The Federal Energy Regulatory Commission last week approved a revised definition of the bulk electric system (BES) that refines the exclusions for radial facilities and local networks.
The commission’s order (RD14-2) approved changes drafted by the North American Electric Reliability Corp. in response to FERC and industry concerns over how NERC was identifying facilities that are subject to its mandatory reliability rules.
In Orders 773 (December 2012) and 773-A (April 2013), FERC approved a new definition of BES facilities, eliminating regional discretion and establishing a “bright-line” threshold including most facilities operating at or above 100 kV. (See Seeking “Bright Line,” FERC Leaves BES Appeal Rules Unclear.)
Although the new definition supersedes the Order 773 definition in total, it will “result in minimal changes to the elements included in the bulk electric system,” FERC said.
NERC said the revised rules respond to the technical and policy concerns raised in the prior orders by adding “clarity and granularity that will allow for greater transparency and consistency in the identification of elements and facilities that make up the bulk electric system.”
The changes, effective July 1, 2014, mostly affect inclusion I4 (dispersed power producing resources) and exclusions E1 (radial systems), E3 (local networks) and E4 (reactive power devices).
In addition, there are minor clarifications to inclusions I1 (transformers), I2 (generating resources) and I5 (static or dynamic reactive power devices). No changes were made to the core definition, inclusion I3 (black start resources) or exclusion E2 (behind the meter generation). (See Bulk Electric Systems (BES) Inclusions and Exclusions.)
Exelon Corp., the American Public Power Association, the Transmission Access Policy Study Group (TAPS) and Public Utility District No. 1 of Snohomish County submitted filings supporting NERC’s revisions. APPA and Snohomish praised the new definition for its focus on core facilities that present the greatest risks of reliability failure.
FERC rejected requests from several other intervenors, including the American Wind Energy Association (AWEA) and the Electricity Consumers Resource Council (ELCON), for changes in NERC’s proposal.
AWEA and First Wind Holdings LLC had asked the commission to modify inclusion I4 to exclude individual power producing resources. The commission said the purpose of inclusion I4 is to include all forms of variable generation. “As we noted in Order No. 773, there are geographical areas that depend on these types of generation resources for the reliable operation of the interconnected transmission network,” the commission said. “… Nothing in the AWEA and First Wind pleadings have convinced us that our determinations in Order No. 773 need to be revisited.”
FERC cited a 2009 NERC report on variable generation that concluded that “[d]istributed variable generators, individually or in aggregate (e.g. small scale photovoltaic), can impact the bulk power system and need to be treated, where appropriate, in a similar manner to transmission connected variable generation.”
The commission said wind farms larger than 75 MVA can affect reliability if all of its wind turbines trip offline simultaneously after small fluctuations in voltage or frequency. “Because variable generation can impact the interconnected transmission network, we anticipate that wind plant owners whose facilities meet the inclusion I4 criteria who seek to exclude individual wind turbines from the bulk electric system through the exception process will be infrequent,” the commission wrote.
In other reliability actions last week FERC also:
Approved five standards requiring generators owners and, in some cases, transmission owners to provide verified data for certain power system planning and operational studies. The rules are intended to improve the accuracy of the studies and the coordination of protection system settings.
Proposed revisions to an existing standard on Transmission Relay Loadability and a new standard on Generator Relay Loadability designed to prevent generators from tripping offline unnecessarily during a system disturbance.
Denied rehearing of Order No. 791, which approved version 5 of the Critical Infrastructure Protection standards.
WASHINGTON – An appellate court panel last week grilled attorneys seeking to overturn FERC’s Order 1000, expressing skepticism over challenges to the agency’s jurisdiction and claims that allowing competition in transmission development will harm reliability.
The three-judge panel for the D.C. Circuit Court of Appeals was less aggressive in questioning FERC’s attorneys, interrupting them less frequently than they did in sparring with lawyers seeking to overturn the order.
“I’m having trouble understanding where this steps on your prerogatives,” Judge Nina Pillard said in response to the attorney for the Alabama Public Service Commission, who contended the order would render state transmission planning “meaningless.”
