CARMEL, Ind. — MISO last week laid out a more detailed proposal for how it will determine the capacity accreditation of electric storage resources under FERC Order 841.
The RTO is proposing to determine electric storage resources’ capacity based on two different measurements: the resource’s power output capability and its energy storage capacity as measured by MISO’s generator verification test capacity (GVTC).
Speaking at an Aug. 8 Resource Adequacy Subcommittee meeting, Senior Adviser of Capacity Market Administration Rick Kim said the rule will ensure both a megawatt and megawatt-hour measurement of a storage resource’s capability.
Kim said for storage resources under 10 MW or that have fewer than 12 months of operational data, MISO will apply a 5% default equivalent forced outage rate in its unforced capacity calculation. Other storage resources will be assigned a forced outage rate based on their quarterly data inputs to MISO’s generating availability data system (GADS). GADS reporting is required for storage resources 10 MW and above and optional for those under 10 MW.
Because NERC hasn’t yet addressed unit reporting for storage resources, Kim said resource operators should use the “miscellaneous” unit type option when reporting unit data.
“It’s going to be another year before we see registration of energy storage resources,” he added.
Kim also said storage resources connected to the transmission system will require either network resource interconnection service or firm transmission service with MISO to ensure capacity deliverability. If resources are connected at the distribution level, MISO will ensure deliverability with the distribution provider and transmission owner on a “case-by-case” basis, he said.
MISO has said that when storage resources are connected at the distribution level, market participants “must have sufficient metering or accounting for non-wholesale transactions to prevent double counting of energy.”
The RTO in June said it would accommodate Order 841 by dividing storage bid parameters into four operating modes: discharging, charging, continuous operations and offline. Market participants will be left to choose a mode for individual dispatch intervals and will also be responsible for managing the state of charge of their storage units. (See MISO Weighing Feedback to Storage Proposal.) Storage resources will be able to set prices under MISO’s extended LMP.
MISO and stakeholders will continue to discuss storage capacity accreditation at the September RASC meeting, with draft Tariff language targeted for October. November will be used to finalize the full Order 841 compliance filing before FERC’s early December filing deadline.
Oklahoma City-based OGE Energy said last week that a strong regional economy and positive regulatory developments led to an improved second quarter for the company, which reported earnings of $110 million ($0.55/share), compared to $105 million ($0.52/share) the year prior.
Earnings just missed Zacks Investment Research’s consensus estimate of 57 cents/share.
OGE’s Sean Trauschke | YouTube
CEO Sean Trauschke said Oklahoma Gas & Electric continues to add customers near its historical average of 1%, the state’s unemployment numbers are at or under the national average and tax revenues are “now growing solidly again.”
“We are seeing growth on our system driven by our low rates and quality service. I’m very proud of our team’s work to deliver this competitive advantage to the communities we serve,” Trauschke told financial analysts during an Aug. 9 conference call.
“Our core is solid, our employees are doing a great job, and we’re effectively executing on our plans across every area of the company,” he said.
OGE Assets | OG&E
OGE in June reached a $64 million settlement with the Oklahoma Corporation Commission that provides full recovery of its investment in the newly converted Mustang Energy Center. The plant’s seven gas-fired combustion turbines have had more than 1,200 starts this year, Trauschke said.
Mustang Energy Center | OG&E
OGE Energy Holdings, which includes OGE&’s 25.6% limited partner interest and 50% general partner interest in Enable Midstream Partners, contributed 11 cents/share to earnings and $35 million in cash distributions.
“Enable continues to perform very well and their financial metrics are strong,” Trauschke said. He told analysts OGE has not changed its thinking around how the petroleum-gathering company is organized.
CARMEL, Ind. — MISO’s market was competitive in 2017, but the RTO should do more to address increasing congestion and low capacity prices, Independent Market Monitor David Patton told stakeholders last week.
Patton said potential economic withholding throughout the year was low, at about 0.11% of load, with market power mitigation rarely necessary.
“The offers we’re getting and the market outcomes are very competitive,” Patton said in a 2017 post-mortem during an Aug. 9 Market Subcommittee meeting, part of his annual State of the Market report. In late June, he recommended seven new market revisions from the report to the Board of Directors. (See 7 New Recommendations from MISO IMM.)
Patton said MISO’s 2017 peak load of about 121 GW was comparable to the nearly 120-GW peak in 2016 and below the forecasted 125-GW peak. However, congestion costs last year still rose 7% to $1.5 billion, in part because of higher natural gas costs for frequently dispatched gas units.
Patton said four key factors have increased the RTO’s costs of managing congestion.
Factor 1: Lack of Market-to-Market Testing
Patton faulted MISO for not requesting testing from other markets to define market-to-market (M2M) constraints for congestion management. He said his team identified almost 170 chronically binding constraints costing $240 million in 2017 that were never classified as M2M, “generally because MISO did not ask for testing.”
“Most of those dollars are because MISO didn’t ask for the test from either PJM or SPP,” Patton said. “When you don’t define market-to-market constraints with your neighbors that are impacting them, then you’re basically subsidizing their flows on the constraint. You don’t go through the settlement process that would bill them for the constraint.”
Patton acknowledged that the RTO put a tool in place in January to screen for potential constraints, but he said his team has not yet assessed the results of the new practice.
Factor 2: Keeping the Current Pseudo-tie Construct
Patton again leveled his aim at the pseudo-tie process and said PJM’s dispatching of the RTO’s resources has to date resulted in 95 new M2M constraints and $155 million in congestion on those constraints.
“It’s no surprise that we think PJM’s Tariff … shows a lack of understanding of how to run an electrical system,” Patton said, adding that PJM cannot effectively model all constraints in the day-ahead market and is overscheduling flows on the MISO system.
