HERSHEY, Pa. — The prevalence of gas-fired generation has skyrocketed in recent years, upending power market structures and leading to nationwide debate over the future of the electricity industry.
Much of that might be attributable to what Christina Simeone, director of policy and external affairs for the University of Pennsylvania’s Kleinman Center for Energy Policy, calls the “Pennsylvania Gas Discount.”
At a conference to analyze Pennsylvania’s electricity markets last week, Simeone unveiled her study on price impacts from the recent expansion in shale gas development.
“The electric power sector is now the natural gas industry’s No. 1 customer both in Pennsylvania and nationally,” she said.
That has come, she said, because production from the state’s Marcellus shale has been prodigious, while “takeaway capacity has not kept up with production growth.” In 2007, Pennsylvania accounted for less than 1% of the nation’s natural gas production and consumed four times more gas than it produced. By 2016, the state had increased its output 2,800%, accounting for 16% of national production — four times more than it consumed.
In-state pipeline construction has not maintained that pace. Simeone said FERC has approved 59 interstate pipeline projects since 2007 that would impact Pennsylvania, but many of them have been delayed. Williams’ Constitution pipeline, for example, was approved in 2014, but construction has been blocked by a permitting battle with New York.
The pipeline constraints have led to an oversupply that has dramatically depressed in-state prices.
“The electric power sector is really where prices dropped the most,” she said.
Average annual delivered power prices in Pennsylvania in 1997 were $3.02/Mcf, 24 cents more than the national average of $2.78. The differential widened to 70 cents in 2007, with Pennsylvania prices rising to $8.01/Mcf.
By 2016, the Pennsylvania average had fallen $1.05 below the national average to $1.95/Mcf.
Correspondingly, in-state consumption since 2007 increased by half, with usage up almost 250% by Pennsylvania gas-fired generators, whose number increased 15% in that time. Gas deliveries for power production nationwide have risen 46% in the past decade, as gas-fired units increased nearly 4%.
The price drop has had a profound impact on power markets, shaking the fundamentals of market design and sparking a national debate about subsidies for financially struggling coal and nuclear generation. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)
Simeone said it’s unclear how long the discount will continue because there are “huge reserves, but we also have this record interest in pipeline takeaway capacity.” If built, the nearly 60 FERC-approved projects could transport more than 20 Bcfd, but producers could also increase supply, prolonging the Pennsylvania discount. Pennsylvania produced about 5,264 Bcf in 2016, according to Simeone’s research, and has a cumulative outflow of 6 Bcfd.
HERSHEY, Pa. — FERC Commissioner Robert Powelson had to hit the ground running after being appointed to the commission in August. He and his colleagues are working to clear the backlog of decisions that accrued during the six months the commission lacked a quorum.
But part of the job also includes dealing with issues he doesn’t want to touch.
“The FERC is trying to stay out of the fuel wars, and that’s what’s going on right now. Coal against gas; nuclear trying to stay above the fray. It’s becoming unnecessarily all about ‘my fuel’s more resilient that your fuel,’” Powelson said last week during an industry conference. “If the [2014] polar vortex is the example of that, there’s a lot of people with sins they need to confess, and I think we know that.”
He pointed to the 24% forced outage rate stemming from that epic cold snap, and noted that he once “called out” the companies that failed to meet their capacity obligations.
“We know who they are. Some of them are in the room today. We have a 12-step program in the back,” he said.
Powelson was speaking at “Decade of Disruption: Marcellus Shale and Regional Energy Markets,” the second annual electricity conference organized by John Hanger, a former Pennsylvania state utility regulator and environmental secretary. Before Powelson spoke, Hanger presented him with a 2017 Energy Leadership Award.
Vortex Fatigue
Powelson’s comments were part of a discussion touching on many industry topics, but that repeatedly returned to the U.S. Department of Energy’s recently proposed grid resiliency pricing rule. The department’s Notice of Proposed Rulemaking used the 2014 extreme weather event as a pretext to endorse — and financially compensate — the reliability of units with 90-day onsite fuel supplies.
“I’m a little fatigued by the use of the polar vortex as this screaming cry for why we have to do something. … I think we did a lot in PJM with Capacity Performance. I’d like to honestly see CP kick in at 100%, make a metric call there and then get into this question,” he said.
Powelson also explained his views on state subsidies in the form of renewable energy credits (RECs) to build preferred wind and solar resources or new zero-emissions credits (ZECs) to support existing nuclear plants. Critics say RTOs must limit the ability of those units to bid into competitive auctions to prevent them suppressing markets by offering at prices below their true operating costs.
“If a state has a [renewable portfolio standard] and wants to value carbon goals, they should be allowed to do that. The problem is when you create a market bastardization of the thing known as the minimum price offer rule … we’ve got to address that issue,” Powelson said. “Those state mechanisms have to be able to pass the minimum offer price rule smell test, so that’s where it gets a little prickly for us as an agency that just allowing a state to go amend its RPS without, in my view, having a strong MOPR screen gives me a little bit of heartburn, because you do know we’re causing a lot of havoc now in the markets to gas units that are dispatching and not being able to cover their marginal costs.”
He provided the example of CAISO, where some gas-fired generators are declining to engage in the market and, in some cases, seeking early retirement. He pointed to PJM as a market doing a good job significantly reducing emissions in the past decade.
“In lieu of a carbon tax, that is market-based decarbonization at its best,” he said.
To incentivize transmission development, he said the industry must focus on tweaking financial mechanisms.
“The big conversation at the FERC is [return on equity] policy and how under FERC Order 1000 we get these projects cited and we get them commercialized,” he said.
Getting Gas to Market
The issue of gas-electric coordination “cries out for a broader conversation,” Powelson said.
“I personally don’t think we’re out of the woods there yet,” he said. “The conversation about gas and electric folks not being able to coordinate efforts, being able to sit them in a room together to have a conversation… Market synchronization would be helpful.”
Powelson said the “tectonic shifts taking place in our bulk power system” and the days of large plant construction appear to have been superseded by interest in unique and localized solutions, like combined heat and power facilities, islanding, microgrids and oxidized fuel cells.
“If you look at the grid right now, 1,000-MW cathedrals, we’re just not there anymore,” he said. “The consumers are demanding these changes.”
As a former Pennsylvania regulator during a period of explosive growth in shale gas production, it wasn’t surprising that Powelson also defended natural gas and promoted its expanded use.
“There will be some in Washington who come into my office and say, ‘Gas is not a baseload resource.’ Well, if you’re in Pennsylvania and Texas and Louisiana and West Virginia and Ohio, you take exception to that,” he said.
However, the gas can’t stay in those areas, he said.
“We need to get it to load centers,” he said, and indirectly criticized New York state’s reluctance to approve pipeline construction permits.
