NextEra Energy touted “one of the best renewable development periods” in its history as it reported third-quarter adjusted earnings on Tuesday, beating analysts’ expectations.
The Florida-based company’s earnings were $1.16 billion ($2.39/share), an increase over 2018’s third-quarter earnings of $1.04 billion ($2.17/share). Zacks Consensus Estimate had projected earnings of $2.27/share.
Speaking with analysts Tuesday, CFO Rebecca Kujawa said NextEra has increased year-to-date adjusted earnings by nearly 12%, compared to the same period in 2018. NextEra Energy Resources drove much of that growth, she said, pointing to a renewables backlog of more than 12.3 GW, more than the operating portfolio it had at the end of 2014, which took 15 years to build.
Energy Resources added 1,375 MW to its backlog in the last three months, Kujawa said. The company added 747 MW of solar and 340 MW of battery storage, all paired with new solar projects, she said, “as we further advance the next phase of renewables deployment that pairs low-cost wind and solar energy with a low-cost battery storage solution.”
Kujawa said NextEra removed 339 MW from MISO’s interconnection queue because of increased transmission upgrades and rising interconnection costs as developers have rushed to get projects approved as tax credits wind down. The “speed bump” only creates opportunities, she said.
| NextEra
“Some of those projects had some obvious customers that wanted to buy some wind and solar projects, which will create opportunities for Energy Resources … It also creates the opportunity or incentive for us to optimize our existing queue positions and existing interconnection rights to maximize all the generation that could be filled for those interconnection requests,” she said.
“Overall, we are pleased with the progress we are making at NextEra Energy,” CEO Jim Robo said in a statement. “I will be disappointed if we are not able to deliver growth at or near the top end of our [$10.00-10.75] adjusted earnings per share expectations range in 2022.”
On a GAAP basis, NextEra’s third-quarter income was $879 million ($1.81/share) compared to $1.01 billion ($2.10/share) a year ago. GAAP earnings considered the effects of the federal corporate tax reduction and non-qualifying hedges.
NextEra’s share price gained $2.87 following the earnings release, closing up 1.2% at $236.24/share.
LITTLE ROCK, Ark. — Google, the world’s ubiquitous search engine — “Google it!” — made its SPP membership official when it participated in October’s Markets and Operations Policy Committee.
The company, which signed a membership agreement in May, observed two MOPC meetings before casting its first vote on the consent agenda. Jeff Riles, Google’s lead for global infrastructure energy policy and markets, contributed to the stakeholders’ discussions when it centered on renewable energy and transmission costs.
Riles, an energy regulatory attorney formerly with Enel, represents Google under the Google Energy brand, which was created to reduce parent company Alphabet’s energy consumption and to produce and sell clean energy. Google joins Walmart as SPP’s only two end-use customer members. (See New SPP Member Walmart Eyes ‘Everyday Low Costs.’)
He said Google joined SPP because of the company’s energy procurement needs and plans to grow its businesses within SPP’s footprint.
“As a consumer, we recognize the benefits that wholesale, competitive power markets provide,” Riles said. “What’s happening here will impact our business. Google wants to follow market developments in SPP and have a voice in its future.”
Google leads SPP’s corporate buyers with 1,135 MW of purchase power agreements, almost quadruple that of T-Mobile and Facebook’s 320 MW apiece.
Riles noted Google has load and “pretty significant” renewable projects in SPP’s footprint. The corporation has already invested $2.4 billion in an Oklahoma data center, and it brokeground earlier this month on a $600 million data center in Nebraska with more load than the nearby city of Lincoln (excluding Cornhusker gamedays). The facility will be powered by 100% renewable energy when it is operational in two years.
In September, Google announced a 1,600-MW package of renewable deals across the U.S., Europe and Chile that it calls the largest corporate renewables purchase ever. The purchase will increase its total wind and solar agreements by more than 40%, the company said.
WASHINGTON — They may not know how to design firewalls or recognize malware, but lawyers are nonetheless essential to companies’ cybersecurity protections, says Paul Tiao, co-chair of Hunton Andrews Kurth’s energy sector security team.
“Lawyers have an incredibly important role when it comes to cybersecurity. That’s becoming increasingly understood,” Tiao told the Energy Bar Association Mid-Year Energy Forum on Wednesday. “Whether you’re trying to help your company develop the right governance structure, or trying to make sure you have the right information security policies; helping your IT folks to identify sensitive systems where your crown jewels are; whether you’re developing an incident response plan, that has an important role for lawyers.”
Tiao said lawyers still face challenges in winning the trust of their technology and information security teams, however. “The perception still among folks from IT … is that lawyers are to be avoided, that lawyers are a problem and that lawyers just say ‘no.’ And the reality here is that lawyers can help make the lives of our IT and information security folks much better.”