“It doesn’t require much of you,” she said earlier, in response to objections from Southern Co., citing what she called the order’s “very flexible and open-ended requirements.”
Judge Thomas B. Griffith questioned the South Carolina Public Service Authority’s contention that the commission lacked authority to allow non-incumbent transmission developers equal footing with incumbents in obtaining funding through regional cost allocation processes.
“It seems to be in the wheelhouse of [FPA section] 206,” Griffith said.
Judge Judith Ann Wilson Rogers also seemed unpersuaded by the challengers.
John L. Shepherd Jr., representing Public Service Electric and Gas, noted that Congress has resisted efforts to extend FERC’s natural gas pipeline siting and construction-approval authority to electric transmission. FERC’s removal of incumbents’ right of first refusal (ROFR), he said, was “a radical mandate that Congress did not authorize FERC to impose.”
Judge Rogers responded that nothing in the order gives FERC authority to decide what gets built or who does it.
Rogers and her colleagues frequently cited a Brattle Group report commissioned by Edison Electric Institute that estimated a need for nearly $300 billion in new transmission facilities by 2030. Brattle found that more than $180 billion in transmission would not be built due to shortcomings in pre-Order 1000 transmission planning and cost allocation rules.
Faced with such evidence, Rogers said, “I’m trying to understand why Congress would tell FERC to … sit on its hands.”
Judge Pillard agreed: “It would be, arguably, irresponsible for a regulator not to require planning in advance,” she said.
Attentive Audience
E. Barrett Prettyman Courthouse
The three-hour oral argument drew a rapt crowd of about 100 spectators — including numerous FERC officials, PJM Assistant General Counsel Pauline Foley and LS Power’s Sharon Segner — to the grand, wood-paneled courtroom at the E. Barrett Prettyman U.S. Courthouse a few blocks from the Capitol.
Order 1000, issued in July 2011, changes the process for planning and paying for new regional and interregional transmission lines. It also allows independent developers to compete with traditional utilities in building new lines.
The court is considering complaints from those who allege the commission overstepped its authority and those who say it didn’t go far enough in ensuring that transmission will be sufficient to satisfy public policy initiatives, such as state renewable portfolio standards.
The main threat to the order comes from challengers in the Southeast and West who allege the commission exceeded its authority under the Federal Power Act in requiring public utility transmission providers to participate in regional transmission planning, and eliminating incumbent transmission providers’ monopoly on building and running transmission.
The order is also being challenged for its cost allocation provisions, which require that those who benefit from new regional transmission facilities share in their costs while ensuring that the costs of interregional projects not be assigned involuntarily.
Repeated Interruptions
Harvey L. Reiter, of Stinson Leonard Street, spoke first on behalf of the Sacramento Municipal Utilities District, South Carolina Public Service Authorityand the Large Public Power Council, which are among those challenging FERC’s jurisdiction.
Reiter was repeatedly interrupted by the panel, which featured appointees from the last three administrations: Rogers (Clinton), Griffith (George W. Bush) and Pillard (Obama).
The pattern was repeated with Andrew W. Tunnell of Balch & Bingham, the Birmingham, Ala., law firm for Southern Co.
Tunnell said the order is “based on speculation” and not on any proof that the current rules are harming transmission. “If there really was a problem it would have come out in the rulemaking process.”
He cited a Department of Energy study praising the Southeast’s transmission planning.
“FERC is going to break what works … and replace it with a very bureaucratic and litigious process,” Tunnell said. “That means you’re not going to have a more efficient transmission planning process, you’re going to have less.”
Public Policy
The judges seemed to show a bit more sympathy for the arguments of the American Public Power Association and the National Rural Electric Cooperative Association (NRECA), who contend Order 1000 didn’t go far enough to protect public policy interests.
While the order requires that load serving entities (LSEs) have input into transmission planning, it “doesn’t require that their advice be heeded,” said the group’s attorney Randolph Lee Elliott, of McCarter & English.
Judge Pillard questioned FERC about the groups’ concerns. “If the parade of horribles came to pass, that’s tough luck?” she asked FERC attorney Beth G. Pacella.
Judge Griffith joined in. “Doesn’t the law require more than that they be part of the process? To meet their needs, not just talk about their needs? It’s not just process. It’s process that leads to a certain result.”
