Electric Power Supply Association and independent power producers.
“This outcome could impact significantly PJM’s administration of the wholesale markets in its region and affect the mission entrusted to these markets — assuring efficient, long-term resource adequacy,” PJM said.
EPSA, the Retail Energy Supply Association, Dynegy, Eastern Generation and NRG Energy asked FERC in January to revoke the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure a Section 205 review of the eight-year PPAs (EL16-33, EL16-34). (See Dynegy, NRG Ask FERC to Void Ohio PPAs.)
They also are requesting an expedited decision, given that the Public Utilities Commission of Ohio could rule in coming weeks. And they contend that the results could impact PJM’s 2019/20 Base Residual Auction, to be held in May.
‘Premature’ Attack
Before the comment window closed Feb. 23, the complaints garnered the support of more than a dozen parties, including the Pennsylvania Public Utility Commission. No one submitted comments supporting FirstEnergy, but the Ohio Energy Group — industrial customers including Alcoa, Ford, GE Aviation and TimkenSteel — wrote in support of AEP.
“The complaint represents a premature collateral attack on a proposed PPA that is not yet finalized and that could substantively change as a result of state commission decisions,” the group said. PUCO is able to protect its own customers from any “affiliate abuse,” and there is no “definitive evidence” that the proposed PPA would distort the PJM markets, it said.
Sammis power plant (Source: Chris Dilts via Creative Commons)
AEP and FirstEnergy filed similar responses, saying allegations of market distortion are unfounded.
“The PUCO is undertaking a comprehensive review of the impact of AEP Ohio’s proposal on Ohio retail customers,” AEP said. “This is precisely the reason why the commission should adhere to its longstanding policy and defer to the PUCO’s resolution of the retail rate matters that form the basis for the complaint.”
Because Ohio is a retail choice state, the companies argue, customers there are not “captive.”
“The commission should reject the complaint on the merits, given that complainants have alleged no change in law in the state of Ohio that alters the basis on which the commission granted FirstEnergy a waiver from the affiliate transaction requirements,” FirstEnergy said.
Retail Choice Irrelevant
The plaintiffs say the state’s policy on retail choice is irrelevant because the PPAs would be funded by surcharges on all customers in AEP and FirstEnergy’s service territories, regardless of whether they take provider of last resort service from the utilities or purchase from a competitive supplier.
Among those supporting EPSA’s complaint was a coalition of 10 northwest Ohio communities.
“This is the first any of us has ever intervened at FERC — and that alone shows our resolve to oppose this awful PPA. It will cost Northern Ohio at least $3 billion,” said the Northwest Ohio Aggregation Coalition.
“When all the jargon is stripped away, the FirstEnergy PPA requires regular people to pay an extra month’s electric bill each year for eight years. It is not for the electricity that they use,” the coalition said. “Instead, the money that people need for school clothes and medical co-pays will go solely to bail out the company’s aged and inefficient coal and nuclear plants.”
Hardwood Flooring and Paneling Inc. in Middlefield, Ohio, said the PPA would cost it an additional $105,834 over eight years to pay for the 2.1 GW the business uses annually.
“That is real money that could be used on more productive purposes [such as] updating our equipment, increasing our inventories and building a new finishing plant for our hardwood flooring products — all of which bring more taxable income to the state of Ohio,” Vice President Barbara Titus wrote.
Ohio Citizen Action wrote on behalf of its 30,000 members, which the group said will be harmed.
The Pennsylvania PUC said it intervened because of “a concern that the FE affiliate PPA, as currently structured, represents a potential threat to the continued efficient function of PJM’s wholesale capacity markets, especially with regard to the upcoming 2019/2020 Base Residual Auction (BRA).
“More precisely, FE’s affiliate PPA presents the risk of potential subsidization of generation facilities that would otherwise be retired, resulting in conveyance of incorrect price signals in the next and subsequent capacity market auction auctions.”
The Ohio Manufacturers’ Association Energy Group, representing about 1,400 companies, said the manufacturing sector is one of the top electricity consumers in the state.
“Any impacts arising from future increases to electricity prices will have a significantly negative effect on their businesses,” it wrote.
OGE Energy fell short of Wall Street expectations Friday when it reported a fourth-quarter profit of $29.4 million and earnings of 15 cents/share. According to Zacks Investment Research, analysts had expected earnings of 23 cents/share.
