FERC attended to some housekeeping Friday by putting to rest a rehearing request rendered moot by MISO and SPP’s settlement of their transmission dispute.
SPP-MISO 1,000 MW contractual tie Source: SPP
The commission dismissed MISO’s rehearing request of its December 2014 order approving the RTO’s use of a “hurdle rate” to manage its north-south flows (ER14-2445-002). The commission also dismissed a related compliance filing.
MISO, its Market Monitor and several regulatory agencies and utilities had sought rehearing, arguing that FERC’s order would cause the $9.57/MWh hurdle rate to climb by 4.5 times, rendering MISO’s North-South interface transfers of more than 1,000 MW uneconomical.
“Because the hurdle rate is no longer effective, and in the [December 2014] order, the commission exercised its discretion to not order refunds … there is no need to address the” matters raised by MISO and others, the commission said.
Under the settlement, MISO will pay SPP $1.33 million monthly until February 2017 to cover flows over 1,000 MW passing through MISO’s North-South interface. MISO is temporarily collecting the funds from members through a miscellaneous charge based on market load ratio share while the RTO and stakeholders continue settlement discussions to decide on a long-term cost allocation (ER14-1736).
FERC last week approved a request by CAISO to eliminate from its Tariff a long-suspended provision establishing convergence bidding at scheduling points on the interties into California.
The commission’s order eliminated the prospect that CAISO would reinstate a market mechanism it revoked within months of implementing it in 2011 (ER15-1451-001). At the time, the ISO’s Market Monitor determined that bidding strategies at the interties underpinned a complex scheme to manipulate prices and inflate payouts in other areas of the California market.
CAISO has in recent years explored reviving the mechanism in light of structural changes in Western markets, but it ultimately sought a full repeal based on concerns that illiquidity in 15-minute trading left intertie points vulnerable to gaming.
FERC’s ruling did not affect convergence bidding at points inside the ISO balancing area. At the request of municipal utilities in Anaheim, Azusa, Banning, Colton, Pasadena and Riverside, FERC also directed CAISO to delete from its Tariff an additional reference to virtual bidding in order to avoid ambiguity.
Convergence — or virtual — bidding allows market participants to hedge their physical positions and limit exposure to day-ahead and real-time price differentials. A convergence bid is a purely financial bid implying no obligation to take or deliver electricity. Instead, a market participant buys or sells “virtual” energy in the day-ahead market, a position required to be automatically liquidated in the opposite direction in real time.
Depending on the relative movements in the two markets, the participant either pockets or pays the difference between the two prices. Bidders are not required to control physical resources or serve loads in the ISO, allowing speculators to take positions in the market.
RTOs have adopted convergence bidding under the theory that the practice narrows the gap between day-ahead and real-time prices as traders arbitrage spreads between the two markets. The benefit is a more predictable spot market, protecting utilities from price swings stemming from load fluctuations and unplanned generating outages.
Troubled from the Start
In California, convergence bidding was fraught with problems since CAISO introduced the practice two years after restoring its day-ahead market. A week after implementing the market in February 2011, CAISO suspended bidding at nodes on nine interties linked to the Mountain States region because of a software glitch that risked overscheduling those points in the physical day-ahead market.
That incident was followed months later by the more serious discovery that some CAISO market participants were using virtual supply bids on the interties to offset virtual demand bids at nodes located just inside the state, a gaming strategy that produced no benefit for the physical market and cost the ISO more than $50 million.
(Virtual trades at CAISO’s New Melones intertie are at the center of market manipulation allegations filed by FERC in December. The defendant last week asked FERC to compel CAISO to disclose information about market design flaws (IN16-2). See earlier story, FERC Seeks $2.5M Fine in CAISO Market Manipulation.)
The strategy was facilitated by predictable differences in prices stemming from what the ISO referred to as a “bifurcated” settlement process, with the interties settled at the hour-ahead price and internal points in real time. Shortly after identifying the issue, CAISO suspended bidding at the interties indefinitely — or at least until it could resolve the bifurcation issue.
Liquidity Concerns
That goal would ultimately elude CAISO. While FERC Order 764 — which mandated 15-minute scheduling between neighboring balancing areas — should have helped, the ISO became concerned about declining short-term trading volumes at the interties, which could reintroduce opportunities for strategic bidding. A 2015 report from the ISO’s Market Monitor indicated that “most of the dozens of CAISO interties have no market participants providing economic bids in the 15-minute market and only a few interties have multiple market participants providing such bids.”