“If anybody here can help, there’s a state capitol — I think it’s called Albany — we would greatly appreciate your advocacy work in there,” he said. “We’re inching our way ahead.”
New York’s reticence has been a major hurdle for getting Pennsylvania gas to New England markets, where there are often supply constraints. Earlier in the conference, ISO-NE CEO Gordon van Welie said he didn’t expect to see another pipeline ever connected into his RTO. Powelson appears to have other plans.
“I would take a little bit of exception to Gordon’s assessment that we’re never going to see a pipeline built,” he said. “I think there’s a steadfast commitment to getting pipeline infrastructure built.”
Or perhaps it will be a case of moving gas into the region by whatever means necessary. Powelson said he shares a half-joking agreement with fellow Commissioner Cheryl LaFleur that “if we can get one thing done in our careers, it’s repeal the Jones Act.”
The Merchant Marine Act of 1920 — commonly known as the Jones Act for its sponsor, Sen. Wesley Jones — forbids foreign-flagged ships from carrying cargo between the U.S. mainland and certain noncontiguous parts of the country, including Hawaii, Puerto Rico, Alaska and Guam. Enacted in the aftermath of World War I — and in case of World War II — it was intended to ensure the country had a large enough supply of merchant ships to survive attacks by German subs.
Powelson called the law an “antiquated document that doesn’t reflect where we are in our energy landscape.” He said it limits the ability to ship LNG around the country from the growing number of export terminals to demand areas, such as New England.
“It’s alarming to me the storage crisis that they face,” he said. “When they hit that constraint, it’s ‘OK, let’s see what we need to do to get something into one of the storage facilities.’ That’s not the way I want to run an RTO.”
No commenter delivered a more damning takedown of Energy Secretary Rick Perry’s call for out-of-market compensation for nuclear and coal generators last week than PJM.
PJM said the Department of Energy’s Notice of Proposed Rulemaking makes “a sweeping and unsupported conclusion that, solely in regions with capacity and energy markets, certain units, regardless of their location, performance history or competitiveness, deserve full cost recovery through out-of-market mechanisms” (RM18-1).
But the Independent Market Monitor and other critics say the alternative PJM proposed in its filing would also be expensive and also undermine the RTO’s markets. Where Murray Energy and its customer FirstEnergy appear to have influenced DOE’s call to aid coal, the Monitor suggests that PJM is acting in the interest of Exelon, which would be the biggest winner from a boost to nuclear plants.
In an interview Thursday at the Markets and Reliability Committee meeting, PJM CEO Andy Ott said the RTO’s proposal will ensure LMPs “reflect which units are actually operational” but is “not going to benefit specific fuel types.”
In his comments on the NOPR, however, Monitor Joe Bowring said that PJM’s proposal appears “to reflect a desire to administratively alter the markets to favor nuclear and coal-fired generation.” Those generation types would receive a “disproportionately large increase in revenues,” he wrote.
Price Formation Report
PJM’s proposal, which would allow less flexible, traditionally baseload units to set LMPs, was first outlined in its June report, “Energy Price Formation and Valuing Flexibility.” (See PJM Making Moves to Preserve Market Integrity.)
“The PJM report claims that baseload — nuclear and coal — generation is undervalued in the market, that negative energy market offers have a pernicious effect in hastening the retirement of baseload generation and that an increasing reliance on capacity market revenues, rather than energy market revenues, results in a bias in the markets,” the Monitor wrote. “The PJM report provides no evidence supporting these claims.”
The Monitor is not alone in his suspicions of PJM.
“The real issue is not necessarily the proposed DOE rule, but what the RTOs like PJM will propose in its place,” Tyson Slocum, director of Public Citizen’s Energy Program and a harsh critic of the RTO rulemaking process, said in an email. “FERC will be far more inclined to endorse whatever the RTOs put forward. What PJM is saying here is that they are NOT opposed to coal/nuclear bailouts AS LONG as the ‘bailouts’ are conducted through the RTO’s ‘market’ rules. While everyone is distracted by the shiny DOE cost-of-service proposal … we cannot simply focus only on the DOE proposal, but what is coming next.”
That is why, Slocum added, Dynegy and NRG Energy filed comments opposing the NOPR even though they acknowledged they would benefit from it: “They love their odds of getting a market-based bailout through MISO and PJM.” (See related story, Vistra Energy Swallowing Dynegy in $1.7B Deal.)
John P. Hughes, CEO of the Electricity Consumers Resource Council (ELCON), said PJM’s June proposal is “simply an unsubstantiated directive to subsidize coal and nuclear plants with no consideration of the impact of the out-of-market costs on load. The one-price-clears-all nature of the market design also means that this gimmick will create a windfall for all generators that are dispatched. PJM is behaving as if it were captured by Exelon. PJM should be moving in the direction of improving market operation and price formation — not against it!”
PJM included in its filing a letter from Harvard economist William Hogan endorsing what he called PJM’s plan to “ensure that the incremental cost of serving load is reflected in LMP.” Hogan said it was “an appropriate step forward in price formation.” He added, however, “I do not expect it likely to produce a dramatic change or have as significant an impact as improved scarcity pricing.”
Consultant James Wilson, who often represents state consumer advocates in PJM, said in an email that it was “notable [that] Prof. Hogan does not support PJM’s proposal as described in the June whitepaper. While he supports some things discussed with PJM verbally, he does not mention or cite to the whitepaper.”
The Electric Power Supply Association (EPSA) told RTO Insider it is encouraged by PJM’s proposal and is hopeful it will be considered on an “accelerated time schedule.” (See sidebar, Reaction to PJM Price Formation Proposal.)
Three-Month ‘Compliance’ Process
The RTO said the DOE NOPR “incorrectly identifies a perceived problem and its cause, and seeks to impose a remedy that is not supported by the reliability and resilience concerns [it] claims to address.”
But while it was dismissive of the NOPR, PJM acknowledged it is behind other RTOs in adopting rule changes to improve price formation. It asked FERC to set a deadline for each RTO/ISO to identify “whether changes in the resource mix [have] created issues in their respective regions that are currently not addressed in the market” and propose solutions “within a commission-specified deadline that is in the near term.”
Asked to define “near term,” Ott said, “we’re thinking three months … would be appropriate.”
If FERC agrees to PJM’s request, said Ott, “We’d still have time to talk about it but it wouldn’t be the traditional … issue charge type” stakeholder process. It would likely be filed by the PJM Board of Managers under Section 206, he said.
Exelon’s Role
Ott said PJM’s proposal “is very consistent” with FERC’s price formation docket (AD14-14) and fast-start NOPR (RM17-3), but that the problem is manifested differently in PJM, which has fewer fast-start units and more large gas combined cycle units. “All we’re saying is it’s a bigger problem than just a few units — it’s not just fast-start units. It’s these others,” he said.
