At the New England Energy Conference and Exposition last week, industry experts said there is no evidence that distributed generation is leading to a “death spiral” for traditional utilities.
Rigby
“We know it’s an issue; with time it could unfold very differently. But for now it’s not really affecting utility credit ratings,” said Peter Rigby, global head of Standard & Poor’s risk analytics and research.
Marone
Anthony Marone, senior vice president of customer and business services at UIL Holdings, said that despite state incentives, rooftop solar’s penetration remains small and has not impacted UIL’s business model. But continued growth will create “equity” issues, he said.
“If you have many times the penetration today, you start to create potentially isolated problems on certain circuits or feeders or certain neighborhoods,” Marone said. “If in every neighborhood there were two systems, maybe it’s no problem. But if you all of the sudden have three, now you’ve got to upsize the transformer, or [if] you have to do other things, the question becomes who pays for that? Is it the consumer who installed the generation or is it society as a whole?”
In May 2013, the Federal Energy Regulatory Commission issued Order 779 requiring the North American Electric Reliability Corp. to develop a standard to protect the grid against geomagnetic disturbances caused by solar storms. The commission said it was acting to close a “reliability gap.” (See FERC Orders Rules on Geomagnetic Disturbances.)
For stage two, FERC required NERC to determine the severity of a “benchmark” GMD event — the threshold against which covered entities would evaluate their system’s vulnerability and develop protective strategies.
What is the threat?
GMD events occur when the sun ejects charged particles that can cause changes in Earth’s magnetic fields. A solar particle can reach Earth in 17 to 96 hours.
NERC determines the severity of a GMD based on the “geoelectric field” — the electric potential measured in volts per kilometer on the earth’s surface — a reflection of the rate of change of the magnetic fields.
The geoelectric field acts as a voltage source that can cause geomagnetically induced currents (GICs) to flow on transmission lines. The magnitude of the geoelectric field is impacted by the geomagnetic latitude — the proximity to Earth’s magnetic north and south poles — and the ability of the planet’s crust to conduct electricity hundreds of kilometers down to its mantle. Local earth conductivity impacts the severity of the geoelectric fields that are formed during a GMD event; a lower earth conductivity results in higher geoelectric fields.
What is covered by the standard?
The standard would apply to planning coordinators, transmission planners, transmission owners and generation owners who own or whose planning coordinator or transmission planning area includes a transformer with a high side, wye-grounded winding connected at 200 kV or higher.
How is the benchmark event defined?
NERC proposed defining the benchmark GMD based on a one-in-100-year frequency of occurrence. Its definition is composed of four elements: (1) a reference peak geoelectric field amplitude of 8 V/km; (2) a scaling factor to account for local geomagnetic latitude; (3) a scaling factor to account for local earth conductivity; and (4) a reference geomagnetic field time series or wave shape to allow analysis of the impact on equipment.
The benchmark estimates that a one-in-100 year GMD event would cause an 8 V/km reference peak geoelectric field at Québec’s geomagnetic latitude and earth conductivity.
The 1989 solar storm that caused the collapse of the Hydro- Québec grid illustrates the potential risk. Shortly before 3 a.m. ET on March 13, 1989, a large impulse in the geomagnetic field was detected near the U.S.-Canada border. That started a series of disturbances that brought down the grid serving Montreal and the rest of Québec within about 90 seconds. The storm also caused large disturbances in the U.S., damaging some transformers severely — including one at the Salem nuclear plant in New Jersey — and nearly knocking out PJM and transmission systems from New England to the Midwest.
NERC’s standard drafting team “spatially averaged” four different station groups of data from Northern Europe, each covering a square area about 500 km wide (310 miles). The team noted that the reliability standard is designed to address wide-area effects caused by a severe GMD, such as increased volt-ampere reactive (var) absorption and voltage depressions.
“Without characterizing GMD on regional scales, statistical estimates could be weighted by local effects and suggest unduly pessimistic conditions when considering cascading failure and voltage collapse,” NERC said.
NERC used scaling factors to adjust the 8 V/km value for different geomagnetic latitudes and earth conductivities.
What is required by the proposed standard?
The proposed standard has seven requirements:
Planning coordinators and transmission planners must determine their responsibilities for maintaining models and performing studies needed to complete the GMD vulnerability assessment specified in Requirement 4.
Planning coordinators and transmission planners must maintain system models and GIC system models needed to complete the GMD vulnerability assessment.
Planning coordinators and transmission planners must have criteria for acceptable system steady state voltage limits for their systems during the benchmark GMD event.