But Laura Schepis, senior director of security policy for the Edison Electric Institute, said utility security professionals can find themselves torn between “two masters.”
“One is this ethic that’s come up since Y2K about information sharing. We are prompted by good … organizations like our Electricity [Information Sharing and Analysis Center] to share about threats and vulnerabilities. ‘Share until it hurts’ is often heard in security conferences. And so, when you detect that a thing on your system is bad, one angel on your shoulder says, ‘Share until it hurts.’
“On the other shoulder is the general counsel saying ‘but don’t use the name.’ And the other angel says, ‘If I can say the name, then my peers across the country would know … what component [I’m] talking about.”
Contracts
One of lawyers’ key roles is negotiating contracts with cybersecurity vendors or other service providers, Hunton partner Andrew Geyer said.
Disputes can arise over everything from the definition of a “security event” to the speed at which notices of such events are made. Audit rights to ensure “the vendor is actually doing what they’ve contractually agreed to do” can also be challenging, he said.
“It’s probably going to be more of a records-type audit. It’s not going to be what you’re probably looking for, which is more of an on-site audit to look behind the curtain and say: I want to verify the integrity of my data. I want to verify the policies and procedures and controls that you have in place.”
As an alternative, companies can rely on third-party audits or certifications, such as system and organization controls (SOC) audits, Geyer said.
Strict liability for breaches is “almost impossible,” Geyer said, but companies can protect themselves by adding a negligence standard.
Geyer used the example of hiring someone to protect your car from being stolen. “I say you need to lock the doors; you need to roll up the windows. You need to park it in a safe area. Those are your obligations to keep my car safe. And then my car gets stolen and, lo and behold, we find out they left the sunroof open. Well, common sense would say I didn’t have to write ‘shut the sunroof’ [into the contract]. It’s pretty obvious. So that’s why you try to get that negligence standard built in with the breach of contract to bridge that gap between the more strict liability and the breach of agreement that the vendors always look for.”
It’s also essential to ensure the vendor faces financial consequences for failures, Geyer said.
“If your normal damages are ‘x,’ the vendor may be willing to go to 2x, 3x, 4x if it relates to a security event. Sometimes that formula works fairly well. If you’re doing a large outsourcing deal where there’s a lot of money on the table, 2x can be a lot of money. If you’re doing a small [software as a service] deal and you’re not paying the vendor a lot — but yet what they’re providing to you is critical to your operation … 10x may not even be close to what the potential damages could be. So, what you try to do is get some sort of bounds: What is enough skin in the game for the vendor that this will incentivize them to comply with the terms of the agreement?”
Several speakers discussed supply chain concerns during the conference, which happened to fall on the same week that responses to NERC’s data request on the “the nature and number” of low-impact bulk electric system cyber systems. The data request was a recommendation of the staff supply chain report approved by the board in May. (See “Supply Chain Report Recommends Expanding Standards,” NERC Standards News Briefs: May 8-9, 2019.)
Hunton partner Ted Murphy said entities should expect additional obligations regarding supply chain issues.
“NERC staff reports … are recommending that responsible entities go beyond the strict letter of the standards and … trying to protect low-impact systems on a best-efforts basis. … That’s not a mandatory and enforceable requirement, but it’s something that’s a current issue. Whenever you have NERC encouraging something, it can become a de facto kind of compliance obligation.”
Tobias Whitney, a cybersecurity specialist for the Electric Power Research Institute, said entities face questions over the security of hardware deliveries — ensuring that what they receive is what the vendor sent — and the provenance of equipment. “Who are the suppliers’ suppliers?” he asked.
“One of the biggest challenges that we see in the industry today is not necessarily your tried-and-true, highly recognizable third-party vendors. … They’re going to provide you evidence of what they’re doing from a compliance … and security perspective. But there’s so many new players now at the grid edge when we’re talking about distributed energy resources, solar PV, electric vehicles [and] the distribution side. So how do we bring them into the loop?”
One solution is “threat modeling,” Whitney said, noting that not every supplier provides the same level of risk.
“I know we have high-, medium- and low-[risk], but I think we need to think … with a little bit more granularity,” he said. “Which systems have direct command and control capability on the grid?
Whitney agreed that third-party accreditation can be one tool. “But how do we get there? … You look at a SOC 2 audit. What does that tell you about a relay at one of your most critical substations? … We need to get from vendor accreditation to a product-level, or a system-level accreditation. … At the end of the day, we’re managing products and systems on the grid — that’s what keeps our lights on.”
FERC’s fourth round of Critical Infrastructure Protection audits still found room for improvement, with the commission’s Oct. 4 report listing seven “lessons learned.”