In its written comments, the Monitor suggested PJM is following the talking points of Exelon, noting the company is the RTO’s “largest participant.”
Bowring said the proposal to extend the fast-start NOPR’s pricing concept to all resources “was not proposed by PJM in Docket RM17-3 but was included in Exelon’s comments in the docket.”
The Monitor said that while PJM “held no open stakeholder discussion of the proposals in the report,” Exelon discussed the RTO’s June report in its second-quarter earnings call. During the call, Joseph Dominguez, executive vice president of governmental and regulatory affairs, said the company would “push very hard” to make sure that PJM would propose its pricing reforms to the commission for implementation by summer 2018.
Bowring said this “aggressive timeline … would not likely be met for a significant market pricing proposal through the PJM stakeholder process.”
PJM did not respond to a request for comment regarding Exelon’s involvement.
An Exelon spokeperson responded: “Dozens of entities including the U.S. Department of Energy, [Edison Electric Institute) EPSA, PJM, Dr. Bill Hogan, and PJM states have similarly concluded that PJM’s energy market rules are flawed and reforms are needed to preserve critical resources for our customers. We will address in our reply comments a number of factual and analytical errors in the IMM’s filing.”
The Monitor said FERC should allow the regular stakeholder process and not rush to approve PJM’s proposal.
“The PJM report’s proposal, which would impose significant costs on customers to the benefit of the owners of nuclear and coal-fired generation, is not the result of the process designed to support independent, deliberate decision-making,” he wrote.
Extended LMP
PJM told FERC it is “actively exploring” the extended LMP method, which would bifurcate its security-constrained economic dispatch into separate dispatch and pricing runs, as is already done in MISO, ISO-NE and NYISO.
PJM says its flat supply curve has diminished generators’ incentives to follow dispatch instructions.| PJM
“Under our proposal, the flexibility would be called a separate product and then you would have the supply demand balance actually set the price,” Ott explained. “Under that scenario, the price of electricity would more reflect which units are actually operational. So it’s not going to benefit specific fuel types. But what it would say is the units that are actually running today, every day — and we have to have them — the pricing would reflect the fact that they are on.
“Today, for example, we may have a $30 unit running but the price is $27. … So the unit that’s $30 would get the $3 through uplift. If the price actually reflected that it was on, the forward prices would pick that up and it would be more economic.”
While coal plants cannot toggle on and off like modern gas-fired plants, Ott said they are flexible within their minimum and maximum outputs. “The challenge today is many of the gas units’ production costs are below all the coal,” he said. “So, the coal tends to sit at minimum.”
PJM said improved price formation “may help to ensure an appropriate mix of resources that can meet future grid demands and have clear incentives to follow dispatch instructions.”
Impact on Incentives
Ott said the only incentive for generators to offer load-following flexibility is the ability to set LMPs.
But PJM says the incentive has diminished because its supply curve has become too flat — particularly between 120,000 MW and 150,000 MW, where load typically peaks in summer and winter — because of “the competitive economics of combined cycle gas turbines, assisted by low-cost shale gas and increasing renewables with zero fuel costs.”
PJM’s winter capacity mix is less dependent on natural gas — and more reliant on coal and nuclear — than almost all other NERC regions in the continental U.S. | PJM
“When [resources are] all within the same 50-cent part of the curve, it’s like, ‘What do I care?’” Ott said. “So a gas resource is sitting here saying, ‘If I’m going to be flexible, I have to buy a flexible fuel contract that will cost me more money. I’ve got to spend more money on maintenance. And I’m not going to do that for 20 cents.’ That’s the reality we’re facing.”
The Monitor contends, however, that separating the real-time five-minute energy price from the five-minute energy dispatch instructions would eliminate the incentive for marginal units to follow the dispatch instruction. “The result would undermine PJM’s control of the system and further increase the cost of serving load,” he said.
Higher LMPs, More Uplift
Ott said the changes PJM has proposed will increase energy prices while reducing uplift and capacity prices. But he said he couldn’t say how it would affect the total cost to ratepayers or whether it would increase overall coal and nuclear revenues because the RTO hasn’t yet run any simulations.
“Obviously, under our proposal, electricity prices would go up. [We’re] pretty sure of that. As far as the magnitude, I think I’d rather wait until we see the proposal.”
The Monitor said, however, the PJM proposal to allow less flexible units to set price would result in higher LMPs and new uplift payments, raising “the cost to consumers of serving the same load in each market interval with no counteracting decrease to production costs.”
“The proposed pricing solution would raise the price to that of any inflexible unit that would provide the marginal megawatt-hour as if it were willing and able to change its output level, which it is not. The pricing solution is a fictitious solution that produces higher prices that are not consistent with the efficient dispatch of the market,” he said.
Jennifer Chen, an attorney for the Natural Resources Defense Council’s Sustainable FERC Project, cited an estimate that including no-load and start-up costs of inflexible units in LMPs would boost energy market prices by 10 to15%.
Bowring said Monday that would put the cost of PJM’s proposal at $3 billion annually, equivalent to paying 25% of the plants’ current replacement value. (See related story, Cost Estimates on DOE NOPR: $300 million to $32 billion+)
Better Options
The Monitor said it has discussed with RTO officials energy market price formation improvements that would not interfere with competitive outcomes. “Improvements to better reflect local scarcity due to transmission constraints, system scarcity and necessary reserves in prices would direct greater market value to the specific resources that support reliability. Some of these changes are already underway in the PJM stakeholder process, while others have made less progress,” the Monitor said.
PJM says the replacement of old coal units with new gas generation is improving — not harming — reliability, as illustrated by its declining EFORd.| PJM
The Monitor said it agrees with PJM on a need to consider changes to the operating reserve demand curves (ORDCs). The RTO said it is conducting the first broad review of its ORDCs since it implemented shortage pricing in 2012.
The ORDCs are based on the largest unit operating on the system. “As such, they do not accurately reflect the value of excess reserves on the system in a manner consistent with the reliability value of those reserves,” PJM said.
“When we developed the N-1 criteria, we were looking at storm-related outages and equipment failures,” Ott said. With the added concern of terrorist attacks on infrastructure, he said, the RTO is evaluating what areas of the grid are vulnerable. For example, Ott noted, NERC’s Critical Infrastructure Protection standard requires expenditures to protect substations designated as critical.
“Is there some criteria you can put around that to say we should be protecting against those types of risk?” Ott said, adding, “realizing that, of course, you can’t protect every piece of equipment.”
Could that mean contingencies based on large gas pipelines that supply multiple generators? “There’s a lot of discussion that has to occur before we get to that point,” Ott said.
Shortage Pricing
PJM said it also will propose new shortage pricing rules that would “incentivize appropriate behavior [and] could mitigate operational reliability concerns.”