CAISO hoped Bonneville Power Administration’s implementation of 15-minute scheduling — synching it with CAISO’s schedule — would boost exports from the Pacific Northwest. But the change had little impact on trading activity.
“The CAISO does not yet understand the causes of this low market liquidity,” the grid operator wrote in an April 2015 filing asking FERC to extend the suspension of convergence bidding on the interties. “Based on informal feedback from market participants, the CAISO believes that some of the possible causes may be neighboring balancing areas not supporting 15-minute schedule changes, difficulty in procuring transmission in 15-minute blocks, an absence of bilateral trading at a 15-minute granularity and reticence of resource owners to adjust their output within the hour.”
According to a report by CAISO’s Department of Market Monitoring (DMM), low 15-minute liquidity could translate into a situation in which convergence bids would first settle at a day-ahead market price that includes intertie congestion, then be liquidated at a 15-minute market price not subject to congestion because of light physical volumes. That would give bidders incentive to profit from the structural differences between congestion prices in the day-ahead market and the 15-minute market.
“Regardless of the causes,” CAISO wrote in its April 2015 filing, “based on DMM’s recent analysis, the CAISO has determined that the existence of such low market liquidity, as evidenced by the lack of economic bids submitted in the 15-minute market, makes it problematic to reinstate intertie virtual bidding.”
ERCOT said last week it continues to expect to have sufficient resources to meet projected peak-demand during the spring and summer, with more than 79,000 MW of generation capacity available.
The Texas grid operator is projecting a spring demand peak of 58,279 MW, a 700-MW increase from last November’s preliminary spring assessment, said Pete Warnken, ERCOT’s manager of resource adequacy, during a March 1 conference call. The revised peak is based on weather conditions from May 2006; the previous estimate used average weather conditions from 2002 to 2014.
Warnken said staff took into account multiple scenarios under a variety of conditions in issuing its Seasonal Assessment of Resource Adequacy (SARA) for this spring. The report includes a new scenario based on low wind power output during peak hours.
ERCOT’s control room Source: ERCOT
ERCOT estimates that even with 9,482 MW of maintenance and forced outages in May, it will still have 11,598 MW of capacity available for operating reserves, well above the 2,300 MW considered acceptable.
The spring forecast is based on expected weather conditions similar to those that occurred in May 2006 and typical seasonal generation outages, based on historical performance. ERCOT expects the spring peak to occur in late May, following completion of most seasonal plant maintenance to prepare for summer’s heat.
“The month of May shows potential for above-normal temperatures, which could lead to an early taste of summer,” said ERCOT meteorologist Chris Coleman.
The grid operator’s latest SARA includes more than 200 MW of installed solar capacity. ERCOT estimates solar resource availability at a 58% capacity factor — or 171 MW — based on its typical performance during peak spring conditions.
ERCOT’s preliminary summer SARA projects a summer peak of 70,588 MW, its first peak above 70,000. The current record is 69,877 MW, set last August.
ERCOT estimates it will have more than 79,000 MW of available generation this summer, including an additional 731 MW of fossil, nuclear and biomass generation from the preliminary spring SARA, 1,068 MW of new gas-fired generation and 723 MW of additional wind energy.
The final summer SARA is scheduled to be released in May.
NV Energy had a smooth integration into the Western Energy Imbalance Market, CAISO said Monday in its fourth-quarter market report.
Department of Market Monitoring (DMM) manager Keith Collins noted that after NV Energy joined the EIM on Dec. 1, Nevada imbalance prices quickly converged with those in CAISO’s broader system, a development that has so far continued into this year. That stood in contrast with the price swings that still beset PacifiCorp’s balancing area, stemming from physical constraints on the system.
“One of the things we noted with the [NV Energy] launch was that the variability [of prices] within the Nevada area was fairly limited,” Collins said.
CAISO attributed NV Energy’s easy adjustment to the high amount of transfer capability between Nevada and California. Limited congestion translates into a freer flow of both imbalance energy and capacity between the balancing areas, avoiding the need to relax CAISO’s flexible ramping constraints in load pockets poorly served by flexible capacity. Relaxation of the constraints ultimately drives up real-time energy prices by forcing relatively fast, efficient units out of the 15-minute energy market queue and into the obligatory market for ramping capacity.
