The Market Implementation Committee last week endorsed the sunset of a task force created in 2012 to develop a process for limiting compensation when resources do not operate within reliability limits.
The Reliability Limited Generator Compensation Task Force (RLGCTF) completed its work after developing Tariff and Operating Agreement language limiting lost opportunity costs and tightening rules on generators’ behavior. FERC approved the changes in an order May 29.
PJM is planning changes to the way it estimates Tier 1 synchronized reserves after SR performance fell far short of expectations during the Sept. 10 heat spike. The RTO wants to make at least some of five proposed changes by the end of the year.
On Sept. 10, PJM received only 200 MW of Tier 1 reserves in the RFC region (the RTO excluding the Dominion zone), less than one-fifth of the 1,435 MW estimated by system operators. Members had claimed 4,000 MW of reserves, PJM staff told the Operating Committee last week.
“Wacky,” remarked one member.
Operators’ lack of confidence in reported reserves led PJM to call on a record amount of demand response on Sept. 11. Gaps are not critical most days, but referring to the stressful September event, a staff member said, “These are the days we need to worry about.” (See Big To-Do List from September Heat Wave)
If all five changes that staff has proposed had been in place, the Sept. 10 estimate would have been about 301 MW, about 100 MW above the actual response, according to Senior Reliability Engineer Chris Pilong.
Pilong said staff wanted feedback on the changes although it does not need member approval to implement them. PJM plans to “nail down” their changes at the next OC meeting, Nov. 5.
The changes being considered would:
Staff said the proposed changes would likely result in more Tier 2 clearing than did this summer.
Pilong said he also plans to propose rule changes to make PJM more confident it has enough of a synchronized-reserve requirement. He plans to bring the matter up at November’s meeting, taking into account the feedback he received from generator representatives.
“Market participants need to have a good feel for when PJM will be raising the SR requirement, or the triggers for it,” one generator representative said. When generators know they will be held back, he said, they won’t “chase LMP because PJM will compensate them for reserves.”
Six sponsors submitted proposals to relieve 15 transmission constraints in the “market efficiency” window that closed Sept. 26, officials told the Transmission Expansion Advisory Committee last week.
To win approval, developers of regional market efficiency projects must produce at least $1.25 in savings for every $1 in project cost. (See PJM Invites Transmission Projects to Reduce Congestion)
PJM said it will release a list of the proposed regional projects this week along with any interregional proposals for relieving congestion on market-to-market (M2M) and other congested facilities serving paths between PJM and MISO. The window for interregional projects closed Oct. 11.
PJM’s top 25 “congestion events” are projected to cost $237.8 million in 2017 (97% of all congestion for the year), rising to $514 million (95% of the total) in 2023. Eight of the 25 locations are market-to-market flowgates. Three spots are located in Commonwealth Edison and two each in Dayton Power & Light, MetEd and PECO.
FERC “preliminarily determined” that Constellation Energy Group violated market-behavior rules by not providing accurate information to the California Independent System Operator, the commission said in a notice. A company spokesman said the investigation concerned two months in 2010. “There is no allegation of manipulative conduct,” the spokesman said.
More: Baltimore Sun; Reuters
The U.S. Court of Federal Claims ruled against Exelon over the company’s claim of $1.69 billion in tax liabilities associated with decommissioning costs for three nuclear plants. The plants, which Exelon bought in 1999 and 2000, were not near decommissioning, the court said. Exelon said the ruling had no impact on earnings; the company has not decided whether to appeal.
More: Bloomberg
FirstEnergy reported finding a rusted hole in the lining of the reactor containment building at the Beaver Valley nuclear plant in Pennsylvania. The company found the hole — about a quarter inch by one-half inch — during a visual check of the lining during a refueling outage. It began making such checks routinely s since discovering a similar hole in 2009.
More: The Plain Dealer
The Midcontinent Independent System Operator began market day simulations for entities in MISO South, which is to join the regional grid operator in December. “We believe we’re on target for a seamless integration,” MISO’s Todd Hillman said.
More: MISO
Energy service company revenues grew by 9% annually from 2009 to 2011 and could double by 2020, the Lawrence Berkeley National Lab reported. Depending on scenarios, the industry could reach more than $15 billion by that year.
Emergency demand response produced 85% to 97% of promised reductions during the July heat wave, according to an analysis presented to the Market Implementation Committee last week.
No results are available from the September heat wave because Curtailment Service Providers have 45 days after an event to provide their data to PJM. The lag means charges for DR deployments won’t show up on bills for months after the triggering events.