Planning coordinators and transmission planners must conduct a GMD vulnerability assessment every 60 months based on the benchmark GMD event.
Planning coordinators and transmission planners must provide GIC flow information for use in the transformer thermal impact assessment (Requirement 6) to each transmission owner and generator owner that owns an affected transformer within the planning area.
Transmission owners and generator owners must conduct thermal impact assessments on affected transformers where the maximum effective GIC value provided in Requirement 5 is 75 amperes per phase (A/phase) or greater.
Planning coordinators and transmission planners must develop corrective action plans if the GMD vulnerability assessment concludes that the system does not meet the performance requirements.
The Federal Energy Regulatory Commission on Thursday conditionally accepted the interregional transmission planning and cost allocation proposals by ISO-NE, NYISO and PJM (ER13-1957et al), completing the commission’s initial review of all of the interregional compliance filings required under Order 1000.
FERC found that the three regions complied with its requirement that neighboring transmission planning regions propose a common interregional cost allocation method by agreeing on the use of an avoided-cost method. As permitted by Order 1000, they proposed to apply their avoided-cost allocation to all selected interregional transmission facilities, rather than having separate interregional cost allocation methods for different types of interregional projects.
FERC said the filing conformed to its requirement that interregional cost allocation methods address regional reliability and economic needs as well as transmission needs driven by public policy requirements.
The commission previously ruled that an avoided-cost method was not permissible as the sole cost allocation method for regional transmission projects because it would “not allocate costs in a manner that is at least roughly commensurate with estimated benefits because it does not adequately assess the potential benefits provided by that transmission facility.”
However, it concluded that an avoided-cost only method is permissible for interregional transmission.
“We find that the interplay between the regional transmission planning and interregional coordination requirements of Order No. 1000 address, at the interregional level, the commission’s concerns regarding use of the avoided-cost only method at the regional level,” it wrote.
The commission rejected avoided-cost-only allocation for regional projects because a regional facility that resulted in a more cost-effective transmission solution than what was included in the roll-up of local transmission plans would not be eligible for regional cost allocation if there was no transmission facility in the local transmission plans that it would displace.
In contrast, the commission said it believed “there will be regional transmission facilities identified in the regional transmission planning process that are needed to meet transmission needs driven by reliability, economic and/or public policy requirements that potential interregional transmission facilities may displace.”
The filing updated the Northeastern Protocol, which the three regions adopted in 2004 to facilitate the exchange of information and establish a committee structure for the coordination of interregional planning. The Joint ISO/RTO Planning Committee, comprised of staff representatives from the regions, will be charged with evaluating interregional transmission solutions with input from the Interregional Planning Stakeholder Advisory Committee, which is open to stakeholders.
The commission required the regions to make only minor ministerial changes in compliance filings due in 60 days.
GROTON, Conn. — Robert Ethier has a dream: A day when ISO-NE no longer needs constant stakeholder meetings to tweak its market rules.
Ethier
“We’ll know when we’ve hit on the right market design when we don’t need to make changes to accommodate the changes in the fundamentals,” Ethier, vice president of market operations for ISO-NE, said during a panel discussion at the New England Energy Conference and Exposition last week. “A good, stable, robust market design should adapt to pretty much whatever you can throw at it.”
Ethier said that although New England’s market has work to do to improve demand-side response and integrate the dispatch of wind, it has made progress over the last decade.
“The market is being driven much more by the fundamentals and by policy than by market design. … These markets are really being driven by the larger forces that are changing our economy — changes in fuel prices, changes in technology, changes in policy needs and desires. And that’s really what ought to be driving the markets. It shouldn’t be the market design that’s dominating the discussion.
“I hesitate to say this but I almost think we can see the day when the rate of change in the markets really decreases because the markets have the flexibility they need to react to whatever gets thrown at them,” he said.
GROTON, Conn. — Electric retailers have made progress in moving away from the cutthroat price competition that shaved margins, but restrictions on billing and metering and “organizational inertia” continue to be challenges, a panel told the New England Energy Conference and Exposition last week.
Cullen Hay, general manager of Direct Energy’s residential operations in the Northeast and Midwest, said his company used acquisitions to grow in the past, as it joined other electric retailers in seeking price-conscious customers even as their costs went up. Power suppliers have fewer barriers to prevent customer attrition than cable TV suppliers, telecommunication companies or banks, he said.
“We all kind of lived under the same mantra that as one customer came in the front door, one customer would walk out the back door,” he said.
Over the last three years, however, electric retailers have begun to increase their customer engagement by offering additional services such as home warranties and rooftop solar, he said. “These are not gimmicks. These are the value-added things that the telecom industry found successful when they were handed a deregulated market,” he said.
