PJM Chief Financial Officer Suzanne Daugherty briefed the Members Committee webinar on the spending plan last week.
Daugherty said PJM plans to add five staffers to its current workforce of 665.
PJM’s composite expense rate continues to be below the 2006 stated rate settlement projections, Daugherty noted.
The operating budget is in addition to a proposed $30 million in capital spending, down $2 million from 2013. (See PJM Plans $30M Capital Spend for 2014)
The Board of Managers is expected to consider the spending plan at a meeting tomorrow.
Thursday’s FERC technical conference on capacity markets elicited sharply differing views on a variety of design concepts and technical issues. Some of the disagreements have been around since the beginning of capacity markets, others are reflecting the influence of new technologies.
Below is a summary of some of the key issues.
Forward Period & Commitment Period
Having divested virtually all of its generation, and not wanting to sign long-term purchase power agreements, Consolidated Edison Co. relies on the capacity market, said Richard Miller, director of energy markets policy. The company’s service territory straddles the New York border with New Jersey and Pennsylvania, giving it experience with both NYISO and PJM.
Miller noted that PJM, which purchases capacity three years in advance, has attracted more than 4,000 MW of new generation in each of the last two auctions (more than 3.5% of the forecast peak), while the NYISO, which has a 6-month forward, has added less than 675 MW (1.7%).
Although PJM primarily acquires capacity for a one-year commitment period, some new resources can lock-in prices for three years.
But Analyst Julien Dumoulin-Smith, of UBS Investment Research said even three years is a “mismatch” with the long life of new generation, noting that California is “trending to a 10-year market.”
Todd Snitchler, chairman of the Public Utilities Commission of Ohio, said bankers told his agency “Five to seven years [commitment] … would make it much more economical to get new generation.”
Robert Erwin, general counsel of the Maryland Public Service Commission, said the short commitment period exacerbates’ bankers concern over the volatility of capacity prices. Bankers have told the PSC: “There’s no way I’m going to lend money on that kind of price signal – and certainly not for one year [of guaranteed revenue].”
Demand Response vs. ‘Steel in the Ground’
The role of demand response was another issue that sparked much discussion.
“It is simply not the case that 1 MW of Demand Response provides the same reliability contribution to the grid as 1 MW of steel in the ground,” said Shahid Malik, president of PSEG Energy Resources and Trade.
James Holodak, vice president of regulatory strategy and integrated analytics for National Grid USA, agreed, bemoaning demand response, which is not subject to must-offer rules, “jumping in and out of the market.”
Andy Ott, PJM executive vice president for markets, said PJM is seeking to treat demand response more as an operational resource reflecting differences in physical characteristics, as is the case with generators. He noted that most of the 14,000 MW of demand response that cleared in the most recent base auction gets two-hour notice and an identical price. “We can’t sustain that,” he said. “We really need to have more diversity.”
“Iron in the ground is worthless,” said Peter Cramton, professor of economics at the University of Maryland. “What consumers should be buying is energy in shortage situations.” He called for an ex-post grading of resources — a “second settlement” — with good performers receiving bonuses and penalties for poor performers.
Dan Curran, market strategist with demand response aggregator EnerNOC, said the “downstream” focus on demand response “is treating the symptom and not the cause.” He said it was more appropriate to set qualifications for participation in DR, as PJM is considering.
Tranches
The commission asked the panelists for their opinion on creating “tranches” of capacity products based on operational characteristics such as fast-ramping or load-following ability given the increase in variable and intermittent resources.
Michael Hogan, of the Regulatory Assistance Project, is a supporter, saying tranches would create a fairer and more efficient market. “We’ve had ObamaCare in energy for years…,” he said. “People are paying for insurance they don’t need for a service they don’t really consume.”
But Cramton called the idea “a nightmare” that would lead to “rent-seeking.”
Sue Kelly, general counsel of the American Public Power Association, also said she feared that tranches would lead to gaming. “There’s always an extremely enterprising financial player who will find a way to arbitrage,” she said.
