Former ERCOT staffer Carrie Bivens on Monday will begin her new role as director of the grid operator’s Independent Market Monitor.
Bivens has spent nearly 14 years with ERCOT, most recently as director of wholesale operations. She oversaw the Texas grid operator’s day-ahead market and congestion revenue rights auctions, as well as integration of load resources, distributed generation and emergency response service. As a subject matter expert in ERCOT’s stakeholder process, Bivens has made frequent appearances in recent years before both its Board of Directors and the Texas Public Utility Commission.
Carrie Bivens, ERCOT’s new IMM director | ERCOT
Virginia-based Potomac Economics has provided ERCOT’s market monitoring services since 2005 and was recently awarded another stint by the PUC, which has jurisdictional authority over the grid operator. Potomac also serves as the IMM for ISO-NE, MISO and NYISO.
Potomac interviewed the candidates and made the final selection. The PUC was given an opportunity to approve or reject the hire.
“I’m grateful to the PUC and to Potomac Economics for the trust bestowed upon me in this vital era in ERCOT as major initiatives such as real-time co-optimization of energy and ancillary services get underway,” Bivens told RTO Insider.
As the IMM’s director, Bivens will collaborate with the PUC to detect and prevent market manipulation and identify potential design improvements for the ERCOT wholesale market. She said her initial focus will be ensuring a “timely and comprehensive” State of the Market report for 2019. The report traditionally comes out in May or June.
Steve Reedy, who served as the IMM’s acting director following Garza’s departure, will return to his role as assistant director.
In a statement emailed to RTO Insider, ERCOT said, “Carrie Bivens’ skills as a manager and communicator are only exceeded by her intelligence and wit. The PUC could not have made a better choice, and ERCOT will miss her.”
Before coming to ERCOT, Bivens worked at FERC evaluating market-based rate filings and conducting market power analyses. She is a native Texan and a graduate from her hometown University of Houston.
ISO-NE will file two versions of its Energy Security Improvements market design with FERC later this month after the New England Power Pool Participants Committee on Thursday approved a modified version of the RTO’s plan that seeks to reduce its cost to consumers.
ESI would allow the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter when natural gas shortages can leave generators without fuel. Option awards will be co-optimized with all energy supply offers and demand bids in the day-ahead market.
The PC approved three amendments by the New England States Committee on Electricity (NESCOE) by a 61.7% sector-weighted vote, with unanimous support from the Transmission, Publicly Owned Entity and End User sectors and unanimous opposition from the Generators. ISO-NE’s unamended proposal received only 39.6% support, with support from Generators, Suppliers and Alternative Resources and unanimous opposition from the other sectors.
ISO-NE said that although FERC has found that certain compliance filings are not covered by the “jump ball” provisions of the NEPOOL Participants Agreement, it “has committed nonetheless to include in its April 15 filing the same information it would include were the filing a jump ball.”
The RTO said it will include a description of the NESCOE proposal “in detail sufficient to permit reasonable review by the commission, explain [ISO-NE’s] reasons for not adopting the proposal and provide an explanation as to why [ISO-NE] believes its own proposal is superior to the proposal approved by the Participants Committee.”
The result of more than a year of stakeholder meetings, the ESI proposal was prompted by FERC’s July 2018 finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022. The Tariff currently allows cost-of-service agreements only to respond to local transmission security issues (EL18-182, ER18-1509). (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)
NEPOOL’s Transmission, Publicly Owned and End User sectors unanimously backed three NESCOE amendments to ISO-NE’s ESI proposal, and a fourth vote that combined all three amendments, while the Generation sector uniformly opposed all the changes. ISO-NE’s unamended proposal had strong support from Generators, Suppliers and Alternative Resources but was unanimously rejected by the three other sectors. | NEPOOL
FERC last August granted the RTO an extension to file the plan by April 15.
In March, the RTO’s unamended proposal failed in the NEPOOL Markets Committee with 42.4% in support, while a proposal including NESCOE’s amendment to set the value of replacement energy reserves (RER) to zero for non-winter months — essentially eliminating it except for three months — only received 51.77% support. (See NEPOOL Markets Committee Briefs: March 24, 2020.)
Mathematics Exercise
The PC approved three amendments proposed by NESCOE before approving the amended ESI package.
