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.”
PJM is standing behind its original solution for congestion issues in the Met-Ed service territory in Pennsylvania, saying a $7 million rebuild of the 115-kV Hunterstown-Lincoln line was superior to a competing project from Ameren.
In a Feb. 11 letter, Jeffrey Hackman, senior director of transmission operations, technical services and business development for Ameren Transmission Company of Illinois (ATXI), asked the PJM Board of Managers to reconsider its decision to include the rebuild (Proposal HL_622) in the Regional Transmission Expansion Plan (RTEP) and to order RTO staff to “objectively and transparently re-evaluate” HL_622 and Ameren’s competing proposal (HL_469).
“ATXI does not make this request lightly but believes it is necessary to ensure that the process is just and reasonable and that customers receive the benefit of the process, which is supposed to result in the more efficient and/or cost-effective project being selected,” Hackman said.
Location of the 115-kV Hunterstown-Lincoln line | PJM
On Wednesday, PJM CEO Manu Asthana told Hackman in a letter that the RTO continues to support the rebuild.
“We have reviewed the record once again and determined that the selection was fully supported by our own staff’s detailed analysis (which included meetings with your staff), the results of an independent consultant’s review, and a review of the cost estimates of the Ameren proposal as compared to other competing proposals,” Asthana wrote. “The results of our analyses were presented at the November 2019 Transmission Expansion Advisory Committee meeting. For these reasons and after this recent additional review of all of the underlying facts, PJM stands by the original selection decision.”
Asthana’s response may not be the end of the dispute. Hackman — who alleged PJM’s actions violated FERC Orders 890 and 1000, and the PJM Operating Agreement and manuals — copied FERC commissioners and top staff on his letter. Asthana did the same in his response.
The line upgrade selected is proposed for Adams County, Pa., territory of FirstEnergy’s Met-Ed, and was proposed by FirstEnergy’s Mid-Atlantic Interstate Transmission (MAIT) subsidiary. MAIT signed a designated entity agreement to perform the rebuild last month (Project b3145).
It was selected from 19 greenfield and three upgrade proposals submitted by seven entities in response to a competitive window that closed in March 2019. The proposals’ estimated costs ranged from $4.65 million to $290.95 million
Ameren’s proposal called for installing a SmartValve — which manufacturer SmartWires describes as a “single-phase, modular, static synchronous series compensator (SSSC), [which] injects a leading or lagging voltage in quadrature with the line current, providing the functionality of a series capacitor or series reactor respectively” — on the Hunterstown-Lincoln line. PJM estimated its cost at $7.15 million.
The PJM cost analysis for HL_622 came in at $7.21 million.
Discretion and Transparency
In his letter, Hackman said Ameren staff expressed concerns to PJM regarding the process the RTO applied to evaluate proposals on two separate occasions: the 2014 30-day reliability window and the 2016/17 long-term market efficiency window.
Hackman said their concerns included a lack of specificity in the OA that “mystifies the basis of decisions” and a lack of transparency and consistency in the decisions on the merits of proposals.
In his response, Asthana said FERC Order 1000 creates “new opportunities, but also new complexities” in regard to new transmission technologies.
In the November 2019 presentation to the TEAC, PJM staff raised concerns with Ameren’s proposal, citing “limited experience with [the] SmartValve device.”
PJM also said Ameren’s proposal had higher permitting risk than the rebuild because it required “new property for [a] substation due to location near historically sensitive area.”
Staff concluded the rebuild would provide additional system capability, while the Ameren proposal could increase flexibility. But PJM said it would not be able to fully exploit the dynamic capabilities of the SmartValve without making changes to the day-ahead and real-time SCADA systems.
It said the rebuild had a benefit/cost ratio of 76.41 versus 72.61 for the SmartValve.
Hackman said Ameren understands PJM has “considerable discretion” under its OA. “However, transparency is necessary when there is this level of discretion, and PJM staff appear to have forgotten that,” Hackman wrote.
“PJM staff did not provide necessary details in the November TEAC to stakeholders explaining why the detailed feasibility review that was performed on Proposal HL_469 resulted in a 53.7% increase to the estimated cost of Proposal HL_469, causing the benefit-to-cost (B/C) ratio for the project to fall below the B/C ratio for Proposal HL_622,” Hackman continued. “PJM failed to provide that information in a timely manner that allowed for review and discussion in the TEAC and before PJM staff presented their recommendation for approval to the PJM Board of Managers.”
Asthana’s letter did not address Ameren’s B/C claim.
Will the dispute end up before FERC?
Asthana offered an olive branch. “We are always open to stakeholder input on potential process improvements and are committed to transparency and communication with stakeholders as part of the evaluation process,” he said. “We appreciate Ameren’s willingness to focus, at this point, on discussing with PJM and other stakeholders potential enhancements to our market efficiency competitive process and appreciate your proposals on these subjects.”
CAISO’s congestion revenue rights auction continued to lose money in 2019 but significantly less than in prior years, the ISO’s Department of Market Monitoring said in a recent report to the Board of Governors.