“We think it’s unfortunate that FERC hasn’t figured out how bad this is yet,” Patton said, adding that there are other ways for MISO to deliver PJM’s purchased capacity without giving it dispatch control over resources located in MISO. He said he hoped more of the RTO’s market participants would come out in public support of the complaint.
Factor 3: Need for Increased Outage Coordination
Patton said transmission and generation outages occurring simultaneously on the same constraint have contributed to $400 million in congestion to date — more than 30% of all of MISO’s real-time congestion.
“What this points to is the need to give MISO more authority in denying or approving outages,” Patton said. “In some cases, MISO is the only one that can coordinate these because of the lack of communication between generation and transmission.”
Greater outage coordination is an ongoing discussion in the RTO’s larger effort around resource availability and need currently being discussed in its Reliability Subcommittee. (See MISO Moving to Combat Shifting Resource Availability.)
Factor 4: Incomplete Facility Ratings
Patton said most of the RTO’s transmission owners don’t adjust their facility ratings to reflect ambient temperatures and wind speeds. He said adjusted facility ratings could have saved the RTO as much as $127 million in production costs in 2017.
“If transmission owners submitted dynamic ratings to MISO, we’d have much more transmission capability,” Patton said.
Capacity Auction
Patton also said the RTO’s capacity auction design is causing capacity prices to remain “inefficiently low.” The 2018/19 auction resulted in almost all local resource zones clearing at $10/MW-day, while the 2017/18 auction resulted in a single clearing price of $1.50/MW-day. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)
Had MISO implemented a sloped demand curve design in its auction, Patton estimated that auction clearing prices would have been $115.74/MW-day in all zones in the 2017/18 planning year and $111.06/MW-day in nearly all zones for the 2018/19 planning year. He said the RTO’s competitive suppliers stand to benefit the most from a sloped demand curve.
Patton said the RTO lost 2.6 GW of capacity on net in 2017 owing to a flawed capacity auction design, “persistent” low natural gas prices that suppress energy prices and environmental regulations “requiring costly retrofits for certain resources.”
MISO Response Timed to Market Roadmap
MISO Executive Director of Market Operations Shawn McFarlane said the RTO is still preparing its required response to the Monitor’s observations and recommendations.
He said this year MISO will align its written response with the release of the RTO’s Market Roadmap list of market improvements to its board. The RTO will publicly post a written response in October, present the response at the November Market Subcommittee meeting and discuss it with the board at the December meeting of its Markets Committee.
“This year we will use most of the 120 days allotted by the Tariff,” McFarlane said, adding that the RTO has historically provided a written response within 90 days.
MISO Charts Market Improvements with Stakeholder Help
Meanwhile, MISO is continuing its Market Roadmap prioritization to determine what improvements it should undertake in 2019. Unofficial Market Roadmap rankings show that the RTO and stakeholders agree that creating short-term capacity reserves is a pressing matter.
MISO melded its market improvement priorities with the Monitor’s and stakeholders’ rankings after a June and July voting period in which 67 stakeholders participated. (See MISO Stakeholders to Rank Market Improvement Ideas.) The preliminary results show the RTO should next year focus on creating an improved combined cycle generation model and developing a short-term capacity reserve product that can supply capacity within 30 minutes.
NEW YORK — NYISO CEO Brad Jones likely summed up the sentiments of the dozens of industry experts attending Infocast’s New York Energy Market Summit last week to learn more about the state’s rapidly evolving grid and changing policy landscape.
“All of us seem so thankful to be in this industry at this time,” Jones said. “There’s so much change going on, so much opportunity to do new things and create new things.”
Kevin Sheen, vice president of business development at Terra-Gen, said New York began falling behind other states in renewable development despite having started a 10-year renewable energy credit (REC) program in 2004 that managed to incent about 1,400 MW of wind over the past decade or so.
Realizing it needed to do more, the state last year began offering 20-year REC contracts, Sheen noted. He said that the state’s commitment to improve transmission signals to developers that New York is worthy of their investment and time. The ISO’s Congestion Assessment and Resource Integration Study process identifies the top congestion elements on the system and indicates where developers ought to be thinking in terms of building additional transmission. (See NYISO Study Identifies Key Areas of Tx Congestion.)
“Delays are part of development — they happen in every market — but I think New York has done the best they can to try to address that,” Sheen said.
Transmission developers cited permitting and interconnection costs as the two biggest risks for new project development.
“We recently saw Deepwater Wind narrowly get through the East Hampton town board process by a 3-2 vote, so five individuals held the fate of that 90-MW cable” connecting the offshore project to land, Anbaric Development Partners project manager Bryan Sanderson said.
Bringing 2,400 MW into NYISO Zones J and K is going to be hard because the ISO’s study process takes three to five years, Sanderson said, leaving companies to bid today on costs they will not know until 2022.
“Imagine New York procuring its first offshore wind farm and the interconnection costs come in $500 million more than projected,” he said. “That would be a huge embarrassment. Just ask Massachusetts about their Northern Pass experience.
“One problem with transmission development is that it eats its own young, so you solve the problem like congestion and the price arbitrage disappears,” Sanderson continued. “How do you pay for your line when your mere existence eliminates your profit stream?”
John Douglas, CEO of transmission developer oneGRID, noted there’s been talk of developing a national backbone grid to optimize renewables, but no one has resolved the problem of who will pay for it and how all the RTOs would interact.
“It’s unfortunate, because we’re going to end up with all these regional, Band-Aid optimizations when there could be something national,” Douglas said.