The RTO currently institutes shortage pricing if its system is short of 10-minute reserves, “which from a reliability perspective would constitute a grave operating condition,” it wrote in its NOPR response. “Modeling and invoking shortage pricing for longer-term reserve products such as 30-minute reserves would provide better incentives and information to the market regarding potentially severe operating conditions by escalating energy and reserve prices earlier and incentivizing behavior that would ameliorate the condition,” PJM said.
ERS Problems?
Ott said PJM does not have a lack of “essential reliability services” as defined by NERC.
“The issue is not that we don’t have enough of resources that can provide these services. The concern that we have is that we’re not paying for them,” he said.
While PJM has a compensation scheme for some ERS such as black start, “We don’t pay for inertia. We don’t pay for voltage control, things like this,” Ott said. “We don’t have a problem with them today, but we aren’t paying for them. So we need to look at — if we continue to not pay for them — [whether] they’re going to go away.”
Ott rejected the notion that its proposals are designed to benefit the same uneconomic resources as the DOE NOPR. “What we’re saying is the price of electricity has to reflect the units that are actually running to serve load. It should be no more; it should be no less. We’re not saying anything about what fuel types,” Ott said. “There are a significant number of times when we have resources operating and the market price doesn’t reflect the fact that the resource is operating. Whether the resource is coal, nuclear or gas, that’s wrong in my opinion.”
Reaction to PJM Price Formation Proposal
RTO Insider invited numerous interest groups to comment on PJM’s proposed price formation proposal. Below is a summary of their responses.
John Shelk, CEO, Electric Power Supply Association
EPSA welcomes and supports PJM’s leadership and active pursuit of further market reforms that are needed in light of continued major changes in the region’s resource mix. The specific issues outlined in PJM’s recent DOE NOPR comments at FERC should be further developed and filed at FERC as soon as possible so that implementation of approved reforms occurs in 2018.
Pat Jagtiani, executive vice president, Natural Gas Supply Association
NGSA is supportive of proposals that provide clear, competitive market signals in a fuel-neutral manner, and we agree that it should be RTOs working with their stakeholder to achieve the best path forward. With that said, we haven’t seen enough detail around PJM’s proposal to provide a detailed comment on their proposal. We do wholeheartedly agree with PJM’s statements that put natural gas’ excellent record of reliability on the record.
Todd Foley, senior vice president of policy & government affairs, American Council on Renewable Energy (ACORE)
ACORE agrees with PJM’s comments on the importance of relying on competitive markets and regional flexibility to ensure system reliability, resilience and lowest possible electricity costs for consumers. We believe that FERC, working with PJM, other organized markets and stakeholders, should establish objective, market-based criteria in price formation to reward system flexibility. We need to see how PJM’s proposals reward system flexibility, since that is what is needed for grid modernization and managing higher penetrations of renewable resources.
Amy Farrell, senior vice president of government and public affairs, American Wind Energy Association
Grid reliability and performance have gone up, all while wholesale electricity prices have gone down, because PJM markets allow uneconomic inflexible units to retire and be replaced by new, efficient and flexible units capable of responding to market signals. Let’s not try to solve a “problem” of low-cost electricity.
The PJM proposal is still being developed, so we don’t have a final position on it yet. However, if PJM divorces payment from performance, ultimately keeping less efficient units online, that could distort the market in the long run. More market-friendly approaches exist. For example, MISO and other market grid operators have improved efficiency and minimized out-of-market payments by incorporating start-up and no-load costs into market prices.
Jennifer Chen, attorney, Natural Resources Defense Council’s Sustainable FERC Project
While we may be able to support shortage pricing and ORDC revisions, PJM’s proposal to allow inflexible resources (largely coal and nuclear) to set LMP raises both process and substantive concerns. From a process perspective, PJM has been working on its inflexible unit pricing proposal without input from the stakeholder body for some time now, and we still do not know the details of it. Yet PJM, in its RM18-1 comments, asked FERC for immediate action and appears to be seeking a near-term deadline to implement its proposal. … Reliability isn’t a justification and PJM didn’t invoke it. In fact, PJM has more than enough resources available with reserve margins hovering around 29% this past summer and the last [Base Residual Auction] clearing a reserve margin of 23.9%. FERC directive on any of these potential reforms would be inappropriate at this point.
We also have concerns about the substance of the PJM proposal based on what’s known about it. … Artificially inflating prices will attract new supply, which would in turn lower energy market prices, defeating an apparent purpose of the proposal to put more money into the energy market. If anything, PJM should act to reduce its oversupply, which would better achieve what PJM set out to do with its price formation proposal.
Tyson Slocum, director of Public Citizen’s Energy Program
RTOs’ constant rejiggering of their capacity markets to accommodate the needs of their powerful members to earn more money for their aging power plants isn’t any better just because they dress up their bailouts in difficult-to-understand pseudo-economic jargon. … So, it will be no celebration for consumers if the DOE cost-of-service remedy is simply substituted by an RTO capacity auction redesign that falsely calls itself as a more palatable “market” solution.
(No responses were received from the Organization of PJM States Inc. (OPSI); Consumer Advocates of the PJM States (CAPS); the PJM Industrial Customer Coalition; the PJM Public Power Coalition; the Solar Energy Industries Association; the Nuclear Energy Institute; the American Petroleum Institute; the National Mining Association; or the American Coalition for Clean Coal Electricity.)
PHILADELPHIA, Pa. — “We don’t know the right answer,” PJM Senior Market Strategist Andrew Levitt said last week. “We think the right answer is going to emerge.”
Levitt was speaking on a panel about distributed energy resource integration in PJM, but the comment could have applied to any of the topics discussed at last week’s Mid-Atlantic Power Market Summit hosted by Infocast.
With all the technological innovation and game changing occurring in the power industry, market rules are having to move quickly to keep pace. While some PJM stakeholders are reluctant to jump to decisions, others have urged that decisions — right or not — have to be made.
“Recently, the market has been thrown upside down,” said Scott Taylor, vice president at generation developer Moxie Energy. “I think the political risk is a big issue that even if it gets sorted out, there’s an overhang with what’s the next attempt?”
Taylor, whose company focuses on gas-fired generation, was referring to the Department of Energy’s recent proposal to provide price supports for coal and nuclear resources. He said that the Notice of Proposed Rulemaking and state subsidies for nuclear units known as zero-emissions credits (ZECs) have shut down investment. Three states — Illinois, New York and Connecticut — have instituted ZEC programs.
Michael Ferguson, director of U.S energy infrastructure for Standard & Poor’s, said the financial woes for such large-scale units hasn’t been a surprise.
“You can almost see it in slow motion where you know there’s a problem out there,” he said. “It’s been playing out in slow motion for a long time.”
Scalpels and Sledgehammers
Surprising or not, the issue has created enough market fervor that the conference featured a debate between Joe Bowring, PJM’s Independent Market Monitor, and Kathleen Barron, Exelon’s senior vice president of competitive market policy. Exelon’s nuclear facilities are the beneficiary of the ZEC programs in both Illinois and New York.
