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.
The Market Implementation Committee endorsed updates to PJM’s Regional Transmission and Energy Practices last week in support of the RTO’s new ExSchedule software and a new product designed to reduce uneconomic power flows between PJM and NYISO.
Chapter 2 of the document was revised to standardize and simplify it to accommodate the retirement of the current EES application and replacement with ExSchedule. The data requirements and data validations section was expanded to align with the new application, which PJM plans to deploy in late April.
Language also was added to reflect the new PJM-NYISO Coordinated Transaction Scheduling product.
The scheduling tool that would be used to optimize power trading between PJM and NYISO is accurate within $5/MWh more than two-thirds of the time, according to a new analysis provided to members last week.
Intermediate Term Security Constrained Economic Dispatch (IT SCED), a tool that PJM operators use to determine resource commitments, would take on a new function in screening interregional trades if its accuracy passes muster with stakeholders.
Under a new product, Coordinated Transaction Schedules, traders would be able to submit “price differential” bids that would clear when the price difference between NYISO and PJM exceed a threshold set by the bidder.
CTS, which is intended to reduce uneconomic power flows between PJM and NYISO, was conditionally approved by the Federal Energy Regulatory Commission Feb. 20. It could be implemented as soon as November if the Markets and Reliability Committee votes to endorse the accuracy of IT SCED. (See NYISO Scheduling Product Wins FERC OK.)
PJM officials told members last week that an analysis of data for the NYISO Interface found the 30-minute forecast that would be used by CTS was accurate within +/- $5 an average of 69% of the time between February and December 2013. It missed by more than $20/MWh about 11% of the time.
The tool was most accurate during the fall months and least accurate in the winter (see chart).
One stakeholder asked PJM to provide the raw data from the forecasts, saying the $5 threshold used in the RTO’s analysis was too broad to evaluate the tool. “Margins on power trades are much less than $5/MWh,” he said.
PJM began posting IT SCED’s forecasted LMPs in December for member review. It plans to begin publishing the forecasts in real time at the end of April.
An analysis by NYISO of its 15-minute forecasts found that they were within +/- $5 from 61% to 73% of the time, based on monthly averages for 2013.
Dynamic Schedule Vs. Pseudo Tie (Source: PJM Interconnection, LLC)
PJM has finalized rules for establishing dynamic transfers, which allow resources in one balancing authority to be operated as if they were in another BA. Dynamic transfers can be accomplished through pseudo ties or dynamic schedules.
The business rules, spelled out in a white paper, are a response to PJM’s proposed capacity import limits (ER14-503). External generators with pseudo ties and confirmed firm transmission could win exemptions from the limits if they also accept a must-offer requirement.
A Department of Energy-funded study concludes that PJM has the best alignment of electric and natural gas infrastructure among U.S. regions on the Eastern Interconnection.
The draft “baseline assessment” conducted for the Eastern Interconnection Planning Collaborative analyzed the electric-gas structure for PJM, TVA and four RTOs on nine measures, including tariffs, pipeline connections and storage capacity.
PJM was judged to have favorable conditions for six of the categories, with two neutral and one — pipeline/local distribution company penalties — negative. Unsurprisingly, the report found ISO New England has the most challenges.
The report noted that PJM has benefited from access to new shale gas supplies in addition to conventional producing regions in the Gulf of Mexico and the West.
Gas-Fired Capacity
The study identified 161 gas-capable power plants larger than 15 MW in PJM with an installed capacity totaling 78.7 GW (43% of PJM’s total ICAP).
New gas-fired generation is largely replacing coal plant retirements in Eastern MAAC and Southwestern MAAC, “while elsewhere in PJM continued reliance will be on mainly coal units, even taking into consideration the continued retirements of coal capacity,” the report said.
Slightly more than half of the generating capacity is located behind local distribution company citygates, with the remainder supplied by interstate pipelines.
LDCs
As elsewhere in the country, most of PJM’s generators supplied by local pipelines have interruptible service.
“The majority of gas-fired generation behind the citygate has chosen interruptible service in light of the high cost of local facility improvements to provide firm transportation service,” the study found. “Hence, the majority of gas-fired generation at the local level behind [citygates] is furnished on a non-firm basis, exposing gas-fired generation to curtailments or interruptions during cold snaps or outage contingencies.”