Jones addressed the conflict between state policies and RTO market principles, pointing out that both ISO-NE and PJM went to FERC with solutions to what they saw as state interventions that could undermine their wholesale markets.
“When New England brought CASPR [Competitive Auctions with Sponsored Policy Resources] to the commission, they said, ‘We want to address it in this way,’ essentially to change the capacity market structure, which would arguably eliminate the impact of state subsidies on new resources,” Jones said.
“The FERC agreed with them, but in a decision which I never knew was possible. They approved 3-2,” Jones said. “Clearly the FERC was torn; they struggled with that decision.” (See Split FERC Approves ISO-NE CASPR Plan.)
Jones said the commission saw ISO-NE’s solution as being different from PJM’s rejected solution in that the former was dealing only with new assets that were being subsidized, while the latter was dealing with both new and existing assets, primarily nuclear and coal units.
“New York looks very similar to PJM, with assets that have been retained, plus new assets, but FERC has not decided to take any action on New York,” Jones said. “I think the commission is waiting to see where the NYISO gets on its work to price carbon directly into the wholesale market.” (See Stakeholders Annoyed by NYISO Carbon Price Draft.)
Off the Grid
Douglas said he realized how most large industrial customers are looking for change when he heard that a survey by one of the nation’s largest utilities found that its top 15 customers all want to get off the grid.
“Imagine you’re an integrated, investor-owned utility and your top customers are all saying they don’t want to have anything to do with you,” Douglas said.
oneGRID is planning the 1,000-MW HVDC Empire Connector project to move energy from upstate into New York City via the Gowanus Substation in Brooklyn. The project is now in the second phase of its solicitation, aggregating wind, solar and biomass supply offers to sell into the city.
Contracted merchant power “is a forgotten pathway to transmission development,” and customers in New York want it, Douglas said.
“We found out how important physical delivery is to customers in New York City for both reliability, and probably more importantly, for resilience,” Douglas said. “HVDC is so controllable that it actually counts as in-city generation, so it’s a tremendous advantage.”
While renewable energy resources are known for changing the direction of power flow on the grid as smaller generators along the line feed their excess electricity back onto the grid, New York City has so far been unaffected by that phenomenon, said Damian Sciano, Consolidated Edison director of distributed resource integration.
“We’re in a dense urban area … so even when someone puts a fairly large solar installation in, or CHP [combined heat and power] — those are the two big things we see in our service territory — it’s pretty much consumed very close to where it’s generated,” Sciano said. “We don’t typically have backfeed on the substations.”
Lawrence Berkeley National Laboratory research scientist Andrew Mills said a team at the lab compared the levelized cost of energy estimates with value estimates and found that the most attractive U.S. sites for offshore wind are located off New England, while the least attractive are far offshore of Florida and Georgia, where the water is deeper and the wind speeds are lower.
Wind energy off the southeast coast is worth about $160/MWh less than the best sites up north, he said.
“We were very interested in questions about the seasonal and diurnal profiles of offshore wind and how much that might be driving differences in the value across these sites,” Mills said. “If you were to just have a flat block of power, which is constant across all hours, we wouldn’t be far off in the estimates we came up with … within 5% or so.”
Differences in average energy and REC prices primarily drive locational variations, not differences in diurnal and seasonal wind generation profiles, he said. The market value of offshore wind was lowest in the most recent year evaluated, 2016, falling roughly 50% from 2007.
The marginal total market value of offshore wind — considering energy, capacity and RECs — varies significantly by project location and is highest for sites off of New York, Connecticut, Rhode Island and Massachusetts. The median, 2007-2016 market value is highest in ISO-NE (around $110/MWh), in part because of higher REC prices. The energy and capacity value is higher for NYISO, particularly Long Island.
If you look south, the median value is “significantly lower, down in the $55/MW range in the non-ISO region south of PJM,” Mills said.
The capacity value can be up to 50% different from that calculated based on a flat block of power, but capacity value is only a small component of overall value, Mills said. The capacity credit of offshore wind in the NYISO and ISO-NE markets is significantly higher in winter than in summer, with offshore wind in these regions benefiting from having capacity credit assessed in both seasons.
FERC on Tuesday approved Tariff revisions that will finally allow SPP to implement a resource adequacy requirement (RAR), reducing its planning reserve margin from 13.6% to 12% (ER18-1268).
The commission found the revisions will help ensure that sufficient capacity and planned reserves are maintained to meet SPP’s balancing authority load requirements. The proposal also clarifies the types of authorities that may impose rules considered force majeure events, defined as “any curtailment order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities.”
SPP revised its filing after FERC rejected a previous submission in September 2017, the second time its RAR proposal was found to be deficient last year. (See FERC Again Rejects SPP’s Resource Adequacy Revision.)
The grid operator said its new Tariff Attachment AA includes all the terms and conditions relevant to the establishment, compliance and enforcement of the requirement that each load-responsible entity (LRE) in the SPP BA area maintain sufficient capacity and planning reserves to serve its forecasted load.
PSO’s gas-fired Tulsa Power Station provides resource adequacy | Public Service Co. of Oklahoma
The RAR change will require LREs without sufficient generation to participate in bilateral capacity markets. FERC noted SPP’s current market is “relatively net long” compared to the planning reserve margin, and that “likely many sellers of capacity are available to meet LREs’ net peak demand and planning reserve margin.”
The commission said it “continue[s] to encourage SPP and its stakeholders to consider the potential for the exercise of market power in the market for bilateral capacity as the overall reserve margin potentially shrinks in the future.”