Even so, the department, a longtime critic of the CRR auctions, still wishes the ISO would get rid of CRRs or at least take ratepayers, who are unwittingly covering tens of millions of dollars in annual losses, out of the equation.
“Rule changes made by the ISO reduced losses from sales of congestion revenue rights significantly in 2019,” DMM Executive Director Eric Hildebrandt wrote in a memo to the board. “However, DMM continues to recommend that the ISO take steps to discontinue auctioning congestion revenue rights on behalf of transmission ratepayers.
“If the ISO believes it is highly beneficial to actively facilitate hedging of congestion costs by suppliers, DMM recommends that the ISO modify the congestion revenue rights auction into a market for financial hedges based on clearing of bids from willing buyers and sellers,” Hildebrandt said.
From 2009 to 2018, CAISO’s CRR auctions resulted in net losses of more than $800 million for transmission ratepayers, Hildebrandt said in his March 25 update to the board. (Hildebrandt’s memo was a summary of a more detailed report filed Jan. 27.)
Auction revenues compared to payments to auctioned congestion revenue rights (2012-2019) | CAISO
Revenues collected in the auction worked out to about 50 cents on dollars paid out, it said. Losses from sales of CRRs totaled $100 million in 2017 and $131 million in 2018, the DMM said. (See CAISO Q4 CRR Revenues Falling Short After Summer Surplus.)
Starting in 2019, CAISO instituted rule changes meant to stanch the flow of money from ratepayers to commodities traders. The rule changes reduced losses significantly last year in conjunction with lower congestion on the grid, the department said.
Losses from sales of CRRs totaled approximately $34 million in 2019, including $22 million in the fourth quarter alone. Transmission ratepayers took in about 68 cents on each dollar paid out, while financial entities reaped $33 million in profits, the department said.
One rule change, called Track 1B, reduced payments to non-load-serving entities by $44 million, according to the DMM. The change limited payments from exceeding the congestion rent collected on the underlying constraints.
Another change, Track 1A, limited the kinds of CRRs that could be purchased at auction. It also appeared to have helped, though the changes couldn’t be quantified, the department said.
The DMM said a third factor — lower congestion than in past years — played a major role too. Day-ahead congestion rent fell from $628 million in 2018 to $355 million in 2019, a 43% reduction.
“Thus, while losses dropped from $131 million to $32 million in 2019,” the Monitor said, “a significant portion of this decrease can be attributed to the drop in overall congestion.”
FERC on Thursday issued a flurry of orders delegating authority and waiving requirements in response to the COVID-19 coronavirus pandemic.
The commission issued:
A policy statement saying it will “expeditiously review and act on requests for relief” to ensure the business continuity of regulated entities’ energy infrastructure (PL20-5).
An order delegating authority to the director of the Office of Energy Market Regulation (OEMR), or the director’s designee, “to take action on uncontested requests for waiver of certain regulatory obligations to address needs resulting from steps entities have taken to meet the emergency conditions” (AD20-13). The delegation will be effective until June 1.
An order delegating authority to the director of the Office of Energy Policy and Innovation, or the director’s designee, to act on requests for extension of filing deadlines or waivers of the requirements of FERC Form 552 (Annual Report of Natural Gas Transactions) and FERC-730 (Report of Transmission Investment Activity). This authority was previously delegated to the director of the Office of Enforcement (RM20-13).
An order extending until Oct. 20 the deadlines for RTOs and ISOs to post monthly reports that would have been due between April and September on uplift and operator-initiated commitments (RM17-2). (See FERC Orders RTOs to Shine Light on Uplift Data.)
An order granting a blanket waiver through Sept. 1 of requirements to hold meetings in-person and obtain notarized documents in any tariff, rate schedule, service agreement or contract subject to the commission’s jurisdiction under the Federal Power Act, the Natural Gas Act or the Interstate Commerce Act (EL20-37). NYISO had requested relief from the notary requirements on March 27 (ER20-1419).
FERC has already granted PJM’s request for a waiver of generator interconnection-related deadlines (ER20-1392).
The commission said its delegation to OEMR will allow more efficient action on uncontested waiver requests. “The need for efficient processing and action is particularly important given the emergency conditions related to COVID-19, as entities may need to seek waiver of various requirements with which they are unable to comply due to the extraordinary circumstances,” the commission said.
It said the waiver “does not permit violations of the filed rate doctrine and the rule against retroactive ratemaking, even in uncontested cases. If such questions arise, they will be considered by the commission.”
The policy statement noted that the entities subject to FERC regulation “have had to take unprecedented actions in response to the emergency conditions, including directing staff to work remotely for an extended period, which may disrupt, complicate or otherwise change their normal course of business operations.”
“We will give our highest priority to processing filings made for the purpose of assuring the business continuity of regulated entities’ energy infrastructure during this extraordinary time,” the commission continued. “We view the reliability and security of our nation’s vital energy infrastructure as critical to meeting the energy requirements essential to the American people.”
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.”