Pacella acknowledged that the order “doesn’t require that [public power] needs be met.” But, she said, parties whose needs are not met by the planning process can file a section 206 complaint to seek a FERC finding that the planning process “is no longer just and reasonable.”
Rebuttal
On rebuttal, Tunnell said FERC should have stopped in 2007, when it issued Order 890, which created a process of voluntary regional transmission planning. “FERC didn’t give voluntary transmission planning a chance,” he said. FERC began the Order 1000 rulemaking while “the ink was still wet” from Order 890 and the commission was considering Southern’s 890 compliance filing, he said.
Tunnell said Order 1000 will “undermine our vertical integration” and with it, its benefits: quicker storm restoration and economies of scale in operations and maintenance. “Transmission planning doesn’t address that,” he said.
“I think we’re all surprised to hear that,” shot back Judge Rogers.
“It’s changing the whole paradigm,” Tunnell insisted. “Transmission is a natural monopoly.”
State Jurisdiction on Planning
Luke D. Bentley IV, attorney for the Alabama Public Service Commission, led off the second of three sessions, this on cost allocation.
Bentley cited a list of state statutes governing transmission planning. FERC did not respond in their brief, “because they can’t,” Bentley said. Order 1000, he continued, would “relegate states to mere stakeholders in the planning process.”
“Yes for interstate transmission,” responded Judge Pillard. “That’s Con[stitutional] Law 101.” FERC balanced federal and state interests, she said, “in a relatively flexible way.”
FERC attorney Lona T. Perry said the commission’s order stops at the state border: “Any project that gets approved in the regional planning process that doesn’t get the requisite state approvals for construction and siting doesn’t get built,” she said.
Jonathan D. Schneider of Stinson Leonard Street, and attorney for the South Carolina Public Service Authority and the Large Public Power Council, said the case isn’t about cost allocation but “about a new funding mechanism that the commission thinks is better,” and that it would force utilities to fund independent transmission developers.
Judge Griffith, questioning FERC Attorney Robert M. Kennedy, observed, “There’s a significant difference between inducement and coercion.”
Kennedy said the commission was simply enforcing “long-standing, well established” principles that assign transmission costs to beneficiaries.
“We’re not imposing a relationship. We’re recognizing a relationship that exists” because of the physics of the transmission system, Kennedy said.
Right of First Refusal
The final session focused on the order’s reversal of previous FERC policy that allowed incumbent utilities rights of first refusal to add new transmission in their franchised territories.
Shepherd, of Skadden Arps, said the ruling unfairly gives non-incumbents the rights to cherry pick transmission projects they’d like to build without the obligation to serve all customers that public utilities face. “It’s not competition, it’s predation,” he said.
FERC’s Perry said that if ROFR prevails, independent developers would only be allowed to participate as merchants, without utilities’ ability to build cost of service projects. She said the commission found no reason to believe that transmission run by independents will be less reliable than that of incumbents.
Comic Relief
The intensity of the argument was briefly broken at the end of the three-hour session, when FERC relinquished some time on rebuttal to Patton Boggs’ Mike Engleman, attorney for LS Power, an independent transmission developer with much at stake in the ROFR battle.
Engleman’s move to the podium surprised one of the judges, who began addressing a different lawyer.
“That’s OK, much of the room doesn’t want me here,” Engleman said, prompting the courtroom to burst into laughter.
Engleman said LS Power spends tens of thousands of dollars on every project but often walks away empty-handed.
“There are rules in multiple regions that say, ‘You can’t play in our sandbox,’” Engleman said.
Shepherd had the last word, picking up on Southern’s claim that non-incumbent transmission developers pose a reliability risk.
“If these guys [attach to] your system and break it, you [the incumbent] have to fix it.”
[Editor’s Note: As a member of the FERC Office of Enforcement, the author of this story testified against Southern Co. in 2003 (docket no. ER03-713) and in 2006 publicly challenged a settlement negotiated between Southern and the commission’s chief of staff (EL05-102).]
Average locational marginal prices rose nearly 10% to $38.66 MWh in 2013, which Bowring noted was “still relatively low if you put it into historical perspective.”
