Members who responded to a PJM survey are about equally divided over the preferred meeting site for the Markets and Reliability and Members committees.
About 39% of those responding said they thought future meetings should be held at PJM’s Conference and Training Center in Valley Forge, while 36% favored remaining at Wilmington’s Chase Center. Another 13% chose a “hybrid” with meetings split between the two venues. Two states and 62 of the RTO’s 920 members responded.
“I don’t know how [statistically] significant this is,” Old Dominion Electric Cooperative’s Ed Tatum said of the survey results during a Members Committee discussion Thursday. Pepco Holdings Inc.’s Gloria Godson agreed, saying she was unaware the poll had been conducted.
The poll was sent to the MRC and MC distribution groups. Dave Anders, PJM director of stakeholder affairs, said the respondents included most of those that regularly participate in stakeholder meetings.
For Valley Forge
CEO Terry Boston made a pitch for Valley Forge, noting its proximity to PJM staff. Ruth Ann Price, deputy Public Advocate for Delaware, responded by noting the number of PJM staffers in attendance. “Access to staff is, with all due respect, specious,” she said.
David Hastings, of Market Interconnection Consulting Services in Illinois, said he preferred Valley Forge because it had more dining options than Wilmington and thus was a better locale for evening meetings with other out-of-town members.
For Wilmington
Some other out-of-town stakeholders said they preferred the Chase Center, which is about a mile from Wilmington’s Amtrak station.
Greg Pakela of DTE Energy said he flies from Michigan to Baltimore-Washington International Airport because it is much cheaper than flying into Philadelphia. The Amtrak from BWI to Wilmington takes about an hour. “The Amtrak access is huge,” Pakela said. Valley Forge does not have easy mass transit access.
Tatum said he prefers Wilmington for the two senior committee meetings. “I think we have a better opportunity to get [members’] senior executives here,” he said. Tatum also said members should consider returning the Market Implementation, Planning and Operating committees to Wilmington, where they were conducted until the CTC was opened in 2012.
The venue question was rekindled after the MRC and MC meetings were temporarily moved to Valley Forge due to highway construction in Wilmington. (See PJM Members Split over MRC/MC Meeting Site.)
“What about D.C. or Baltimore or points south, or even Ohio?” asked Dominion’s Lisa Moerner, who is based in Richmond, Va.
Anders said the RTO had conducted meetings around its footprint several years ago. “We found we had the same people coming to the meetings when they were in Columbus or Chicago and the same people on the phone,” Anders said. “We had very little difference.”
No Decision
With the two sides far apart — one member observed there was less consensus on this subject than on capacity market rules — Members Committee Chairman Dana Horton cut off the debate. “We’ll continue the discussion next month,” he said.
Disappointed but not surprised, federal and RTO officials began assessing their options last week after an appellate court refused to reconsider a ruling voiding the Federal Energy Regulatory Commission’s jurisdiction over demand response compensation.
The D.C. Circuit Court of Appeals rejected requests by FERC, PJM and other parties for an en banc review of a May 23 ruling by a three-judge panel that overturned FERC Order 745.
The court ruled 2-1 that FERC’s order, which required PJM and other RTOs to pay demand response resources market-clearing prices, violates state ratemaking authority. (See Court Throws Out Demand Response Rule.)
FERC Chairman Cheryl LaFleur and Commissioner Philip Moeller said they were disappointed in the ruling.
“We have a variety of opinions on that across this table. Personally I was sad to see it denied because I did not want our commission to lose jurisdiction over demand response,” Moeller said at last week’s commission meeting. “While the final chapter hasn’t been written I thought it was unfortunate. It’s not the end of the world if states are the ones now that have to procure DR. It’s real money to real consumers. They will treat it responsibly.”
Commissioner Tony Clark, who supported the court’s ruling, said DR could still be used for planning in conjunction with price-responsive demand and advanced metering.
“This is now an opportunity for us to move forward,” he said. “It does not mean we should ignore demand response. Rather DR reductions can still be accounted for if they’re measurable, verifiable.”
LaFleur said she would consult with her colleagues on whether to ask the Supreme Court to review the ruling — a very long shot — as well as discussing what guidance the commission can provide the regions assuming the ruling stands.