FERC suggested last year the proposal could be “more fully develop[ed].” It provided guidance that SPP require all power purchase agreements be backed by verifiable capacity; that the proposed treatment of firm power purchases and sales in the determination of net peak demand was unduly discriminatory; and that the RTO was unable to support its proposal to post publicly a list of all LREs unable to meet their RAR.
Westar Energy protested the most recent filing, separately and with Kansas Power Pool and Missouri Joint Municipal Electric Utility Commission. FERC sided with SPP in each of the arguments.
The RAR proposal is effective July 1, 2018. SPP said this would allow LREs to participate in a full cycle of the annual process before being exposed to a deficiency payment.
SPP’s Board of Directors and stakeholders approved a package of policies in January 2017 that included reducing the RTO’s planning reserve margin to 12%, which translates to a 10.7% capacity margin. LREs with resource mixes that are at least 75% hydro-based are allowed a planning reserve margin of 9.89%.
A stakeholder task force spent more than two years developing the package, which was projected to reduce SPP’s capacity needs by about 900 MW and save members $1.35 billion over 40 years. (See “Stakeholders Endorse 12% Planning Reserve Margin, Policies,” SPP Markets and Operations Policy Committee Briefs.)
SPP said it intends to recalculate the planning reserve margin every two years, “based on a probabilistic analysis using a loss-of-load expectation study.” Any future changes to the planning reserve margin must go through the RTO’s Regional State Committee, composed of state regulators, for approval.
Commission Rejects PMU Proposal over Cost Concerns
The commission rejected without prejudice to SPP a second Tariff change that would have required phasor measurement units (PMU) at new generator interconnections, saying the proposal’s language is unclear (ER18-1078).
The American Wind Energy Association argued against the Tariff proposal, questioning the extent to which transmission owners should be required to fund PMU installations. AWEA raised concerns that SPP did not address funding obligations and said that, as drafted, the proposal would have allowed TOs to exercise market power and force interconnection customers to fund installations.
FERC found the revision’s proposal to allow TOs the option to fund PMU installations only when their interconnection customers are affiliates “could result in affiliated interconnection customers having lower costs than non-affiliated interconnection customers.” That would give affiliates an undue competitive edge, the commission said.
The agency said SPP did not address how TOs would account for the costs of the installations for their own generators or those of affiliated interconnection customers, and how the costs would be treated under the transmission formula rates in order to prevent unreasonable and/or unduly discriminatory rates.
The commission said any subsequent SPP proposal should clarify how TOs will treat PMU installation costs to avoid including them in transmission rates. Doing so, it said, could effectively result in non-affiliate customers subsidizing installations for generators belonging to TOs and/or their affiliated interconnection customers.
FERC also said SPP should develop Tariff language regarding responsibility for ongoing PMU communication and operation and maintenance expenses, and clarify the extent to which the interconnection customer can use existing equipment, such as relays or digital fault recorders with phasor measurement capabilities, or provide data from PMUs already deployed and/or sited on the generator side of the interconnection point.
PMUs are devices that measure the voltage, frequency and angle of the grid’s electrical waves, using a common time source for synchronization. The devices can take samples hundreds of times a second, while the standard supervisory control and data acquisition systems can have scan rates of 10 to 30 seconds.
The proposal cleared SPP’s board and stakeholder groups in January.
The results of PJM’s 2018 Base Residual Auction were “not competitive” and illustrate the need to change how the RTO sets its capacity offer cap, the Independent Market Monitor said Thursday in its second-quarter State of the Market report.
“The outcome of the [2021/22] Base Residual Auction was not competitive as a result of participant behavior which was not competitive, specifically offers which exceeded the competitive level,” the report said.
In a separate analysis released Thursday night, the IMM calculated that total revenues from the auction would have been only $6.57 billion had all identified noncompetitive offers been capped at their net avoidable cost rate (ACR). The analysis said offers exceeding net ACR, while permitted by current rules, amounted to “economic withholding” and boosted total auction revenue by 41.5% to $9.3 billion.
The Market Monitor’s analysis found that clearing prices in the 2018 Base Residual Auction would have been lower everywhere but the PSE&G zone had prices been capped at net avoidable cost rate. Not identified is the DEOK zone, which cleared with the rest of the RTO at $140/MW-day, but would have priced at $128/MW-day. | PJM, Monitoring Analytics
Capping at net ACR would have reduced the RTO clearing price from $140.53/MW-day to $90.47/MW-day. “All binding constraints would have remained the same except that the ComEd import constraint would not have been binding and the DEOK import constraint would have been binding,” the analysis said.
It singled out nuclear units, saying more nuclear capacity was offered at higher sell offer prices and fewer nuclear megawatts cleared than in 2017.
Although the IMM has regularly cited structural market power in the capacity market, 2018 was the first time that mitigation efforts failed and market prices were inflated, said Joe Bowring, president of Monitoring Analytics, which serves as PJM’s independent Market Monitoring Unit (MMU).
“I think it’s significant,” Bowring said in an interview. “It’s the result of the fact that the offer cap in the rules is mis-specified and needs to be fixed. We’ve been making that point for a while. But that issue resulted in an impact on this auction.”
PJM issued a statement Friday disagreeing with the Monitor’s conclusions.
“While PJM respects the Market Monitor’s opinion, the facts regarding the 2021/2022 Base Residual Auction are clear. The auction was conducted in accordance with all Tariff-specified requirements and rules, including those rules related to the application of offer caps, and the offers were in concurrence with those rules. The Market Monitor expresses an opinion of what the offer cap should be; the proper forum for such concerns about competitiveness of offers is the Federal Energy Regulatory Commission.”