Based on “several” audits, the Office of Electric Reliability’s (OER) Division of Reliability Standards and Security, assisted by the Office of Enforcement’s Division of Audits and Accounting, concluded that most of the cybersecurity protection processes and procedures adopted by registered entities met CIP standards, although potential compliance infractions were observed. Staff from NERC and the regional entities also participated.
FERC officials elaborated on the report in an interview with ERO Insider on Oct. 17.
OER Deputy Director David Ortiz declined to say how many audits were conducted, saying it was “more than two, less than 10.”
The first recommendation was that entities consider all generation assets when categorizing bulk electric system (BES) cyber systems associated with their transmission facilities, not just generation they own.
“While entities generally categorized BES cyber systems effectively, in some cases entities did not consider all generation facilities as required,” the report said.
“You may have a situation where you have other parties that own generation within your footprint,” explained FERC IT specialist Alan Herd. “And in that situation, you want to make sure that you’re fully evaluating any potential impact to your transmission facility [from] the generation that’s owned by you or owned by a third party. … The risk is there if you’re not considering all potential assets of impact.”
The auditors also found that some entities did not maintain complete training records for their third-party contractors or verify employees’ recurring authorizations for using removable media. “While entities consistently verified employees’ recurring authorizations to electronic security perimeters (ESPs) and physical security perimeters (PSPs), entities did not always verify access to removable media in such reviews,” it said.
They also found some instances in which entities had “overly permissive” firewall access internet protocol (IP) ranges and loose controls on access to employee’s PIN numbers used for accessing PSPs.
“Entities commonly use a key card and PIN authentication as the two different physical access controls. However, some entities do not limit access to PIN numbers to the minimum number of necessary employees,” FERC said. “For example, staff has observed some registered entities store their employee PIN numbers as plain text within the [physical access control systems] management system and allow a broad range of employees (e.g., system operators or administrators) to have access to view the employee PIN numbers.”
It also recommended entities use color covers or labels to clearly mark transient cyber assets and removable media.
“While entities generally only used transient cyber assets and removable media to access BES cyber systems, staff observed several instances in which ‘unmanaged’ cyber assets or storage media were used by accident,” FERC said.
FERC said its recommendations concerned practices that could improve security but are not necessarily required by the CIP Reliability Standards.
Would FERC like to see these recommendations made mandatory?
“When staff makes these observations … they tend to reflect implementation practices. …The standards are objective-based and typically don’t cover implementation issues,” said Ortiz. “We don’t have an opinion on whether or not they should be requirements. We’re just highlighting them as possible ways to improve security in light of the standards. Every one of the recommendations ties back to a specific requirement.”
FERC began conducting the audits in fiscal year 2016. Its first report, covering FY16 and FY17, included 21 recommendations. The “lessons learned” count dropped to 10 in its FY18 report.
OER Director Andy Dodge said the new report is meant to supplement the previous findings, which he said FERC still backs.
“The seven items that we identified as lessons learned … were new this year [in] that we may not have identified [them] in previous years. It’s not any indication that there’s less opportunities for improvement or to improve the security of the bulk electric system,” Dodge said.
Has CIP compliance improved since FERC began doing the audits?
“I think it’s difficult to say just because [of] the differences between each of the entities that we do,” said Herd. “We typically try to get a variety of different types of entities, different registrations, sizes, footprint. I’d say it’s difficult to compare them against each other.”
“But we have found in general … that since 2016 when [CIP] version 5 was implemented, that generally security staffs and [subject matter experts], utility operators have a much stronger understanding of CIP standards than” before, he added.
Kenneth McIntyre, NERC’s vice president of standards and compliance between May 2016 and April 2019, wrote a 2015 commentary defending FERC’s audits when they were initiated.
At the time, McIntyre noted, NERC was rolling out CIP version 5.
As with the previous versions, McIntyre wrote, “much effort has been devoted to figuring out loopholes and work-arounds to circumvent compliance obligations.
“… Based on industry’s track record, it is easy to assume that FERC may have concerns that there is still too much ‘minimization’ of scope for the CIP Standards throughout the industry,” he continued. “Additionally, FERC does have legitimate concerns around the lack of consistent interpretations from region to region and NERC themselves.”
McIntyre, now executive director for MISO, did not respond to a request for comment.
Ortiz declined to comment on McIntyre’s observations. “What I will say is that version 5 of the CIP standards was a significant change in the overall approach to cybersecurity. Principally, it went to this risk-based system [in] which the main standard, CIP 2, which required classification of assets, was really critical. And an understanding that that was a big shift in the standards was the primary motivation for FERC undertaking its own audits—not to get around the entities or go around NERC. We do all these, we lead them, but we do them in collaboration with NERC and the relevant entity.”
FERC said it plans to conduct additional CIP audits in FY 2020.