“It makes it very difficult to understand what went on,” said Barry Trayers, representing Citigroup Energy Inc. “If you look back years later you’ll say `the September event wasn’t so bad.’ No, because [the charge] ends up in January.”
Dave Pratzon, who represents generators, said the results suggested “a little bit of response fatigue” in the ATSI zone, where DR was dispatched three times in July and twice in September.
ATSI’s DR performance fell from 95% on July 15 to 91% July 16 and 87% on July 18. “This may be our first little bit of data on what response to repeated calls will look like,” Pratzon said.
PJM says it expects to call on DR increasingly in the future, leading some to predict performance will suffer. (See Cool Reception for DR “Fatigue” Study)
The Planning Committee endorsed PJM staff’s recommendation to increase the Installed Reserve Margin (IRM) to 16.2% for delivery year 2014/15 (up from 15.9% in the 2012 analysis). The committee also endorsed margins of 15.7% for delivery years 2015/16 through 2017/18. The boost is because of the increasing alignment of the RTO’s peak demand with demand outside of the region. (See Installed Reserve Margin May Increase for 2014)
PJM will flag potential upgrade requirements earlier in the transmission study process under manual changes outlined last week to the Planning Committee.
“We’re going to bring you more violations and you’re going to have to give us more upgrades,” said Steve Herling, PJM vice president for planning.
PJM evaluates the expected transmission impact of a new generator based in part based on the historical probability that it will reach commercial operation.
In past years, studies identified many reinforcements which were ultimately not needed as projects dropped out of the backlogged queue.
Improvements in study processing have reduced the backlog. As a result, some projects have cleared the Impact Study phase (studied at 53% probability) without any apparent violations, only to have violations indicated when they are evaluated at 100% in the Facilities Study.
This can delay completion of the Facilities Study, cause costly surprises to project sponsors and hamper base case development.
As a result, PJM plans to eliminate the 19% probability for Feasibility Studies and replace it with the 53% currently used for Impact Studies. Impact Studies will use the 100% probability.
PJM will make the change for studies beginning in November (Y3 Impact Studies, due 3/31/2014 and Z1 Feasibility studies, due 2/14/2014).
PJM says the changes will give customers more accurate estimates of required upgrades before entering Facilities Studies. In addition, projects with no identified impacts at the Impact Study phase won’t remain in “limbo” awaiting Facilities Studies.
Herling said planners faced a tough tradeoff: “Do you start with a bigger list and whittle it down or start with a small list and surprise people later?
“To give people clean Impact Studies or [ones incorrectly indicating] minor upgrades … we saw as too much to ignore.”
He said upgrade requirements that occur late in the process are problems for generation developers who “have already been talking to their banks.”
The committee will be asked to endorse the changes, which affect Manual 14B, at its next meeting.
“We have to act on this quickly or we’re just going to compound the problem,” Herling said. “…If we can come up with something better in six months we will.”
PJM contact: Aaron Berner
PJM has narrowed the list of favored solutions to the Artificial Island stability problems, officials told the Transmission Expansion Advisory Committee last week.
Eight companies proposed 26 potential solutions ranging from $100 million to $1.5 billion in the window that closed June 28.
![Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons](/ext/resources/2013/09/Salem_and_Hope_Creek_Nuclear_Reactors_7238282472.jpg)
PJM’s initial analysis focused on combining the lower cost proposals with static VAR compensators to provide reactive support. The analysis found that proposals interconnecting with facilities to the Delmarva Peninsula on the west are effective and have the lowest estimated costs.
PJM plans to hire an engineering consultant to review the proposals in more detail, including validation of cost estimates and identification of risks.
PJM’s Paul McGlynn said the consultant would not review all 26 proposals but that it was “premature” to identify any proposals as finalists.
“We’re not taking anything off the table at this stage,” he said. “I wouldn’t glean too much from what I said today because we still have a lot of work to do.”
PJM expects to recommend a solution to the TEAC and the PJM Board early next year.
Artificial Island is the home of the Salem and Hope Creek nuclear plants in Hancocks Bridge N.J. Five utilities and three independent developers made proposals in PJM’s first competitive transmission project under FERC Order 1000.
RALEIGH, N.C. — The capacity market and the role of demand response dominated the discussion as more than 170 state regulators, PJM staff and stakeholders gathered here for the OPSI annual meeting last week.
The role of imports and the coordination of the gas and electric markets also were the subject of remarks during nine sessions involving more than 40 panelists.