For those LDCs that provide firm service to generators, it is generally the lowest priority firm service. Several of the LDCs serving generation in PJM have supply or transportation rates specifically for gas-fired generation, but most do not.
Due to state regulations, LDCs in eastern PJM generally require gas-fired generators on interruptible contracts to have dual-fuel capability. Dual-fuel requirements are much less common in LDCs in western PJM and MISO, the study found.
Interstate Pipelines
Two companies, Transco and Texas Eastern, supply about half of the gas-fired capacity on interstate pipelines. In total, 13 of the 28 interstate pipelines that traverse PJM serve generation.
Sixty-four generators are supplied by interstate pipelines, including five with access to more than one provider and one that also has access to LDC gas.
Only 13 generators hold firm mainline transportation contracts in their own names, 10 of them with sufficient volumes to fuel more than half of their nameplate capacity. Most generators rely on gas marketers for supplies.
PJM, like MISO, NYISO and ISO-NE, does not require generators to hold firm transportation. “The competition inherent in electric markets, in which generators must clear based on price, may discourage the inclusion of incremental costs associated with firm transportation in bid structures, even where such costs could be recoverable under market rules,” the report said.
Next Steps
Comments on the draft — the first of four “targets” that EIPC is studying — are due March 14.
Later studies will:
Evaluate the capability of the natural gas systems to meet gas demand over the next decade (target 2);
Identify contingencies on the natural gas system that could hurt electric system reliability, and vice versa (target 3), and
Review the operational and planning issues affecting the availability of dual fuel-capable generation (target 4).
Comments on the target 2 sensitivities are due today.
EIPC will hold a stakeholder webinar March 21 to discuss the results from target 2 and begin work on target 3. A “mid-point” stakeholder meeting June 25 and 26 will discuss on-going work in targets 3 and 4.
PJM’s plan to implement new demand response rules in time for the May capacity auction is in doubt following a Federal Energy Regulatory Commission order requiring the RTO to provide more information to support its proposal.
The March 6 deficiency notice (ER14-822) shows that commission staff is taking seriously state regulators’ and curtailment service providers’ objections to changes in the speed and granularity with which DR would be deployed.
PJM has 15 days to respond to the order, which lays out 10 questions regarding the dispatch and compensation of DR. PJM had requested the commission approve the changes effective March 15.
Several of the questions focus on “Pre-Emergency” dispatch of DR and the reduction in the default response time from two hours to 30 minutes. The commission also asked about PJM’s proposal to make DR offer prices contingent on the speed of resources’ response and how that stratification compares to current rules for generators.
In addition, FERC asked PJM to explain how it will weight factors such as location and minimum notification time in deciding which resources to dispatch.
Changes Summarized
Current rules require PJM operators to provide two hours’ notice before dispatching DR. Under the proposal approved by PJM stakeholders in December, resources will be dispatchable in 30 minutes unless they can demonstrate they are physically unable to do so.
The new rules, which were backed by a 70% vote of the Members Committee Dec. 9, also would limit the Emergency DR designation to resources using back-up generators that are subject to environmental permits. Other resources will be known as Capacity DR. In addition, the minimum event duration will be reduced from two hours to one hour and the strike price will be reduced. (See Members OK DR Dispatch Rules after Late Amendments.)
Cost Concerns
In response to protests by CSPs EnergyConnect and Comverge, FERC asked PJM to defend its claim that day-of sub-zonal dispatch will “not impose prohibitive costs on demand resource providers.”
The proposal would allow PJM to call for curtailments immediately after defining a sub-zone, with most resources expected to respond within 30 minutes.
In a Feb. 4 filing, EnergyConnect and Comverge said that automated equipment needed to meet the 30-minute lead time could run “well into six figures.”
“The average size of a Demand Resources customer is less than 0.5 MW. In the upcoming 2014-15 delivery year, capacity prices are approximately $46,000/MW year, or an average of $23,000 per customer.” Thus it would take years to recover payback of those investments, the companies said.
Barriers to Entry?
The CSPs and the PJM Industrial Customer Coalition also raised equity concerns, pointing out that only about half of the RTO’s combustion turbines have start times of less than 30 minutes and that combined cycle and steam units require much longer lead times.