Transource Energy filed a reconfigured version of the Independence Energy Connection project with Maryland regulators on Thursday as part of a settlement with state officials and landowners long opposed to the Ohio-based company’s original plans.
“We appreciate the state agencies, incumbent utilities and landowner input received when developing this alternative,” said Todd Burns, Transource’s director, in a statement emailed to RTO Insider. “We are pleased to present this alternative to the respective commissions for their consideration.”
Transource announced the settlement one week after Assistant Attorney General Sondra McLemore sent a letter to the Maryland Public Service Commission that indicated a finalized agreement between Transource and the state’s Power Plant Research Program (PPRP) would be filed “within four business days.” The company also filed a copy of the alternative configuration with the Pennsylvania Public Utility Commission and said regulators in each state will take both proposals into consideration.
Transource spokesperson Mary Urban said Wednesday that the company spent the summer modeling an alternate plan that would use existing infrastructure in the Baltimore Gas and Electric zone to revamp the eastern segment of the project, originally proposed to extend 15.8 miles from a new Furnace Run substation in York County, Pa., to the Conastone substation in Harford County, Md.
The updated configuration, designed in consultation with PJM, would increase the size of the new substation in Pennsylvania and add 4 miles of lines that would connect to an existing right of way and eventually feed into two upgraded BG&E substations. The settlement changes nothing about the western segment of the project, a 230-kV double circuit transmission line that would run 28.8 miles from Franklin County, Pa., into Washington County, Md.
Transource’s proposed alternative plan for the eastern segment of its Independence Energy Connection project. | Transource Energy
PJM selected the $383 million IEC — its largest market efficiency project to date — during the 2013/14 long-term planning window to address congestion in the AP South interface. The RTO has since reviewed its benefits to the grid five times, determining in each round that the project remains the most effective way to reduce load costs.
The RTO’s most recent analysis, completed in September, determined the IEC would generate a $856 million reduction in congestion costs over the next 15 years, with a benefit-cost ratio of 2.1 — well above PJM’s 1.25 threshold required for inclusion in its Regional Transmission Expansion Plan.
Protesters argued, however, that the need for the eastern segment of the project could be met by existing 230-kV lines. The PPRP urged the PSC to suspend the project while PJM studied the market efficiency of this alternative and three others — a request that was granted in January. (See More Info Needed on Tx Line Options, MD PSC Says and Cancel Transource Line, Md. Panel Says.)
PJM’s analysis determined that the protesters’ preferred configuration would require upgrades at the Furnace Run substation in order to alleviate potential reliability violations. The plan would cost $54 million to $94 million more than the IEC and produce $267 million less in congestion benefits to the region, it found.
Transource and the PPRP filed a joint petition in June to suspend proceedings regarding the company’s certificate of public necessity and convenience in order to reach a settlement on the eastern portion. The PSC granted a 30-day extension Aug. 27.
PJM staff told the Transmission Expansion Advisory Committee on Thursday that it’s unclear how the RTO will proceed if state regulators approve the alternative configuration — one that hasn’t been vetted by stakeholders or studied fully in the RTO’s planning process.
MISO’s Planning Advisory Committee will vote by email on whether to send the RTO’s nearly $4 billion 2019 Transmission Expansion Plan (MTEP 19) to its Board of Directors for approval — but the committee could also advise two changes just ahead of the vote.
PAC leadership was set to conduct its annual vote over whether to move the plan forward for board consideration at its Wednesday meeting, but members called for an email vote.
MISO’s Environmental and Other Stakeholder Groups sector, led by the Clean Grid Alliance (CGA), also tacked on two separate motions that call for planners to re-examine a possible market efficiency project and delay the RTO’s first storage-as-transmission asset (SATA) project for more study on alternatives. Taken together, PAC members have three ballots to consider. Voting will take place through Wednesday.
The PAC will decide on the plan itself, plus two additional stakeholder-originated motions that might delay a project or add another to the buildout package.
Project Manager Sandy Boegeman said MTEP 19 now contains 479 transmission projects costing $3.97 billion. The RTO will post the final MTEP 19 project list Nov. 6.
MTEP19 investment by facility type ($ millions) | MISO
Helena-to-Hampton Corners
CGA’s first motion asks that MISO revisit the Helena-to-Hampton Corners second-circuit project, which the group said should have been included in MTEP 19 as a market efficiency project. (See MISO Readies MTEP 19, Debates Futures Change.) The $36.1 million, 345-kV project, originally identified in this year’s Market Congestion Planning Study, was set to solve congestion in southern Minnesota at a 4.22:1 benefit-to-cost ratio, but MISO said the project quickly lost value once forecasted wind generation was removed from the equation.