Ex Parte Rule
PJM General Counsel Vince Duane told the Markets and Reliability Committee meeting Thursday that RTO officials cannot discuss the matter with the FERC commissioners because of ex parte rules.
Duane said PJM will issue a report in several weeks outlining potential responses to the order. “It will be more of a thought piece than a position paper or white paper,” he said.
While the ruling dealt specifically with the treatment of DR in wholesale energy markets, Duane said “I think the capacity market jurisdiction is impacted very squarely by the court opinion.
“There may be some of our rules that encroach on what really looks more like a retail activity.”
Yesterday, FirstEnergy filed an amended version of its complaint (EL14-55) seeking to eliminate the DR that cleared in May’s Base Residual Auction. Duane said, “I tend to think that’s a long shot” that FERC will undo the BRA results.
Order 745
Order 745 required PJM and other RTOs to pay DR participating in the day-ahead and real-time energy markets LMPs identical to those for generation.
FERC said it had authority for the order under sections 205 and 206 of the Federal Power Act because reducing retail consumption through DR can aid reliability and lower wholesale prices. The commission made a distinction between “price-responsive” DR, which it acknowledged was a retail product subject to state regulation, and responding to incentive payments, which it called “wholesale demand response.”
The court’s majority, ruling on a complaint by the Electric Power Supply Association, disagreed. “A reduction in consumption cannot be a ‘wholesale sale’” and thus does not come under federal jurisdiction, the court said.
Demand Response Growth Forecast Cut
A study by Greentech Media predicts that the loss of Order 745 will reduce the annual growth rate of the DR industry from 8% to 4.9% through 2023. The report predicts the $1.4 billion U.S. DR market will grow to only $2.3 billion in 2023, down from a previous forecast of $2.9 billion.
Report co-author Geoff Wyatt said DR providers will have to adapt their business models in response to the ruling. “With more policy decisions being made at the state level, the fragmentation of the demand response market will only be exacerbated,” he said.
Shares in DR market leader EnerNOC closed Friday at $18.76, down 6% for the week but virtually unchanged from where they stood before the court’s May 23 ruling.
The Federal Energy Regulatory Commission last week rejected for a second time PPL Electric Utilities’ request to be relieved from its obligation to purchase the output of an 18-MW qualifying facility (QF) in Pennsylvania.
FERC’s Sept. 18 order reiterated its October 2013 ruling that PPL had failed to prove that a planned IPS Power Engineering cogeneration facility at a beef processing plant in Souderton, Pa., would be able to sell into PJM’s markets.
In 2009, FERC ruled that PPL would no longer have to purchase capacity and energy from QFs larger than 20 MW in PJM. The order established a rebuttable presumption that facilities below 20 MW did not have “nondiscriminatory” access to PJM’s wholesale markets.
The commission’s two Republican members expressed misgivings about the 2013 ruling, issuing a concurrence in which they said the commission’s standard for rebutting the presumption for QFs below 20 MW should not be unreasonably high. Since then, however, FERC has eliminated mandatory purchase requirements for two QFs below 20 MW, both owned by a larger company, GDF Suez Energy, which does participate in wholesale markets.
Last week’s ruling also rejected a request from the Pennsylvania Public Utility Commission for clarification on how the qualifying facility mandatory purchase obligations should be applied in retail-choice states, such as Pennsylvania. The PUC sought guidance on how utilities such as PPL would comply with the obligations if they are not default suppliers and have no load to serve.
FERC dismissed the PUC’s questions as “largely broader issues beyond the scope of this proceeding.”
WASHINGTON — Natural gas industry representatives reacted coolly last week to the idea of a centralized gas trading platform, suggesting the industry could improve its service to electric generators through smaller, incremental changes.
The issue was the subject of a nearly three-hour meeting called by Federal Energy Regulatory Commissioner Phillip Moeller.
The idea of a trading platform for natural gas was proposed at an April 1 FERC technical conference by Donald Sipe, an attorney representing the American Forest and Paper Association. (See PJM May Offer Firm-Fuel Premium.)
Sipe said a trading platform would address a lack of price transparency and liquidity in the gas market by applying lessons from RTOs on matching supply and demand in real time.