Jeff Bentz, NESCOE director of analysis, proposed the amendments “because the concerns we raised as early as April 2019 and even before haven’t been addressed to our satisfaction, and we believe that puts consumers at great risk, especially during extended cold snaps.
“As we sit here today, the only commitment from ISO-NE is to consider increasing the quantities through a yet-to-be determined addition for load forecast error and to add even more consumer cost through some type of forward market concept that likely will increase costs and not add much additional reliability benefit,” Bentz said. “NESCOE brings forward these three amendments to help bring the cost-versus-benefits inequities closer in balance.”
The first amendment to set the RER value to zero for non-winter months passed with 63.76% in favor, as did the second NESCOE amendment, which was to remove the RTO’s ability to adjust reserve levels to account for load forecast errors.
Massachusetts Assistant Attorney General Christina Belew said her office supported the first amendment “because we don’t think the RER product is required under the [Northeast Power Coordinating Council] Directory 5. We think it has a tenuous link to fuel security, and it is disproportionately expensive.” Directory 5 sets minimum requirements for “the amount, availability, distribution and activation of reserve in addition to those specified in applicable NERC standards.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article amplified their remarks afterward to clarify their presentations.]
“This whole effort was built around the Analysis Group’s assessment of a way to pay for a very minor, 10-day LNG contract, so it was all about 10 days of LNG,” said Brett Kruse of Calpine, who voted against all the amendments but supported the RTO’s proposal. “For the record, none of the folks that voted against in the Markets Committee, nor any of the folks who’ve spoken out against it today, have offered an alternative to secure winter fuel security for New England.
“If you look at this as a mathematics exercise, the numbers don’t add up without the entire ISO New England package, and even then, it’s marginal,” he said. “Second, we’ll make prudent business decisions year over year, and if that means going into a winter where we don’t think we’re going to be able to recoup the costs of an LNG contract we probably won’t buy it.”
NESCOE’s third amendment, to include a $10/MWh adder to the strike price in all hours, passed with 61.27% in favor. NESCOE said it would reduce the cost and risk of the energy call option for providers without materially affecting resources’ incentives under the program.
Down, not Out
Bentz said NESCOE’s objections to the unamended ESI proposal fell into two categories.
“First of all, the ISO’s proposal is an unpredictable, year-round call option approach,” Bentz said. “We think it exceeds the scope of the FERC’s order in 2018, and instead of just addressing winter fuel security, the ISO creates this novel, untested and potentially very expensive program for pricing reserves in the day-ahead market.
“Secondly, ISO-NE’s proposal is going to produce an unjust and unreasonable rate,” Bentz continued. “The ISO’s approach is highly vulnerable to producing uncompetitive outcomes due to the inability to effectively mitigate market power. It procures substantially more reserves than the system needs, and at an excessive cost to customers.
“The ESI design is not good value for the money, and collectively, the six New England states are not in favor of this design as being presented here today,” Bentz said.
ISO-NE COO Vamsi Chadalavada offered the grid operator’s perspective on ESI.
“In our view, we are working to balance energy security concerns, not just for the immediate time frame, but for the longer term, and think a more complete design will accomplish that,” Chadalavada said. “We are mindful and sensitive to consumer costs, and it’s certainly been one of the considerations as we built the risk-responsive design.”
The regional electric power system is evolving fast and the RTO has sometimes been reactive, he said.
“This design positions us better as New Englanders because it allows us to be more proactive in terms of the uncertainties that we face,” Chadalavada said.
OKs Early EIP Sunset
The committee also approved Tariff revisions to sunset the RTO’s interim Inventoried Energy Program (IEP) after capacity commitment period 2023/24, one year earlier than the end date in the current Tariff. The early sunset would be conditioned on FERC’s approval of the ESI proposal for implementation no later than June 1, 2024.
FERC in February rejected a request by ISO-NE and NEPOOL to roll back the sunset date for a Tariff provision that allows the RTO to retain a resource for fuel security reasons. The RTO said it plans to refile the Tariff revision when it files its ESI proposal. (See FERC Rejects ISO-NE Fuel Security Sunset Rollback.)
Other Actions
The PC also approved as part of its consent agenda revisions to Market Rule 1 relating to energy efficiency resources’ capacity supply obligations during scarcity conditions, as proposed by NESCOE and recommended by the MC in March.