“The new wave of the industry is knowledge …. Our mission statement is getting our consumers the information they need to make really intelligent decisions. And that goes with consumption-reduction tools like [the] Nest [thermostat] and online portals that allows them to see what their consumption looks like, what their community’s consumption patterns look like” to identify inefficient appliances and make informed decisions.
“That’s the retail, residential industry in the next five years. And it’s already happening.”
Progress, Challenges in Pursuit of C&I Customers
High capacity and transmission costs in regions such as PJM and New England are leading more commercial and industrial customers to welcome companies offering to improve efficiency in return for a share of the cost savings, said Dean Musser, CEO of Tangent Energy Solutions.
“The power customers [are] out there pushing and pushing for ways to innovate. And it’s up to us in this industry to capture that innovation,” he said.
Michael Volpe, who heads SunEdison’s distributed generation business in PJM, said electric retailers could be doing better among C&I customers if not for “organizational inertia.”
“In my experience most energy buyers have a lot of technical acumen but are hesitant to pursue things that they may perceive to be risky due to the long-term nature” of the payback, he said.
The choice, he said, is “getting into the offices of the CFO and sharing how the energy opportunity set has broadened [or] giving the power [to lower-ranking employees] to promote it up” the corporate chain.
Smart Grid Unfulfilled
Musser said the industry and its customers are not getting the full benefits of the billions invested in smart meters.
Philadelphia’s PECO Energy has smart meters for every C&I customer, he said. “But the data is not available until a day later. And if you want a pulse to get the data right away, [it costs] $1,800 and it’s going to take six months.
“That little pulse is two wires coming out of the meter that will enable this … customer to have real-time data every 15 minutes so they can see their consumption and take advantage of all the new products. … But if you’re looking at it a day late that doesn’t help at all.
“Some utilities are adopting methods where there’s free pulses now to get customer adoption. But across the U.S. it’s all over the board for what it costs and how long it takes to get a pulse out of a utility meter,” he said.
Itemized Bills
Hay said limits on itemized bills also are hurting efforts to educate customers about the value of options available to them.
Hay
“Customers may not read direct mail pieces and they may not read their email. But they will look at their bill,” he said. “We are limited to the number of line items we have and the amount of information a supplier like us [can provide]. A more engaged customer is going to be interested in the whole product catalog. We have to find a way to give them that information.”
Because of those limitations, Hay said, his company would like to be the ones sending the bills instead of the distribution utility.
“We are pushing for supplier-consolidated billing with any utility in the U.S. market that will allow us to do so. We are pushing it as part of the [New York] REV program.
“It’s going to have costs associated with it, but we’re prepared to bear those costs. I believe that the impact to churn and the impact to customer attrition that comes from us not having that direct relationship will far exceed whatever cost structure we have to take on.”
The Delaware Public Service Commission on Tuesday unanimously approved Exelon’s $6.8 billion acquisition of Pepco Holdings Inc.
“There is a whole list of very positive things in this agreement,” Chairman Dallas Winslow toldThe News Journal.
The commission had delayed making its decision earlier this month when it learned that the Maryland Public Service Commission was going to make its decision soon (see below). Commission staff had argued that Maryland’s decision would be helpful, as their settlement with Exelon and Pepco contains a “most favored nation” clause, assuring that Delaware receives the same benefits as other states in the deal.
The commission has yet to make a formal order that reflects the balancing of benefits and did not say when it would do so. The approval leaves D.C. as the only holdout on a decision. The deal has been approved by the Federal Energy Regulatory Commission as well as regulators in New Jersey and in Virginia.
Maryland Approves with 3-2 Vote
The Maryland Public Service Commission voted 3-2 to approve the deal on May 15, saying Exelon’s reputation for service excellence was a deciding factor.
It conditioned the deal on higher reliability standards, $100 rate credits for residential customers and $43.2 million in energy efficiency programs in Montgomery and Prince George’s counties.
Voting in support were Chairman Kevin Hughes and Commissioners Kelly Speakes-Backman and Lawrence Brenner, who noted that Exelon ranked in the top-quartile of reliability metrics, while PHI has lagged.
“Simply put, the evidence demonstrates that Delmarva and Pepco will be better utilities because of the merger,” they said in the order released Friday, which included 46 conditions. “Exelon has demonstrated that it knows how to run electric and gas distribution companies; indeed it is nationally recognized for its standards of excellence.”