Last week’s discussion was not an official FERC meeting, although Moeller did obtain a docket number (AD14-19) for receiving written comments. He was the only commissioner to attend.
PJM: Dual-Fuel Solution?
Among those who spoke was PJM Executive Vice President of Operations Mike Kormos, who recalled PJM generators’ complaints last winter about the difficulty in getting gas and the uncertainty in when they will receive it. “From a reliability perspective, that’s unacceptable to us,” Kormos said. “We can’t just roll the dice and hope somebody gets gas.” Kormos said that the answer for the electric side may be to “just forget [gas-only units] and go dual fuel.”
“Maybe it’s not the most economic solution, but if the gas side can’t be flexible enough to meet our needs, then our answer’s got to be, from a reliability perspective, that we need to go to dual fuel and something else,” he said.
Christine Tezak, managing director of ClearView Energy Partners, said no solution will be perfect. “If you’re trying to do everything at least-cost dispatch, in five-minute increments, at some point you do have to reconcile the fact that you are using a fuel that’s only moving at 23 mph. And electricity is moving at the speed of light, and there’s going to be a disconnect.”
Gas industry representatives questioned the need for a trading platform, instead calling for spending on additional pipeline capacity.
Who Pays?
“The problem we’ve got here is, who pays for what is desired?” said Don Santa, CEO of the Interstate Natural Gas Association of America. “Where is the wherewithal for those who want these capabilities, in terms of the infrastructure to support the services, to be able to pay for it?”
Bob Reilley, vice president of regulatory affairs for Shell Energy, said any trading platform should be voluntary. “I can’t object to a user putting out his needs on a public forum,” Reilley said. “On the other hand … if he doesn’t want to do so, I would still like to be able to serve him.”
Some electric industry representatives also questioned the need for a centralized trading clearinghouse.
“We don’t see the type of weekend issues or off-peak hours issues that I’ve seen discussed here,” said Jerry Yupp of Florida Power & Light. “We’re able to find the gas we need dealing directly with suppliers, not through an electric platform on the weekends.”
Moeller tried to assuage the concerns of those on the gas side who were worried that FERC would make a broad, sweeping order to change the gas market. Rather, Moeller said, he wanted both sides to reach an agreement so that FERC would not have to react to a crisis, such as the January polar vortex.
“The fact that we have a convergence of the electric industry and the natural gas industry, which is only increasing — in one sense it’s a celebration of the fact that we have plentiful domestic gas that we didn’t know we had a few years ago,” Moeller said. “It is a really good set of problems to have. It’s a chance for everyone to win.”
PJM electric consumers are spending $433 million a year in excess capacity because the RTO’s load forecasts fail to capture the full impact of energy efficiency, according to a report by The Brattle Group for a coalition of environmental organizations.
Unlike ISO-NE and NYISO, PJM’s energy forecasts do not account for all energy efficiency projected to come online during the forecast period, according to the report, which was commissioned by the Sustainable FERC Project, an initiative of the Natural Resources Defense Council and others.
Improved forecasts could reduce both environmental impacts and customer costs, the report said.
Including the missing energy efficiency would reduce PJM’s cumulative average growth rate for energy and peak demand to 0.8% from 1.1% through 2022, with a reduction in total customer costs of $433 million annually through 2017/18 and by $127 million annually beyond.
Short-run capacity reductions of $527 million annually are partially offset by $93 million in increased energy costs due to reduced reserve margins.
The projected cumulative GWh savings from new energy efficiency relative to 2013 will reach 11,213 GWh (1.3% of load) in 2017 and 27,245 GWh (3% of load) in 2022.
“In ISO New England (ISO-NE) and the New York ISO (NYISO), targeted efforts have been undertaken to capture the effects of existing and planned energy-efficiency programs that may be unaccounted for in the forecasting process,” the report said. “Such targeted efforts do not exist for the PJM Interconnection.”
PJM Capturing only Some Energy Efficiency
PJM’s current load forecast includes historical energy efficiency embedded in econometric forecasts and supply-side energy efficiency that clears in capacity auctions.