The Oklahoma City-based parent of Oklahoma Gas & Electric recorded $447.1 million in revenue for the quarter. For the year, OGE posted a profit of $271.3 million ($1.36/share), compared with earnings of $395.8 million ($1.98/share) in 2014.
OGE shares closed down $1.88 Friday at $25.08, a 7% drop. It began the year at $26.29/share.
CEO Sean Trauschke attributed the earnings shortfall to low energy prices.
“The significant drop in commodity prices had an impact on our business as well as our communities,” he said in a statement. “However, we have made significant investments to improve our business and our company is better positioned to handle these challenges.”
Trauschke told analysts Friday the company is on target to continue to grow its dividend of 10% through 2019.
OG&E has approximately 825,000 customers in Oklahoma and western Arkansas. Its OGE parent also holds a 26.3% limited partner interest and a 50% general partner interest in Enable Midstream Partners.
WILMINGTON, Del. — A problem statement and issue charge seeking to develop RTO-wide criteria for end-of-life transmission facilities kicked off a long and heated discussion before being approved by an 80% sector-weighted vote of the PJM Markets and Reliability Committee on Thursday.
Just two of 12 Transmission Owners voted in favor of the proposal, which won 90% or more support from each of the other sectors.
Ed Tatum of American Municipal Power presented the proposal, which AMP co-sponsored with Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition, the PJM Public Power Coalition, LS Power and ITC Mid-Atlantic Development.
“Aging infrastructure is a primary driver of investment,” Tatum said, noting that $5.5 billion in replacement projects have been identified and more are expected. That’s because most of the grid was built 30 to 50 years ago, he said. “We’re concerned about the number of dollars being spent.”
Some transmission owners have criteria for end-of-life facilities, but others do not, treating them as supplemental projects, Tatum said. Supplemental projects are improvements not required for compliance with PJM system reliability, operational performance or economic criteria.
Uniform guidelines would improve how the local and regional planning process determines the need for replacement facilities, according to the problem statement.
The newly formed End of Life Task Force will be charged with developing “alternatives for providing more transparency and consistency in the review of end-of-life projects, including the development of PJM end-of-life-criteria.” It will report to the MRC.
The majority of transmission owners opposed the plan, saying the problem statement prescribed a solution, that such guidelines should be voluntary and that it was illegally treading on the rights of transmission owners to maintain their own equipment. They called for an education session before bringing the issue back for a vote and said any such task force should report to the Planning Committee.
Tatum said the sponsors rejected a proposed revision by the TOs to make the guidelines voluntary because “making it voluntary is the status quo.”
And, he said, “Based on the conversations I’ve had with a number of you, I think that the definition you all may be using for maintenance is a bit expansive. My water heater blew last week and I didn’t maintain it, I replaced it.”
Speaking on behalf of the TOs, Chip Richardson of PPL said, “The TOs have expressed some concern that the very nature of this problem statement would violate their rights. … We think that the MRC needs to understand that this is a task to do something. This is not a problem statement or opportunity to do something. We’re implementing a solution that this group has chosen.”
Richardson said the TOs would have supported the issue if the guidelines were voluntary. He called for an education session to address three issues: to whom the task force should report; the rights of the TOs and PJM under the Consolidated Transmission Owners Agreement; and the implications of such criteria on cost allocations for projects in the Regional Transmission Expansion Plan.
“We’re launching a solution but are not well informed of what the implications are,” he said.
Tatum said it was not the intent of the sponsors to infringe upon TOs’ rights and that the task force would not be considering the issue of cost allocation. While the problem statement suggests “criteria and guidelines” would improve transparency, the task force would consider other approaches that accomplish the goal, he said.
PJM Vice President of Planning Steve Herling said transparency was the RTO’s primary concern as well, and to that end it could support the problem statement and issue charge.
“There’s an expectation as we start our planning process … that there is the opportunity for full vetting,” he said. “As long as [the criteria] are out there and people can see them and we have the opportunity to vet the issues and solutions, I think we’re OK with this moving forward. I’m less concerned with who the group reports to. The same people are going to have to be on the task force regardless.”
Jason Barker of Exelon cautioned that the task force’s work could embroil PJM in litigation if it treads on TOs’ rights under the CTOA.
“This is unquestionably a discussion about cost allocation. The overture here is that that’s not an intent … but it naturally follows from the discussion we’re having. Let’s acknowledge the elephant in the room,” he said, adding, “With regard to the committee reporting, it’s interesting that the sponsors want to put this at the MRC. We have a PC that’s described in our Operating Agreement: ‘The [Planning Committee] shall advise the [Markets and Reliability Committee and PJM] on matters pertaining to system reliability … and planning strategies and policies.’ That’s exactly what we’re talking about here. This is exactly in the PC’s wheelhouse, and there’s really no reason to diverge from it aside from politics.”