Voting against the deal were Commissioners Harold Williams and Anne Hoskins. “The merger will impose substantial competitive harm to Maryland’s electricity market by eliminating across-the fence competition, silencing PHI’s unique non-generation voice, and chilling innovation in new energy-related technologies and products,” they said in a 51-page dissent. Exelon still needs to win the approval of Delaware and D.C. to close the deal.
The approval revises certain provisions of a settlement Exelon had reached in March with Montgomery and Prince George’s, in which the corporation agreed to pay a one-time $50 rate credit to each residential customer of Pepco’s two utilities in the state, Delmarva Power & Light and Potomac Electric Power Co. (PEPCO). Exelon had also agreed to invest $57.6 million in energy efficiency. (See Exelon, Pepco Ink Deal with Md. Counties, but Critics Stand Firm.)
The commission also required Exelon to:
Develop 15 MW of solar generation by the end of 2018 — 5 MW in Montgomery County, 5 MW in Prince George’s County and 5 MW in the Delmarva service territory.
Establish a $14.4 million Green Sustainability Fund — $8.4 million for Montgomery and $6 million for Prince George’s — for the counties to fund solar, energy storage and other distributed generation projects.
Exceed Pepco’s level of charitable giving of $656,000 annually for at least 10 years.
Remain a part of PJM at least until the end of 2024.
Develop a pilot program for recreational and transportation use by residents of Pepco’s transmission right-of-ways.
Exelon and Pepco have until May 26 to accept the commission’s conditions. In a statement, Exelon CEO Chris Crane said the company was pleased with the decision and that the commission had recognized its reliability marks, but that the conditions in the order would be “challenging.”
“It poses some stringent conditions that will be difficult to fulfill, but all of us at Exelon accept the challenge and commit to proving ourselves in an expanded role in Maryland,” Crane said.
Critics Disappointed
Commissioners Williams and Hoskins dissented, echoing criticism that has been levied at Exelon throughout the proceeding.
“Maryland will lose its wires-only electric utilities, Pepco and Delmarva, which will be purchased by an energy conglomerate concerned with protecting its vast fleet of electric power plants, from which it derives most of its revenue,” they said. “Exelon’s economic interests to shield that fleet from emerging distributed energy technologies and other competitive threats are inherently misaligned with the interests of the customers of Pepco and Delmarva, who are predominantly concerned with efficient, cost-effective and reliable electric service.”
They also noted that the Green Sustainable Fund would not benefit Delmarva Power’s territory on the state’s Eastern Shore.
While Montgomery County Executive Ike Leggett had reached the county’s settlement with Exelon, the County Council unanimously passed a resolution saying the settlement didn’t go far enough to protect ratepayers and encourage renewable energy. Councilmember Roger Berliner, an energy attorney who spearheaded the resolution, said he was “deeply disappointed with the decision.”
“Exelon has a proven track record of favoring its own nuclear generation holdings over renewable technologies like solar and wind,” Berliner said. “This merger poses an unacceptable threat to both ratepayers and our environment.”
Berliner did acknowledge the beneficial conditions of the approval. He said that he has been “knocking on Pepco’s doors” to open up their rights-of-way, but the utility “stiff-armed us for years.”
The order includes a concession Berliner had sought — a Montgomery County “green bank” through which the county will use Exelon contributions to “leverage” investment in clean energy and energy-efficiency technologies.
But Berliner lamented the fact that these breakthroughs were achieved through the acquisition process, and by the level of Exelon’s commitment to renewable energy, which he said, “just didn’t go far enough.”
Environmentalists agreed.
“We are disappointed by today’s decision, which comes as a blow to the future of clean energy in Maryland,” said David Smedick of the Sierra Club. “The meager conditions added by the commission do not come close to mitigating the harms that the merger will cause to Marylanders.”
Maryland Attorney General Brian E. Frosh also blasted the order.
“Today is a bad day for consumers, and a great day for monopolies,” he said in a statement. “This merger — which the PSC approved by the slimmest of margins — would create a company controlling service to 80% of Maryland’s electric consumers, with the incentive and ability to stifle competition and suppress innovation. The harm to customers under this arrangement are obvious and substantial.”
PJM Independent Market Monitor Joe Bowring was disappointed by the ruling.
“They didn’t accept our conditions, so we didn’t think they did enough,” Bowring said. “What we would have liked was for Maryland to accept the conditions we proposed,” which the Monitor has proposed to all of the involved entities.
One to Go
Opposition to the Exelon-Pepco marriage continued to grow last week in D.C., where regulators may make a decision as soon as May 27, when the record closes.