Grades
For the 2018 BRA, the Monitor gave “not competitive” grades to the aggregate and local market structures, as well as market performance and participant behavior. Market design was judged “mixed.” The Monitor gave the 2017 BRA the same grades for market design and structures but rated both participant behavior and market performance as competitive.
The IMM said this year’s auction failed the competitive test because of the way PJM sets the offer cap under Capacity Performance rules.
| PJM, Monitoring Analytics
“Some participants’ offers were above the competitive level. The MMU recognizes that these market participants followed the capacity market rules by offering at less than the stated offer cap of net CONE [cost of new entry] times B [balancing ratio]. But net CONE times B is not a competitive offer when the expected number of performance assessment intervals is zero or a very small number and the nonperformance charge rate is defined as net CONE/30. Under these circumstances, a competitive offer, under the logic defined in PJM’s Capacity Performance filing, is net ACR. That is the way in which most market participants offered in this and prior Capacity Performance auctions.”
Because net CONE times B exceeds the competitive level in the absence of performance assessment hours (PAHs) — periods requiring urgent actions, such as the dispatch of emergency or pre-emergency demand response — it should be re-evaluated for each BRA, the report said.
Repeating a recommendation it first made in 2017, the Monitor said PJM should develop forward-looking estimates for both B and the expected number of PAHs used in calculating rates for nonperformance charges.
The Monitor said CP rules, which increased penalties for nonperformance, “have significantly improved the capacity market and addressed many of the issues” it previously identified.
But it also said the CP Tariff language is overly rigid. “If the Tariff had defined the offer cap consistent with PJM’s filing in the Capacity Performance matter, the offer cap would have been net ACR rather than net CONE times B,” the report said.
“The bottom line is net CONE times B is way too high, especially when the performance assessment hours are less than 30,” Bowring said.
Of the 1,132 generation resources that submitted CP offers for delivery year 2021/22, 953 (84%) used the net CONE times B offer cap, while 129 (11%) were price takers.
Only eight generation resources (0.7%) requested the Monitor calculate unit-specific ACR-based offer caps. “The fact that so few resources requested unit specific offer caps is further evidence that the net CONE times B offer cap exceeds competitive offers,” the Monitor said.
PJM Disputes
PJM noted that market sellers must declare whether they will use net ACR or the net CONE times B offer cap 120 days before the auction.
“During the weeks where actual offers are submitted and the auction is cleared, the IMM has full visibility into all data relevant to the auction, including resource offers. If the IMM believed that economic withholding was taking place based on submitted offers and preliminary auction clearing results, the IMM could have consulted with the asset owner during that time period,” PJM said.
“If the IMM believes that economic withholding took place, the proper course of action is for the IMM to refer the market seller responsible for such offers to FERC for further investigation. If the IMM believes that the current rules regarding the default offer cap allow for economic withholding, the IMM, like any other stakeholder, can bring forward a problem statement and issue charge to be discussed by the PJM stakeholder body.”
PJM also questioned the IMM’s simulation results for nuclear units offering at their ACR. “They are based upon hypothetical offers that could have been submitted on the basis of the IMM’s anticipation of potential performance assessment hours, as well as the IMM’s determination of the appropriate value of ACR to use for certain resources as opposed to their actual going-forward costs,” PJM said. “Given these errors in the assumptions, the simulations bear no direct relevance to any hypothetical auction outcome had different offer-capping rules been in place for this auction.”
PJM spokesman Jeff Shields said the RTO does not agree that there is a problem with the current offer cap. “PJM is supporting stakeholder consideration of proposals that could result in adjustments to the default offer cap, but it is unclear whether a proposal that results in such an adjustment will be approved,” he said.
Should the proper offer cap be net ACR? “No. This assertion is dependent upon an expectation of performance assessment hours,” Shields said. “Whether a given submitted offer was above the competitive level, even though it was within the rules, is a matter for FERC.”
Comparison with 2017
The Monitor’s quarterly report also repeated its concerns over generation subsidies, saying they “threaten the foundations of the PJM capacity market as well as the competitiveness of PJM markets overall.” The Monitor wants to extend the minimum offer price rule (MOPR) to include existing units as well as new resources.
Although the Monitor found the capacity market problematic, it said PJM’s energy markets produced competitive results in 2018. Compared with the first half of 2017, PJM saw the following in the first six months of 2018:
Energy prices and fuel prices were higher and more volatile, resulting in higher margins for generation types. Average energy market net revenues increased by 160% for a new combustion turbine; 63% for combined cycle plants; 525% for coal plants; 44% for nuclear units; 10% for wind; and 20% for solar.
Total energy uplift nearly tripled from $49.7 million to $146.4 million.
Payments for DR programs increased 13.7% to $271.7 million.
Congestion costs increased by 214% to $896.6 million. Auction revenue rights and financial transmission rights revenues offset only 50.7% of total congestion costs for the 2017/18 period, the first in which new rules required the allocation of balancing congestion to load instead of FTR holders. ARR and FTR revenues offset 98.1% of congestion costs for load during the 2016/17 planning period.
New Recommendation: FTR Liquidations
The report includes two new recommendations. The Monitor said PJM should set a high priority on reviewing how it liquidates FTR holdings, a recommendation prompted by GreenHat Energy’s default in June, when it failed to pay a weekly invoice of $1.2 million. PJM has asked FERC to approve a waiver of rules that require immediate liquidation of a defaulting member’s FTR portfolio (ER18-2068). (See “Default Details,” PJM MRC/MC Briefs: July 26, 2018.)
Bowring said he supports a change in the rules that allows PJM to liquidate the portfolio over a longer period. “These are long-term” positions, he noted.