The Energy Market was deemed competitive, despite the evaluation of the local market structure as not competitive “due to the highly concentrated ownership of supply in local markets created by transmission constraints.”
Fuel Source
Coal rebounded in 2013, generating 44% of PJM’s power, up 6 percentage points over 2012. Nuclear was next (34.8% of the RTO’s electricity, up 1.4 points). Gas’s share dropped to 16.3%, down 12.2% because of higher fuel prices.
Wind’s output was up 17.4%, though it still generates a relatively small amount of electricity (2%), while oil saw a 61% drop in energy production.
As far as installed capacity, coal ended the year with 75,559 MW, or 41.3% of ICAP, down 0.4% from the year before. Gas was up 0.6% over the course of the year, ending at 53,380 MW, or 29.2% of ICAP. Nuclear was even at 33,076 MW, or 18.1%.
Demand Response
DR revenue rebounded in 2013 from 2012 but was still below the more than $500 million in each of 2010 and 2011.
Congestion
Congestion costs were up 28% in 2013 to $676.9 million. Despite the increase, congestion remained less than a third of the $2.05 billion in 2008.
The 2013 PJM State of the Market was, to quote that noted economist Yogi Berra, mostly “déjà vu all over again.”
The 2012 report had called for substantial changes to the capacity market, demand response and the treatment of uplift. The 2013 report, which was unveiled by Market Monitor Joe Bowring during a press briefing Thursday in Washington, identifies shortcomings in the same areas.
The results of five of six markets — Energy, Capacity, Synchronized Reserve, Day-Ahead Scheduling Reserve and FTR Auctions — were judged competitive, as in 2012, along with the Regulation Market, which was judged not competitive for most of 2012.
Capacity Market
While the Capacity Market remains competitive, the 444-page report by Monitoring Analytics labeled the aggregate market structure and local market structure as not competitive, as in most prior years since 2007.(See sidebar, PJM 2013 by the Numbers.)
Bowring’s recommended changes for the market were no surprise either. Among them: Requiring that all resources be physical; making all demand response a year-round product subject to must-offer rules and requiring all imports be pseudo tied.
Alternatives to internal generation must be “full substitutes,” he said, not the currently “inferior products” which are suppressing capacity prices.
“If demand response is going to be in the capacity market…it should be available every hour and it should be treated as a real product. It is a real product,” said Bowring. The report calls for classifying all demand response as Economic and eliminating Limited and Extended Summer DR.
Bowring said DR providers can build such generation “substitutes” by aggregating resources into portfolios, a requirement he acknowledged would make DR more expensive.
Generation at Risk
Under current rules, Bowring said, DR and imports are suppressing capacity prices, particularly in western PJM. Add in low natural gas prices, which have caused LMPs to fall, and the result is 87 generators, totaling 14,597 MW of capacity, at risk of retirement. That is in addition to the 24,933 MW currently planning to close.
The 87 generating units — combustion turbines, coal, gas, oil and dual-fuel plants — were unable to cover avoidable costs in 2013, or didn’t clear the 2015/2016 or 2016/2017 base capacity auctions.
Although the report did not assess the viability of PJM’s existing nuclear fleet, Bowring said he was not surprised by reports that Exelon Corp. is threatening to close three of its nuclear generating stations in Illinois. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Bowring said although he lacked data to calculate the current nuclear fleet’s operating costs, no new nuclear plant could be profitable under current prices. “The net revenues are only covering 30 percent or so of costs,” he said.
At the other end of the spectrum, revenues for solar generation in the PSEG zone were double their fixed costs, due largely to state and federal subsidies.
Uplift
(Source: State of the Market 2013, Monitoring Analytics, LLC)
Energy uplift increased by $231 million or 36% in 2013. The two main culprits were reactive services, with an increase of $263.5 million, and black starts, which were up $78.2 million. Balancing and day-ahead charges dropped.
The report says PJM should increase its transparency by having operators record the reasons for dispatching out-of-merit generators and identifying the units that are receiving uplift payments.
Ten generating units — less than 1% of all units — received 38% of all uplift in 2013, but PJM confidentiality rules prohibit these units from being identified.
