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.
Demand Response Performance – July 2013 (Source: PJM Interconnection, LLC)
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 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
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.)
DR `Too Blunt’
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
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.
Capacity Market Incentives
Several speakers recommended changes to the capacity market, saying current rules don’t encourage new generation or support existing plants.
Chuck Whitlock
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
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.
Capacity Imports
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
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.
Auction Arbitrage
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
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.
No `Magic’ from FERC Conference
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.”
Gas-Electric Coordination
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
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
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.
Paul Sotkiewicz
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.
Capacity imports could clear at lower prices than internal resources under proposed import limits being considered by PJM.
PJM officials are planning to create an RTO-wide import limit as well as individual limits for PJM interfaces with the North, South and West, Stu Bresler, vice president of market operations, told the Market Implementation Committee last week.
If the external limit is not reached, the “rest of RTO” and “outside RTO” regions would clear together at the same price. Once the cap is reached, however, the marginal external resource would set the price for the “outside RTO” region while the marginal internal resource would set the price for the “rest of RTO” region.
If there is price separation, internal resources will clear at a higher price than imports, just as resources east of PJM’s west-to-east constraints are often priced higher, Bresler said.
An alternate approach being considered by PJM is to require that resources have firm transmission as a condition for allowing them to offer into the auction.
PJM said last month that its initial analysis indicated the RTO should be able to absorb the more than 7,400 MW of imports that cleared in May’s capacity auction for 2016-17.
Officials said that their initial review found PJM can import 11,000 to 12,000 MW simultaneously. That would allow at least 7,500 MW of imports to clear in the capacity auction, with an additional 3,500 MW reserved for the RTO’s Capacity Benefit Margin — a set aside to be used in emergencies. (See Current Capacity Imports OK: Study)
However, PJM’s Mark Sims told the Planning Committee last week that the estimate may be overly optimistic because it assumes redispatch of almost 10,000 MWs. “We know in real-time that these kinds of adjustments … haven’t happened,” he said.
Capacity Price Curve With Import Cap (Source: PJM Interconnection, LLC)
Sims said staff will conduct a revised analysis that puts more “realistic” limits on redispatch. The new analysis also will set a threshold distribution factor of 3% rather than the 1% factor used in the original analysis. “We don’t want to consider distribution facilities in Florida,” he said.
The Planning Committee approved a problem statement on a proposed cap last month in response to the May capacity auction, in which cleared imports increased by more than 3,000 MW.
Officials plan to seek Planning Committee approval of the import caps next month. PJM wants to implement the new rules prior to posting the planning parameters for the next Base Residual Auction.
PJM will perform a cost-benefit analysis before proceeding with a combined-cycle bidding model expected to cost up to $1 million.
Combined Cycle Plant Diagram (Source: General Electric Company)
PJM’s Tom Hauske told the Operating Committee that incorporating the Alstom model — chosen by the OC to ensure more consistency among offers — will be more complicated and costly than initially expected. Hauske said the changes will affect more than eMKT and scheduling and won’t be implemented until 2015 instead of June 2014.
Given the new cost estimate of between $750,000 and $1 million, Hauske said, “We have to be able to justify it” for inclusion in PJM’s budget.
All 53 combined-cycle units in PJM, which can now offer as steam units or combustion turbines, would be required to use the new model. Sellers will have to offer the new combined cycle configurations for at least three months. All units would be aggregated under one unit ID.
Maryland officials aren’t saying what their next move is in the wake of a federal court ruling that voided the state’s contract with developers of a 725 MW combined cycle plant in St. Charles.
Judge Marvin Garbis
U.S. District Judge Marvin J. Garbis ruled that the “contract for differences” the state Public Service Commission negotiated with Competitive Power Ventures unconstitutionally interfered with the Federal Energy Regulatory Commission’s jurisdiction over interstate wholesale energy sales.
“Because states have no authority, either traditional or otherwise, to set wholesale rates, the compensation received by CPV for its wholesale energy and capacity sales is exclusively subject to the regulation of FERC,” the judge wrote in a 149-page order.
The ruling invalidates the PSC’s April 2012 order directing Baltimore Gas and Electric Co., Potomac Electric Power Co., and Delmarva Power & Light Co. to enter into contracts that guaranteed CPV Maryland LLC an income stream so that it could finance construction of the Charles County facility.
Robert J. Grey, general counsel for PPL Corp., one of the companies that challenged the CPV deal, said the ruling “upholds the integrity of competitive generation markets.” PSEG Power LLC and Essential Power LLC were the other plaintiffs.
An appeal is likely, although Regina L. Davis, spokeswoman for the PSC said Friday that the agency was reviewing the ruling and had no immediate comment.
Charles County Commissioner Ken Robinson said the county remained “cautiously optimistic” that the project will proceed.
Merchant Option?