By comparison, flexible capacity issues continue to weigh the EIM’s PacifiCorp East area, with the ramping constraint being relaxed in more than 10% of intervals over the quarter, frequently boosting real-time prices by the maximum $60/MWh adder associated with capacity procurement shortfalls. CAISO did note, however, that relaxations in PacifiCorp East declined during December, reversing the uptrend seen in the previous quarter. While generating units returning from outages likely helped relieve constraints, the DMM suggested that NV Energy’s entry into the EIM might be providing longer-term structural benefits for PacifiCorp.
“The market is more of a regional market with the inclusion of NV Energy because of the increased transfer capacity,” said Collins. “It’s more of a single market.”
Bid Cost Recovery Payments Down
Collins pointed to the decline in bid cost recovery (BCR) payments as the second biggest “theme” of the fourth quarter. CAISO payouts came to $25 million under the market mechanism, compared with $31 million in the third quarter and $25 million during the same period in 2014. BCR payments attributed to residual unit commitments (RUC) fell from $10 million to $3 million quarter over quarter because of decreased payouts to “long-start” units.
“This is a big shift, although virtual supply has played a role,” Collins said.
The DMM report describes the link between the virtual — or convergence — bidding market and bid cost recovery payment volumes, explaining that lower virtual supply volumes in the fourth quarter “primarily” caused the RUC process to commit fewer resources compared with the prior period. The report notes that RUC procurement “appears” to be driven by the need to replace cleared virtual supply bids, which offset physical supply in the day-ahead market.
“Part of that is that renewables tend to be under-scheduled,” Collins said. “Virtual schedules are counterbalancing that.”
The report also showed that real-time commitments accounted for $12 million in BCR payments, in line with historical norms, while day-ahead payments were lower than any fourth quarter since 2011.
Additional highlights from the Market Monitor’s report:
Day-ahead and 15-minute prices declined to the lowest level of the year, with day-ahead peak averaging $33/MWh. December saw both markets fall to their 15-month lows. Collins noted that both loads and natural gas prices continued to trend lower, with the latter hitting 15-year lows.
Price spikes increased in the five- and 15-minute markets but remained “relatively infrequent.” October saw an “unusually high” number of intervals in which prices surged to more than $1,000/MWh because of low day-ahead scheduled load and regional congestion.
Congestion in the ISO was relatively low and had little impact on prices.
The volume of dispatchable import bids in the 15-minute market increased by 19% compared with the third quarter, while export bids jumped 20%. Most 15-minute import-export activity was submitted by small number of entities on three interties — Malin, Palo Verde and Rancho Seco.
Exelon on Monday offered a split D.C. Public Service Commission a “middle ground proposal” in a bid to salvage its acquisition of Pepco Holdings Inc.
In a joint filing, the companies asked the commission to approve either the original settlement negotiated with Mayor Muriel Bowser or the revised proposal outlined by Commissioner Joanne Doddy Fort and supported by Commissioner Willie Phillips on Feb. 26. Commission Chairwoman Betty Ann Kane opposed the revised settlement after voting 2-1 with Fort to reject Bowser’s deal. (See DC PSC: Will OK Exelon-Pepco Deal for Additional Concessions.)
The companies also offered a third alternative: adopting Fort’s revised settlement, while addressing the mayor’s concerns with shielding residential customers from rate hikes. It would give the PSC discretion to use an additional $20 million — which Bowser’s settlement earmarked for smart grid and environmental programs — for rate relief.
The companies did not offer to increase the $72.8 million customer investment fund (CIF) they are offering D.C. to approve the merger.
The deal began to look doubtful last Tuesday as Bowser, the Office of the People’s Counsel and Attorney General Karl Racine announced their opposition to revised terms set out by Fort. D.C. Water followed with its rejection later in the week. (See Exelon-Pepco Deal in Doubt as Mayor, Consumer Advocate Balk at New Terms.)
Together they represent three of nine settling parties that must agree to the new deal in order for it to be approved without further commission action. At issue for all was the reallocation of $25.6 million from the CIF that would have shielded residential consumers from rate hikes until 2019. The PSC voted 2-1 to defer a decision on how to spend the funds until the next Pepco rate case, signaling that it would distribute the money to nonresidential customers as well.
The commission’s Feb. 26 order had required responses from the settling parties by March 11. Exelon and Pepco asked the PSC to rule on their new proposal no later than April 7.