Gloria Godson of Pepco Holdings Inc. said the initiative “may be a back door way of imposing a risk profile on the TOs.”
A TO’s asset management practices result in a certain life expectancy for each asset and when the asset needs to be replaced, she explained after the meeting. “If the PJM stakeholders become the determinants of when and how transmission assets will be replaced, [they] will effectively be imposing their risk profile on the TOs and usurping this key corporate decision-making of the company owning the asset,” she said. “Who is going to bear the risk for these assets going forward?”
Dan Griffiths, executive director of the Consumer Advocates for the PJM States, said that no one in his group opposed it.
Jim Jablonski, of the Public Power Association of New Jersey, said he would welcome more transparency in the rates that consumers are charged.
One municipality has seen its annual bill rise over four or five years from $300,000 to $1.5 million, he said. “I get questions about why this is happening,” he said. “I need to be able to explain.”
Co-sponsor Susan Bruce, representing industrial customers, said, “Customers have seen their bills increase on the transmission side like never before.”
The task force’s work, she said, “is meant to be done in a way that is respectful of TOs’ rights and those who end up paying” for transmission costs.
WASHINGTON — A parade of witnesses implored the U.S. Commodity Futures Trading Commission Thursday to reverse its position in a case that they say could undermine the broad exemptions the commission granted RTOs and ISOs in 2013.
At issue is the CFTC’s draft order on a request from SPP seeking the same exemptions from the Commodity Exchange Act (CEA) that the commission granted the six other RTOs and ISOs.
CFTC Chairman Timothy G. Massad (seated), Commissioner Sharon Y. Bowen (L), former Commissioner Mark P. Wetjen (center), Commissioner J. Christopher Giancarlo (R). Wetjen resigned last August, leaving the five-member panel two members short. Source: CFTC
The CFTC’s 2013 order exempted electricity transactions subject to FERC-approved tariffs from most provisions of the CEA while retaining its general anti-fraud and anti-manipulation authority.
SPP was the only grid operator not party to the 2013 order because its day-ahead market was not fully implemented until March 2014. Unlike the 2013 order, however, the draft SPP order includes a preamble stating the CFTC’s intent to preserve “private rights of action” under Section 22 of the CEA.
Representatives of the ISO/RTO Council (IRC), the Public Utility Commission of Texas, the Edison Electric Institute and energy management firm ACES made their case against the preamble language in a hearing of the CFTC’s Energy and Environmental Markets Advisory Committee. No witnesses spoke in favor of the added language.
Undoing the Balance
The preamble could undo “the careful balance of public interests that Congress struck when it directed coordination between the CFTC and the FERC to avoid ‘duplicative regulation’” in the 2010 Dodd-Frank Act, the IRC said in a Feb. 23 letter to the commission.
Texas PUC Commissioner Kenneth W. Anderson Jr. told the committee that FERC and the PUCT are more “efficient” than private legal proceedings in resolving disputes. Allowing private actions, he said, would result in “collateral attacks on FERC- and PUCT-authorized valid market rules, undermining the efficient operation and regulation of electricity markets.”
“This provides an end-run around the absence of a private right of action” in the Federal Power Act and Texas Public Utility Regulatory Act, Anderson said.
Uncertainty
Lopa Parikh, EEI
“Even if the commission decides to only apply this to the SPP RTO … that still creates a lot of uncertainty for EEI members, primarily because most EEI members operate in more than one RTO,” said Lopa Parikh, EEI’s senior director of federal regulatory affairs.
She noted that the commission did not address whether products such as financial transmission rights and virtual trades are subject to the CEA. “And so now to have the possibility of a number of district courts and lower-level courts opining on this decision further creates regulatory uncertainty,” Parikh said.
Administration of FTRs “would no longer be clearly linked to the underlying physical attributes of the grid, as it inevitably would be argued that FERC was divested of jurisdiction over these products due to the ‘exclusive jurisdiction’ provisions of the CEA,” the IRC said. “Such an outcome would create, for the first time, a ‘regulatory gap’ between the allocation and trading of the product itself and its use in addressing real-time congestion on the grid, a matter clearly within FERC’s jurisdiction.”
Jeff Walker (ACES)
Jeff Walker, senior vice president and chief risk officer for ACES, said there was no evidence for a “public interest determination” to add the private rights language to the SPP order.