“However, this approach does not capture the existing EE that did not bid into/clear in the [auctions] or any new/incremental EE programs predicted beyond the three-year forward capacity market window,” Brattle said. “Both ISO-NE and NYISO have addressed these issues in their load-forecasting processes to account for the full effects of the EE investments and produce a more accurate load forecast.”
PJM Responds
PJM spokesman Ray Dotter said the RTO has “a solid record for including energy efficiency” in its markets and load forecasts, noting that the last Base Residual Action cleared 1,339 MW of energy efficiency.
“The reduction in the load forecast that Brattle predicts for 2017, 1.1%, is well within the margin of error expected over a three-year forecast,” Dotter said. “The annual capacity market also procures 2.5% less capacity than the load forecast indicates to allow for corrections to the expected demand closer to the actual delivery year. The ‘hold back’ provides opportunities for energy efficiency in the shorter-term auctions.”
Still, Dotter said PJM is considering improvements in the way it incorporates efficiency into its forecasts. Dotter said the RTO will begin discussing potential changes and the impact of the D.C. Circuit Court decision on demand response with stakeholders soon. (See related story, Appeals Court Snuffs Hope for FERC DR Jurisdiction.)
Study Methodology
Brattle based the study on publicly available filings for each of the 20 utility zones in PJM: utility and state integrated resource plans and demand side management filings, and Energy Information Administration Form 861.
The consultants applied their methodology to publicly available data for New England and found that it identified about half the missing energy efficiency identified by ISO-NE. “This implies that our projection approach is likely to underestimate the level of new EE that will be implemented in the forecast period. Therefore, our results are most likely on the conservative side.”
Stakeholder Criticism
The Sustainable FERC Project is a coalition of clean energy advocates and other public interest organizations “focused on breaking down federal regulatory barriers to the grid integration of renewable energy demand-side resources.”
The Brattle report provides support for stakeholders representing PJM load, who complain that the RTO’s load forecasts have been too high since at least the recession.
One of the authors of the Brattle report, Kathleen Spees, Ph.D., also helped lead the consulting firm’s review of PJM’s Variable Resource Requirement curve parameters, which Brattle performed for the RTO as part of the recent Triennial Review.
Brattle’s work on the 2014 Triennial Review did not include an analysis of PJM’s load forecasting. In its 2011 review, Brattle recommended PJM “increase the transparency and stakeholder understanding of the load forecasting process,” noting that it had been the subject of stakeholder complaints.
PJM will revise its conflict of interest policy to reflect the increasing number of consumer product companies, manufacturers and technology companies becoming involved in the electric industry.
The Federal Energy Regulatory Commission prohibits PJM staff and board members from owning stock in any “market participant,” which FERC defines as including PJM members and their affiliates. Exempt are companies that do “not have economic or commercial interests that would be significantly affected by the [RTO’s] actions or decisions.”
PJM’s proposed revisions to its Operating Agreement are based on those approved by FERC for NYISO and MISO.
PJM plans to add a new Section 10.2.1 to the OA (“Financial Interests”) similar to its current Code of Conduct. The section will include a new definition of “prohibited securities,” applicable to the stocks of PJM members, non-incumbent transmission developers, “eligible customers” — transmission owners, power marketers or others generating electricity for resale — and their affiliates.
PJM would allow employees and directors to invest in companies with a de minimis relationship to the RTO, as determined by a “no” answer to each of the following questions:
Is the company’s primary business purpose to transact in the electricity industry or is it a non-incumbent transmission developer pre-qualified to be a designated entity under PJM’s transmission planning?
Are the member’s annual PJM total financial settlements more than 0.5% of the member’s annual gross revenues?
Are the member’s annual financial settlements in PJM more than 3% of the total transactions for which PJM Settlement is a counterparty?
General Counsel Vince Duane said the changes were needed to simplify compliance and ensure the policy doesn’t create employee recruiting or retention problems.
”It’s no longer intuitive that a Google or a Microsoft is not a member,” Duane said. Google is an investor in the Atlantic Wind Connection, a proposed transmission project to serve off-shore wind generators.
From left to right: David Morenoff, Larry Gasteiger, Jamie Simler, Arnie Quinn and Norman Bay.