Four D.C. Council members and more than half of the District’s 42 local advisory neighborhood commissioners — some of whom rallied on the steps of the Wilson Building Tuesday — are lobbying Mayor Muriel Bowser to take a stand against the transaction, though she doesn’t have an official role in the decision.
Councilman David Grosso submitted a May 12 letter to the D.C. PSC urging the board to reject the deal. The following day, People’s Counsel Sandra Mattavous-Frye filed a brief advising the PSC against the takeover.
“While this merger provides a wealth of benefits for Exelon and PHI’s shareholders, it exposes District of Columbia ratepayers to a number of unnecessary risks,” she said. “I am primarily concerned that Exelon has failed to commit to meeting established reliability standards, that any financial benefit to consumers will be erased with the first rate case and that the major decisions impacting the city’s electrical infrastructure will be made by executives in Chicago.
“As it regards the city, I am concerned that the success the District has achieved in the area of deploying renewables will be compromised by Exelon’s corporate philosophy that favors generation companies. Moreover, I have no confidence in Exelon’s ability to deliver on the promise of more jobs.”
A Year in the Making
The deal, announced last April as an all-cash transaction, has been more than a year in the making. If the deal is approved, it will create the Mid-Atlantic’s largest electric and gas utility.
Exelon is familiar with mergers. The company is the product of the 2000 pairing of Philadelphia’s PECO Energy and Chicago’s Commonwealth Edison. In 2012, it acquired Baltimore’s Constellation Energy.
It hasn’t always been successful in its deal making, however.
Exelon dropped a proposed merger with Public Service Enterprise Group in 2006, and had its overtures spurned by PPL in 1995 and NRG in 2009.
Exelon has said the deal will boost its customer count to almost 9.8 million from 7.8 million and increase its rate base to almost $26 billion from $19 billion.
Exelon hopes to close the deal by the end of the year.
WASHINGTON — Despite changing its meeting date to avoid threats of mass demonstrations next week, the Federal Energy Regulatory Commission couldn’t avoid another protest drama Thursday.
FERC instituted a new policy that forced all non-employees — lawyers, lobbyists, reporters and protesters — through a lengthier and more rigorous-than-normal security screening that included photographs. After receiving a paper ID badge and going through a metal detector, the known protestors were directed left, while the others went right to the escalator to the second-floor Commission Meeting Room.
When the protestors were informed they would be quarantined in a commission hearing room where they could watch video of the meeting, they began chanting “Shut FERC down!” (See video.) While organizers claimed the protesters numbered three dozen, only about 15 appeared in a video the group shot after being ejected.
Suits, not T-shirts
Among them was Ted Glick, national campaign coordinator at the Chesapeake Climate Action Network, who wore a suit rather than the red T-shirt he and other protesters had worn in previous meetings. (See Protests Continue — on Camera — at FERC.)
About 20 minutes into the meeting, as the commission was discussing a ruling on an Order 1000 compliance filing, the protesters apparently exited the hearing room. The protesters’ chants were audible — if not discernible — in the meeting room until they were escorted out of the building.
FERC Chairman Norman Bay joked, “I hope the protesters haven’t moved from pipelines to Order 1000,” prompting laughter.
But at least three protesters slipped the dragnet and were able to make brief statements before being escorted out.
PennEast Pipeline
The first two, Patty Cronheim of Hopewell Township, N.J., and Angela Switzer of Delaware Township, N.J., stood up to protest the proposed PennEast Pipeline. The 36-inch pipeline would deliver about 1 billion cubic feet of gas per day from Luzerne County, Pa., to Transco’s pipeline interconnection in Mercer County, N.J., 108 miles away.
“You’re destroying lives, you’re abusing eminent domain,” Switzer said before being led out of the meeting. “This is corporate greed over public need.”
Switzer said afterward she is concerned the pipeline, which would cross her 60-acre farm, could result in contamination of her water wells. “I live in an arsenic-rich zone and there’s a chance when they drill through the bedrock they’re going to release arsenic into my wells,” she said. “… FERC is not listening to us.”
The backers of the project — AGL Resources; NJR Pipeline Company; PSEG Power; South Jersey Industries; Spectra Energy Partners; and UGI Energy Services — are hoping for FERC approval in 2016.
A third protester, Maggie Henry, of Bessemer in Western Pennsylvania, stood up as the meeting was adjourned, shouting “In the shale plays of Pennsylvania, you are killing people!”
In a press conference afterward, Bay turned serious, reading a statement in which he criticized the repeated meeting interruptions as “disrespectful” and ineffective.