Sean Brady, CGA’s regional policy manager for the East, said he thought MISO’s order of evaluations shortchanged the benefits of the project because the RTO simply finished evaluations first on the nearby 18-mile Helena-to-Scott County line rebuild, which was studied as a network upgrade for proposed generation in the interconnection queue.
“It’s a more cost-effective line based on the information we’ve seen,” Brady said of the Helena-to-Hampton Corners project.
“We believe that we followed the Tariff. We believe that we followed the process,” MISO Director of Planning Jeff Webb said, adding that the RTO could review its policy of studying interconnection upgrades before it evaluates an annual crop of reliability projects.
Webb added that there are going to be “sequencing” issues as long as MISO evaluates transmission projects by type.
Entergy’s Yarrow Etheredge said stakeholders shouldn’t “upend” the planning process this year. She reminded stakeholders that the Helena-to-Hampton Corners project can always be re-examined as part of MTEP 20.
Brady said he thought the economic analysis behind American Transmission Co.’s Waupaca-area energy storage project was “lacking,” and he urged MISO to re-evaluate the project. He said it’s likely that a traditional wires solution would have more economic benefits.
“A wires solution would be available 24/7, 365, where a battery solution is only available two hours at a time,” Brady said.
Other PAC members seemed unreceptive to the idea.
Etheredge said it wasn’t the PAC’s place to “second-guess” MISO’s MTEP evaluations. ATC’s Bob McKee also pointed out that MISO did evaluate the battery solution against traditional wires alternatives submitted by his company. He pointed out that CGA itself wasn’t offering up any alternatives with its opposition.
CGA’s Natalie McIntire argued that MISO’s evaluation process for SATA projects is nascent and largely untested.
“To me, it’s not clear we have an agreed-upon process to evaluate projects like these,” McIntire said.
MISO has yet to file its SATA proposal with Despite Pushback, MISO Pursuing TO-only SATA.) So far, the Waupaca project remains in Appendix B of the MTEP 19 report, listing projects considered to have a documented need but not yet ready to deploy, with costs not included in MTEP spending totals. The board will hold a separate vote to approve the project after the RTO has SATA rules in place.
New Task Team Put to Vote
As if three motions weren’t enough, PAC members will also decide via email ballot whether to form a new task team to examine sharply rising network upgrades in the interconnection queue and whether MISO’s annual transmission planning process might be overlooking projects. Renewable proponents raised the idea at the September PAC meeting as a growing number of stakeholders press the RTO to address transmission planning assumptions and devise ways to prevent new generation projects from becoming responsible for most transmission development. (See More MISO Members Join Call for Tx Planning Change.)
Sector representatives first debated whether the creation of new task teams needed to go before the Steering Committee, which assigns new issues to stakeholder committees. Webb said he didn’t want to burden the SC unnecessarily with a “bureaucratic loop,” as the PAC doesn’t need permission to spin off its own task teams.
Special MTEP 20 Studies
The PAC will also work out what areas MISO will single out for one-off studies as part of MTEP 20.
In lieu of newly designed futures scenarios next year, MISO has promised unique, targeted studies in the MTEP 20 cycle to identify possible transmission projects. The RTO this summer decided to stop work on a futures update for 2020. (See MISO Halts Futures Work for 2020, Plans 2021 Rebuild.)
Members of the Environmental and Transmission Owners sectors have recommended the RTO study the Minnesota-Wisconsin transfer limitation — known to the MISO community as MWEX — because of the constraint’s voltage stability issues and its location between renewable-rich areas of the footprint and customer bases to the east.
“This study is recommended not only to evaluate this particular constraint, but also as a valuable opportunity to better understand how to assess the implications of non-thermal constraints within the MISO footprint in future economic planning studies,” the TOs wrote in comments to the RTO.
EDF Renewables also asked the RTO for a review of the top congested flowgates in MISO West in light of generation additions and retirements.
FERC last week again denied Southwestern Electric Cooperative’s multiple challenges to Ameren Illinois’ 2017 update to its transmission rate formula, saying the co-op had rehashed arguments previously rejected by the commission.
The ruling, issued Thursday, showed that Southwestern came up short in nearly all its arguments for a rehearing of the Ameren subsidiary’s accounting for accumulated deferred income taxes (ADIT), regulatory expenses and undeveloped land holdings (ER17-1198-002).
The complaint wasn’t the first time Southwestern has contested Ameren Illinois’ formula rate. The cooperative previously teamed with Southern Illinois Power Cooperative to unsuccessfully challenge several aspects of the utility’s 2016 filing. (See FERC: Ameren Illinois Formula Rate Stands.)