The committee also unanimously approved revisions to Market Rule 1 to address FERC’s March 10 order rejecting provisions governing how ISO-NE’s Internal Market Monitor calculates the economic life of resources that want to retire or permanently leave the capacity market. The provisions were intended to correct calculations that ISO-NE said overstated the true economics of some resources and could result in improperly high delist bids. But the commission said the rules’ effective date would upset market participants’ “settled expectations” after the Forward Capacity Auction 13 qualification process for delist bids had begun (ER18-1770-002). (See FERC Reverses Ruling on ISO-NE ‘Economic Life’ Rules.)
The proposal asks FERC to make the changes apply prospectively beginning with FCA 16.
ISO-NE CEO Gordon van Welie said that the RTO activated emergency operation procedures to counter the COVID-19 pandemic on March 12 and that “it’s been really gratifying to see how smoothly the transition went.”
“We have all these contingency plans, emergency plans, and have experimented with half the workforce working from home, but we never had to implement them for real before now,” van Welie told the New England Power Pool Participants Committee on Thursday.
The RTO has more than 95% of its workforce now working remotely, with remote deployment to continue through at least May 4, and is taking special care for the health of crews for the two control centers, ISO-NE COO Vamsi Chadalavada said.
“The industry has really come together in a very refreshing and collaborative way,” he said. “I think folks have closed ranks; there’s a lot of cooperation; and best practices are being shared in near real time. There are extensive communication protocols across the country and internationally.”
Comparison of a few similar days between 2019 and 2020 for midweek in the second half of March. 2020 load curves show as lower and delayed ramp in the morning; overnight loads are lower with closings of 24-hour operations. | ISO-NE
The Electric Power Research Institute has been hosting sessions, and the RTO conducts its own conference calls with generators and every key link in the supply chain to ensure reliability, Chadalavada said.
Chadalavada reported overall March 2020 demand approximately 3 to 5% lower than in prior years, with load curves having changed shape with the pandemic outbreak from the second half of March as the New England states started to require people to stay home.
“The load curves that are now being established mimic snow days when people typically stay home and businesses are either shut down or otherwise operating at not full speed,” he said. “We see that the morning ramp is delayed. What used to be a ramp around 7 a.m. is now extending to 8 a.m. or even 9 a.m.”
Comparison of the unadjusted output of a single load forecast model to the actual New England load in March. Peaks and valleys are similar until around March 15, when the coronavirus began to hit the region. | ISO-NE
The situation presents a challenge to forecasting load, especially now, and the deviation from actual load has in the last few days been “north of 3%, so we’re clearly not meeting our target 1.8% error, but our forecasters are vigilant and staying very close to system conditions,” Chadalavada said.
The RTO is exploring the risk of underestimating loads after the pandemic-induced economic shutdown, he said.
With continued choppiness expected over the next week, “we are trying to train our models, but as you can assume, two weeks of training is almost insufficient for any model to upgrade its performance,” Chadalavada said. “Coming out of it will be an even bigger challenge, so right now I see the algorithmic foundation as the biggest challenge for forecasting load.”
In terms of settlement, the RTO has well established procedures, he said.
“If there are any delays in flow of data, and if we have to make adjustments to it because of any reason, I’m sure we will act quickly and work with all of you to do so,” Chadalavada said.
In his monthly litigation report, NEPOOL Secretary David T. Doot delivered noted FERC’s actions last week to delegate additional authority and issue waivers of some requirements in response to the pandemic. (See related story, FERC Loosens Requirements in Pandemic.)
A publication that covers financial mergers and acquisitions said Friday that NextEra Energy is toying with the idea of acquiring Kansas City utility Evergy.
According to M&A by Reorg, recent activist pressure from Elliott Management, which manages funds that own an economic interest equivalent to approximately 10 million shares of Evergy’s common stock, may make the company more willing to consider a sale.
NextEra has hired Citi to advise on the potential acquisition, and internal evaluations are at the preliminary stages, according to the report.
The publication said American Electric Power and Ameren are also said to be interested in Evergy.
NextEra declined to comment, following its policy to not respond to market rumors.
AEP and Ameren also declined to comment. Ameren did note it is focused on executing its strategic plan, which is based on “strong organic growth” in its regulated businesses.