“Nothing indicates the RTO markets … are opaque pools of interconnected financial entity transactions or instruments,” said Walker, whose company has load-serving entities in five of the seven ISOs and RTOs.
Walker described a scenario involving a generation owner that purchases hedges before taking an outage to repair tube leaks in its boiler.
“Coincidentally, local RTO prices spike,” causing losses for another market participant that held a short physical position and wasn’t expecting the spike. “What does it do? It files a Section 22 action against the generation owner for market manipulation in one of the 100 or so federal district courts.
“Section 22 does not require the plaintiff to prove that the generation owner was not acting in a prudent utility practice manner when scheduling the repair outage,” Walker said. “That is legal uncertainty.”
Separate Rulemaking?
Several witnesses said if the CFTC addresses the private rights issue, it should be done in a separate rulemaking.
“Having worked a lot on these issues in the years right after the passage of Dodd-Frank, there were times when the relations between the CFTC and the FERC were rocky. I think we’ve come into a period of relative calm more recently, which I think those in the industry have welcomed,” said Sue Kelly, president of the American Public Power Association.
“There’s no one from FERC here, so let me just say for them, this could really ruffle some feathers,” she continued. “So I think if you are going to tread into this area, you need to do so very carefully and respectfully of the two agencies’ jurisdiction and have a real full airing of this issue.”
Commissioners Appear Split
All three of the current CFTC commissioners began their terms in 2014, after the 2013 RTO exemption order.
The draft SPP order, published last May, said, “It would be highly unusual for the commission to reserve to itself the power to pursue claims for fraud and manipulation … while at the same time denying private rights of action and damages remedies for the same violations.
“Moreover, if the commission intended to take such a differentiated approach … the RTO–ISO order would have included a discussion or analysis of the reasons therefore,” it continued. “Thus, the commission did not intend to create such a limitation, and believes that the RTO–ISO order does not prevent private claims for fraud or manipulation under the act.”
Commissioner J. Christopher Giancarlo expressed concern over the private rights language in his opening statement. “Commenters have warned that permitting private suits will undermine regulatory certainty and could result in collateral attacks on the finely calibrated electricity market structure that state and federal regulators have enacted,” he said, citing a CEA Section 22 suit by Aspire Commodities and Raiden Commodities against GDF-Suez Energy North America for allegedly manipulating electricity prices in ERCOT. A district court judge dismissed the case in February 2015 based on CFTC’s exemption order, a decision upheld by the 5th Circuit of Appeals last week.
CFTC Chairman Timothy Massad
But Chairman Timothy Massad indicated less sympathy for the witnesses’ concerns over litigation to which regulators are not a party and the risk of conflicting district court rulings. “We face that every day … so I don’t think that issue is really unique here,” he said.
“We certainly want to balance the value of regulatory certainty with the need to make sure there is adequate recourse for private actors. The CEA does provide for private rights of action,” he added.
He also indicated no interest in starting a separate rulemaking on the issue, saying, “I think we have taken a lot of public comments on this in the context of the SPP order.”
Commissioner Sharon Y. Bowen was noncommittal, saying only that she wanted to hear market participants’ concerns.
Michigan Attorney General Bill Schuette is asking the U.S. Supreme Court to enforce its ruling last year and order EPA to put its Mercury and Air Toxics Standards on hold.
Schuette asked the court to issue a stay on the four-year-old mercury rule, which he said it invalidated in its Michigan v. EPA decision last year. In the decision, the court supported Michigan’s position that the mercury rule did not sufficiently consider the adverse economic impact the standard would impose. “We are simply asking the court to enforce its ruling and require the EPA to follow the law like everyone else,” Schuette wrote in a statement.
According to Schuette, the D.C. Circuit Court of Appeals “has failed to vacate the unauthorized rule, leaving it in place with the same force of law despite the Supreme Court’s rejection of it.” His office filed the request last week with Chief Justice John Roberts.
FERC Chairman Norman Bay last week said energy storage has the potential to become a “game changer” when it comes to economic benefit and system reliability. Bay said the commission will need to manage ways to bring the new technology into the nation’s grid.
“Developments in storage have the potential to bring economic and reliability benefits to consumers, perhaps even to be game changers,” he told an audience at the IHS CERAWeek conference in Houston. “Everybody recognizes costs will decline, but the question is how much and how soon.”