The debate focused on the minimum offer price rule (MOPR), which screens capacity auctions for subsidized bids and exchanges them for class-specific standardized offers. In current market conditions, the restated bids effectively ensure that such bids don’t receive capacity obligations and inappropriately suppress the clearing price.
Responding to criticism of the rule, Bowring said he has “yet to hear one iota of evidence” of it hurting market participants. “It’s very much not a sledgehammer; it’s very much a scalpel,” he said.
Barron questioned the timing of concerns. “We didn’t have a minimum offer price rule for renewables. … Why do we suddenly care about it when it’s nuclear?”
She noted that the ZEC payments can adjust downward to reflect changing market conditions, but Bowring countered that they never adjust negatively to pay consumers back.
“Clearly, there’s an efficient way to deal with carbon,” he said. “This is an inefficient way to handle it.”
Barron said the programs allowed states to prevent backsliding on emissions levels until they can develop long-term policies.
“Versus the replacement cost of bringing on new generation that’s clean, [the ZEC payment] is a bargain,” she said. “It’s cheaper to keep them than to let them go. … You need to have an objective way to value what you care about, and once you do that, you let the chips fall where they may.”
Plants that still can’t cover their costs after receiving carbon valuations should then retire, she said.
Taylor said his company is not interested in developing renewable resources because the field has “too many players in it right now” and remains “real estate heavy.”
Andrew Rosenbaum, a managing director at RBC Capital Markets, agreed that renewables can’t support themselves.
“No one’s really building merchant renewables,” he said. “How many of the various support mechanisms do you get your arms around is an interesting question.”
Jim Guidera, who heads Credit Agricole CIB’s energy and infrastructure group, noted that potential for corporate taxes reductions under President Trump has made it harder to make deals because there could be less benefit for writing off failed projects.
“Elections matter,” he said. And with gas remaining at low prices, “it’s a tough model.”
That low gas is stifling innovation, according to Abe Silverman, deputy general counsel at NRG Energy.
“When prices are high, we incent creativity and we incent innovation. With the shale gas revolution, the price to beat is too low right now,” he said. “I think we need to raise the price to drive decarbonization.”
Silverman debated with Scott Vogt, vice president of energy acquisition at Commonwealth Edison, over who should control engagement with end-use customers. With incumbent utilities solely allowed to consolidate charges into a single bill, “we’re basically competing for one line on the bill,” Silverman said.
Vogt countered that retail suppliers are able to send separate bills if they prefer and in fact asked utilities to bill for them.
HERSHEY, Pa. — From societal benefits to electricity market design concerns to regulatory issues, it’s clear that a decade of shale gas production has had a major impact that extends well beyond Pennsylvania’s borders, panelists said last week during a power industry seminar focusing on the Marcellus shale.
“It only seems appropriate to hold a discussion on competitive markets in a region that has one of the most impactful disruptions in the energy sector in recent history,” NRG Energy CEO Mauricio Gutierrez said at “Decade of Disruption: Marcellus Shale and Regional Energy Markets,” an electricity conference organized by John Hanger, a former Pennsylvania state utility regulator and environmental secretary during the early stages of Marcellus development from 2008 to 2011.
Gutierrez noted that the “shale gas revolution” has “changed the landscape” of the power generation industry and manufacturing in the U.S.
Philadelphia Gas Works CEO Craig White said one of the biggest advantages of shale gas for his company has been sustained low prices, which have allowed for investment in infrastructure.
“The biggest problem we had [before] is prices would spike above oil,” which reduced demand, White said. Low prices have allowed his gas delivery utility to replace aging distribution pipes while still lowering customer rates.
While shale gas has been an “unequivocal win for retail consumers … it’s also been a win for electric power customers,” said Christina Simeone, director of policy and external affairs for the University of Pennsylvania’s Kleinman Center for Energy Policy. “The electric power sector is really where prices dropped the most.”
Increased reliance on gas is leading the power sector down the right path for decarbonizing the country’s economy, according to Risky Business Project research reviewed by the World Resources Institute’s Karl Hausker.
By transitioning energy consumption from fossil fuels to electricity, decarbonizing electricity production, and finally driving through any efficiencies developed along the way, the U.S. can reduce carbon dioxide emissions by 80% by 2050, Hausker said. But generators needn’t worry about betting the farm on renewables. If done correctly, it’s “an incredible growth opportunity for the electric power sector,” he said.
“It’s crazy to shut down a safe nuclear plant if it’s producing at a reasonable cost,” he said. “We are still [projected to be] using a lot of natural gas in 2050. … It is a key bridge fuel.”
While the Risky Business Project plan calls for hundreds of billions per year in infrastructure spending over the next 30 years, Hausker said the impediments are largely political, such as opposition to siting substantially more generation and transmission infrastructure.
“Technologically, we can do this. … Economically, the cost is manageable,” he said. “We really need to put the pedal down hard and really come up with better business models. … If you’re serious about [addressing] climate change, we have to build out the power sector, so please, tamp down the NIMBYism.”
The plan also “needs to be resilient in the face of falling fossil fuel prices,” he said, because International Energy Agency modeling indicates that by 2050, oil and coal prices will drop by 40% and gas by 33% compared to reference prices.
“Whatever we do, we’re going to need to expand the transmission system a lot too,” he said.
While speaking on a separate panel, ISO-NE CEO Gordon van Welie contended that expansion is more a challenge on the pipeline side than the wires side in his region.
“Quite frankly, it’s not likely. We’ve got as much pipe as we’re ever going to see in New England,” he said. “But for the fuel security issue, we’ve actually been a pretty reliable grid. … There’s hardly any congestion left in New England.”
Pennsylvania Public Utility Commissioner Andrew Place supported decarbonizing through the electricity industry. “If we are going to tackle our climate goals … the best way to do that is through our energy markets,” he said.
Who will lead the effort to decarbonize generation remains to be seen. As panel costs have plummeted, solar arrays combined with energy storage systems “can actually beat” gas-fired generators on price alone without factoring in renewable energy credits (RECs), Community Energy CEO Brent Alderfer said. The issue, he said, is getting long-term power commitments. “For some reason,” gas plants have been able to secure long-term investment based on short-term price signals while renewables have not, he said.
“The only folks that have taken a generation facility and turned it into what Facebook wants, which is a 15-year delivered power renewable contract, are cost-of-service utilities.”
Another panel discussion featured a debate on recent state and federal actions to promote large-scale, zero-emission production from nuclear plants.
NRG’s Abe Silverman argued that states, including Illinois, New York and — as of last week — Connecticut, have committed more than $10 billion to support aging nuclear generation that is too expensive to clear energy auctions, while new renewable development could produce the same power for half the price. He called for a process to identify the desired attributes (such as zero emissions) and value it so competitors can develop novel solutions to address them.