Evergy announced in early March that it had reached an agreement with Elliott to establish a new strategic review committee to explore ways to improve shareholder value. Elliott said at the time that Evergy is now “well positioned to significantly increase investment in critical electric infrastructure to benefit key stakeholders.”
Evergy also agreed to add two new independent directors to its board, raising the number of directors to 17. The board’s membership will be reduced to 13 by retirements before the May shareholders’ meeting.
The two new directors, former Energy Future Holdings senior executive Paul Keglevic and NRG Energy CFO Kirk Andrews, will comprise half of the Strategic Review & Operations Committee, which will look at “potential strategic combination(s)” or a modified long-term standalone operating plan. It can retain its own independent consultants, advisers and counsel to facilitate its review and has an information-sharing agreement with Elliott.
“Elliott recognizes our commitment to serving the best interests of all Evergy stakeholders,” Evergy CEO Terry Bassham said in the announcement. “We welcome these new, highly qualified directors and the significant and valuable experience they bring to this effort. The comprehensive strategic and operating review we are undertaking will help ensure that Evergy is directing capital to the greatest opportunities and continuing to consider all opportunities to enhance shareholder value.”
Evergy, an SPP member, was created in 2018 by a merger between Kansas City Power and Light and Westar Energy. It serves 1.6 million customers in Kansas and Missouri.
FERC said Friday that PJM must rebill parties with interest to reverse incorrect cost assignments for transmission projects to meet individual utilities’ planning criteria.
In 2015, the commission approved a PJM Tariff change that assigned 100% of the costs of Form 715 transmission projects to the sponsoring utility’s ratepayers. But FERC reversed itself last August after the D.C. Circuit Court of Appeals said it had erred.
The commission on Friday rejected rehearing on its August order and clarified that PJM should issue refunds dating back to May 25, 2015, with interest (ER15-1387-005, ER15-1344-006).
The commission rejected arguments by Linden VFT and Consolidated Edison Company of New York that the commission should have limited its remand order to high-voltage facilities.
Dominion Energy replaced a 500-kV line between the Cunningham and Elmont substations. | Dominion Energy
“PJM’s Tariff uses the solution-based DFAX [distribution factor] method to determine whether transmission facilities have benefits outside of the zone of the transmission owner constructing the project and allocates costs to zones based on the application of that methodology,” FERC said. “Because the benefits of lower-voltage facilities may accrue to other zones, we do not see a basis for limiting cost allocation for lower-voltage facilities planned under Form No. 715 local planning criteria to only the local zone of the constructing transmission owner.”
Linden also sought rehearing on the issue of refunds, arguing that the commission’s “default” policy is to reject refunds in cases of rate design.
The commission responded that it “does not have a general policy concerning refunds” but makes decisions based on each case individually.
“Here, the commission has found the facts and equities favor refunds,” it said. “For example, requiring refunds in this case requires only redetermining past payments; it does not involve the difficult issues often associated with the rerunning of auctions.”
PJM said it identified 443 transmission projects that had been assigned 100% to the zone of the TOs filing the Form 715 planning criteria between May 25, 2015, and the remand order on Aug. 30, 2019. It determined that it needed to revise allocations for 44 of the projects.
The new allocations reassigned costs for several projects in the Public Service Electric and Gas zone to Con Ed, East Coast Power, Neptune Regional Transmission System, Rockland Electric, PECO Energy and Jersey Central Power & Light.
Dominion Energy, which had been assessed for 100% of the rebuild of the Elmont-Cunningham 500-kV line, is now sharing the cost with 23 other utilities.
SPP stakeholders last week unanimously approved the initial set of protocols that will guide the RTO’s Western Energy Imbalance Service (WEIS) market in the Western Interconnection.
The Western Markets Executive Committee, meeting by phone on Friday, also formally disbanded the WEIS Protocol Review Task Force, which drafted the protocols. It will be replaced by the Western Markets Working Group, which has scheduled its first meeting for April 29. (See SPP Launches Western Market Groups.)
“I think [the protocols] are in a really good spot,” said SPP’s Gary Cate, who worked on the task force. “We know of some sections that need cleanup … but this is a living document. There are things in here that both the SPP team and the protocol team thought this is how the market should work. If we’re going to find it doesn’t work or what we thought is clear is not clear, we’ll clean those up or add new sections.”