“The joint applicants believe that the commission can address its concerns with the residential customer base rate credit, as well as the settling parties’ concerns with the terms of the [revised settlement], through additional alternative terms which preserve the function of the residential customer base credit and move $20 million in CIF monies from the newly created [Modernizing the Energy Delivery System for Increased Sustainability] pilot project subaccount to a separate customer base rate credit fund.”
The $20 million fund would be spent following Pepco’s next base rate case as directed by the commission, potentially providing commercial customers rate relief or increasing funding for the Low-Income Energy Assistance Program.
“In the event that the commission determines that any or all of the additional $20 million should not be used for these purposes, it could allocate any unused portion of the $20 million to the MEDSIS pilot project subaccount.”
The companies said their proposal “does not prevent the commission from using CIF monies to advance the grid modernization proceedings in [a second docket,] Formal Case No. 1130. Instead, the revised allocation provides the commission with additional discretion over how best to use $20 million of the $72.8 million CIF to advance its competing priorities.
D.C. Councilwoman Mary Cheh (at podium) is joined by other councilmembers and candidates at press conference opposing merger Wednesday.
“It would be tragic if customers lost the $72.8 million CIF and the many other benefits of the merger recognized by the commission and the settling parties because of disputes over how a portion of the CIF should be allocated,” they wrote.
The mayor, OPC and attorney general had no immediate comment on the companies’ revised proposal.
The Power DC coalition immediately asked the PSC to reject it.
“Exelon’s latest filing is another example of the company’s total arrogance and disregard for D.C. residents,” said spokeswoman Anya Schoolman. “The Public Service Commission shouldn’t let Exelon rearrange deck chairs on the Titanic. It is time for D.C. to move on.”
Councilwoman Mary Cheh also signaled her opposition. “We expected that Exelon would try a Hail Mary pass, but from my analysis it doesn’t appear to satisfy requirements set forth by the Office of the People’s Counsel in terms of protections for ratepayers,” she said.
Exelon not Giving Up
CEO Christopher Crane said in a Feb. 3 earnings call that the company would abandon the merger and begin buying back the 57.5 million shares it issued for the $6.8 billion deal if D.C. regulators did not approve it by March 4.
But company officials said Thursday they were delaying the deadline as a result of the PSC’s action Feb. 26.
“March 4 was the date after which Exelon and Pepco Holdings would have the right to stop pursuing the merger, if the Public Service Commission had not acted by then,” Exelon said in a statement. “Because the commission issued its order on Feb. 26, the March 4 date is no longer a trigger, and we are free to stop pursuing the merger if either party so chooses.”
Political Posturing?
Guggenheim Securities analyst Shahriar Pourreza said the fate of the merger may depend on whether Bowser and other officials truly want out of the deal or are playing politics.
“The big swing factor is if the mayor, attorney general and Office of [the] People’s Counsel are politically posturing or if they used Friday as an excuse to get out of this deal,” he told RTO Insider. “If it’s the former, it’s probably workable.” But, he said, “the longer they wait, the more the fundamentals of Pepco deteriorate and … the less attractive this transaction is.”
The PSC said that if all settling parties agree to its offer, the merger will be approved without further commission action. None of the D.C. officials opposing the PSC settlement has proposed a counteroffer.
The acquisition would give Exelon Pepco’s stable regulated income and the crown as the nation’s largest utility. But Pourreza said the deal has “materially deteriorated” over time. In a research note earlier in the week, he said, “We believe there is increasing likelihood Exelon could walk from the deal.”
Pepco ‘in Distress’?
“You kind of wonder if this even makes sense for Exelon,” he said. “There are plenty of single-state regulated utilities that they can go acquire that are not in as much financial distress as Pepco. This is not a healthy utility as a standalone entity.”
The PSC disagrees.
“There is no evidence in the record that Pepco could not continue to perform, and perform adequately and reliably as required by law, absent the … approval of Pepco’s sale to Exelon,” it said in its order Feb. 26. “Indeed, as the commission found in [its August 2015 order in the case], ‘PHI is financially healthy as a standalone company and would continue to be so if the merger is not consummated.’”
The merger already has the blessing of FERC and regulators in Delaware, Maryland, New Jersey and Virginia. They signed on under a “most favored nation” status, meaning in the end, all will be compensated equivalently — a disincentive for Exelon to sweeten the deal further with the district, Pourreza said.