Consultant James Wilson urged a “purist” view: “Stay focused on the peak day… rather than [making] it more complicated through ramping … or tranches.”
The Markets and Reliability Committee heard first reading last week on the following manual changes. Members will be asked to endorse the changes at the MRC’s next meeting.
WASHINGTON — Some came to praise PJM’s Reliability Pricing Model. Others said they’d like to bury it.
Six years after RPM’s inception, the Federal Energy Regulatory Commission convened a technical conference last week to ask the question: How’s the capacity market working for you?
The commission said it was time for a broad look at the strengths and weaknesses of PJM’s model and those launched later in ISO New England and NYISO and how the markets should evolve in the future. Commissioner Tony Clark likened the session to a “checkup.”
The day-long session, which featured 26 panelists and attracted an overflow crowd of hundreds, was the prelude for a potential FERC rulemaking. (The speakers’ written testimony is available in FERC’s eLibrary under Docket # AD13-7.)
PJM Represents `Best Practices’
Capacity Clearing Prices – Delivery Years 2006-2017 (Source: FERC)
The consensus among the speakers was that PJM’s market deserved the highest marks. “PJM does represent the vast majority of best practices here,” said securities analyst Julien Dumoulin-Smith of UBS Investment Research. Lee Davis, who heads NRG Energy’s operations in the three eastern regions, said his company is investing “hundreds of millions” to upgrade 600 MW of generation in PJM because of its confidence in the RTO. In contrast, he said, the company is retiring capacity in New England because of the instability in the region’s market rules. “We look at risk just as highly as we look at revenues,” he said.
Changes Needed
That’s not to say PJM’s model couldn’t use improvement, even its supporters acknowledged.
Andy Ott, PJM executive vice president for markets, cited concerns about the volume of imports that cleared in this year’s auction (see PJM Likely to Limit Capacity Imports)and said PJM needs to address the “asymmetry” between the base capacity auction and the incremental auctions (see PJM Seeks to Curb Capacity Auction Speculation). He also cited price volatility in western PJM due to MISO’s “inadequate construct.”
Compromises Weaken Model
Consultant Roy Shanker said “FERC got it right” in setting capacity market rules but that compromises have eroded the construct. He cited PJM’s short-term resource procurement — which removes 2.5% of the reliability requirement from the demand curve — as “blatant price discrimination.”
There also was debate about the optimal forward and commitment periods, the role of demand response, the wisdom of creating “tranches” to reflect differences in resource capabilities and how capacity can accommodate the growing role of variable resources and new technologies such as storage. (See sidebar, Old Issues, New Technologies in Capacity Debate)
States, Public Power Bash MOPR
The central debate, however, was a crossfire between those who contend capacity prices are too high and those who say they are too low.
State and public power representatives said the markets interfere with state policies and have failed to attract competitively-priced new generation.
“A capacity market that does not recognize new capacity developed pursuant to the requirements of state statutes and regulations … cannot endure,” said Jeffrey Bentz, of the New England States Committee on Electricity.
Reality on the Ground
James Jablonski, representing the Public Power Association of New Jersey, said PJM’s capacity market rules don’t recognize “the reality on the ground.”
Despite capacity prices of $245 per MW Day in PSEG North, Jablonski said, no generation is being built because of the difficulty siting in the densely-populated state. “There’s no point in having … customers paying for something that doesn’t have a way of getting built.”
Ed Tatum, vice president of RTO and regulatory affairs for Old Dominion Electric Cooperative, said PJM’s rules to curb buyer-side market power are unnecessary. “I would like us to stop looking behind every tree for the boogeyman of monopsony power,” he said. “You have to think about intent [to exercise market power]. You have to think about incentives. You have to think about ability.”
He noted that PJM’s minimum price floor for generation sponsored by public power — the net Cost of New Entry (CONE) — has almost doubled since it was instituted.