The federal government is due to release a new rule meant to prevent offshore wellhead blowouts such as the one that caused the 2010 Deepwater Horizon disaster in the Gulf of Mexico.
The Interior Department’s chief of staff, Tommy Beaudreau, told a Columbia University audience that a new rule has been in the works since the disaster. “We’ve been working ever since to try to develop new standards and new rules with respect to well control, both with respect to that critical piece of equipment, the blowout preventer,” he said.
Blowout preventers are designed to pinch shut well piping near the head in the event of a blowout. The Deepwater Horizon blowout preventer did not work.
Presidential contender Donald Trump last week shared a proposal if he gets elected: scrap EPA.
“Environmental protection — we waste all of this money,” he said during Thursday’s Republican debate. “We’re going to bring that back to the states. We are going to cut many of the agencies, we will balance our budget and we will be dynamic again.”
While he was short on details, such as who or what would oversee environmental policy in the absence of the agency, he said eliminating it would save $8 billion, its entire annual budget.
Lamar Alexander Calls for End to Nuclear Waste Stalemate
Alexander
Tennessee Sen. Lamar Alexander, speaking at a Senate Appropriations Subcommittee, said it is critical for the country to finally develop and execute a program to handle nuclear waste and called for the moribund Yucca Mountain project to be restarted.
“At a time when everyone wants to produce more carbon-free electricity, it makes no sense whatsoever to undermine this source of power by continuing this logjam and not opening Yucca Mountain to dispose of used nuclear fuel,” the Republican said during a subcommittee hearing on the Obama administration’s proposed budget for the Nuclear Regulatory Commission.
He said he would call for a pilot program to designate consolidated storage sites for used nuclear fuel until a permanent repository is developed.
Ole Miss Researchers Get $3M to Investigate Spent Fuel Options
The Department of Energy has awarded $3 million to finance the research of two University of Mississippi professors trying to find new ways to monitor spent nuclear fuel that is sealed up in dry-cask storage. Josh Gladden and Joe Mobley, physics professors, are working on ways to use ultrasonic and acoustic methods to monitor spent fuel.
Their methods could make it possible to ensure the fuel is properly stored, without having to open the storage containers. It is necessary to monitor both the fuel inside the casks, and the casks themselves, to make sure they are intact.
“Since quite a few of these casks are nearing the end of their engineered lifetime, the inspection requirement must be fulfilled in the next five years or so,” Gladden said.
Former NRC Commissioner Calls for Change in Reactor Licensing
Former Nuclear Regulatory Commissioner Jeffrey S. Merrifield said it is time to reconsider licensing requirements for advanced nuclear reactors, saying a new model is needed to help drive private sector development.
“Deployment of this new generation of reactors will require a new model, one that is more dynamic and capable of forming private-public partnership in support of private sector innovation,” he told attendees of a technical summit at the Oak Ridge National Laboratory.
“The current framework of U.S. government policy, legislation, regulation and requirements, research and development support, and fee-based licensing is more aligned with past development efforts,” he said. “This is particularly true of the U.S. Nuclear Regulatory Commission licensing process, which presents one of the largest risk factors confronting private developers of advanced reactors.”
The Arkansas chapter of the Sierra Club released the “2016 Arkansas Clean Air Solution,” which calls on Entergy to shut down Arkansas’ two largest power plants, Independence and White Bluff, by 2027.
Sierra Club said the plan would help the state meet federal clean air safeguards under the Regional Haze Rule. EPA is set to finalize a regional haze plan for Arkansas in August. Under the agency’s proposal, the two plants will be required to significantly reduce emissions of sulfur dioxide.
Entergy has said it plans to stop burning coal at White Bluff by 2028.
South Mississippi Electric Cooperative and Delta Electric Power Association say they are ready to begin generating electricity using a 100-kW solar system recently installed on the eastern edge of the Mississippi Delta. Atlanta-based Hannah Solar installed the 360 panels, which are situated behind Delta Electric’s offices in Greenwood, Miss.
David O’Bryan, Delta Electric’s general manager, said an official commissioning ceremony is scheduled in late March. He said customers in surveys called for more solar plants.
South Mississippi Electric is currently constructing four other similar solar plants in Mississippi, with the goal of partnering with Origis Energy USA to build a large-scale solar facility in southern Mississippi, capable of powering 10,000 homes.
PSEG Solar Source, PSEG’s merchant solar generation arm, bought a 36.3-MW solar project in Colorado from juwi Inc. The $54 million acquisition brings the company’s total solar portfolio to 16 utility-scale projects.