New Recommendation: REC Transparency
The Monitor also said states with renewable portfolio standards should make the data on renewable energy credits (RECs) more transparent. D.C. and all but five of the 13 states in PJM have a mandatory RPS. Virginia and Indiana have voluntary standards, while Kentucky and Tennessee have no renewable targets. West Virginia repealed its voluntary standard in 2015.
Although FERC has determined that RECs are not regulated under the Federal Power Act unless they are sold in a bundled transaction that includes a wholesale sale of electric energy, RECs affect market prices and the mix of clearing resources, the report said. “Some resources are not economic except for the ability to purchase or sell RECs.”
But data on REC prices, clearing quantities and markets are not publicly available for all states. In addition, RECs do not need to be consumed during the year of production, resulting in multiple prices for a REC based on the year of origination, the Monitor said.
“RECs markets are, as an economic fact, integrated with PJM markets, including energy and capacity markets, but are not formally recognized as part of PJM markets. It would be preferable to have a single, transparent market for RECs operated by PJM that would meet the standards and requirements of all states in the PJM footprint including those with no RPS. This would provide better information for market participants about supply and demand and prices, and contribute to a more efficient and competitive market and to better price formation. This could also facilitate entry by qualifying renewable resources by reducing the risks associated with lack of transparent market data.”
The Monitor said the CO2 price implied by REC prices ranges from $4.74/metric ton in D.C. to $35.41/ton in Pennsylvania, while solar RECs’ implied prices range from $18.07/ton in Pennsylvania to $861.52/ton in D.C.
Those contrast with the 2018 average clearing price of $4.31/ton in the Regional Greenhouse Gas Initiative and the social cost of carbon, which is estimated at about $40/ton. “The impact on the cost of generation from a new combined cycle unit of an $800/ton carbon price would be $283.56/MWh. The impact of a $40/ton carbon price would be $14.18/MWh,” the Monitor said. “This wide range of implied carbon prices is not consistent with an efficient, competitive, least-cost approach to the reduction of emissions.”
NEW YORK — New York is charting its own course for integrating distributed energy resources into its grid, different from the path trod by states with already high rates of penetration, industry experts said this week.
“California and Hawaii had to be reactive to distributed generation, but New York is taking a more proactive approach in trying to incent greater penetration of clean energy resources,” ScottMadden’s Chris Sturgill said at the New York Energy Market Summit held Aug. 6-8.
Sturgill noted the New York Public Service Commission this spring approved new DER measures as part of the state’s Reforming the Energy Vision initiative, which has enabled market participation for non-wires alternatives and the expansion of energy efficiency, demand response programs and demonstration projects. (See NYPSC OKs Con Ed EV Charging Program, REV Initiatives.)
“It’s easier to bring DER onto the grid now, thanks in part to informed dialogue between the utilities and DER owners,” Sturgill said.
“New York is pursuing aggressive policies to promote renewable energy, preserve competitive markets and resolve regulatory uncertainty,” said Paul A. DeCotis, senior director of West Monroe Partners.
Data First
Conference panelists pointed out that the growth of DERs and electric vehicles is changing once predictable load patterns. Utilities need to ensure continued reliability, recognizing that regulators are not as close to the system as they are, they said.
“I would start with data,” said Stuart Nachmias, Consolidated Edison vice president for energy policy and regulatory affairs. “We continue to support implementation of smart meters, and also the communications infrastructure to make them usable … but price signals are important to get generation closer to load … which is how New England evolved their locational pricing.”
Con Ed subsidiary Orange and Rockland Utilities, which serves customers in southeastern New York and northern New Jersey, has “seen a lot of solar proposals, which is not where the demand is,” Nachmias said.
Melissa Kemp, Northeast policy director for Cypress Creek Renewables, said New York must have a larger conversation about how to compensate solar projects.
“Initial costs may avoid later costs, such as avoided transmission spending, and a project may have positive health benefits, and those positive attributes should be accounted for, if not compensated,” Kemp said.
She also pointed to the importance of maintaining the low-income customer perspective and protecting against unnecessary rate increases. She added that those customers would also bear any extraordinary costs in the future, which could be avoided by increased spending now.
Ross Kiddie, director at West Monroe Partners, noted that New York utilities submitted their second Distributed System Implementation Plans (DSIP) to the PSC a week earlier (Case No. 14-M-0101) and asked what are the must-have technologies to deal with DERs.
If people had controllable toasters, the utility or aggregator could preset a million of them and stagger their times to avoid spikes, said James Pigeon, NYISO manager of distributed resources integration.
“As we move forward, and the aggregators have the ability to control these assets, things will change,” Pigeon said. “The NYISO is not looking to change the business model and apply unique programs to every node on the grid. … We want to apply one model and have those resources respond to NYISO direction, whether for demand management or price signal.”
Damian Sciano, Con Ed director of distribution planning, said the electric system is moving from dozens of large generators to thousands of small-scale residential units, which could go into the millions when every customer’s appliances are connected to the grid.
“NYISO looks at New York City as just Zone J, but to us it’s a bunch of distribution lines that have thermal limits and voltage concerns,” Sciano said. “So when an aggregator puts together a bid for say 10 MW, it may completely satisfy what the NYISO is looking for, but it may be 10 MW on a part of the grid where we can only tolerate 2 MW at any given point.”
It goes back to the DER management system, even if someone else is aggregating something for the utility, he said. “We want to know exactly what’s being generated, very much preferably real-time, and understand how it’s affecting our system,” Sciano said.
Emilie Nelson, NYISO vice president for market operations, said she is focused on administering capacity and pricing at the wholesale level.
“If you rewind 15 years, the expectation for natural gas prices was not what they are today, so expectations can shift; reality can shift. A functioning market allows for third parties to bring in new solutions,” Nelson said.