In the more recent complaint, Southwestern had contested allowing Ameren Illinois to direct construction work in progress (CWIP) expenses and renewable energy compliance costs to certain accounts for the recovery of ADIT. The cooperative argued that parent company Ameren — not its subsidiary — should be recovering CWIP expenses for the 500-mile, 345-kV Grand Rivers project in Illinois and Missouri.
Ameren Illinois linemen | Ameren
But FERC said it already addressed those ADIT issues in 2016 when it ruled that Southwestern’s arguments amounted to a “collateral attack on an allocation specified in the formula rate” because the co-op only challenged the ADIT accounting, not Ameren Illinois’ ability to recover the CWIP.
“Despite claiming that it would not relitigate issues, Southwestern is doing precisely that by raising the same arguments on rehearing of the June 2019 order as it did in the 2016 formal challenge proceeding. We reject those arguments for the same reasons the commission rejected them in [2016],” FERC said.
Southwestern also argued that all of the utility’s regulatory expenses should be recorded in one specific account and that certain regulatory expenses should be excluded from recovery “because they relate to Ameren Illinois’ retail business.” But FERC agreed with the utility that not all expenses related to rate calculations and true-ups are “in connection with formal cases before regulatory commissions.”
The co-op also insisted that Ameren Illinois exclude regulatory expenses linked to generator interconnections from the transmission formula rate, which FERC said was an unreasonable request.
“As a transmission owner in MISO, Ameren Illinois may incur costs associated with disputes it may have with generators involving, for example, payments for network upgrades,” FERC said.
The commission additionally rejected Southwestern’s argument that Ameren Illinois should not be earning a return on land held for future use but not associated with a specific plan. It said the utility previously explained that the land is earmarked for future transmission expansion projects “anticipated to be needed due to projected generation additions or retirements.”
However, FERC did call for a review of Ameren Illinois’ regulatory expenses, directing the company to file within 30 days two separate summaries of any changes it may have made in how it records expenses related to formal challenges and cases before regulatory bodies.
FERC last week established hearing and settlement judge procedures for Xcel Energy Services’ challenge to GridLiance High Plains’ annual informational filing reflecting its 2019 projected net revenue requirement.
The commission also accepted Xcel’s motion that it combine the docket with a previous settlement proceeding involving GridLiance’s proposed annual transmission revenue requirement (ER19-1357, ER18-2358).
Acting for subsidiary Southwestern Public Service, Xcel in July filed a formal challenge, arguing that inclusion of GridLiance’s Oklahoma Panhandle transmission facilities in its annual update is improper.
GridLiance, which shares the same SPP transmission pricing zone as SPS, submitted its annual update for the upcoming rate year in March. It included in its projected total costs those associated with the Oklahoma assets, which have been upgraded and have a projected ATRR of nearly $8.9 million.
Xcel said the facilities’ inclusion would result in a cost shift to SPS of more than $6 million in 2019 and more than $1 million per year for other load-serving entities in the zone.
The company argued that GridLiance’s Oklahoma facilities are the only assets in service under GridLiance’s formula rate and said that its entire rate base is premised on the claim that they are eligible for recovery as transmission facilities under Attachment AI of the SPP Tariff. Xcel said GridLiance’s entire rate base should be removed from its formula rate because GridLiance has failed to demonstrate that the assets qualify as transmission facilities under Attachment AI or the commission’s seven-factor test.
FERC Order 773 established a process allowing an entity to seek a determination regarding whether facilities are “used in local distribution.” The seven-factor test involves a case-by-case analysis of seven indicators.
FERC found that Xcel’s challenge “raises issues of material fact that cannot be resolved based on the record before us” and said they would be more appropriately addressed in settlement procedures.
“In the event that the [Oklahoma facilities] fail to meet the definition of transmission facilities under Attachment AI, the [assets] could be included in SPP transmission rates if they meet the commission’s seven-factor test,” FERC wrote.
GridLiance said the order confirms its position that Attachment AI governs the definition of transmission within SPP, despite FERC’s clarification. It said “arguments to the contrary” conflict with more than a decade of precedent regarding how facilities are included within SPP’s Tariff.
“Most notable in the order is FERC’s validation of SPP’s use of Attachment AI … in determining whether facilities qualify for inclusion within SPP,” GridLiance High Plains President Brett Hooton said.
GridLiance acquired the facilities in question — 410 miles of 69- and 115-kV lines and related substation infrastructure — from Tri-County Electric Cooperative in 2016.
The commission also approved Westar Energy’s contested settlement offer updating loss factors in its tariff (ER18-1418).
The Kansas utility, now operating as Evergy Kansas Central after a merger with Kansas City Power & Light, was seeking to raise its loss factors from 3.07% to 3.47% based on a study it performed using data and load-flow models from 2016 supplied by SPP. That figure was a result of a 2013 settlement that locked it in for five years, with an updated study to be filed every succeeding five-year period.