The PSEG Larimer Solar Energy Center is about 25 miles north of Fort Collins, Colo., and has a 25-year power purchase agreement with the Platte River Power Authority. The project was originally called the Rawhide Flats Solar facility. It was built on a 290-acre site own by PRPA. Construction is scheduled to be completed by the end of this year.
“We are delighted to be a part of an initiative that contributes to growing Colorado’s clean energy supply,” said Diana Drysdale, president of PSEG Solar Source.
Louisville Gas & Electric and Kentucky Utilities have offered a limited number of free smart meters for residential and small business customers. The new meters are linked to a website that allows customers to monitor their electricity usage in 15-minute increments. The PPL-owned utilities say the meters will allow customers to better understand their electric consumption.
The program is limited to the first 5,000 LG&E and 5,000 KU customers who enroll. The utilities said they will track participation and interest levels this year to determine if the program should be continued.
The smart meter installation program is separate from KU’s demand conservation program, which uses a device attached to central air conditioning and heat pumps to temporarily interrupt service on peak days to reduce system load.
Dairyland, Xcel Announce Plans to Double Wisconsin’s Solar
Dairyland Power Cooperative and Xcel Energy have announced plans that will add almost 22 MW of solar capacity in Wisconsin, doubling the amount of utility-scale solar generation in the state.
Dairyland is buying the output from 12 solar arrays with a combined capacity of almost 19 MW. Xcel has entered into contracts to purchase the output of solar gardens in the western part of the state for about 3 MW.
Xcel is adding solar throughout the Midwest and said it plans to have more than 250 MW of solar in Minnesota by the end of this year.
Once the biggest natural gas driller in Ohio, Chesapeake Energy no longer has any rigs operating in the state. The nation’s second-largest gas producer, which has been shedding assets and cutting costs in the face of low energy prices, announced fourth-quarter losses of $2.2 billion, compared to $639 million in profits the year before.
While many oil and gas drilling companies are scaling back, few have shown such a drastic reduction in Ohio’s Utica shale fields as Chesapeake. Two years ago, the Oklahoma City company had 64 rigs operating across the country. It now plans to operate four to seven nationwide.
Exelon Wind Turbine Collapses During Snowstorm in Michigan
A wind turbine at an Exelon wind farm in Huron County, Mich., collapsed during a snowstorm last week but caused no injuries or damage, county and company officials said.
The turbine toppled about 5 a.m. on Thursday during a period of high winds and heavy snow. The closest residence is about 2,200 feet from the fallen turbine and mast. Company officials said an investigation is underway to determine the cause.
Peter Sena, who has held a number of executive and operational positions at FirstEnergy and NextEra Energy, has been named president of PSEG Nuclear. He will report to PSEG Power President William Levis.
Sena comes to PSEG from NextEra, where he was senior vice president of operations and chief operations officer. Before that, he spent 15 years with FirstEnergy’s nuclear generation organization.
He is a U.S. Navy veteran and holds a degree in fuel science from Pennylvania State University. He has served as a member of Penn State’s Nuclear Engineering Advisory Board and currently serves on Auburn University’s advisory board.
ERCOT’s Technical Advisory Committee last week tabled a proposal to pay lost opportunity costs to generators ordered to ramp down for grid reliability, choosing instead to take advantage of extra time on the calendar and schedule a workshop on the issue.
The Board of Directors remanded the proposal (NPRR649) back to the TAC in February. It had received 56% support in a TAC roll call vote in November, short of the two-thirds threshold for approval. (See LOC Rule Sent Back to ERCOT’s Stakeholder Process.)
The TAC set March 7, 9 or 23 as possible dates for the workshop. The committee doesn’t meet again until March 31, giving it a month and a half before it must report back to the board April 12 with either a final version of NPRR649, an alternative version or reasons for rejecting it.
TAC Chair Randa Stephenson said she would prefer an early workshop, but she also wanted to ensure ERCOT staff had enough time to draft language that helps the committee develop alternative recommendations.
Kenan Ögelman, vice president of commercial operations, said the delay would give staff ample time to write a new nodal protocol revision request that would be an “option B.”
“It would be very different from the existing 649,” Ögelman said. “We would like to spend more time on option B and describe it better.”
Staff is working on what Ögelman called “attestation language” that better describes the circumstances of ramping down units in the day-ahead market.
The attestation language “needs to be broad enough to cover the multiple ways people use their units for hedging purposes,” Denton Municipal’s Lance Cunningham said.