Storage Issues
Sturgill asked how the ISO will consider proposals for energy storage resources in the wholesale market, particularly for those that are dual participation or trying to collect multiple pieces of the value stack. (See NY Releases ‘Roadmap’ for 1,500-MW Storage Goal.)
New York City is dedicated to working with utilities and others to value new DER technologies properly, including storage, said Susanne DesRoches, Mayor Bill de Blasio’s deputy director for infrastructure and energy.
“We see storage being able to support transmission and support the local network … for the complex picture in New York City, which is a bunch of islands with a unique power supply,” DesRoches said. “Storage should be valued properly for the attributes it provides for the system, and also we need clear permitting.”
Storage needs to be treated fairly on the system, said Peter Mandelstam, executive director for GRID Alternatives Tri-State, the largest solar energy nonprofit in the U.S.
“Having been involved in a lot of regulatory battles over the decades, both at the state and federal level, the most important thing is to get the rules right,” Mandelstam said. “Storage is now here, is now integral to the complete decarbonization of our electric system … the digital age now allows for the metering.”
Illinois Commerce Commissioner John Rosales, also vice chair for electricity at the National Association of Regulatory Utility Commissioners, said smart metering “is the catalyst” to put together a microgrid or adopt new technologies such as energy storage.
As a regulator, “you’ll never make everyone happy; there will be winners and losers, and they’ll be so unhappy that they will sue you,” Rosales said. “However, it’s important to remember that not making a decision is a decision.”
CARMEL, Ind. — MISO said Tuesday it plans to refile a plan to create external capacity resource zones with FERC by the end of the month.
And the RTO still promises to make zone determinations in time for the 2019/20 planning year capacity auction, officials say.
FERC rejected the proposal earlier this month, saying two aspects of the plan rendered it unreasonable. (See FERC Rejects MISO Plan for External Capacity Zones.) One of the rejected provisions would have allowed external resources bordering two local resource zones to choose in which zone they receive auction credits, while the other would have made holders of evergreen supply contracts eligible for excess auction revenues indefinitely.
During an Aug. 8 Resource Adequacy Subcommittee meeting, MISO attorney Jacob Krouse noted the RTO asked FERC to view the proposal as an integrated package, making the rejection total.
“The commission, under the NRG paradigm, rejected the filing,” Krouse said, referring to the July 2017 D.C. Circuit Court of Appeals ruling that FERC overstepped its authority when it suggested changes to a PJM proposal. MISO stakeholders warned last year that a rejection of the proposal was possible in light of the ruling. (See MISO Members: Court Rebuff May Reduce External Zone Chances.)
But RTO leadership appears undaunted by the rejection, planning to refile the proposal with two revisions Aug. 31.
“MISO believes that with the clear guidance we received from FERC … we are going to be able to refile at the end of the month,” Krouse said. “FERC did not note any concern with the vast majority of MISO’s proposal — just those two parts.”
Under proposed revisions, border resources that have participated in past Planning Resource Auctions will be assigned to the local resource zone in which they previously participated. New external resources that border two or more local resource zones will be assigned to the zone where the unit maintains the greatest electrical connection. MISO said it will measure electrical connectivity through line ratings using a contingency basis.
“MISO is proposing to assign resources to a single [local resource zone] instead of multiple zones,” Krouse explained.
For evergreen supply contracts, MISO now proposes to allow units to collect excess auction revenues only until the end of the original term of the agreement or for two years, whichever is longer. Krouse said the RTO’s filing will also include an option that removes the two-year extension, ending hedge eligibility as soon as the original contract expires. He said MISO intends to let FERC choose the provision it prefers.
Krouse asked for stakeholders to provide reactions to the changes by Aug. 17 and said the RASC will schedule a special Aug. 22 conference call to discuss feedback.
MISO Director of Resource Adequacy Coordination Laura Rauch said the change for border resources will apply only to a small subset of MISO resources.
Some stakeholders said the proposed treatment of evergreen contracts might violate the Mobile-Sierra doctrine, which holds that rates negotiated in a contract should be presumed to be just and reasonable.
“MISO is not changing the terms of the arrangement, so Mobile-Sierra would not apply,” Krouse said, adding that the RTO is not encroaching on the terms of buying and selling power. Rather, such contracts would simply become ineligible for additional hedges from MISO after the original term of the agreement or the proposed two-year transitional period.
“We in no way intend to change or limit the terms of evergreen contracts,” Rauch said. “These contracts were signed without consideration of the capacity construct.”
Others commended the RTO for continuing to pursue external zone designation.
“I really appreciate MISO going in and being aggressive on this. … We’ve been talking about this for half of a decade,” said Coalition of Midwest Power Producers CEO Mark Volpe.
The owners of Salem Harbor Power Station have asked FERC to dismiss allegations that the plant misled ISO-NE with supply offers it could not meet because of insufficient fuel.
FERC’s Office of Enforcement filed an Order to Show Cause on June 18, saying that owners Footprint Power should forfeit more than $2 million in capacity payments Salem Harbor Unit 4 received for a period in June and July 2013 during which the plant’s fuel supply prevented it from operating at its offered capacity. Enforcement also sought $4.2 million in civil penalties. (See Salem Harbor Plant Facing FERC Action.)
Salem Harbor Power Plant | Tetra Tech
In its Aug. 2 response, Footprint’s attorneys said Enforcement “overstates” what ISO-NE expected from the plant, claiming the RTO was aware that NOx emissions limits prevented it from running at full capacity for an entire day. Enforcement also failed to consider the time it took the plant to reach full output from start-up, the attorneys wrote in a 383-page answer that includes audio recordings of conversations between plant and ISO-NE operators and a passage from Joseph Heller’s “Catch-22” (IN18-7).