A senior-level retirement has given Cheryl LaFleur an opportunity to put her stamp on the Federal Energy Regulatory Commission during her brief chairmanship.
LaFleur announced last week that Michael C. McLaughlin, director of the Office of Energy Market Regulation (OEMR), is retiring Dec. 1 after 30 years at the agency. LaFleur appointed Jamie Simler, currently director of the Office of Energy Policy and Innovation (OEPI), as his successor.
Replacing Simler as head of OEPI will be Arnie Quinn, currently director of OEPI’s Division of Economic and Technical Analysis.
Last month, LaFleur promoted David Morenoff to General Counsel, where he had been serving in an acting capacity for nearly two years.
First Meeting for Bay
Last week’s meeting was the first since the Aug. 20 resignation of Commissioner John Norris and the first for Norman Bay, former director of the Office of Enforcement, as commissioner. (Bay’s deputy, Larry Gasteiger, succeeded him as acting director.)
Bay announced that two of Norris’ former aides, Laura Vendetta and Benjamin Williams, have joined Bay’s staff as confidential assistant and program analyst, respectively. Bay also introduced his three other advisors: Bob Kennedy, formerly of the Solicitor’s Office; Janel Burdick, formerly in Enforcement’s Division of Analytics and Surveillance; and Tatyana Kramskaya, a former manager in OEMR’s East Branch.
LaFleur announced that former Norris aide Andy Weinstein had joined her office as legal advisor.
Honorable’s Schedule Unclear
Meanwhile, hopes for a pre-election confirmation hearing for Colette Honorable are in doubt following the Sept. 7 death of Honorable’s husband, Rickey Earl Honorable, 46. President Obama nominated Honorable, chairman of the Arkansas Public Service Commission, to replace Norris on Aug. 28.
PJM stakeholders deadlocked Thursday over changes to the $1,000 energy offer cap, leaving the RTO’s board considering yet another unilateral filing with the Federal Energy Regulatory Commission.
None of three proposals considered by the Markets and Reliability Committee won a two-thirds majority.
The primary proposal from the Cap Review Senior Task Force (proposal B), which would have eliminated the cap for cost-based offers and let them set LMPs, won only 42% support in a sector-weighted vote of the MRC, with unanimous opposition from the Electric Distributor and End Use Customer sectors.
The proposal would have limited cost-based offers to production cost plus a 10% adder for unquantifiable costs. Market-based offers would be limited to the cost-based offer or the cap on 30-minute demand response ($1,849/MWh for delivery year 2015-16), whichever is more.
A revised version of that proposal that would maintain the cap on market-based offers also failed with 42%.
An alternative by the Delaware Public Service Commission (proposal A), which would have allowed cost-based offers above $1,000/MWh but would not have allowed them to set LMPs, also fell short at 61%. The proposal won unanimous support from the ED and EUC sectors and almost 60% of Other Suppliers, but it received less than 30% of Transmission Owners and Generation Owners. (See voting report.)
In January, FERC granted the RTO’s request for a waiver allowing make-whole payments for generators with operating costs more than $1,000. PJM said the waiver was necessary to allow some gas-fired generators to cover marginal costs that hit $1,200/MWh in late January, as spot gas prices spiked as high as $140/mmBtu. The January order allowed PJM to fund the make-whole payments through uplift charges. In February, FERC granted a second waiver eliminating the cap through March 31, allowing high-cost generators to set LMPs.
One-Sided Debate
While generators’ representatives were curiously silent before the votes, load representatives were vocal in their opposition to eliminating the offer cap, which they said was necessary to counter market power and ensure generators operate efficiently.
“Our members have a strong desire to retain the cap as it is,” said Dan Griffiths, executive director of the Consumer Advocates of PJM States.
Walter Hall of the Maryland Public Service Commission said there were only a few generators — reliant on gas supplies from constrained pipelines — that claimed costs exceeding $1,000/MWh in January. “You’re really just importing market power from the natural gas industry into the electric industry,” Hall said. “We think that’s inappropriate.”
John Farber of the Delaware PSC said there was little evidence of the need to lift the offer cap. “It’s yet to be proven that there is a boogey man in the closet,” he said.