“Thus, overly restrictive rules that drive Demand Resources out of the market would invariably only lead to the reliance on and retention of older, less flexible, fossil fuel steam plants with hours and perhaps days of notice times required for startup,” Comverge and Energy Connect said. “It is difficult to understand how changes of this sort … could benefit the market.”
EnerNOC, in a Feb. 11 filing, said PJM’s proposed exemptions to the 30-minute start time were too narrow, calling them a “transparent attempt to erect a market barrier” to DR.
Must-Offer Requirement
Meanwhile, Market Monitor Joseph Bowring has asked FERC to impose on DR a must-offer requirement similar to that for generation resources, saying PJM’s proposal doesn’t go far enough in addressing disparities between the competing resources. Several generation-owning utilities have also called for such a requirement.
EnerNOC said a must-offer requirement is unnecessary because the new rules making most DR “pre-emergency” resources will provide PJM sufficient flexibility.
While generators’ must-offer requirement acts as a protection against withholding, EnerNOC said, DR participants don’t have an incentive to withhold. “Demand Resource participants are load, and as such do not have an interest in raising prices,” EnerNOC said.
Impact on BRA
FERC’s deficiency notice raises questions about whether the proposed changes will be implemented in time for the May 12-16 Base Residual Auction.
The proposal would mandate the 30-minute dispatch beginning delivery year 2015/16. CSPs would be able to choose among 30-, 60- and 120-minute dispatch for DY 2014/15.
All other provisions would be effective for 2014/2015.
Stakeholders reacted warily last week to a proposal that would allow PJM dispatchers to cut interchange ramp limits to reduce price volatility and uplift.
Dispatchers can limit ramp to protect reliability under current rules, but the action has been “very rarely, if ever,” taken, PJM’s Lisa Morelli told the Market Implementation Committee last week.
Short Term Solution
Morelli said that using ramp to control price volatility and uplift is one of the short-term solutions being considered by an MIC sub-group charged with finding ways to better capture operator actions in market clearing prices. The Energy and Reserve Pricing and Interchange Volatility Sub-Group has met four times since its creation by the Markets and Reliability Committee in November. (See MIC to Consider Real-Time Pricing Changes.)
The MRC asked for the implementation of initial changes in time for this summer, leaving too little time to consider any changes that require a FERC filing, lengthy stakeholder discussion or software changes, Morelli said.
The volume of interchange often increases when LMPs are high, but it is difficult to forecast. If generation or DR has already been called and cannot be cancelled, more interchange than expected creates excess reserves, which suppress energy and reserve prices and increase uplift.
During the Jan. 7 polar vortex, for example, operators forecast 5,665 MW of imports at 2 p.m. but received almost 3,000 more than that (see chart).
Scenarios
Morelli said the limits could be reduced when operators have dispatched demand response or additional internal generation in maximum generation emergency actions. Changes in ramp limits would be communicated to market participants through banner notifications in ExSchedule or other real-time communications tools, with monthly reports explaining the reasons for the adjustments.
To create “more transparency,” Morelli said the sub-group is developing guidelines for how and when operators might change the ramp limits.
Market Interference?
The proposal alarmed some members, who questioned the propriety of PJM taking actions that could impact market participants.
“It doesn’t seem that appropriate for PJM to be in the market,” said Bruce Bleiweis of DC Energy. “An RTO or ISO shouldn’t be making changes in the market that change the outcomes for participants.”
Jung Suh, of Noble Americas Energy Solutions, said he worried about “overeager use” of the tools by operators.
Another stakeholder said that although he supports efforts to reduce uplift, he is concerned that individual operators may react differently under similar situations, creating uncertainty for market participants. “Saying that the operator will figure it out is not very reassuring because we’re reformulating price formation,” he said. Such actions usually require a Tariff change, he noted.
Adam Keech, director of wholesale market operations, said PJM will draft manual changes to try to answer stakeholder concerns about how operators would exercise their discretion.
“But the expectations that we’re going to have some kind of written rule set when operating conditions are never the same … might be a little bit of a stretch,” he said. “If it’s too prescribed it’s useless … because whatever situation you’re trying to describe never shows up.”
Next Steps
PJM officials want to bring changes to a vote at the April MIC meeting to meet the summer target. “It is a fairly aggressive timeline,” Morelli said. “We do acknowledge that the best solution may be a longer term solution.”