“The day-ahead offers reflected [the plant’s fuel] limitations. And as the taped phone calls show, the operators repeatedly caveated their estimates about potential availability as uncertain,” they wrote.
Footprint said Enforcement overstated the maximum amount of fuel the plant could burn by more than 82%. Enforcement staff did not interview plant operators and there is no evidence investigators talked with the RTO’s operators about their expectations, Footprint said.
The company also said Enforcement’s calculations understated the amount of fuel the plant had available to burn.
“Enforcement thus offers a conundrum where every option is a violation. If Salem Harbor offers what it considers to be a good estimate of the projected output of Salem Harbor, that is deceptive because the projection is higher than anything empirically proven to be available in advance. If Footprint offers a lower level of output from Salem Harbor, but one that has been empirically proven to be available in advance, that is physical withholding. This is no idle, after-the-fact thought. The principals of Footprint were veterans of the business and regulatory landscape facing New England independent power producers. They understood the regulatory environment in ISO-NE as well as anyone. And they actually were concerned at the time that under-offering Salem Harbor 4 could expose them to withholding claims.”
The filing acknowledges Unit 4 ran low on fuel in July 2013 but noted that the plant was then less than a year from retirement. “Fuel oil had to be bought in large amounts — a barge of oil cost over $5 million in the summer of 2013. And given that the plant historically ran very infrequently, much of that money might end up wasted.” Unit 4 retired less than a year after the period in question, and it and its fuel tank have since been demolished.
Footprint said Enforcement is attempting to penalize it for running low on fuel because the plant was not hit with ISO-NE’s shortage-event penalties. “If the commission wants to create greater incentives to store fuel oil on site, it obviously can do that prospectively by changing the definition of shortage events in the ISO-NE Tariff so that they occur more frequently. The commission in fact approved just such a change in late 2013. But the commission cannot lawfully change the Tariff to make shortage events more frequent looking backwards. … Viewing things from a broader perspective, the Pay-for-Performance capacity model is not going to work as intended if Enforcement gets to pile on its own chosen sanctions, above and beyond shortage-event penalties, whenever it thinks alleged performance limitations somehow have not already been sufficiently punished.”
Footprint also said the case should be dismissed based on the five-year statute of limitations. It disagreed with Enforcement’s prior claims that the issuance of a show cause order within five years is sufficient.
It requested a meeting with the commissioners and senior staff to discuss its defense, “with or without Enforcement present.”
California’s Public Utilities Commission has increasingly focused on wildfire prevention as electric utilities have been blamed for a series of devastating blazes in recent years, the commission’s president told state lawmakers Tuesday.
CPUC President Michael Picker said the commission’s role had shifted significantly from economic regulation to fire safety during years of high temperatures and low humidity “that result in intense fires with 145-mph winds.”
He and others called such conditions the “new normal” in California.
Picker made his comments before a joint committee of state senators and assembly members tasked with ironing out differences in SB 901, which deals with climate change, wildfire prevention and the legal liability of the state’s three investor-owned utilities: Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
Passed by the State Senate in June, the bill would require a utility’s wildfire mitigation plan to describe what factors it will consider when determining whether to de-energize lines in the face of fire danger and include procedures for notifying affected customers. (See Calif. Senate OKs Utility Wildfire Cost Recovery.) The mitigation plans are subject to CPUC approval.
The hearing was one of several called to draft a workable bill before the legislature adjourns its two-year session Aug. 31, when the bill would otherwise die.
The conference committee’s first hearing was held July 25, when one of its co-chairmen, Sen. Bill Dodd (D), said he was primarily concerned with the safety of residents after hundreds in his Napa County district lost their homes, and some were killed, in the catastrophic wine country fires of 2017.
California Department of Forestry and Fire Protection (Cal Fire) probes have blamed 16 of last year’s Northern California fires on “electric power and distribution lines, conductors and the failure of power poles” owned by PG&E.
The nearly 52,000-acre Atlas Fire in Napa, for example, started when a tree limb and a falling tree came into contact with PG&E power lines, Cal Fire said in a June statement. That fire killed six residents and destroyed 783 structures.
PG&E last quarter took a $2.5 billion pre-tax charge for third-party claims related to 14 of the fires.
Wildfires, the Atlas Fire, made for a smokey San Francisco sunrise in October 2017 | Bob Dass via Creative Commons
Opening the July 25 hearing, Dodd said the state needs greater regulation of line maintenance, including vegetation removal, inspection and power shutdowns during extreme weather conditions, “so power lines don’t start fires.”
He placed part of the blame on the CPUC, alleging lax oversight.
“That means better utility planning and greater accountability for those who operate the grid, including checking compliance before a fire,” Dodd said on the dais in July. “That’s an area where the CPUC has done quite poorly regulating utilities and ensuring public safety.”
Testifying at the same hearing, Picker said the loss of life and homes from wildfires had been keeping him up nights, though he hadn’t expected fire-prevention to be a major part of his job.
“I have to say that fires are not something I thought I would deal with when I came to the Public Utilities Commission. But it’s obvious they are becoming a bigger and more dramatic issue here in the state of California.”
The CPUC in December approved more stringent wildfire standards for utilities, creating a “high fire-threat” district where correction of fire hazards is to be prioritized through improved vegetation management and increased wire-to-wire clearances. (See CPUC Targets Wildfires, Multifamily Solar, RMRs.)
The next hearing on SB 901 is scheduled for Aug. 9, when the subject will be the liability of investor-owned utilities for the destruction of private property caused by wildfires.