“Let’s compete for carbon production, not just hand it out on a no-bid contract,” he said.
Kathleen Barron of Exelon, the beneficiaries of zero-emission credit (ZEC) programs in Illinois and New York, argued the inverse, calling ZECs “short-term programs designed to bridge the gap” for states to develop carbon policies.
“It’s cheaper to keep the current fleet going than it is to build new renewables,” she said. “They are competitive [in markets] if you factor in the cost of the avoided emissions.”
Van Welie said he supported ZEC programs.
“It’s about jobs. I don’t know how you solve that problem through market design,” he said. “The New England states want to control the speed at which they go down the path of decarbonization. Given all the constraints on the system, that’s a pretty innovative outcome.”
PJM CEO Andy Ott reiterated his RTO’s position that subsidies suppress prices in competitive markets.
Ott and van Welie mutually opposed any single-solution federal mandates, such as the price supports for coal and nuclear units recently proposed by the Department of Energy. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)
“It’s not going to be productive for us to be forced to work on Andy’s problem or for Andy to be forced to work on our problem,” van Welie said. “We’re not going to build more coal in New England, so having a discussion about building more coal in New England is a pointless exercise.”
“The issues we’re facing are unique to our fleet. The issues Gordon’s facing are unique to his fleet,” Ott said.
The two CEOs agreed that the solution is defining and valuing attributes. PJM has run into problems posting negative prices to reduce wind production when there is oversupply because it harms large, inflexible baseload units dispatched earlier in anticipation of upcoming demand spikes. The RTO has proposed defining a “load following” attribute for the ability to adjust output as necessary and pay units to do so.
Pennsylvania’s deregulation 20 years ago was just the first step, said Jim Steffes, executive vice president for North American corporate affairs at Direct Energy.
“It wasn’t about design in 1997. It was about stranded cost recovery for utilities,” he said.
With consumers now holding increased technological power, such as through smart meters and other ways to monitor and control power use, they are much better equipped to engage directly with their retail supplier. For example, smart thermostats have been shown to reduce usage by 10%, Steffes said, and “it’s not forced conservation.” Yet, incumbent utilities maintain control of the customer interaction.
“Why do we still have this irrational, noncompetitive player in the market?” he asked. “The fact that we don’t know even know if they’re competitors or not creates a barrier.”
“We really have to get the utility out of the place of being the gatekeeper,” said Mike Starck, general manager of NRG’s northeastern retail business.
NRG’s Gutierrez had kicked off the conference on that issue, calling for four reforms in Pennsylvania by 2020. He argued that all “business transactions,” such as customer switches and sharing meter consumption data, should be standardized and routed through PJM, and that competitive suppliers should be allowed to compile all fees and send customers a single bill that includes utilities’ distribution charges, an idea known as supplier-consolidated billing. Currently, only utilities have that ability and suppliers must send a separate bill if they want to bill directly.
“It is essential to unlocking innovative payments and bundled products,” he said. “Consumers demand simplicity and convenience. They want a single energy bill that includes not only the energy needed to keep their lights on and houses warm, but also the other products and services that they need provided to them, whether it’s home security or energy efficiency devices.”
Gutierrez also called for defining and valuing necessary generator attributes and adjusting utilities’ tariff structures to prohibit them from offering retail products or generation.
The Department of Energy’s proposal to provide “full recovery” of coal and nuclear plant costs in RTOs with capacity and energy markets was short on details, notably providing no estimate of the cost of such policies.
But PJM’s Independent Market Monitor and several other stakeholders have published estimates ranging from $300 million to more than $32 billion. (See related story, Critics Slam PJM’s NOPR Alternative as ‘Windfall.’)
In its response to the DOE proposal, PJM’s Monitor estimated the NOPR would cost ratepayers in the RTO $3 billion annually — equal to 36% of capacity payments in 2016 — if nuclear and coal units were all paid 25% of current replacement value. (The current replacement value of a coal plant is $1,434/MW-day and that of a nuclear plant is $2,639/MW-day. In contrast, the gross cost of new entry for a combustion turbine is $312/MW-day and a new combined cycle is $406/MW-day.)
The cost would rise to $13 billion — a one-third increase in the total cost of wholesale energy — if nuclear and coal units were paid 50% of replacement value.
If the units received full replacement value, the price tag would rise to $32 billion — an 84% increase in total wholesale energy costs.
Robert Chilton, executive vice president of Gabel Associates and a former New Jersey regulator and consumer advocate, told FERC he calculated the NOPR would result in increased costs of about $7.1 billion annually for the first five years. Gabel mostly represents generators in PJM.
Chilton cited cumulative costs of between $35.4 billion ($28.9 billion net present value) and $100.8 billion ($64.1 billion net present value) over a five and 15-year term, respectively. His analysis assumes all fixed and variable costs are recovered by the eligible generators and all incremental net revenues are returned to customers.
Four Scenarios
A separate analysis, by the Climate Policy Initiative and Energy Innovation Policy & Technology, put the nationwide cost of the NOPR at between $300 million and $10.1 billion annually, based on which of four scenarios are used. (Energy Innovation is devoted to supporting policies “that most effectively reduce greenhouse gas emissions.” The Climate Policy Initiative seeks to improve energy and land-use policies to “help nations grow while addressing increasingly scarce resources and climate risk.”)
The upper-band estimate by two clean energy organizations projects coal generators would receive $3.5 billion in out-of-market costs, while nuclear plants would receive $6.6 billion, benefiting a handful of companies. | Climate Policy Initiative and Energy Innovation Policy & Technology
Their analysis assumed the NOPR would include PJM, ISO-NE and NYISO, which have mandatory capacity markets, as well as MISO, whose capacity market is voluntary.
The $300 million lower-band estimate assumes units with negative net cash flows (energy and capacity market revenue, minus the sum of fuel, variable and fixed operations and maintenance, and annual capital expenditures) receive uplift payments to bring their net revenue up to zero.
The $10.1 billion upper-band estimate assumes covered units would receive all their fixed operation and maintenance, full recovery of undepreciated past capital expenditures and ongoing capital expenditures, at a guaranteed rate of return, on top of energy and capacity market revenues. It also assumes payments to all coal and nuclear units in the RTOs — not just those with negative cash flows — and that coal plants will increase generation to their maximum output. (Nuclear units generally already run at maximum output.)
Small Number of Winners
About $7.3 billion of the $10.6 billion would be paid by PJM ratepayers, raising the RTO’s total costs by 17%. “Spreading the incremental costs evenly over the 65 million people served by PJM results in an increase of $112 per person per year (though this probably is not how costs would be passed through),” the report said.
In both the high and low scenarios, nuclear plants account for two-thirds of the out-of-market payments.