“I respect the First Amendment rights of the protesters and I want to hear their views. But there are ways to do that and there are ways not to do that,” he said. “The way not to do it is to disrupt our proceedings. In my view the disruptions are disrespectful, they violate the law [and] they can pose public security concerns. They often violate the ex parte rule. They prevent us from doing our work and it’s a turnoff. It’s ineffective and unpersuasive as a matter of advocacy.”
Bay also noted that the commission does not regulate the production of natural gas. “If someone is upset with fracking, they should probably talk to the states. If I had any advice for the protesters it would be this: tell them to reconsider what they’re doing and I would urge them to stop disrupting our meetings.”
FERC acknowledged that it had rescheduled the meeting at the recommendation of Federal Protective Services, which wanted to avoid demonstrations planned for the week of May 21-29, including the scheduled May 21 session. Beyond Extreme Energy, the organization that has been coordinating the FERC protests, had said it is hoping to attract more than 500 demonstrators to FERC during the week.
In November, about 100 climate change protesters blockaded FERC headquarters, snarling traffic on First St. N.E. About 25 were arrested.
More change is coming to the Federal Energy Regulatory Commission, as Commissioner Philip Moeller announced last week that he won’t be returning for a third term.
Patrick McCormick sits left of Sen. Lisa Murkowski during Norman Bay and Cheryl LaFleur’s confirmation hearing last year.
News of Moeller’s departure set off one of Washington’s favorite parlor games: guessing his replacement. Sources have tabbed Patrick McCormick III, chief counsel for Senate Energy and Natural Resources Committee Chairman Lisa Murkowski (R-Alaska), as the likely nominee.
Murkowski named McCormick as her chief counsel in 2013. He joined Murkowski’s staff as special counsel in April 2011 from Hunton & Williams, where he was a partner and led the firm’s regulated markets and energy infrastructure practice. Among McCormick’s law clients were Xcel Energy and coal giant Peabody Energy.
He was also registered as a lobbyist for FirstEnergy and the CCS Alliance, which promotes carbon capture and sequestration.
McCormick took a big pay cut to join the committee. He reported earning $567,000 in 2010 and $374,000 through April 15, 2011, at Hunton & Williams. His initial salary when he joined the Senate committee staff was about $81,000.
Before joining Hunton & Williams in 2005, McCormick was the managing partner for the Washington office of Balch & Bingham, longtime counsel for Southern Co.
McCormick also served as a deputy assistant general counsel for FERC, where he dealt with electric rates and corporate regulation, and in the law and governmental affairs departments of Potomac Electric Power Co. (PEPCO). He earned a Bachelor of Arts in history at Wheeling Jesuit University in 1977 and his law degree from Catholic University of America in 1984.
McCormick did not respond to a request for comment Monday.
If he is confirmed, and Murkowski has her way, McCormick could be implementing the first major energy legislation since the Energy Policy Act of 2005.
On May 7, Murkowski introduced 17 legislative proposals that she said would modernize the nation’s energy policies, improve infrastructure and speed review of natural gas pipelines on federal lands.
“America’s energy landscape has undergone a dramatic change since Congress last acted on comprehensive energy legislation. Our domestic energy supply has gone from scarce to abundant,” she said. “Our energy renaissance underscores the need to modernize America’s energy policies.”
Moeller to Remain Pending Replacement
Moeller, whose term expires June 30, said he will remain on the commission until a replacement is sworn in. A Republican, Moeller joined the panel in 2006.
“It’s been an honor and a privilege to serve on the commission every single day since I joined the commission in July 2006,” he said in a statement. “I send thanks to President Bush and President Obama for nominating me, as well as the members of the United States Senate who unanimously confirmed me to both terms.”
Moeller’s departure comes as the commission is adjusting to a new chairman, Norman Bay, who replaced Cheryl LaFleur in April. (See LaFleur Chairmanship Ending; Bay to Take Gavel.) The newest commissioner, Colette Honorable, joined the panel in December.
McCormick’s arrival could make for some interesting interpersonal dynamics on the commission given Murkowski’s cool reception to Bay’s nomination. (See GOP Remains Skeptical on Bay Nomination.)
Moeller’s departure means he won’t have a chance to become chairman if a Republican wins the White House in 2016.
Before joining the commission, he worked from 1997 through 2000 as an energy policy adviser to U.S. Sen. Slade Gorton (R-Wash.). Before joining Gorton’s staff, he was the staff coordinator for the Washington State Senate Committee on Energy, Utilities and Telecommunications. Before becoming a commissioner, he headed the D.C. office of Alliant Energy and worked in the D.C. office of Calpine.