FERC accepted the proposed revisions in June 2018 and established hearing and settlement judge procedures. Several Kansas utilities intervened and filed comments or protests in the proceeding, including Nemaha-Marshall Electric Cooperative Association. (See FERC Sets Westar Loss Factors for Settlement.)
Nemaha-Marshall argued the settlement was unjust and unreasonable because it removed all references to “composite loss factors” from the relevant section of Westar’s tariff. The co-op said the composite loss factors are used in several other agreements and are necessary to protect customers from paying Westar transmission losses that it does not incur and that are already being recovered under other tariffs.
FERC found Nemaha-Marshall’s contention “unpersuasive,” saying it did not raise issues of material fact concerning the loss factors’ just and reasonableness. It said language in Westar’s network integration transmission service agreements still prohibits Westar from recovering transmission losses.
“Nothing in the settlement allows for Westar to collect transmission losses already recovered under the SPP Tariff,” the commission said.
FERC directed the utility to file the revised tariff provisions within 30 days.
The NYISO Business Issues Committee last week voted to recommend that the Management Committee and Board of Directors approve a cost-containment mechanism for the ISO’s public policy transmission planning process that features voluntary cost caps in developer proposals.
NYISO Senior Manager for Transmission Planning Yachi Lin joined Assistant General Counsel Carl Patka in presenting the case to make a filing with FERC over the cost-containment provisions.
Under the proposed rules, transmission developers could propose either a hard or soft cap for capital costs. The hard cap would represent the amount over which the developer agrees not to recover capital costs from ratepayers, while the soft cap will be defined as an amount above which shareholders and ratepayers share excess costs, based on a defined percentage, with the developer’s share at least 20%.
“It’s up to developers to propose what risk percentage of the capital costs they want to bear,” Lin said.
One scenario of 2030 public policy transmission needs from the New York City mayor’s office. | New York City Mayor’s Office
Developers would be able to use the procedures in proposing projects as solutions to any public policy transmission need (PPTN) identified by the New York Public Service Commission.
“No doubt this is going to be a huge issue with the [Climate Leadership and Community Protection Act], for which transmission will need to be built,” said BIC Chair Aaron Breidenbaugh, who represents Consumer Power Advocates.
A stakeholder who wished not to be identified asked what the ISO would do in cases in which the developer is also the transmission owner, and a delay by the TO is in the list of excusable conditions for exceeding the cap.
Patka said he did not want to go into debate on the issue, and that “it would all come out in the wash at FERC … but we will make it clear that we’re talking about actions that are not controllable by the developer themselves.”
A developer that proposes a solution may voluntarily provide a capped amount for defined categories of capital costs and may only rely on the permitted excusing conditions to recover costs over those amounts.
Couch White attorney Michael Mager, who represents Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said the group has “long felt that the Tariff had a gaping hole when it comes to cost containment … while this measure may not be perfect, it does advance the ball.”
The New York State Energy Research and Development Authority and NextEra Energy echoed that support.
Couch White attorney Devlyn Tedesco, who represents New York City, commented that the city does not support the proposal because of a concern that it may not provide full cost containment and may not adequately protect consumers for the duration of the useful lives of the projects.
Patka said, “We added language to the Tariff expressly at the request of end users that the cost-containment mechanism must achieve ratepayer protection at least as effective as that proposed by the developer [OATT 6.10.6.3].”
Jane Quin, director of the energy markets policy group for Consolidated Edison, said her utility and Orange and Rockland Utilities appreciated the work and supported the concept, but that they would be abstaining because the changes also include changes to the ISO evaluation processes, with no provision in the case where the TO upgrades its own facilities.
Patka committed to address cost containment for upgrades as soon as the ISO begins to address the treatment of rights to build and own such upgrades in its PPTN planning.
The FERC filing is slated for December if the plan is approved by the MC on Oct. 30 and by the board next month.
“If approved by FERC, the measures would be effective in time for the public policy transmission solicitations that will start to be prepared early in the year,” Patka said. “We’re basically running out of time in our current public policy planning process.”
Enhancing Credit Requirements
The BIC also voted to recommend the MC and board approve changes to enhance credit reporting requirements and remedies.
Sheri Prevratil, manager of corporate credit, presented the proposed changes, including Tariff revisions that would require FERC approval.
The changes were prompted after certain market participants last year defaulted on their payment or credit obligations to NYISO. Some of those parties filed for Chapter 11 bankruptcy, while others were expelled from the ISO.
The proposed Tariff changes would increase minimum participation criteria, requiring a market participant to certify it has appropriate experience and resources to satisfy obligations as they become due. The changes would also clarify what investigations need to report, if legally permitted, and add an obligation to disclose information on nonpublic investigations when possible.