Jablonski urged a return to the self-supply provisions in the 2006 RPM settlement. “We don’t bother you, you don’t bother us…We know we can build for less than [net CONE] so it makes no sense to buy from the capacity market.”
Generation Owners Cry Foul
Representatives of generation owners, however, said capacity prices are too low, due in part to state-subsidized generation projects in Maryland and New Jersey. Shahid Malik, president of PSEG Energy Resources and Trade, said his company decided against building a merchant generator because of concerns it would be undercut by a subsidized competitor.
William Massey, now counsel to COMPETE, a coalition of generators and others, said Maryland’s “contract for differences” with Competitive Power Ventures’ 725 MW St. Charles generating plant “skews the capacity market in a way that this commission should not allow.”
“That’s just not true,” Robert Erwin, general counsel of the Maryland Public Service Commission, shot back. He said Maryland’s initiative “irons out” volatility. “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.”
Commissioner LaFleur asked if the impact of state programs such as Maryland isn’t the same in reducing prices, even if it is not the state’s intent.
Erwin conceded its new generation could depress prices. “But it’s no different than a state that says we’re going to have emission limits on power plants,” which would have the opposite effect, he said.
Capacity Market Not Voluntary
Susan Kelly, general counsel of the American Public Power Association, parried with Commission Chairman Jon Wellinghoff, who said APPA’s members were not required to join RTOs and thus participate in capacity markets. “It’s not a legal requirement,” Wellinghoff said.
Kelly responded: “If you have to take transmission service from the organization it’s kind of silly not to be a member… no system can be an island.”
FERC’s Next Step
Some panelists said they hoped the conference would be a prelude to a future rulemaking.
Consultant Susan Tierney called for a policy statement — “a visioning thing” — on the role of capacity markets in the future.
Richard Miller, director of the energy markets policy at Consolidated Edison Co. called on the commission to impose “some minimum level of standardization.”
Others said the role of the capacity market should shrink to its initial concept — a “residual” role that supplements bilateral contracts and self-supply.
“The mother of all rulemakings – Standard Capacity Market Design – scares me,” said Kelly.
“I guarantee that’s not what it would be called,” responded LaFleur, prompting laughter from the audience.
LaFleur added: “There is not a `thing’ to be named. We have to distill what we learned.”
The following issues were approved by the Markets and Reliability and Members committees Thursday with little discussion. Each item is listed by agenda number, followed by a summary of the issue and links to prior coverage in RTO Insider.
Markets and Reliability Committee
2. PJM MANUALS
Members endorsed manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.
Members endorsed changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.
3. COORDINATED TRANSACTION SCHEDULING
Members approved a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.
The Market Implementation Committee on Sept. 11 approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based.
The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.
The committee approved a proposal introduced by Dave Pratzon, of GT Power Group, (Package B) after the Operating Committee selected it over a proposal from PJM and the Market Monitor (Package A).
Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.
Members approved new rules to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.
The MRC selected Alternative 2 under which state estimator data would be used to interpolate output for each five-minute period with curtailments.
6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS
Members approved two proposals to streamline the demand response registration process.
Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.
The MRC approved the following changes:
Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.
The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.
7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) CHARTER
Members approved the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.
PJM said the changes were needed to reduce growing uplift costs resulting from Operating Reserves, “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss.
Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal approved by the MC.
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.
Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes endorsed by the MC.
The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.
A proposal to allow intra-year switching to nodal pricing failed at the Members Committee Thursday, falling just short of the two-thirds vote needed for approval.
The proposal by retail marketer Direct Energy, which would have allowed a limited number of such switches monthly, was opposed by members who said it would create administrative problems for electric distribution companies (EDCs) and potential losses for Financial Transmission Rights holders. The sector-weighted vote was 3.3 in favor and 1.7 against, short of the 3.34 total needed for passage.