If the merger doesn’t go through, Pourreza said, other suitors might be deterred from trying to purchase Pepco, given the regulatory hurdles D.C. has presented. “I think that these regulators have jeopardized this utility,” he said.
Dividend in Doubt?
On Monday afternoon, Pepco’s stock closed at $24.22, down 20 cents (0.82%) for the day. Exelon’s shares closed at $33.92, up 56 cents (1.68%).
If the merger doesn’t close, Pepco shares could lose $4 to $5 per share, Pourreza wrote. “Given that [Pepco] has been out of a rate case since 2014 and the delays with this merger, [it] has materially deteriorated as a standalone company, in our view.”
That could push its $1.08/share dividend to a 6% yield.
“It’s even questionable if they can support the dividend,” he said. “It’s pretty mind-boggling, the games that these regulators are playing. The agreement that the commission brought on Friday is very workable. I sort of question whether the commission did this because they knew that the settling parties wouldn’t go for this.”
Pourreza said he was at a loss to speculate what more Exelon could offer to salvage the deal, noting that “in a perfect world,” it should be offering less, not more, for Pepco at this point.
“I thought what the commissioners put out was equitable and now all of a sudden this is coming down to the $27 million issue,” he said. “It doesn’t make any sense to me. I tend to think [Bowser, Racine and OPC Sandra Mattavous-Frye] want out of this deal. … This is very abnormal.”
Cheh said the difference between using the fund to insulate ratepayers temporarily, only to have Exelon recoup the difference after four years, and disbursing the money when there is an actual rate case is not dramatic.
That, she said, leads her to think that Mattavous-Frye — an initial opponent of the merger who reversed course to back the mayor’s settlement — used the PSC’s proposed changes as an excuse to back away from the deal.
“Once Mattavous-Frye was out, the mayor was kind of stuck, I kind of think, because what was she going to say, ‘I think it was a good deal?’” Cheh said.
“What was at issue was a power struggle between the PSC and the mayor and who trusts whom,” Cheh said. “The fact that it may be scuttled over who gets to play with this money seems another surprising turn in all of this.”
One sticking point is that the rate relief would be shared with commercial customers, Cheh said. The U.S. General Services Administration, representing the federal government, the largest electricity consumer in the district, opposed the merger until the PSC offered the concession to broaden rate relief.
The settlement would have protected residential ratepayers through Bowser’s four-year term and potential reelection campaign.
“People have been saying all kinds of things,” Cheh said when asked if that might be a factor in Bowser’s insistence on preserving the rate credit. “Now that my rate increase may come right in the middle of your term — if you were the mayor, that’s something you would take into account.”
FERC on Tuesday approved changes to NYISO’s scarcity pricing logic that the ISO says will better reflect the real-time value of demand response (ER16-425).
NYISO implemented its current, ex-post scarcity pricing logic in 2013. The new logic allows the ISO to incorporate scarcity pricing into its real-time optimization. (See NYISO Seeks OK for New Scarcity Pricing Rules.)
“NYISO’s proposal increases price transparency by ensuring consistency between resource schedules and pricing outcomes in real-time when NYISO activates [demand response] resources, thereby reducing the potential for uplift costs,” the commission said.
“NYISO’s proposal recognizes that capacity that is available within 30 to 60 minutes can be dispatched to meet load prior to activating [demand response] resources. Thus, NYISO will procure a greater amount of available operating capacity from the market before relying on [demand response] resources and triggering scarcity pricing than under its existing rules,” FERC added.
As a result of the new logic, the ISO will:
Increase the value of Southeastern New York 30-minute reserves from $25/MW to $500/MW at all times to align the value of reserves with the actual cost of providing them;
Increase in the value of the middle pricing point of the regulation service demand curve (shortages of regulation service greater than 25 MW but less than 80 MW) from $400/MW to $525/MW at all times;
Reduce the target level for Southeastern New York 30-minute reserves to zero during actual or anticipated severe weather conditions (“storm watch events”); and
Increase the New York control area 30-minute reserve demand curve values priced at less than $500/MW to $500/MW, effective in real time during any DR activation.
The changes were supported by the Electric Power Supply Association, the Independent Power Producers of New York and the New York Transmission Owners.
The commission rejected protests by the New York Department of State’s Utility Intervention Unit, saying its concern that NYISO’s filing missed an opportunity to remedy an alleged flaw in its existing scarcity pricing mechanism was beyond the scope of the case.