Under all four scenarios, more than 80% of the coal subsidies would go to five companies, with NRG Energy’s revenue boosted by $40 million to $1.2 billion annually, and FirstEnergy and Dynegy seeing an increase of up to $500 million each.
Exelon would receive half of the nuclear subsidies, as much as $3.6 billion. Other winners would include Entergy and Public Service Enterprise Group.
Depending on the final rule, the NOPR could also bring 2 to 4 GW of recently retired plants back into service, resulting in additional costs of $113 million to $228 million annually. “While costs represented here are annual, they could continue in perpetuity, since generators would now have no reason to retire,” the report said.
FERC last week denied Public Citizen’s request for rehearing on Entergy’s sale of the James A. FitzPatrick nuclear plant in New York to Exelon. The commission dismissed as “irrelevant” the group’s concerns about the impact of the state’s zero-emissions credits (ZECs) on either Exelon’s market power or the broader NYISO energy and capacity markets.
James A. FitzPatrick Nuclear Plant
The commission authorized the sale last December over Public Citizen’s protests, saying the issues raised concerned the effects of the ZEC program rather than the impact of the plant sale on competition, rates, regulation or cross-subsidization.
In its rehearing request, Public Citizen argued that the commission had “committed errors of fact by inaccurately reporting the nature” of its protest, which “plainly and repeatedly raised the connection between the proposed transaction and the ZEC” program.
The commission’s Oct. 24 order (EC16-169-001) said that “under commission precedent, issues unrelated to the commission’s analysis of a proposed transaction under [Federal Power Act] Section 203 should be addressed in other proceedings or forums. Further, Public Citizen offers no analysis regarding how the [sale] would affect wholesale markets, with or without the ZEC program.”
WILMINGTON, Del. — Consumer representatives and the Independent Market Monitor expressed concern Thursday over PJM’s plans for vetting energy offers exceeding $1,000/MWh, with the Monitor seeking manual changes and consumer groups fearing excessive demand response costs.
The issues arose during a discussion at the Markets and Reliability Committee meeting on changes to Manual 11: Energy & Ancillary Services.
The manual changes, part of PJM’s implementation of FERC Order 831 (RM16-5), passed with 13 objections and two abstentions after Catherine Tyler, senior economist for Monitoring Analytics, reiterated complaints the Monitor filed with the commission in response to the RTO’s May 8 compliance filing on the order.
The order doubled the “hard” offer cap for day-ahead and real-time markets from $2,000/MWh — a response to the 2014 polar vortex, which caused natural gas price spikes that left some generators in the Northeast complaining they were unable to recover their costs. Incremental energy offers must be capped at the higher of $1,000/MWh or a resource’s cost-based energy offer, with $2,000/MWh being the maximum offer eligible for setting LMPs; approved offers over $2,000 are eligible for uplift payments.
The Monitor said PJM’s plan does not follow the order’s requirement that RTOs build on existing mitigation processes in verifying that offers above $1,000 are based on actual or expected costs and does not mention the Monitor’s role in that process.
“We will review offers over $1,000,” said Tyler. “The manual should make that clear.”
The Monitor told FERC that PJM instead “proposes to create a new cost-based offer verification process,” does not provide a way for verifying cost-based offers that fail its automated screen and lacks a process for verifying DR offers over $1,000. It said the commission should require “a new proposal that builds on existing cost verification processes, including the Market Monitor’s cost verification process and fuel cost policies.”
Greg Poulos, executive director of the Consumer Advocates of PJM States, requested the vote on Manual 11 be conducted separately from three other manual changes, saying the Monitor should have joint approval with PJM of energy offers over $1,000.
It was the DR issue that concerned Susan Bruce, of the PJM Industrial Customers Coalition. She said although her group is “a big supporter of demand response … we’re concerned we don’t have the same rigor” in ensuring the cost inputs in DR offers as for generation.
The lack of rules creates “opportunities for strategic behavior,” Bruce said.
PJM’s Pete Langbein said that although the RTO has considerable experience in verifying generation offers, “we’re a little bit in uncharted territory” for DR. He said PJM wants to analyze “what costs we see from DR in the next six to 12 months” before creating rules.
Bruce agreed it would be difficult to guess what costs DR providers will file but said that during the interim, “customers will be vulnerable” to potentially inflated and improper costs.
Langbein said PJM will address the issue in the stakeholder process and deal with offers in the interim on a “case-by-case basis.”
Bruce Campbell of CPower said he supported the RTO’s approach. “It’s difficult for me to imagine a standard that would be workable at this point beyond what PJM has outlined.”
PJM’s Chantal Hendrzak added that the RTO wants to wait for FERC’s response to its compliance filing before implementing standards. The rules will not go into effect until the RTO receives the commission’s response, she said.
The New Jersey Board of Public Utilities filed comments supporting the Monitor, saying, “PJM’s filing appears to be yet another attempt by PJM to minimize the role of the IMM.” The Delaware Public Service Commission called on FERC to reject PJM’s filing, saying its formulaic screen is unsupported and would result in higher prices than verifying all offers above $1,000.
PJM responded to the Monitor’s comments in June, reassuring FERC that all cost-based offers must be in accordance with the market seller’s RTO-approved fuel-cost policy, “including the IMM’s review of such policies.” The RTO said the proposed screen is “an additional safeguard” to ensure only legitimate generation offers greater than $1,000 are eligible to set LMPs.
WILMINGTON, Del. — State and consumer representatives grilled PJM officials Thursday over proposed changes to price-responsive demand (PRD) bids, with the head of the Organization of PJM States Inc. accusing the RTO of flouting the 2005 Energy Policy Act.
PJM says PRD bids should be available year-round, the same as generation resources under Capacity Performance rules. But OPSI argues they should be allowed the option to make only seasonal contributions because PJM’s summer peak loads exceed winter peaks by more than 20,000 MW.
“What problem are you trying to solve?” asked OPSI Executive Director Gregory Carmean at Thursday’s Markets and Reliability Committee meeting. “The states obviously would like to see the effectiveness of their demand-side programs reflected in PJM’s load forecasts.”
PRD — a program that lets customers agree to reduce their loads in response to energy prices in exchange for reduced capacity requirements — was developed during 2010-12, before CP rules changed the requirements for demand response. It requires dynamic retail rate structures and advanced metering. PRD providers — electric distribution companies, load-serving entities or curtailment service providers — must be able to remotely curtail load when a PJM maximum emergency event has been declared and LMPs exceed trigger prices.
Because PJM approved its first PRD plans for the 2020/21 delivery year, it must now bring the rules in line with CP, the RTO says.
Thursday’s discussion came during a first reading of three proposals developed by the Demand Response Subcommittee.