DREAM Task Force Submits Final Report
The TAC told its Distributed Resource Energy Ancillaries Market (DREAM) Task Force to develop a matrix of “actionable, clear points” for the committee to consider at its April meeting.
ERCOT has distributed generation resources in more than 7,600 locations but its congestion revenue rights software can only handle about 600 resource nodes at a time. As a result, DG installations receive load zone pricing when injecting, regardless of their location within a load zone.
The committee was responding to the final report of the task force, which was chartered to analyze the regulatory and market framework governing distributed generation resources’ participation in ERCOT.
The report sought the TAC’s direction on eight policy questions that might be put to stakeholder votes. Ögelman told the committee ERCOT would like to merge a staff white paper with the DREAM team’s work before going through the stakeholder process.
“We would like to start working on NPRRs and other potential changes,” Ögelman said. “We would like to engage stakeholders further on an individual basis as we work through the issues.”
“I want to be clear on exactly what DREAM and ERCOT are asking TAC to do with this information, the items in the white paper and presentation,” said Diana Coleman, senior market specialist with the Texas Office of Public Utility Counsel.
ERCOT, which has a little more than 550 MW of DG, is projecting those resources will grow by 10% annually.
The task force said ERCOT lacks explicit rules for DG resources 10 MW or greater that are connected at a distribution voltage, and that intend to inject into the distribution system rather than reduce load. It also needs a more precise definition of the term “customer,” the task force said, citing “ambiguous reference[s] to distribution customer, load, etc.”
“These are rapidly growing, very flexible resources,” said Shell Energy’s Greg Thurnher, the task force chair. At 10% growth, he noted, ERCOT would essentially be adding the capacity of a nuclear unit similar to those at the South Texas Project over about seven years.
Thurnher said the wide disparity of business interests and opinions within the DREAM team “make it difficult to make further progress — absent a voting structure.”
ERCOT has DG resources in more than 7,600 locations in competitive areas. Its congestion revenue rights software can only handle about 600 resource nodes at a time.
“There are computing constraints to how large we can make this system,” Thurnher said.
“The key to the nodal market is having as much visibility into the market as possible,” Calpine’s Randy Jones said. “We need to give ERCOT the observability they have to have, and to be able to model” DG resources.
Other stakeholders said the proposed changes are an “unnecessary layer of complexity.” They also discussed optionality between load zone and nodal pricing.
“These types of resources are growing in ERCOT and will have an impact on market solutions,” Ögelman said. “The stakeholders can address the potential growth in distributed resources, and you address those by having market rules.”
Regional Haze Workshop
The committee and its Wholesale Market Subcommittee agreed to hold a workshop devoted to regional haze and reliability-must-run (RMR) services.
ERCOT staff had proposed a fall date for the workshop, after any potential litigation on EPA’s regional haze rules is settled. However, the WMS and other market participants expressed a desire to hold the workshop earlier.
“You’re not getting anything by fall from the courts,” Stephenson said.
“If [market participants] are more focused on the RMR aspects of it, we can have the workshop sooner, rather than later,” Citigroup Energy’s Eric Goff said. “If you’re talking about the regional haze aspect, that’s a lot of moving parts.”
Goff noted that EPA dismissed ERCOT’s concerns about reliability implications, saying, “If ERCOT doesn’t have enough notice on RMR operations, maybe it should change the notice of suspension requirements.
“I don’t know if they considered the kind of Pandora’s box that opens,” he said. “ERCOT could benefit from the market’s input on fleshing out the protocol language.”
Ögelman said ERCOT staff would commit to coming back to the TAC and reviewing the RMR processes, but that its answers might be different.
“ERCOT needs to bring their concerns and ideas,” Stephenson said. “The stakeholders have their concerns. Now, we need ideas and solutions.”
Ancillary Service Redesign Project
ERCOT staff is conducting an additional cost-benefit analysis on the ancillary service redesign project and should be done in time for the Protocol Revisions Subcommittee’s March meeting, ERCOT’s Kenneth Ragsdale told the TAC.
While ERCOT has been successful in complying with NERC reliability standards, its ancillary service framework, which dates back to the late 1990s, “does not adequately address ongoing changes to the ERCOT system,” nor does it anticipate those in the future, such as DG and utility-scale intermittent renewables, according to NPRR667.
“ERCOT still believes 667 has some worthy concepts in it,” Ragsdale said.
He said staff is considering phased transition plans for the NPRR, allowing it to be implemented sooner.