Although some of the voices were new, the debates were familiar to those who have attended stakeholder meetings. (All presentations from the conference can be found at the OPSI website.)
Demand response and its role in the capacity market was a frequent theme.
As currently defined and deployed, DR is “too blunt an instrument,” said PJM CEO Terry Boston. Boston said PJM needs to be able to deploy some DR with less than two hours’ notice and do so with more geographical granularity.
“We need to focus it down to the … 69 (kV) and below feeder level” — the cause of the problems that led to load shedding in September, Boston said. “When we have shorter notice and longer dispatch, DR will have arrived.”
Gloria Godson, vice president of federal and PJM policy for Pepco Holdings Inc. and Katie Guerry, senior director of regulatory affairs for curtailment service provider EnerNoc, said they support PJM’s efforts to make DR more of an “operational” tool but said rapid changes risked alienating participants.
“It’s appropriate for the product to evolve. It’s not appropriate for demand response to be like all other resources,” said Guerry.
Godson said PHI lacked the ability to dispatch DR by the zip code or pNode. And more important than whether PHI has the technology to make changes is “when the customers are ready” for them, she said.
She opposed proposals to require DR to offer into the energy market, saying it would increase customers’ risk. “That’s not what we signed up for,” she said.
Guerry agreed: “Customers are not in the business of generating energy,” she said. “If we start requiring customers to be active participants in the energy market my concern is we are going to deter those customers from” taking part in DR.
In separate comments, Dan Griffiths, director of the Consumer Advocates of PJM States (CAPS) made a similar point. “For consumers, it’s about mitigating costs, not making profits — particularly for residential customers.”
Dallas Winslow, chairman of the Delaware Public Service Commission, said regulators gave DR proponents leeway in crafting rules. “The pendulum went too far perhaps; we don’t want it to swing back the other way too far.”
Stu Bresler, PJM vice president of market operations, said he was encouraged Guerry and Godson’s comments. “I think I hear more areas in which we’re aligned than in which we are not,” he said.
Several speakers recommended changes to the capacity market, saying current rules don’t encourage new generation or support existing plants.
Chuck Whitlock, president of Midwest commercial generation for Duke Energy, said his company’s Ohio River plants are among the cheapest coal plants in the country. Still, they struggle to earn revenues because of capacity prices suppressed by DR and low energy prices resulting from cheap natural gas and intermittent resources, he said.
Nick Akins, president and CEO of American Electric Power, echoed Whitlock’s complaint. He said PJM should use a five-year rolling average to set clearing prices to reduce volatility. He also said PJM should buy capacity in seven- to 10-year increments to incentivize new generation.
“There is just no product that provides for long term capacity in the market,” he said. “What the market is telling us right now is not to invest.”
Meanwhile, Allen Freifeld, senior vice president, law and public policy for Viridity, said PJM should procure DR six or nine months before delivery rather than three years ahead. “For demand response, the three-year forward is a barrier to entry,” he said.
The role of capacity imports also was the subject of considerable debate.
Boston noted that imports into PJM have been cut twice this year by Transmission Loading Relief (TLR) declarations. Overreliance on imports, Boston said, are “a clear and present danger to reliability.”
AEP’s Akins said PJM is taking a risk in buying capacity as far away as Louisiana. “I wouldn’t depend on that much capacity from Baton Rouge to Shreveport let alone [to] Columbus, Ohio,” he said.
Susan Bruce, representing the PJM Industrial Customers Coalition, said customers benefit from imports that increase competition and lower prices. “We should not be erecting unreasonable barriers to their participation,” she said.
Participants generally agreed with PJM Market Monitor Joe Bowring, who said the RTO needs to address arbitrage between the Base Residual Auction and Incremental Auctions. “We need to address the lack of risks associated with what has become a financial strategy,” he said.
Steve Schleimer, vice president of governmental and regulatory affairs for Calpine, said PJM should increase the penalty for failing to deliver promised capacity, calling the current 20% penalty “way too low.” Alternatively, he said, suppliers should give up all the upside in trading between the base and incremental auctions, excluding a 10% “dead band.”
Bruce agreed that there should be no speculation between the auctions but warned against “unnecessarily blunt” solutions.
In a luncheon address, FERC Commissioner Cheryl LaFleur told attendees that she heard two conflicting messages at the commission’s technical conference on capacity in September: “`We need stability, consistency, certainty or we won’t invest. However, there are a lot of things that are broken. Can you fix them please?’” (See Capacity Market Attracts Praise, Criticism at FERC)
Citing the tensions between must-buy obligations and municipal utilities’ desire to self-supply she added, “To no one’s surprise we did not come up with a magical solution.”