FERC also rejected the UIU’s argument that the proposal could result in less efficient dispatch of generating resources and higher production costs. “We find that the benefits of increasing price transparency and incorporating scarcity pricing in the real-time market software outweigh such concerns,” the commission said, adding that “additional system changes may be required to further optimize the scarcity pricing mechanism and avoid the potential issues” the UIU raised.
FERC ordered the ISO to submit a compliance filing clarifying tariff provisions differentiating between scarcity events, when it calls on DR, and shortage events, when the market is short of operating, regulation, or transmission reserves.
The changes will become effective once NYISO deploys the required software changes. The ISO expects to complete the work by June 30.
Dynegy and Exelon proposed last week that MISO Zone 4 procure capacity in three-year forward auctions separate from the rest of the RTO.
The two companies — Illinois’ biggest power producers — offered separate proposals that would adopt elements of PJM’s model beginning in 2017. Both proposals were offered during MISO’s Competitive Retail Solution Task Team meeting Feb. 22.
The companies say that MISO’s Planning Resource Auction, currently held about three months before the beginning of a planning year on June 1, isn’t conducted far enough in advance to create a clear price signal. Both claim their proposals would further reliability and boost investments in new and existing power plants.
Exelon Proposal
“The overarching principal of Exelon’s Southern Illinois solution is to adapt PJM’s Reliability Pricing Model (RPM) to Zone 4, while integrating with the rest of MISO as seamlessly as possible,” Exelon wrote in its proposal. The company said the RPM “has proven to be highly successful at maintaining reliability at a reasonable cost to consumers using competition to determine market revenues.”
The company proposes that Zone 4 acquire capacity three years in advance in one-year commitment periods, as in PJM. The 2020/21 Planning Resource Auction would take place in April 2017.
Exelon’s proposal also requests a switch to a downward-sloping demand curve in Zone 4 and mandatory participation for all loads and internal supply in the zone. Exelon also wants “strong performance incentives” for resources that clear the auction.
Dynegy, which also called for use of downward-sloping demand curves, proposed holding four competitive auctions during the first quarter of 2017 to procure capacity through mid-2021. The company additionally proposed that by the first quarter of 2018, MISO would hold a three-year forward auction for delivery during the 2021/22 planning year.
Dynegy said the auction would procure 100% of the zone’s planning reserve margin requirement, based on load forecasts independently verified by a third party.
Participation would be mandatory only for load-serving entities and electric distribution companies in local resource zones with retail choice. Dynegy acknowledged its proposal would primarily affect the generators it purchased from Ameren Illinois in 2013.
Monitor Offers Own Proposal
Independent Market Monitor David Patton said a voluntary forward procurement — a single-year “strip” or a multiyear contract — “could be useful if desired by participants.”
But he said the mandatory forward auctions proposed by Exelon and Dynegy would be less efficient than MISO’s “prompt” procurement in facilitating efficient investment and retirement decisions.
In forward markets such as PJM, Patton said, generation owners must determine whether their older plants will continue to operate for an additional four years — three years plus the planning year. “In prompt procurement markets, old units can operate until they suffer equipment failure and can make efficient decisions to mothball or retire based on the auction.”
Forward markets also do not ensure that new resources offer capacity at prices close to the cost of new entry, he said.
Patton acknowledged that higher capacity prices in PJM have caused increasing levels of capacity exports from MISO. But he said that MISO’s design required “only incremental but meaningful” changes to address the challenges in Zone 4.
He would continue a single PRA for the entire footprint but replace the vertical demand curve with a variable reliability target in the competitive retail area. “Capacity product and obligations should be comparable throughout all of MISO,” he said.
Patton also said adding economic import limits to the existing electrical import limits would create a more efficient mix of resources inside and outside of deregulated markets.
MISO Offers Criteria, No Comment
MISO officials withheld comment on Exelon’s and Dynegy’s proposals, saying they want to consider a second round of stakeholder presentations at the next Competitive Retail Solution Task Team meeting March 7. Once the task team evaluates proposals, MISO will submit a recommendation to the newly created Resource Adequacy Subcommittee.
“We appreciate the dialogue and participation from stakeholders to collaboratively develop a solution,” MISO spokesperson Andy Schonert said. “We continue to study both Exelon and Dynegy’s proposals and look forward to more feedback from stakeholders on this topic.”