Farber said his proposal ensured that no generator would be forced to operate at a loss while preserving the “circuit breaker” of the current cap by ensuring generators with lower costs don’t receive a windfall from higher LMPs.
Susan Bruce, representing the PJM Industrial Customer Coalition, said her group was supporting the Delaware proposal “in the spirit of compromise and in the interest of having one less [disputed] issue before FERC.”
David “Scarp” Scarpignato of Direct Energy said offers exceeding $1,000 should set LMPs. “We don’t believe actual costs should go into uplift,” he said. “It’s unhedgeable. That’s a really bad deal for a load-serving entity.”
One More Try
When the last of the three votes failed, PJM’s Adrien Ford declared the task force’s work done. Andy Ott, executive vice president for markets, indicated that PJM’s Board of Managers would consider a unilateral Section 206 filing with FERC. “We do have to move forward if the group can’t reach consensus,” he said.
But Ed Tatum of Old Dominion Electric Cooperative said stakeholders should make a last-ditch effort to reach compromise before the next Members Committee meeting Oct. 30. “We need to have a Section 205 [consensus] filing,” he pleaded.
PJM CEO Terry Boston also urged members to reach consensus. “There is a limit on how many issues we can dump on FERC between now and Dec. 1,” he said. “I don’t think FERC is going to respond kindly if we keep bringing 206 disagreements.”
The task force, which had been slated for sunsetting, will instead meet at 1 p.m. Oct. 10 to consider its options.
The Government Accountability Office expects 13% of the nation’s coal-fired generating capacity to retire between 2012 and 2025, an increase from the 2% to 12% range the GAO predicted two years ago.
At the same time, the GAO is reducing its forecasts for coal capacity receiving retrofits to meet Environmental Protection Agency emission regulations to 70 GW, down from its previous forecast of 102 GW.
About 38% of the total 42.2 GW expected to retire are in four PJM states: Ohio (14%), Pennsylvania (11%), Kentucky (7%) and West Virginia (6%), according to the GAO report released last week.
In a 2012 report, the GAO called for the EPA, the Department of Energy and the Federal Energy Regulatory Commission to develop a formal, joint process for monitoring the electric industry’s response to EPA regulations.
The new report said the agencies have taken steps to implement the recommendation, including regular joint meetings with RTO officials and other stakeholders.
The new report, requested by Alaska Sen. Lisa Murkowski, the ranking Republican on the Senate Energy and Natural Resources Committee, makes no additional recommendations.
Senate Confirms 2 for US NRC Posts
Stephen Burns
The Senate last week confirmed two nominees to the Nuclear Regulatory Commission, bringing the commission to full strength. Jeffrey Baran, aide to Rep. Henry Waxman (D-Calif.), and Stephen Burns, a former NRC general counsel, were confirmed with votes that generally fell along party lines.
Baran replaces Bill Magwood, who has accepted a position with the Paris-based Nuclear Energy Agency. He will finish Magwood’s term, which expires June 30, 2015. Burns will replace George Apostolakis, who left June 30 after the White House did not re-nominate him. Burns’ term will run through June 30, 2019.
EPA to Accept Comments on Carbon Rule Until Dec. 1
The Environmental Protection Agency has extended the comment period on its proposed carbon emission rule for 45 days to Dec. 1.
“We’ve got a number of requests from a variety of stakeholders that they would like more time,” Janet McCabe, acting assistant administrator for the Office of Air and Radiation, said in a press conference Tuesday.
The rule, which would affect existing power plants, is intended to cut carbon emissions from the power sector 30% below 2005 levels when it is fully implemented in 2030. The agency has received about 750,000 comments so far. McCabe said the expanded comment period would not affect plans to finalize the rule by June 1, 2015.
The Obama Administration last week threatened to veto a package of Republican-sponsored House bills that include expanding offshore drilling, approval of the Keystone XL pipeline and expedited approval of liquefied natural gas exports.
Republicans passed the proposals in a move to emphasize their stance against President Obama’s energy policies. But the White House said the bills “would roll back policies that support the continued growth of safe and responsible energy production in the United States” and run contrary “to the administration’s commitment to promoting safe and responsible domestic oil and gas development.”