The coordination of the gas and electric markets, another subject that’s on the mind of FERC, was the topic for a session Tuesday morning.
Abe Silverman, chief regulatory counsel for NRG Energy, said generators in New England are sometimes forced to choose between responding to RTO dispatch orders and pipeline tariffs.
“In the future, security constrained economic dispatch is actually going to have to take into account fuel constraints,” he said. “I don’t know how you do that. I don’t know if you can do that.”
Stan Chapman, senior vice president for marketing and customer services for Columbia Gas, said the penalties his pipeline can impose are not enough to dissuade generators from “drafting” gas from the pipeline without a supply contract.
“What scares me is when a generator tells me, `You should interrupt your gas customers to keep the electric system operating. They’ll understand.’”
Because generators are reluctant to sign firm gas contracts, Chapman recommended PJM purchase pipeline capacity and release it to generators.
That was a nonstarter to Paul Sotkiewicz, PJM’s chief market economist. “That would be PJM taking a market position on behalf of a group of market participants,” he said. “And that’s just not going to happen.”
RALEIGH, N.C. — Some of the attendees had drifted away by the final session of last week’s annual meeting when OPSI and PJM publicly celebrated the renewal of PJM’s contract with Monitoring Analytics.
“We could have had a very different situation up here” had the contract not been renewed, said Michigan Public Service Commissioner Greg White.
“We would have had better attendance,” joked Maryland Public Service Commissioner Lawrence Brenner, chairman of OPSI’s Market Monitoring Committee.
In March, the Organization of PJM States Inc. (OPSI) joined industrial consumers and cooperatives in protesting the PJM Board of Managers’ plan to issue a request for proposals for monitoring services. OPSI, which represents state regulators in the PJM footprint, said the board’s proposed RFP contained language that could undermine the independence of the monitoring function. Other protestors expressed concern that PJM would suffer a loss of institutional knowledge if it replaced Monitoring Analytics.
But all was seemingly forgiven last week as PJM Board Chairman Howard Schneider and Jean Kinsey, head of the board’s competitive markets committee, shared the dais with Monitoring Analytics President Joe Bowring and several OPSI board members in a panel discussion that closed the two-day conference.
Schneider said that itself marked progress: In past years, no board members had been on the panel for the Market Monitor Advisory Committee meeting. “We hope this is a harbinger of things to come in the future,” Schneider said. “Not only do you need to get Dr. Bowring’s view of how things are going, you also need PJM’s view.”
The rapprochement was made possible when the board dropped plans to solicit competing bids and announced in April that it was negotiating a new contract with Monitoring Analytics.
That did not end tensions with OPSI, however. In July, Brenner sent a letter to the board complaining that the state regulators had not been consulted in the drafting of the new contract. (See PJM, Monitoring Analytics Sign New Contract) Brenner said the board’s action ignored a 2008 order in which the Federal Energy Regulatory Commission authorized OPSI to provide advice to the commission and PJM regarding market monitoring issues.
OPSI later asked FERC to amend the contract to include clarifications — included in a transmittal letter — regarding the balance between board oversight and the monitor’s independence.
The commission rejected OPSI’s request in a Sept. 27 order, but said it expected “that PJM and the [Independent Market Monitor], having made commitments in the transmittal letter, will abide by them.”
That was sufficient, Brenner said last week. “All’s well that ends well.”
Kinsey said the contract was “much improved” over the original because it clarified the Board of Managers’ oversight of the monitor, including regular performance reviews. The pact runs through the end of 2019.
While all expressed relief at the resolution of the contract dispute, there was no mistaking the underlying tensions that remain.
Both Bowring and Schneider are strong-willed personalities and can be blunt when they disagree.
When Brenner said he was happy to be able to call Bowring the “current and future market monitor,” Schneider interjected — “Current and future king” — with a chuckle.
“He has managed to annoy just about everybody in this room,” Robert Hanna, president of the New Jersey Board of Public Utilities, said of Bowring. “To me that’s a very good sign. He’s not in the tank for anybody. He does it in a principled way and he lets you know the basis.”
Schneider also tweaked Brenner gently. The chairman observed that PJM’s stakeholder process “seems to be working well.”
“Sometimes slowly,” Brenner said.
“Sometimes slowly and sometimes too fast, as you tell us,” Schneider responded.
“Touché,” Brenner conceded, smiling.