WASHINGTON — In the 11 months since the Environmental Protection Agency proposed its Clean Power Plan, the idea that the final rule should include a reliability “safety valve” has become an article of faith among utility, state and RTO officials.
Count former state regulator Sue Tierney among the nonbelievers.
“I don’t think a reliability safety valve is needed because … we have those mechanisms in place today,” Tierney told a Bipartisan Policy Center forum Friday. “We have reliability-must-run contracts. We have ways to address voltage support. We have ways to address inertia. … We will not allow a plant to retire if it’s needed for reliability purposes.”
John Moore, NRDC
Tierney, senior advisor for the Analysis Group, and John Moore, senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project, were in the minority in cautioning against a mechanism for providing relief from the EPA’s carbon emission rule.
Indicating their support at the forum were Gerry Cauley, CEO of the North American Electric Reliability Corp.; PPL CEO William Spence; Michael Dowd, director of the Virginia Department of Environmental Quality’s air division; James W. Gardner, vice chairman of the Kentucky Public Service Commission; Craig Glazer, PJM’s vice president for federal government policy; and John Novak, the National Rural Electric Cooperative Association’s executive director for environmental issues.
Federal Energy Regulatory Commissioner Colette Honorable mostly listened and asked questions.
Jason Grumet, BPC
BPC President Jason Grumet said the forum was intended as “a constructive, messy, complicated conversation.” He opened the four-hour discussion by declaring what was out of bounds: “We are not going to debate the interim [EPA] targets. We are not going to be debating the legality of the rule. We’re not going to be debating the existential question of whether climate change exists,” he said.
Tierney began her comments by remarking that preparations for EPA’s Mercury and Air Toxics Standards also prompted apocalyptic warnings. Yet when the rule took effect April 16 — albeit, with a reliability safety valve included — the lights did not go out, she said.
“Business as usual is not assuming that the problems are going to go away,” she said. “Business as usual in this industry is making sure reliability is addressed all the time.”
Fear of Complacency
Tierney and Moore spent much of their time debating NERC’s Cauley and PJM’s Glazer.
Gerry Cauley, NERC
“One thing I’d like to challenge is assertions that because the grid and the utility industry [have] been resilient in the past and resolved all problems … [they] will continue to do so,” Cauley said. “We don’t work that way. If a power company operates on that presumption we go get ‘em and fine them a million dollars a day. Because you can’t go off into unknown areas and not have a well-planned, well-operated system.”
Glazer spoke on behalf of the ISO/RTO Council, which included a detailed reliability safety valve proposal in its comments to EPA. “If we do this right, Sue is right, we shouldn’t need the reliability safety valve. But boy it is a good thing in our view to have.”
Spence, representing the investor-owned utilities of the Edison Electric Institute, agreed. “We’re not asking for a free pass,” he said. “We’re just saying if we get ourselves into a situation where we need to do something, [EPA can provide relief from compliance]. I think that’s a reasonable ask.”
William Spence, PPL
“There will be nothing that will derail the Clean Power Plan quicker than having a reliability event,” he added. “So I would suggest [to] people who really want to see [EPA’s 30% emissions reduction] pushed across the finish line: We ought to have all the tools that we possibly can have.”
Novak said the mechanism could be needed if Virginia lost the North Anna nuclear plant. “What if for some reason [North] Anna goes down for several years — or like San Onofre in California, it goes down forever?” he asked. “Are there going to be sufficient offsets to make up for 1,000 MW or more of non-emitting generation? How long will it take to get that extra … energy?”
Dowd said he was concerned about relying on existing law and mechanisms to ensure reliability.
“The question of whether reliability trumps environment has not been established,” he said. “… The courts have not decided that.”
Undermining Markets
Tierney said the flexibility of the proposed rule — which would allow states to engage in interstate emissions trading and to lower emissions through energy efficiency, renewables and low-carbon fuels — provides ways to balance reliability and compliance.
Susan Tierney, The Analysis Group
Tierney said the IRC’s proposal could result in an “administrative nightmare” and undermine the discipline needed to develop market-based compliance programs.
“Just about every [concern] that I’m hearing about could be solved with market-based approaches,” she said. “The biggest thing that will be an impediment to the development of carbon markets would be a safety valve that creates the ability to leak carbon into the atmosphere.”
Glazer responded by quoting former Defense Secretary Donald Rumsfeld’s quote: “You go to war with the army you have, not the army you wish you had.”
“The reality is we are not going into this with a mandatory, nationwide [carbon] market,” he said. “This is not Waxman-Markey,” the cap-and-trade bill that failed to win Senate passage in 2010.