MISO released criteria that capacity proposals must meet for consideration, including acknowledgement that nearly all states in the RTO’s footprint are rate-regulated. Any new structure would be required to improve MISO’s ability to ensure sufficient resources, optimize economic use of existing and potential resources and maintain the benefits of MISO membership.
FERC Actions
Meanwhile, FERC continues to mull a number of MISO capacity issues.
On Feb. 25, the commission said it is considering a joint rehearing request by Illinois Attorney General Lisa Madigan and Illinois Industrial Energy Consumers, who are seeking clarification on whether “going-forward costs” used to calculate facility-specific reference levels should include sunk costs (EL 17-50, et al.).
With its window for limited tree felling closing in four weeks, Constitution Pipeline is again asking FERC for permission to allow the operation in New York (CP13-499).
The developer wrote the commission on Thursday, citing a federal court’s dismissal of an injunction sought by environmentalists seeking to halt cutting in Pennsylvania.
Crew installing silt fence (Source: Cardno)
Constitution argues this means the director of the Office of Energy Projects should allow it to conduct similar operations along the entire 124-mile route from the shale gas fields of northeast Pennsylvania to Schoharie County, N.Y. The 2nd Circuit Court of Appeals denied the environmentalists’ motion on Feb. 24 (16-345).
Constitution has to cut trees between Nov. 1 and March 31 to comply with U.S. Fish and Wildlife Service recommendations to mitigate impacts on migratory birds and the northern long-eared bat.
“Issues pertinent to this request were before the court and the court’s order provides additional support and the proper timing for the director to act on Constitution’s request … [with] the March 31 deadline established by the U.S. Fish and Wildlife Service fast approaching,” the letter states.
Constitution asked FERC to grant it a Notice to Proceed by March 2. FERC granted an NTP for Pennsylvania only on Jan. 29.
The developer said it would use chainsaws to cut trees at or above ground level and would not disturb soils or root systems. It said it would leave the felled trees in place until other construction started. But the operation has been challenged by environmentalists and New York Attorney General Eric Schneiderman, who contend that Constitution must first have clean water permits from the state Department of Environmental Conservation. (See New York AG: No Tree Cutting for Pipeline Without Water Quality Permits.)
Constitution said it had completed 70% of its planned cutting in Pennsylvania.
The project is a joint venture of Williams, Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings.
MISO officials presented a review of load and prices during an informational forum Feb. 23. Some highlights:
Real-time LMPs averaged $22.14/MWh for the month, a 21% decrease from a year earlier, while the day-ahead average fell 20% to $22.79/MWh. But rising natural gas costs helped boost power prices compared with December, with month-on-month real-time and day-ahead averages increasing 7% and 9%, respectively.
January marked the end of an 11-month decline in natural gas prices, as the Chicago Citygate rebounded 17% to average $2.33/MMBtu for the month, while Henry Hub jumped nearly 20% to $2.30/MMBtu. Still, Chicago Citygate prices remained far below the January 2015 average of $3.09/MMBtu.
MISO’s January load averaged 78.5 GW, up 8.2% from December but down 3% from the average for the same month a year ago, the grid operator reported. Load peaked at 98.2 GW on Jan. 19, compared with last January’s 106.5 GW peak and far short of the winter record of 109.3 GW set in January 2014. Day-ahead physical energy last month totaled 56.6 TWh, while real-time load hit 58.4 TWh, a drop from the 60.3 TWh in January 2015.
MISO wind output also hit an all-time peak of 12.7 GW on Jan. 27, exceeding the previous high of 12.6 GW set on Nov. 19. That figure, however, was quickly surpassed by a new record of 13.1 GW on Feb. 18.
MISO Develops New Metric to Monitor Queue Delays
MISO will measure progress in its generation queue using a new metric: study cycle scheduling, a process that makes existing interconnection agreements and facilities studies the basis for subsequent studies.
Using the metric, the RTO will flag the interconnection queue with “concern” or “review” status if generation interconnection studies can’t be completed on time. Jeff Bladen, executive director of market services, said MISO is currently experiencing delays in the queue because of an influx of restudies related to withdrawing interconnection projects.
“This new metric is allowing us to see more of the delays, but it’s also demonstrative of why reforming the queue process was so important,” Bladen said.