David Scarpignato, head of PJM regulatory affairs for Direct Energy, said the changes would allow retail marketers to offer more innovative products. He said it would not have significant impact on EDCs or other market participants because it would cap switches at to 5% of the EDC network service peak load.
The Members Committee in 2005 unanimously endorsed a Tariff change allowing the switch to nodal pricing. But after more than seven years under the new rules, all but 15% of PJM load is still using zonal pricing.
The rules give customers one chance a year to switch to nodal pricing, effective June 1 in alignment with the planning year. Customers must provide notice of their intention to switch by October or January depending on type of service.
Scarpignato said the annual window for switching has limited retail marketers’ ability to provide innovative products such as price responsive demand, which he said is most attractive to those with nodal pricing.
The current rules mean it can take a customer up to 17 months to make the switch after deciding to do so — “major barrier” to adoption, Scarpignato said.
Scarpignato said the change would also help reduce congestion costs across PJM and assist PJM operations, which has said it would like more “granular” dispatch of demand response resources. Under the current zonal dispatch, Scarpignato said, “some of the DR in that zone is actually hurting” PJM’s attempts to relieve constraints.
Scarpignato’s argument won support from representatives for Old Dominion Electric Cooperative and Dominion, as well as from Howard Haas of Monitoring Analytics, PJM’s independent Market Monitor. “Nodal pricing is the way to go,” Haas said. “Unequivocally it is the way to go.”
Representatives from Exelon Corp. and Pepco Holdings spoke in opposition.
Jason Barker, of Exelon, said his company saw little “utility” to allowing intra-year switching and significant financial risk to the remaining zonal customers, who could see their costs increase.
“As the operator of three EDCs we do see substantial downside,” he said. “We’re disappointed that it’s come before the Members Committee after being roundly defeated at the MIC.”
Gloria Godson, of Pepco, said the change would be a “significant burden” on EDCs. “We will have to add additional staff to manage this.”
Scarpignato said the intra-year switches would have minimal financial impact on FTR holders and others in the zone. He said new customers connect to the grid year-round without major impacts.
In answer to a question from Godson, PJM’s Tom Zadlo said the change could impact FTRS. “It is potentially possible that there are some impacts on FTRs but it’s impossible to quantify.” The impact would depend on the size of the loads that switched, he said.
Marji Philips, representing Hess Corp., said economists’ preference for nodal pricing is similar to their support for energy–only markets in lieu of a capacity market. “It’s good in theory. As a practical reality it stinks.”
Philips said that PJM’s hedging tools are based on zones and hubs. If many customers switch to nodal pricing in mid-year, she said, it could create “ghettos” where customers will have to pay more of a risk premium because suppliers can’t hedge their loads.
Fourteen of 16 public power members voting supported the change along with three-quarters of 20 other suppliers and all eight end use customers. Transmission companies voted 7-2 against while generation owners split 5-5.
Scarpignato said after the meeting that his company was not giving up. “It was an extremely close vote,” he said. “We’re considering our options.”
The volume of data generated by the smart grid threatens to drown utilities, who have yet to figure out what to do with the information or how to store it, according to industry experts. “It’s generating terabytes of data,” said a representative of the Electric Power Research Institute at a panel discussion at the Illinois Institute of Technology.
NorthWestern Energy will buy 11 hydroelectric plants from PPL Montana – the same power-producing dams that NorthWestern’s predecessor, Montana Power Co., sold in the wake of deregulation almost 15 years ago. NorthWestern said it agreed to buy the 11 dams along five separate Montana rivers for $900 million, subject to approval by state and federal regulators.
FirstEnergy Corp. plans to spend several hundred million dollars to replace the steam generator and reactor vessel head at its Beaver Valley Unit 2 reactor, in Pennsylvania, in 2017. It also plans to replace the two steam generators at its Davis-Besse plant in Ohio in February during a longer-than-normal refueling outage.