CPV officials did not respond to requests for comment. Last month, the company announced that it would build a 700-MW combined cycle plant in Woodbridge, New Jersey as a merchant facility because of uncertainties created by legal challenges to state-sponsored contracts there.
On Oct. 11, a federal court judge threw out New Jersey’s contracts, also on constitutional grounds, with CPV, Hess Corp. and NRG Energy. The three were selected through a solicitation by the New Jersey Board of Public Utilities for construction of 2,000 MW of generation.
Despite the ruling, the CPV and Hess plants are being built. Hess, which began construction late last year on its 655 MW plant in Newark, said it expects to complete the plant in 2015. CPV said it expects construction on the $842 million Woodbridge project to begin within weeks. NRG cancelled its project after failing to clear in two consecutive capacity market auctions.
CPV said in 2009 that it needed state backing to secure long-term financing to build in Maryland. In the interim, however, low natural gas prices and retirements of coal-fired plants have led to a spurt of unsubsidized generation in PJM. CPV said the debt syndication for its New Jersey plant was oversubscribed “reflecting the project’s strong fundamentals.”
Panda Power Funds in July proposed an unsubsidized 859-MW combined cycle plant in the Washington suburb of Prince George’s County, Md. LS Power Group, which had earlier sought subsidies to build in New Jersey, is building a plant in West Deptford without state backing.
Contract for Differences
Under the Maryland contract, CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices are higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices are higher than the contract, CPV would make payments to the EDCs.
Boston Pacific Co., a consultant hired by the PSC, estimated the contract would save residential ratepayers $0.32 to $0.49 per month over the life of the 20-year contract. However, PSC General Counsel Robert Erwin told FERC’s technical conference Sept. 25: “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.” (See Capacity Market Attracts Praise, Criticism at FERC).
PJM Capacity Market ‘Failed’
The PSC took its action to spur new generation after concluding that the state faced “a critical shortage of electricity capacity” because it is a net importer and is subject to higher prices because of transmission congestion.
The PSC said that PJM’s capacity market “has failed to attract new generation” to the Southwest Mid-Atlantic Area Council (SWMAAC), which encompasses most of Maryland.
“Since its inception in 2007, RPM has brought no new generation to Maryland, in spite of the fact that clearing prices for capacity in the SWMAAC have averaged almost double those of the non-constrained portions of PJM,” the PSC said. Existing generators had no incentive to build more capacity, regulators said, because increasing supply would reduce prices.
Request for Proposals
Aerial map of CPV St. Charles location
CPV was selected over two other bidders that responded to the state’s request for proposals (RFP).
The contract for differences required CPV’s plant to clear in PJM’s annual Base Residual Auction. New generators participating in the auction are subject to the Minimum Offer Price Rule (MOPR), which sets a minimum offer price based on the net Cost of New Entry (net CONE), a measure to prevent buyer-side market power.
In the 2012 capacity auction, PJM approved a MOPR bid floor of $96.13/MW-day for the CPV plant. Prices in SWMAAC and MAAC cleared at $167.46/MW-day in SWMAAC and MAAC, although a PJM sensitivity analysis found prices in SWMAAC would have been almost $30 higher had the bid capacity been 750 MW lower.
MD Argument ‘Unpersuasive’
Garbis said he found “unpersuasive” Maryland’s argument that the contract price is a competitive market price because CPV initially proposed it as part of the RFP. He noted that the PSC had reserved the right to select none of the proposed contract prices. “Accordingly, although it was proposed by CPV, the contract price in the CfD is a price ‘set’ or ‘determined’ by the PSC,” the judge ruled.
Garbis also rejected the state’s contention that the contract was a “mere financing arrangement outside the jurisdiction of FERC.”
“While there exist legitimate ways in which states may secure the development of generation facilities, states may not do so by dictating the ultimate price received by the generation facility for its actual wholesale energy and capacity sales in the PJM Markets without running afoul of the Supremacy Clause,” he wrote.
‘Win’ for Consumers?
The COMPETE Coalition, an organization that represents generators and others, called the ruling “an important win for electricity consumers,” saying subsidized development would “needlessly shift the financial risk of new construction from power plant developers to consumers.”
The Maryland Office of People’s Counsel, which represents residential utility customers, was less sanguine. “If the order stands, it could restrict the state’s ability to address reliability problems within the state,” People’s Counsel Paula M. Carmody told The Baltimore Sun.
PJM officials said they are pleased with the response to their request for additional black start resources, as more than 50 generators responded with offers.
“There appears to be a large pool of viable units, both proposed and existing,” said Mike Kormos, PJM executive vice president for operations.
Officials said it will take months to select their fleet of black start resources from among current resources and the new bidders. Locational needs and costs will be the determining factors.
Black start units must be capable of starting without an outside electrical supply, maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.
The solicitation was one of the recommendations of the System Restoration Strategy Task Force, which also increased the pool of potential resources.
PJM expects to lose some existing black start capacity by 2015 due to coal plant retirements.
![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)