The protocols’ settlements section and some formulas need to be revised, Cate said. Connectivity testing, market trials and parallel operations will likely highlight other revisions that need to be made, using a revision request process modeled on SPP’s.
To emphasize the point, David Kelley, SPP’s director of seams and market design, noted that the grid operator’s Integrated Marketplace protocols are currently in version 75.
“That gives you a flavor of how dynamic the protocols are,” Kelley told the committee. “You guys have the ownership of these protocols and this doc. It’ll change as often as you guys approve it to be changed.”
When it came time to vote, Chair Tim Vigil, with the Western Area Power Administration’s Colorado River Storage Project, asked whether committee members had any questions. He was greeted by dead silence, a sign of the impending vote.
The task force approved the protocols without opposition. Each of the companies on the committee also had a representative on the task force.
The WEIS market is scheduled to go live next February. SPP will centrally dispatch energy from the participants every five minutes to provide price transparency and bilateral trades.
FERC has extended the implementation deadline for the latest version of the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communication Protocols for Public Utilities (RM05-5-028).
The commission acted Friday at the request of SPP and MISO, which said the original July 27, 2020, deadline would not give them enough time to follow NAESB’s implementation outline. They also said that Open Access Technology International (OATI), which provides the Open Access Same-Time Information System software to much of the industry, will not complete necessary upgrades by the deadline.
NAESB home page | NAESB
FERC adopted Version 003.2 of NAESB Standard WEQ-002 on Feb. 4, saying it was “necessary to increase the efficiency of the wholesale electric power grid.” (See FERC Adopts NAESB Business, Communication Rules.)
The commission’s order required public utilities and utilities with reciprocity tariffs to make compliance filings through eTariff by May 25. The commission said it would set an implementation date for the proposed tariff changes in its orders on the compliance filings.
Utilities that incorporate the complete set of NAESB standards without modification would have had to implement the standards by July 27.
The commission’s notice Friday extended the deadline for compliance filings through e-Tariff to July 27, 2021. It said it will determine an implementation date for all utilities, including utilities whose tariffs incorporate the NAESB standards without modification, no sooner than Oct. 27, 2021.
NAESB’s voluntary standards become mandatory for FERC-regulated public utilities after they are incorporated into the commission’s regulations. The rule requires public utilities and entities with reciprocity tariffs to modify their open access transmission tariffs to include the Wholesale Electric Quadrant (WEQ) standards that FERC incorporated by reference.
OATI and the Edison Electric Institute have asked FERC to clarify its order adopting the standard, saying that some language in its order might conflict with the commission’s “Dynegy redirect policy.”
The policy states that “transmission customers receiving firm transmission service and requesting redirect rights do not lose rights on the original path until the redirect request is accepted by the transmission provider, confirmed by the transmission customer and passes the conditional reservation deadline.” (See EEI, OATI Seek Clarification on FERC Order.)
Bob Cummings, NERC’s senior director of engineering and reliability initiatives, has retired from the organization after 24 years, NERC said on Friday.
Cummings joined NERC in 1996, having spent nearly 20 years working in grid planning and operations in the Eastern and Western interconnections. His early contributions to the organization included helping develop the practice of e-tagging, which helps to track the flow of electricity across the bulk power system, along with the concept of predicting and controlling transmission congestion in the Eastern Interconnection with an interchange distribution calculator.
Following the Northeast blackout of 2003, Cummings led the investigation into the incident and created NERC’s System Protection and Control Task Force. He later created the organization’s event analysis program and directed it for five years, either leading or working on analyses for 12 major bulk power system disturbances. He also served as the principle investigator on the Arizona-Southern California outage of September 2011 and the D.C. area low-voltage disturbance event of April 7, 2015.
“Bob’s commitment and passion for bulk power system reliability has served as an inspiration for industry and the ERO Enterprise,” Mark Lauby, senior vice president and chief engineer at NERC, said in a press release. “His leadership has led to significant contributions helping to ensure the continued reliability of the bulk power system.”
Since 2018, Cummings has served on the Department of Energy’s Electricity Advisory Committee. The committee assists in coordination between DOE and other federal agencies, state governments and industry on electric reliability and emergency response; coordinates electricity policy issues; and monitors developing generation, transmission and distribution issues. He has also contributed to updating the standards of the Institute of Electrical and Electronics Engineers to address reliability issues related to system protection and renewable resources.