A new provision would allow NYISO to reject a new applicant determined to be an unreasonable credit risk based on a credit questionnaire and other review. The ISO would request additional information from new applicants upon registration and from existing market participants on an annual basis, with a new credit questionnaire to be included in the officer certification form due by April 30 each year.
LBMPs down 43%
NYISO locational-based marginal prices averaged $22.22/MWh in September, down about 20% from August and more than 43% from the same month a year ago, Principal Economist Nicole Bouchez said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $33.88/MWh, a 26% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in lower compared to August. Average daily sendout was 419 GWh/day in September, down from 487 GWh/day in August and 458 GWh/day a year earlier. Transco Z6 hub natural gas prices averaged $1.78/MMBtu for the month, down slightly from August and 35.4% from a year ago.
NYISO monthly average internal LBMPs 2018-2019 | NYISO
Distillate prices were down 14.3% year over year and up slightly from the previous month, with Jet Kerosene Gulf Coast averaging $13.86/MMBtu, compared to $13.32 in August, while Ultra-low Sulfur No. 2 Diesel NY Harbor climbed to $13.79 from $13.02 in August.
September uplift increased to -13 cents/MWh from -20 cents in August, while total uplift costs, including the ISO’s cost of operations, came in lower than the previous month.
The ISO’s 17-cent/MWh local reliability share in September was down from 25 cents the previous month, while the statewide share climbed to -30 cents/MWh from -45 cents.
The New York Public Service Commission last week said it expects winter electricity prices will be slightly lower than a year ago, based on a declining price trend and normal weather forecast (19-M-0382).
“We anticipate energy consumers will benefit from lower-than-average energy prices this winter, which is welcome news for all of us,” PSC Chair John B. Rhodes said Thursday.
The commission’s Winter Preparedness Report forecasts a similar trend for natural gas, based on a normal weather forecast, but it noted that Enbridge, owner of the Texas Eastern and Algonquin Pipelines, told utilities it would reduce pressure at times this winter on both pipelines.
Resulting capacity reductions would impact deliveries into the Goethals station in Staten Island and the South Manhattan Gate station in Manhattan, requiring measures to offset the loss, the PSC said.
Statewide weighed average full service residential supply price – winter months (cents/kWh) | NYISO
Rhodes on Oct. 11 signed an order forcing National Grid subsidiaries Brooklyn Union Gas and KeySpan Gas East to connect 1,100 of 3,300 customers that had been denied natural gas service connections (19-G-0678).
“We will continue to closely monitor the utilities serving New York state to make sure they have adequate sources and supplies of electricity and natural gas to meet current customer demands this winter,” Rhodes said.
The commission reported sufficient capability to meet electric demand this winter, saying owners of major generators in southeast New York continue “to implement lessons learned from the polar vortex winter of 2013-2014, including having increased pre-winter on-site fuel reserves, having firm contracts with fuel oil suppliers, conducting more aggressive replenishment plans, and having more proactive pre-winter maintenance and facilities preparations.”
Largest Storage Project in New York
The PSC also approved construction of what will be New York’s largest battery storage facility, the 316-MW Ravenswood facility to be built on the Ravenswood Generating Station property in Long Island City, Queens (19-E-0122).
The New York PSC approved a 316-MW storage facility to be built at the site of the Ravenswood Generating Station, on the East River in Long Island City, Queens.
“When complete, this facility will displace energy produced from fossil plants during peak periods, resulting in cleaner air and reduced carbon emissions,” Rhodes said.
The storage facility will displace some out-of-service peaker units on the property and should be partially operational by March 2021, the commission said. It will provide peak capacity, energy and ancillary services; offset more carbon-intensive peak generation with power stored during the off-peak period; and enhance grid reliability in New York City.
Expanding Value Stack Eligibility
The commission also expanded the eligibility of New York Power Authority customers located within Consolidated Edison’s service territory for excess electricity generated by eligible distributed energy resources projects (19-E-0464).
According to NYPA, expanding value stack eligibility to its customers in Con Ed territory will open up DER market potential and help the state meet its goal of installing 6,000 MW of distributed solar by 2025. DER developers will have additional incentive to develop renewable projects in New York City, with many NYPA customers already having committed to develop renewable projects.
New Cybersecurity Rules
The commission also adopted new cybersecurity and data privacy requirements for third-party companies that electronically receive and exchange utility customer data with the utilities’ information technology systems (18-M-0376).
The new requirements provide a foundation of protections to ensure the privacy of customer data and protect utility IT systems, while at the same time enabling data access, the PSC said.
NextEra Energy touted “one of the best renewable development periods” in its history as it reported third-quarter adjusted earnings on Tuesday, beating analysts’ expectations.