“All uplift payments should be public information. They are [currently] totally non-transparent,” Bowring said. “No one in the market really understands what’s going on.”
Identifying the causes of uplift and the generators receiving payments would allow competition to reduce those costs, he said.
In addition, the report says up-to congestion trades should be required to pay uplift charges like other virtual transactions.
Interchange Ramp
Bowring was adamant in his opposition to a proposal floated by PJM officials last week that would allow operators to reduce interchange ramp limits to reduce price volatility. (See Ramp Limits Cause Stir at MIC.)
“In our view, we see nothing wrong with [price] swings. It’s what happens in markets. [PJM] Operators should not be concerned with price volatility,” Bowring said.
State of the Market 2013 High Priority Recommendations
Editor’s Note: RTO Insider will have a full report on the State of the Market in our next newsletter, March 25.
Nearing the end of one of the harshest winters in its history, PJM is considering requiring cold-weather testing of generators, officials told the Operating Committee last week.
Generation Outages by Unit Type (Source: PJM Interconnection, LLC)
During the polar vortex in early January, forced outages downed as much as 20% percent of PJM’s generation, including almost one-third of combustion turbines and diesel units. Operators had to resort to demand response and a voltage reduction to keep the grid functioning. Generator failures dropped to more typical rates of 8% to 10% later in the month.
The early January failure rate was the worst PJM has experienced since 1994, according to a “frequently asked questions” report on the January cold released last week. PJM, then only consisting of the MAAC region, saw rotating blackouts for several hours during the 1994 “Deep Freeze.”
Executive Director of System Operations Mike Bryson said the high initial failure rate has officials considering rules to require winter start tests for generators. Reintroducing winter capacity tests is also under consideration, he said.
Winter testing would “give GOs the opportunity to test units that don’t ordinarily start or that are using alternative fuels,” he said. “I’m less worried about capacity.”
Among the issues that stakeholders will need to discuss are the timing of the tests and compensation for generation operators. “You don’t want to start too early because that doesn’t replicate the cold weather,” said Bryson, who suggested the checks could be conducted between Thanksgiving and the end of December. Waiting until January, he said, “sort of defeats the purpose.”
One stakeholder suggested installing heaters on units and that providing additional staffing could help reliability but added that those costs aren’t recoverable.
Although the North American Electric Reliability Corp. may eventually issue cold weather reliability standards, Bryson said PJM should move to institute its own requirements by the fall.
“I don’t want to do nothing for next year,” Bryson said.
The Commodity Futures Trading Commission has begun regular information-sharing with the Federal Energy Regulatory Commission after several years of wrangling and pressure from the Senate to make good on promises of cooperation.
The CFTC is now sending FERC its Large Trader Report on a routine basis so FERC will not have to request it case-by-case for market surveillance.
The sharing, which followed memorandums of understanding the agency heads signed in January, is a milestone in the government’s efforts to police market manipulation. But conflicts over the two agencies’ jurisdiction are still being played out in court.
As the commissions announced their initial data-sharing last week, they also announced establishment of a staff-level Interagency Surveillance and Data Analytics Working Group to coordinate the sharing “and focus on data security, data-sharing infrastructure and the use of analytical tools for regulatory purposes.”
Last month, eight senators leaned on the CFTC to make good on the sharing promised in the Jan. 2 MOUs, which were required by the 2010 Dodd-Frank law.
Sen. Dianne Feinstein (D-Calif.), who has pressed the agencies more than once for action, last week commended them for starting the “overdue” sharing. “FERC investigators have caught multiple entities manipulating California’s markets in recent years – even without access to this critical data,” she said. “I am hopeful the trading data … will allow FERC to prevent the complex and sophisticated schemes that robbed consumers and disrupted economic activity during the Western energy crisis.”
One of the January MOUs outlined a process by which the commissions would notify each other of activities that may involve overlapping jurisdiction, and when entities request authorization or exemptions that may fall in that overlap. The other MOU established processes for sharing information of mutual interest.
The eight senators who wrote to the CFTC Feb. 10 said they were impatient that no concrete action had taken place yet because of what the CFTC had said were data transfer issues.