Pepco Holdings Inc. named former Dayton Power and Light Co. CEO Paul M. Barbas to its board of directors. Barbas is also a former chief operating officer of Chesapeake Utilities Corp. and executive vice president of Allegheny Power.
Members agreed Thursday to consider new rules to allow batteries, flywheels and other advanced storage technologies to bid in the capacity market.
The Market and Reliability Committee approved a problem statement and issue charge with only two no votes despite some wariness from some members.
The proposal was sponsored by Demansys Energy LLC, which aggregates commercial and industrial customers for participation in the regulation market.
Janette Kessler Dudley, vice president of business development and regulatory affairs, noted that PJM currently has no rules allowing batteries or other advanced storage resources to participate in the Reliability Pricing Model. “What my company is interested in is parity,” she said.
Steve Lieberman, of Old Dominion Electric Cooperative, said he was not convinced storage is compatible with other capacity resources.
He said the issue should receive a lower priority than those currently before the Capacity Senior Task Force. “We should proceed carefully as far as expectations go,” he said.
Members ultimately decided the move the issue from the CSTF to the Planning Committee.
Gloria Godson, of Pepco, said she supported the inquiry but that PJM shouldn’t approve new rules until it fully understands the technologies. She noted the amount of “retooling” the RTO has done to address problems with the integration of demand response.
Raghu Sudhakara, of Rockland Electric Co., noted that NYISO already allows four hour resources to participate in its capacity market. “There’s no reason PJM, being as sophisticated as it is, can’t accommodate new technologies,” he said.
PJM currently has about 56 MW of non-pump storage.
PJM should be able to absorb the more than 7,400 MW of imports that cleared in May’s capacity auction for 2016-17, officials told a special meeting of the Planning Committee Friday.
Officials said that their initial review found PJM can import 11,000 to 12,000 MW. “We may have gotten close to what our limit would be, but we haven’t gotten to it yet,” said Stu Bresler, PJM vice president of market operations.
Officials cautioned that their results were preliminary and subject to change with further analysis.
Friday’s meeting was prompted by a problem statement approved by the Planning Committee Sept. 12.
The committee will seek to adopt a methodology for determining an RTO import limit that can be applied in the PJM planning process as well as included in next year’s Base Residual Auction. “It would function much like a CETL (Capacity Emergency Transfer Limit) for the entire RTO,” Bresler told the Markets and Reliability Committee in a brief discussion Thursday.
In addition to ensuring space for capacity, PJM must account for long term transmission contracts and 3,500 MW for the RTO’s Capacity Benefit Margin, which is reserved for importing capacity from external areas in emergencies.
Officials said their initial review identified a 500/230 kV transformer in the Duke Energy Carolinas zone as the limiting facility.
Bresler said PJM likely will propose a combination of path-specific limits with an overall RTO import cap. “The sum of the path-by-path limits could exceed what an overall limit would be,” he said.
Officials were unable to say Friday how much of the RTO’s total import capacity is to PJM’s west, the source of most of the imports that cleared in the May auction.
Market Monitor Joseph Bowring last week released an analysis that he said proves his contention that up-to congestion (UTC) transactions are increasing shortfalls in Financial Transmission Rights funding.
“There’s no reason to believe up-to congestion transactions help price convergence,” Bowring said in presenting his monthly report to the Members Committee webinar. “But they do increase day-ahead congestion.”
The monitor’s analysis was based on a simulation of market results with and without UTC bids for a five-day sample in May.
The analysis found that UTCs affect unit commitment and dispatch in the day-ahead market, increasing the number of binding constraints and negative balancing congestion.
For the five days examined, the FTR funding deficit was $4.4 million with UTCs versus a surplus of $22,000 with UTCs removed — a difference of $4.6 million.
In its 2012 State of the Market report, the monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.
The monitor said the RTO deviation rate for 2012 would have been reduced by 59% percent if UTC transactions had been included in the calculation of operating reserve charges.
The average cleared volume of UTC trades increased 73% between 2011 and 2012.