Cauley acknowledged that electricity markets are resilient. “But they’re not infallible, because they are limited by gas supply [and] by resources that do get retired.
“Do I want to bet the future of grid reliability five years from now, 10 years from now on a robust carbon market? I don’t think we’ve seen that yet and I don’t know that there’s any assurance that that will materialize,” he said.
No ‘License to Steal’
Craig Glazer, PJM, with piece of transmission tower
Glazer said the IRC’s proposal was designed with a high burden of proof and only time-limited relief to ensure it didn’t become a “license to steal.” It would require independent verification that there is a reliability problem that can’t be addressed through carbon offsets.
“If somebody can just run into the governor’s office and get a five-year, 10-year extension, this is going to be a farce,” he acknowledged.
Moore said any increased emissions resulting from such relief should be offset by reductions elsewhere.
He recalled the fight over GenOn Energy Management’s coal-fired Potomac River Generating Station outside D.C., which shut down in September 2012 under pressure from environmentalists and public officials.
“Because of the ex parte rules … I couldn’t call Joe McClellan, who was [FERC’s] reliability coordinator. We couldn’t have him at meetings. FERC became irrelevant to the process,” Glazer said. “So I implore you to find creative” alternatives.
Sitting to Glazer’s left, Commissioner Honorable nodded. “Noted,” she said.
VALLEY FORGE, Pa. — PJM provided more details last week on the April 21-22 transmission outage that resulted in the dispatch of demand response in the Erie area.
PJM’s Joe Ciabattoni told the Operating Committee that early on April 21, one of the three feeds into the Erie area, located in the PENELEC zone, was on a scheduled outage when a circuit breaker failed, taking one of the remaining paths out of service.
“That resulted in severe low voltage in a load pocket of about 200 MW,” he said. “If we had lost a third feed in the area, we would have lost that load pocket.” Ciabattoni noted at last week’s Market Implementation Committee meeting, where the matter also was discussed, that there always are voltage concerns in that area when there are planned or unplanned outages, and that an upgrade is included in next year’s Regional Transmission Expansion Plan.
When a workaround to bypass the breaker did not come to pass, PJM issued a PENELEC zone-wide voluntary call for DR to alleviate some of the voltage violations and implemented a switching solution, he said, estimating the DR available that evening at 130 MW.
“Going through the midnight period, we lost some generation in the area, which further aggravated the situation,” Ciabattoni said, so a voluntary call for DR again was made the following morning, when an estimated 73 MW was available. Because the outage occurred during a non-compliance period, all of the response was voluntary.
A sub-zonal call for DR was not made, he told the MIC, because it would have required a prior-day’s notice.
The event sparked the creation of two new closed-loop pricing interfaces in order to capture the DR dispatch in LMPs rather than in uplift — ERIE-PN, which is within the PENELEC zone, and the entire zone itself.
However, Stu Bresler, PJM vice president of market operations, told the MIC that PJM would not have let DR set prices for the full zone because the issue was isolated to the Erie area.
Black Start Service Undergoes Annual Revenue Recalculation
Black start generators are in the process of requesting changes to their annual revenue requirements, reflecting adjustments to net cost of new entry, operations and maintenance and fuel storage costs.
All combustion turbines and combined cycles, including black start units, are required to make changes to their accounting of maintenance expenses, said Thomas Hauske, senior lead engineer.
Unit owners and the Independent Market Monitor have until Thursday to agree on changes. PJM must accept or reject submitted values by May 27. The new rates take effect in June.
Curtailment service providers registered 6,700 MW of pre-emergency DR and 1,550 MW of emergency DR as of April 30. Lead times break down as follows: Quick (30 minutes), 5,600 MW; Short (60 minutes), 350 MW; and Long (120 minutes), 2,300 MW. There are 6,000 MW of Limited DR (June- September); 2,100 MW of Extended Summer (May- October); and 150 MW of Annual DR. The figures will not be finalized until May 31.
The products are always called as a group unless they are out of season or they have been called too many times and PJM wants to save some Limited DR calls for later in the summer.
PJM has automated its dispatch of DR through its emergency procedure postings.
ill lose its wires-only electric utilities, Pepco and Delmarva, which will be purchased by an energy conglomerate concerned with protecting its vast fleet of electric power plants, from which it derives most of its revenue,” they said. “Exelon’s economic interests to shield that fleet from emerging distributed energy technologies and other competitive threats are inherently misaligned with the interests of the customers of Pepco and Delmarva, who are predominantly concerned with efficient, cost-effective and reliable electric service.”