“Considering the CFTC’s technical ability to share data with other nations and other regulators,” the senators wrote to CFTC acting Chairman Mark Wetjen, “we believe that technical barriers preventing the sharing of information with FERC — a fellow arm of the federal government — could be addressed and solved in a matter of weeks under your direction and leadership.” The trader-report sharing came a few weeks later.
The CFTC has not yet asked for access to FERC data on an ongoing basis.
Questions surrounding the exchange of information are only part of the conflict that has characterized the commissions’ relationship. FERC lost a fight to pursue a market manipulation case against Brian Hunter, of hedge fund Amaranth Advisors, when the U.S. Court of Appeals for the District of Columbia Circuit ruled the CFTC had exclusive jurisdiction over the matter.
FERC has continued to assert its jurisdiction, however, particularly in the power arena. Last year it ordered Barclays Bank PLC to pay $470 million in fines and disgorged profits for allegedly manipulating California’s power markets.
The bank challenged FERC’s authority, saying the agency lacks jurisdiction over transactions that involve futures and swaps and do not involve actual physical transmission or delivery of power.
The case is pending before the U.S. District Court for the Eastern District of California (FERC v. Barclays Bank PLC et al., Case No. 2:13-cv-02093-TLN-DAD).
Attorneys at Bracewell & Giuliani said the case’s “resolution may significantly affect the scope of FERC’s enforcement authority going forward.”
The commission seems to agree. In a filing in February, FERC said that a ruling in Barclays’ favor would “eviscerate the regulation of wholesale electricity markets contemplated” in the Federal Power Act.
Responding to concerns raised by last spring’s sabotage of a Pacific Gas and Electric substation, the Federal Energy Regulatory Commission has ordered development of reliability standards to protect the grid from physical attack.
The North American Electric Reliability Corp.’s standards, due in 90 days, do not have to require uniformity, FERC said in its order to NERC, nor are they likely to apply to the majority of facilities (RD14-6). NERC CEO Gerry Cauley and FERC commissioners Philip Moeller and John Norris warned last month that an overreaction to the threat could be expensive and counterproductive. (See FERC-NERC: Don’t Overreact to Sabotage Threat.)
Identify Critical Facilities
NERC’s standards must require owners and operators to take at least three actions. The first step is a risk assessment to determine what facilities, if damaged, could have a critical impact on grid operations.
The next steps are to evaluate potential threats and vulnerabilities to those critical facilities and then to develop and implement security plans.
FERC told NERC to include a procedure that would ensure confidential treatment of sensitive information but still allow appropriate oversight for compliance.
“The commission is not requiring NERC to adopt a specific type of risk assessment, nor is the commission requiring that a mandatory number of facilities be identified as critical facilities,” the order said. It added that FERC “expects that critical facilities generally will include, but not be limited to, critical substations and critical control centers.”
Once facilities are identified, FERC said, the standards need not dictate specific protective steps to be taken. But they “need to require that owners or operators of identified critical facilities have a plan that results in an adequate level of protection.”
FERC expects that the number of critical facilities will be relatively small. Most substations, for example, would not be deemed critical under the standards.
“We do not expect that every owner and operator of the bulk power system will have critical facilities under the reliability standard,” the commission said. “We also recognize that the industry has engaged in longstanding efforts to address the physical security of its critical facilities.”
Norris’ Concerns
Commissioner Norris issued a concurring statement expressing concerns that the expedited 90-day deadline and the commission’s ex-parte rules will inhibit the development of intelligent rules.
“I believe the order does not sufficiently justify the uniquely expedited nature of the standard development process, particularly when it will foreclose the Commission from engaging with stakeholders during that process,” Norris said.
The Electric Power Research Institute will lead an educational session on smart inverters March 31 as the Planning Committee begins work on developing standards for the devices.
The Markets and Reliability Committee approved a problem statement/issue charge on Feb. 27 directing the Planning Committee to set rules for the devices, which allow solar PV and other renewables to provide reactive power. (See Enhanced Inverters Clear MRC.)
The Planning Committee will meet twice monthly on the issue. PJM will provide a second educational session April 18.