Reserve Discount Factor Proposal
ERCOT staff told the committee it will be recommending changes to the reserve discount factors (RDF) used in its physical response capability calculation as a result of unannounced testing conducted in 2014-15.
When temperatures are below 95 degrees, staff is suggesting a resource’s high sustained limits (HSL) should not be discounted. However, when temperatures exceed 95 degrees, HSLs would be discounted, but only by 1%, instead of the current 2%.
Manager of Operations Planning Sandip Sharma said ERCOT would recommend procuring additional responsive reserves when temperatures are above 95 degrees.
Amanda Frazier, senior director of regulatory policy at Energy Future Holdings, said her company analyzed 12 months of data and found similar results to ERCOT’s. “We did see a difference in the high hours,” she said. “But does it make sense to reduce the RDF to zero in hours not above 95?”
Calpine’s Jones questioned ERCOT’s motivation. “If you’re producing more [responsive reserves] for price formation, just say so,” he said.
Ögelman responded that the idea behind the change was “not necessarily” price formation, but the 1% discount factor.
“There’s evidence we should wait a bit, and there’s evidence we should reduce it all the way to zero,” he said. “In the proposal, it can only come down 1%. I would point to the existence of reserve discount factors as the driver for action.”
ERCOT staff will take the proposal back to the Reliability and Operations Subcommittee. According to the staff timeline, the issue will come back to the TAC in April.
NPRRs, Subcommittee Goals Approved
The TAC approved its goals and strategic objectives for 2016, along with the goals of its Commercial Operations, Reliability and Operations, and Wholesale Market subcommittees.
The committee also easily approved two NPRRs and a system change request, along with a nodal operating guide revision request it had tabled in January.
NPRR749, Option Cost for Outstanding CRRs.
NPRR750, Clarify Resource Status when Providing Fast Responding Regulation Service.
SCR787, Maintain NDCRC Data for Generator Transfer Between Resource Entities.
NOGRR143, Alignment of Nodal Operating Guiders with NERC Reliability Standard, BAL-001-TRE1.
Budget Issues
The Protocol Revisions Committee told the TAC that ERCOT has raised its internal labor rate from $65/hour to $75/hour in calculating impact-analysis cost estimates and project labor costs for staff who work on capital projects. The PRS said the old rate had been in effect for more than 10 years.
ERCOT has allocated a $400,000 contingency fund for 2016-17 market projects to ensure board-approved revision requests are not delayed. The change does not affect the system administration fee.
Leadership Posts Filled
The TAC unanimously approved the re-election of Adrianne Brandt as its vice chair. Brandt left Austin Energy for San Antonio’s CPS Energy shortly after the year began, requiring a second vote from members before she could officially take her position.
The committee also approved the Retail Market Subcommittee’s leadership (Chair Kathy Scott of CenterPoint Energy and Vice Chair Rebecca Reed Zerwas of NRG Energy) and that of its four working groups and task forces.
NEPOOL’s proposal was based on the 2014/15 winter program — which provided compensation for any unused oil or LNG remaining at the end of the winter — and added demand response.
ISO-NE’s proposal provided compensation for unused oil or LNG, but it would have also compensated nuclear, hydro, biomass and coal-fired resources and did not include DR.
Pilgrim nuclear plant (Source: Entergy)
Entergy had challenged the order, saying FERC’s stated preference for a market-based solution to mitigate winter natural gas supply constraints should have tipped the balance toward the RTO’s more fuel-neutral program.
“The record reflects that including such resources in the program would not provide any additional winter reliability benefit to the region,” the commission wrote. “While Entergy argues that additional payments to coal, nuclear and hydro resources would likely incentivize these resources to take incremental measures to ensure performance during the winter, this assertion is contradicted by substantial expert testimony supporting the NEPOOL proposal.”
FERC repeated its assertion that it prefers market-based solutions, but it said an out-of-market solution is “appropriate” until ISO-NE’s Pay-for-Performance program begins later in early 2018.
Shortly after the September order, Entergy’s Pilgrim nuclear plant in Massachusetts was removed as a capacity resource for the 2019/20 commitment period. It will be closed no later than 2019. (SeeEntergy Closing Pilgrim Nuclear Power Station.)
The Department of Energy has awarded $3 million to finance the research of two University of Mississippi professors trying to find new ways to monitor spent nuclear fuel that is sealed up in dry-cask storage. Josh Gladden and Joe Mobley, physics professors, are working on ways to use ultrasonic and acoustic methods to monitor spent fuel.