“The rapid pace of change on the bulk power system — meaning the move from a fuel-diverse, central-station model with large reserve margins to a fast-ramping, tightly managed system consisting largely of natural gas and renewable resources — has been the greatest challenge and reward of my career,” Cummings said. “Addressing the reliability risks posed by today’s bulk power system paradigm requires more flexible resources and a more flexible engineering-based approach to planning and operations.”
FERC on Wednesday reaffirmed its conclusion that bidding results in ISO-NE’s 2013/14 Winter Reliability Program were just and reasonable despite the fact that the largest participants may have had market power (ER13-2266-004).
ISO-NE’s program offered compensation to demand response and generators able to burn oil to prevent New England from falling short of power in the winter because of the retirement of coal-fired units and tight natural gas supplies.
Wednesday’s order was prompted by a D.C. Circuit Court of Appeals ruling in December 2015 that said the commission had failed to justify its approval of the auction results. Although ISO-NE estimated the program would cost no more than $43 million for up to 2.4 million MWh of energy, the RTO filed for approval of bids totaling 1.95 million MWh at a cost of $75 million.
The court said that in approving the auction results, FERC failed to address how much of the program’s cost was attributable to profit and risk mark-up or to explain the economic forces that it believed restrained participants from submitting excessive bids.
The court was acting on an appeal by TransCanada Power Marketing, which contended ISO-NE’s pay-as-bid auction resulted in excessive costs because resources were incented to raise their bid prices knowing they would probably be accepted.
In response to the D.C. Circuit’s remand, FERC directed ISO-NE to query bidders on the process they used to formulate their offers. It also ordered the RTO and its Independent Market Monitor to opine on the reasonableness of the bids based on that information. (See ISO-NE Ordered to Justify Cost of Winter Reliability Program.)
The IMM found that each participant had market power because there was insufficient supply to meet the RTO’s 2.4 million MWh procurement target and that the program did not include a mechanism for mitigating their leverage. It said market participants were aware of their market power because the first auction failed to attract sufficient supply to meet the target.
About 70% of the supply offered into the auction came from only four participants, a concentration that the IMM said allowed them to submit bids above a competitive level.
After the remand by the D.C. Circuit, the IMM calculated that the supply curve would intersect with the assumed procurement level of 1.95 million MWh — the amount procured in the second auction — at a marginal cost of $15.08/MWh-month.
ISO-NE and its Independent Market Monitor calculated different expected marginal bids for the Winter Reliability Program because the RTO assumed procurement of 2.25 million MWh and the IMM assumed the purchase of only 1.95 million MWh. | FERC
The Monitor boosted that price to $18.85/MWh-month — a 25% risk premium reflecting participants’ limited information regarding the auction’s supply and demand curves and uncertainties over how the RTO would value resources in what was the first year of the program.
The IMM estimated the auction resulted in potential cost overages of $6.6 million, compared to what the program would have cost if all bids were at or below $18.85/MWh-month. The IMM concluded that 75% of the supply offered was competitive, but the remaining 25% “included sufficiently high markups to raise concerns that participants submitting bids for this supply may have exercised market power.”
“Market design issues, lack of information, uncertainty and measurement accuracy issues … prevent us from concluding, with certainty, the extent to which participants exercised market power or the impact it had on program cost,” the Monitor said.
ISO-NE conducted a similar analysis but assumed a supply curve of 2.25 million MWh, which it said would result in a clearing price of $24.86/MWh-month, or $31.08/MWh-month including the 25% adder.
It concluded there was no evidence that market power was exercised because there were no bids above $31.08/MWh-month. Using $24.86/MWh-month, it estimated $1.72 million in potential cost overages.
“We find that although the IMM found that the auction was not structurally competitive, ISO-NE nevertheless demonstrated that the Winter Reliability Program prices were just and reasonable because there were factors that sufficiently restrained parties’ ability to exercise market power,” FERC said. “These factors included the facts that, ahead of the auction, participants lacked information about ISO-NE’s chosen level of procurement, the costs and strategy of their competitors, and how ISO-NE would value the non-cost reliability factors that it would consider in addition to price when selecting bids.”