The RTO’s proposal would extend DR’s annual requirements to PRD. A second proposal would limit the triggers for assessing CP penalties to just penalty assessment intervals. The third, from DR-participant Whisker Labs, would extend the existing PRD rules to the winter, create a summer-only product and allow it to be aggregated with a winter resource for an annual CP resource.
Carmean said PJM was acting in “direct contradiction of Congress’ intent” in the Energy Policy Act of 2005, which said that DR “shall be encouraged” and “unnecessary barriers to demand response participation in energy … markets shall be eliminated.”
“I have not gone back to read the law,” said PJM’s Pete Langbein, who presented the proposals, which the RTO plans to bring to an MRC vote next month. But he said PJM had made modifications to its monitoring and verification rules and expanded regions to ease requirements for DR. “We are continuing to work on this in the seasonal task force,” he said, referring to the group being created as a result of a problem statement and issue charge approved by the MRC in August.
Greg Poulos, executive director of the Consumer Advocates of PJM States, said he shared Carmean’s concerns. “Residential customers can no longer participate in this program,” he said. “Customers are kind of getting the short end [of the stick].”
“It seems to be a different product now,” added Morris Schreim, senior adviser to the Maryland Public Service Commission.
Carmean said the changes could mean “stranding hundreds of millions spent on [advanced metering infrastructure] meters. … OPSI believe the PRD program as it exists today should be allowed to continue.”
Earlier this month, OPSI drafted a resolution calling on PJM to postpone the imposition of annual resource requirements on PRD “until it has implemented an improved mechanism for summer seasonal resource participation in excess of winter seasonal resource participation, or until such time that winter reliability requirements equal or exceed summer reliability requirements.” (See “OPSI, PJM at Odds over PRD,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)
On Friday, PJM CEO Andy Ott responded with a letter to OPSI. “PJM agrees demand response resources are valuable, and we seek ways to have them receive compensation in accordance with their contribution to reliability,” Ott said. “For seasonal resources that do not participate as Capacity Performance resources, the new stakeholder group will explore measures to value their contribution to grid reliability.”
WILMINGTON, Del. — PJM members approved a Tariff revision setting 78.5% as the balancing ratio to be used in calculating the default market seller offer cap (MSOC) for the 2021/22 Base Residual Auction next May.
PJM said the change was a stopgap measure required for next year’s BRA because there have been no penalty assessment hours (PAHs) since 2015. PAHs are one factor used to calculate MSOC for Capacity Performance resources. (See “Give me a B…,” PJM MRC/MC Briefs.)
The Tariff change passed with no opposition but 10 abstentions.
The MSOC is the product of the net cost of new entry (CONE) and the average of the balancing ratios for the three years preceding the delivery year. PJM proposed using 78.5% because it was used for the 2020/21 BRA earlier this year.
“I’m not sure how you got here,” said Gary Greiner of PSEG Energy Resources & Trade. “I do know 78.5 is not the right number.”
Susan Bruce of the PJM Industrial Customers Coalition agreed that the stopgap number was not correct. “I think there’s something to be said for the fact that there have been no performance assessment hours. That should be telling us something, but that’s part of a larger conversation,” she said.
The Independent Market Monitor’s Catherine Tyler also criticized the number as incorrect. She said PJM should instead rely on its avoidable cost rates, which she said is “already well defined in the Tariff.”
With one abstention, members also approved a problem statement and issue charge to develop a long-term solution. The issue was assigned to the Market Implementation Committee with a target of developing a solution in time for the 2022/23 BRA.
Bruce asked that PJM make clear in its FERC filing that the 78.5% balancing ratio is “not to be precedential in any fashion.”
DER Subcommittee Charter Sent Back to MIC
The MRC postponed voting on a draft charter to transfer all work on distributed energy resources into a subcommittee because of a disagreement over a proposed amendment by FirstEnergy.
The charter would create the Distributed Energy Resources Subcommittee, reporting to the MRC. It arose from concerns that the current problem statement and issue charge on DER is overly narrow and inhibited discussions that should include markets, operations and planning implications. The talks had been taking place in special sessions of the MIC.
FirstEnergy sought to add an amendment saying “Market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the relevant electric retail regulatory authority (RERRA).” (See “Amendment on DER Charter Sparks Debate,” PJM MRC/MC Briefs.)
MRC Secretary Dave Anders said that some stakeholders thought the amendment had been considered in the draft that came out of the MIC-DER group and others did not. The MIC did not formally vote on the measure.
As a result, the charter will be returned to the MIC, which will vote on versions with and without the amendment, with the winner brought to an MRC vote next month.
MRC OKs Sharing Generator Data for Restoration Planning
Members approved Operating Agreement revisions governing PJM’s sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)
The changes will allow PJM to provide confidential generator data for any unit:
that is or will be modeled in TO energy management system; and
that is or will be identified in a TO restoration plan.
The second reference to “or will be” was added as a correction between the first read and Thursday’s vote. The corrected version was endorsed with no objections or abstentions.
PJM Chief Financial Officer and MRC Chair Suzanne Daugherty informed members that the RTO’s consulting subsidiary, PJM Technologies, has signed a contract to help the Chinese province of Zhejiang develop a real-time energy market.
Daugherty declined to share financial details of the contract but said it will involve three to four full-time equivalent PJM staffers for 18 months. The province, south of Shanghai, has a load equal to almost half of PJM’s.
For security, the PJM employees will be working on dedicated computers separate from the RTO’s network, Daugherty said.
IRM, Manuals Endorsed
The Markets and Reliability Committee unanimously approved the 2017 installed reserve margin (IRM) study results. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)
The IRM dropped nearly 1 percentage point, from 16.6% to 15.8%, for delivery year 2021/22, thanks largely to an anticipated fleet-wide EFORd (equivalent forced outage rate – demand) reduction from 6.59% to 5.89%. EFORd measures the probability a generator will fail completely or in part when needed.
The reduced EFORd is the result of 7,150 MW in planned retirements with a 14.56% weighted average EFORd, and the anticipated entry of 16,980 MW of new generation with a 4.42% EFORd.
The IRM will be 16.1% for 2018/19 and 15.9% for 2019/20.
The MRC also endorsed the following proposed manual changes with one abstention and no objections:
Manual 11: Energy & Ancillary Services. Revisions, which also include changes to the OA and Tariff, were developed to address capping of intraday offers. The current rule offer caps units that fail the three-pivotal-supplier test, but prohibits reapplying the cap during the unit’s day-ahead commitment or minimum run time. The changes would re-evaluate capped units when offers are updated. The changes would also apply to self-scheduled resources. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)
The Members Committee unanimously approved the IRM study results, the Tariff changes for the balancing ratio, and changes to Manuals 11, 14B and 19 approved earlier by the MRC. (See descriptions in MRC briefs above.)
The committee also approved Tariff and Operating Agreement revisions to clarify definitions, as recommended by the Governing Document Enhancement & Clarification Subcommittee.