Consumers Energy Reaches Accord with EPA and Justice Department
Michigan’s Consumers Energy will spend more than $2 billion on emissions-control upgrades at Michigan power plants as part of an agreement with the Environmental Protection Agency and the Department of Justice. The settlement comes at the end of five years of negotiations between the parties.
The EPA in 2007 and 2008 alleged that the company violated opacity regulations and operated some plants without necessary permits or that required emissions-control equipment. The company also agreed to pay a $2.75 million civil penalty.
The company also agreed to retire seven of its oldest coal-fired power plants: three units at the J.R. Whiting Generating Complex near Luna Pier; two at the B.C. Cobb Generating Plant in Muskegon; and two at the Karn/Weadock Generating Complex near Bay City, with a combined capacity of 950 MW.
The Nuclear Regulatory Commission has approved GE-Hitachi Nuclear Energy’s Economic Simplified Boiling Water Reactor design for a proposed third unit at Dominion Virginia Power’s North Anna nuclear power station. The NRC approval means that the reactor design meets safety requirements for use in the U.S.
The NRC’s OK was part of the design approval and construction permitting process for the Virginia utility. Dominion says it expects to receive necessary approvals in 2016 for North Anna 3, although it has not yet decided whether to build the unit.
The NRC’s approval brought some criticism. “No reactor is earthquake-proof, and Dominion has no business building another reactor on an active fault line,” said Glen Besa, director of the Sierra Club’s Virginia chapter. North Anna’s two 980-MW reactors were out of service for three months after a 5.8-magnitude earthquake in 2011. A comprehensive inspection concluded the plant suffered no damage.
Natural gas production in the U.S., bolstered by shale-gas drilling, continues to increase steadily. A report by Bentek Energy estimated that production increased 0.4 billion cubic feet per day from July to August. Bentek says production set a record of 69.04 billion cubic feet per day on Aug. 29, eclipsing a record set the previous month.
“The U.S. continues to break natural gas production records almost on a daily basis,” said Jack Weixel, Bentek’s director of energy analysis. August was the eighth consecutive month of production increases. Compared to August last year, natural gas production was up 6%.
Sherwood-Randall Confirmed as DOE Deputy Secretary
The Senate confirmed the appointment of Elizabeth Sherwood-Randall to the No. 2 post at the Department of Energy last week.
Sherwood-Randall was President Obama’s adviser on nuclear weapons and arms control since 2013. Before that, she was his European affairs adviser. She will replace Daniel Poneman, who stepped down as deputy secretary in June after five years.
“Liz’s confirmation comes at a historic time in our nation’s energy evolution,” Energy Secretary Ernest Moniz said. “She joins us with deep expertise in the department’s nuclear security mission, including both nuclear weapons and countering proliferation.”
A Department of Energy report that tested water wells near a natural gas drilling site that was hydraulically fractured found no evidence that fracking had contaminated groundwater. The study, released last week, found that no chemicals used in the fracking process had migrated to six test water wells at a Pennsylvania site.
Critics said the study was too small to prove that fracking is safe. They called for tighter regulation of drilling until a final determination is made.
PJM will revise its eMKT application to capture more detailed information and require generation owners to use it to verify their operating parameters under a proposal outlined to members last week.
Generation owners will be required to ensure all data in eMKT is accurate, particularly notification times, minimum run times, unit status and unit limits (emergency and economic min & max).
PJM will also require owners to make all updates in eMKT, and operators will use only that data for unit commitment decisions. Verbal notifications will be permitted only if previous unit commitments cannot be met or a unit trips or encounters other problems in real time.
“We want to get away from all the phone calls and changing information in real time,” said PJM’s Chantal Hendrzak, who presented the proposal to the Markets and Reliability Committee Thursday. “We want to be able to pull that information out of eMKT.”
Among the additional information that PJM will be requiring are details on units’ dual-fuel capabilities (e.g., time to transition, megawatt output during transition) and operational restrictions (e.g., emissions limits).
Generators would also be able to update their energy offers and cost-based start-up and no-load costs during the operating day to reflect gas-price volatility.
The proposed changes are expected to be brought to an Operating Committee vote next month.
Members who responded to a PJM survey are about equally divided over the preferred meeting site for the Markets and Reliability and Members committees.