PJM said it will change Manual 11’s rules regarding compensation for demand response despite a lack of stakeholder support.
In an unusual move, the Markets and Reliability Committee last month balked at endorsing the manual changes, which outline when Economic Demand Response qualifies for payment.
In an email to the Demand Response Subcommittee Friday, PJM’s Dave Anders cited a provision of the Operating Agreement that gives PJM the authority to make manual changes without a two-thirds member endorsement. “While PJM rarely exercises this right and responsibility, PJM has determined that this is the proper course of action in this case,” Anders wrote.
The changes were backed by only 57% of the MRC in a sector-weighted vote Feb. 27, with no End Use Customers and less than half of Other Suppliers voting in support. (See Manual Change on DR Compensation Rejected; 3 Others OK’d.)
Most Generation Owners and Transmission Owners voted in support of the changes, which specify that demand reductions are eligible for compensation only when they “are not implemented as part of normal operations.”
Load reductions “that would have occurred without PJM dispatch, or that would have occurred absent PJM energy market compensation” would be ineligible for compensation, according to the new rule.
PJM officials contend the manual changes only explained the RTO’s existing interpretation of FERC Order 745, and would not change operating practices.
But John Webster, of Icetec Energy Services, said the new language would give PJM too much latitude in determining the motives of DR participants and when they should be compensated. He said any revisions should be made through Tariff changes and subject to full stakeholder review.
“It’s kind of a national crisis,” an Oak Ridge National Laboratory scientist said about the systems vulnerable to shock from climate change. In a report for the Department of Energy to inform the third annual National Climate Assessment, the Oak Ridge author identifies vulnerabilities and challenges to energy systems, including electricity. For example, according to the report, one meter of sea level rise could prompt 4.6 million people in seven Florida counties to relocate, which would stress power infrastructure because those people account for more than 11% of power demand in the area. Before the people moved, however, the seven counties could be susceptible to hurricane-induced sweeping blackouts lasting weeks.
The report may help Public Service Electric & Gas’ case for the $3.9 billion Energy Strong program it wants authorized to shore up utility infrastructure against storms like Superstorm Sandy.
The House of Representatives voted 229-183 to block the Obama administration’s plan for power plant greenhouse gas controls. The White House has said it would veto the measure if it passed the Senate as well, which is considered unlikely. The bill, the Electricity Security and Affordability Act, would reverse the Environmental Protection Agency’s proposal for limits on GHG emissions from new power plants, proposed in January, and would bar the EPA from issuing GHG rules for existing power plants until at least six U.S. plants have achieved the carbon capture technology standards for at least a year. The measure also requires EPA to study the domestic and global impact of the proposed rules.
Meanwhile, at the IHS CERAWeek conference in Houston, EPA Administrator Gina McCarthy assured attendees that “conventional fuels like coal and natural gas are going to play a critical role in a diverse energy mix for years to come.” At the same event, American Electric Power chief Nick Akins said he was encouraged by EPA’s outreach on the issue but was skeptical about the outcome.
A bipartisan energy efficiency bill passed the House of Representatives 375-36 in action widely hailed as proof that efficiency is a value honored by both parties in the ongoing political wars. The measure’s provisions are largely voluntary or involve studies, but it could provide a platform for negotiation with the Senate if that body passes its own, much broader, energy efficiency bill. The Shaheen-Portman bill could see a Senate vote soon. The House bill calls for a study of the feasibility of improving efficiency in commercial buildings, with encouragement for owners and tenants to implement high-efficiency measures and a requirement for development of a voluntary Tenant Star program to recognize commercial-building tenants that achieve high levels of efficiency. The program would be similar to the existing Energy Star efficiency labeling program for appliances.
With support voiced from the Federal Energy Regulatory Commission, the Governors Wind Energy Coalition said it would pursue activities this year to promote construction of transmission lines that support renewable energy development. Among things the group will promote: establishing one-stop shops for transmission siting; supporting state and regional cooperation through collaboration among policymakers, utility commissions and system operators; and removing legislative barriers to siting, “such as those that don’t allow state utility commissions to consider economic, reliability, environmental and functional benefits beyond state boundaries in considering transmission siting.”