MISO is awaiting FERC approval of the proposed queue changes it filed Dec. 31. If approved, MISO will work to complete existing generation interconnect agreements and existing studies by May 20. (See MISO Unveils Queue Reform Transition as Wind Advocates Seek Delay.) MISO says the proposal will “reduce the delays and provide more certainty to timelines.”
“The reforms that we filed are to help resolve issues that are much more transparent with the metric,” Bladen said. He said that MISO was aware of the delay issues “at some level,” but the new metric made the issues much clearer.
FERC has accepted SPP’s proposal to address an underfunding problem in the RTO’s transmission congestion rights (TCR) market by reducing the number of auction revenue rights available in the annual allocation process (ER16-13).
The commission’s Feb. 19 order sets the amount of transmission system capability to be offered during the annual ARR allocation process at 60% for the fall, winter and spring seasons (October-May), as recommended by the RTO’s Market Monitoring Unit. SPP had proposed an 80% allocation during those months.
TCR market participants can convert firm transmission service reservations into a credit against daily congestion costs, either through a TCR or through payments received for the ARR.
‘Necessary Step’
FERC found adjusting the ARR allocation rules “are a necessary step” to correct the TCR underfunding.
“We view adjusting the system capability assumptions used to determine feasibility in the annual ARR allocation process as an important step toward reducing the potential for underfunding TCRs, thereby creating a more efficient TCR market,” the commission wrote.
The Monitor told FERC that the first full year of the Integrated Marketplace’s TCR operations produced a “high degree of disparity” between TCR payments and revenues, net of TCR uplift and TCR auction charges. It contended “this indicates that TCR auction prices did not accurately reflect the realized value of TCRs.”
The Monitor listed three contributing factors: “(1) the awarding of ARRs and TCRs beyond the physical limits of the transmission system, (2) the delayed reporting of planned transmission outages, and (3) the excessive valuing of self-converted TCR bids in auctions.”
TCR funding was 82% for its first full year, and the ARR funding level was 113%, the Monitor said. It shared data with FERC “demonstrating that, in every month, day-ahead congestion revenues fell short of TCR payments, while auction revenues exceeded ARR payments.”
FERC said using the 60% assumption during the October-May period will “better reduce the need to expand transmission constraint limits during the monthly processes, which contributes to the TCR underfunding problem.” Awarding fewer infeasible ARRs during the annual allocation process, the commission said, will mean SPP “will not have to expand transmission constraint limits as frequently.”
“As noted by the Market Monitor, expanding limits can lead to situations where TCR market flows exceed day-ahead market flows for certain transmission paths, resulting in TCR underfunding,” FERC wrote.
ARR Over-Allocation
SPP submitted its Tariff revisions to FERC in October, saying its market’s TCRs were underfunded because of an over-allocation of ARRs. The RTO told the commission “disparate system capability percentages used between the ARR and TCR processes” were largely responsible, resulting in awarding infeasible ARRs, and proposed more closely aligning the system capability percentages used between the annual ARR allocation and TCR auction processes.
The Integrated Marketplace, which became binding in March 2014, was originally designed to allocate ARRs in a single, annual process, with 100% transmission system capability assumed year-round when determining the feasibility of ARRs for the annual allocation.
SPP’s proposed Tariff revisions set ARR allocations at 100% for June, 90% for July-September and 80% for the remaining months.
The Monitor told FERC it did not support the proposed use of an 80% ARR allocation, saying it did not match the 60% system capability number used in the TCR auction process. It said the mismatch would result in potential TCR underfunding and noted the 80% allocation was “contrary to an earlier proposal, presented by SPP staff.”
The proposal was changed from 60% to 80% at the Markets and Operations Policy Committee level of the stakeholder process, the Monitor said, and it could not support the revised proposal because it “was not supported with analysis.”
SPP acknowledged that the proposed 80% figure “was the result of a compromise to achieve a more gradual approach to addressing the problem of TCR underfunding.”
FERC concluded that SPP had failed to “provide analysis or evidence to support the … assumption proposed for use during the October through May period.”
Collins pointed to the decline in bid cost recovery (BCR) payments as the second biggest “theme” of the fourth quarter. CAISO payouts came to $25 million under the market mechanism, compared with $31 million in the third quarter and $25 million during the same period in 2014. BCR payments attributed to residual unit commitments (RUC) fell from $10 million to $3 million quarter over quarter because of decreased payouts to “long-start” units.