FERC compared the $75 million cost of the program to ISO-NE’s estimate in 2013 that the value of lost load “could reach into billions of dollars for a region the size of New England.” The RTO had cited estimates of the costs of the 2003 Northeast blackout, which ranged from $4 billion to $10 billion ($2003).
For a “competitive benchmark,” FERC looked at what costs would have been had the RTO used a single-price clearing auction — which incents bidding based on individual resource’s marginal cost — rather than pay-as-bid, in which participants seek to bid just below their estimate of the clearing price.
If resources bid based on marginal costs, FERC said the auction would have cleared at $15.08/MWh-month for a total of $88 million — above the actual total of $75 million ($12.82/MWh-month).
TransCanada protested the auction results, saying that ISO-NE’s “reliability need … created an essentially inelastic vertical demand that suppliers were aware of.”
FERC disagreed, saying that while the RTO said it would purchase “up to” 2.4 million MWh of winter reliability service, it ultimately purchased only 1.95 million MWh. “Contrary to TransCanada’s view, structural market power alone (i.e., a structurally uncompetitive market) does not necessarily result in unjust and unreasonable rates,” the commission said.
FERC also disputed the IMM’s conclusion that the 70% market share held by the four largest participants — the result of a C4 concentration test — was evidence that the auction was uncompetitive.
The commission said its preferred concentration test, the Herfindahl-Hirschman Index (HHI) — which sums the squares of the market shares of each market participant — resulted in an HHI of 1,462, “indicating a moderately concentrated, but not a highly concentrated, market.”
Even assuming there was structural market power, “there is no conclusive evidence that participants knew they had structural market power; therefore, participants would have bid competitively,” FERC said. “This is particularly likely given that the Winter Reliability Program presented a new product market with no prior auctions, making it more difficult to determine which other oil-fired generators would choose to participate and then what quantity of service each would bid (to cover their respective costs and include profits sufficient to warrant their participation in the auction).”
FERC on Wednesday resolved a dispute over overlapping congestion charges on the MISO–SPP seam when it accepted a settlement between Southwestern Electric Power Co. (SWEPCO) and the city of Prescott, Ark.
The settlement outlines a new rate schedule and documentation that the utility must provide the city for a power supply agreement (ER20-869).
Prescott filed its complaint against SWEPCO, an American Electric Power subsidiary, and MISO last April, but the issue behind the complaint can be traced to the 2013 integration of Entergy into the RTO. The city opposed Entergy’s integration because it would be moved into MISO and served by a pseudo-tie from SPP member SWEPCO under a power supply agreement. SWEPCO proposed eight years ago to build a new transmission line to buffer the city from excessive charges from MISO, but it was never built.
Prescott’s 2019 complaint claims that the failure of MISO and SWEPCO to guard it from congestion have pinned the city with about $770,000 per year in duplicate congestion charges and unreasonable transmission rates. SWEPCO neither hedged the city’s transmission congestion risks nor protected it from rate pancaking, abandoning duties under the power supply agreement, Prescott contended.
City of Prescott, Ark., water tower | Waymarking
The situation also spurred SWEPCO to file a separate complaint alleging MISO violated its joint operating agreement with SPP regarding congestion charge assessments for loads that are pseudo-tied out of MISO and into SPP. The utility said the charges resulted in a $963,974 overpayment to MISO for one four-month period in 2016. A FERC investigation into MISO and SPP’s potentially overlapping congestion charges is ongoing. (See FERC Sets Briefings on MISO, SPP Congestion Fees.)
Under the settlement agreement approved Wednesday, SWEPCO must file updated depreciation rates as formula rate inputs to FERC whenever the Louisiana Public Service Commission, Arkansas Public Service Commission or the Public Utility Commission of Texas approve changes to the utility’s state depreciation rates that would affect Prescott’s rates. If four years pass without an update, SWEPCO must make a FERC filing to update its depreciation rates.
The settlement also holds SWEPCO to providing Prescott with an annual populated formula rate, “including detailed work papers and other relevant supporting documentation, and to responding to Prescott’s requests for additional data related to the formula rate calculations.”
Finally, SWEPCO must also detail all RTO transmission charges and MISO market charges in its monthly invoices to Prescott.
FERC trial staff said the settlement agreement “reflects thoughtful and reasoned negotiations undertaken by all participants in good faith.”
