Xcel Energy last week reported year-end earnings of $1.372 billion ($2.64/share), up from 2018’s performance of $1.261 billion ($2.47/share) and marking the 15th straight year the company has met or exceeded its guidance.
Minneapolis-based Xcel attributed the positive results to favorable regulatory rulings in its utilities’ states. Colorado’s Public Utilities Commission verbally awarded Xcel a $41.5 million rate increase and a 9.3% return on equity, below its requests of $158 million and 10.2%. In December, Minnesota’s PUC approved a one-year deferment of Xcel’s three-year $465 million rate case.
“I would challenge anybody to find a utility that is more focused and has … 100% of their growth coming from regulated operations,” CEO Ben Fowke said during a conference call with analysts Thursday. “There’s nobody that’s more pure-play and vertically integrated than Xcel Energy, and that’s the way we mean to keep it.”
Transmission being built in Xcel subsidiary Southwestern Public Service’s territory | SPS
Fowke said Xcel’s operations and maintenance costs were down almost 1%, “even while making incremental investments in our system,” and noted three wind projects, representing almost 700 MW of capacity, were completed under budget. The company has another 2 GW of wind projects under construction, he said.
For the quarter, Xcel posted earnings of $292 million ($0.56/share), as compared to 2018’s final quarter earnings of $215 million ($0.42/share).
The company’s share price opened down at $67.10 on Thursday but finished the week at $69.19, after setting a new all-time high of $69.52 Friday morning.
SANTA FE, N.M. — SPP’s Board of Directors last week approved a transmission plan that will result in an estimated $545 million in projects over the next six years.
The 2020 SPP Transmission Expansion Plan (STEP) report, a comprehensive list of transmission projects in the RTO’s footprint over a 20-year horizon, lists 78 primarily substation upgrade projects as being approved for construction. Another 16 notifications-to-construct, valued at a projected $88.7 million, were withdrawn.
Newly appointed COO Lanny Nickell said during the board’s Jan. 28 meeting that the STEP represents the least amount of transmission investment since 2008. It includes two 345-kV projects that will be competitively bid through SPP’s transmission owner selection process: a $77 million, 60-mile line near Tulsa, Okla., and a $152 million, 105-mile line and terminal equipment in Kansas and Missouri.
The RTO has already issued a request for proposals for the Oklahoma project and expects a board decision in October. The latter project terminates in Associated Electric Cooperative Inc.’s service territory and will require a cost-and-usage agreement to first be filed at FERC.
SPP member companies last year completed 39 system upgrades in eight states at an estimated cost of $190.4 million, the report said.
The expansion plan was approved as part of a consent agenda that included a number of mostly minor revisions to SPP’s bylaws, one of which codified the board chair’s role as chair of the Strategic Planning Committee.
The package also included a revision request (RR389) that provides a testing exception for derated generating units that were out of service or derated because of a forced outage during the preceding peak season, allowing them to satisfy an operational test requirement after repairs are complete.
WEIS Tariff Approved, on to FERC
Directors approved a standalone Tariff and related governance documents for the Western Energy Imbalance Service (WEIS) market, scheduled to begin operations on Feb. 1, 2021.
The approval clears the way for SPP to file the Tariff for FERC’s approval, along with a Western joint dispatch agreement (WJDA) and a charter for the Western Markets Executive Committee. The WJDA is the contractual arrangement between SPP and WEIS participants that governs the RTO’s obligations to administer the market and its compensation for running the market.
Members Committee representatives from Dogwood Energy, Evergy, Nebraska Public Power District, Oklahoma Gas & Electric, Oklahoma Municipal Power Authority, Public Service Company of Oklahoma and Southwest Public Service abstained from their advisory vote over concerns that members did not have enough transparency into the market’s development.
Board Chair Larry Altenbaumer sought to assuage members’ concerns that Western activities were being kept from them.
“We want to ensure that we are very robust in our communications with the members and are transparent in terms of our process,” he said. “We’re committed to making sure everyone is well informed.”
The WEIS Tariff is based on the Energy Imbalance Service market SPP operated in the Eastern Interconnection from 2007 to 2014. It will provide guidance for customers to become participants, convey how they will communicate with the RTO, and outline how the market will be settled and billed.
Seven Western Interconnection utilities have signed up to participate in the five-minute, real-time balancing market, which will be offered as a contract service. (See SPP Board OKs $9.5M to Build Western EIS Market.)
SPP’s Market Monitoring Unit will provide market oversight. In a memo filed with the board’s meeting materials, MMU Executive Director Keith Collins said the Monitor “fully supports” the WEIS and the expansion of electricity markets, but he also listed his concerns over market liquidity, settlements and market power.
Collins said the proposed Tariff language does not address the “potential negative” effect on the market when minimum load requirements are not met, and he noted that SPP is not currently working on protocol language to address the MMU’s market-liquidity concerns.
The MMU has begun a study to determine what mitigation measures may be necessary to ensure market efficiency in the WEIS, Collins wrote.
Brown Delivers Optimistic Final Report
Outgoing CEO Nick Brown joked he had prepared a two-hour sermon for his last report to the board but put it off until his final appearance before the board during April’s round of governance meetings.
“Now is not about the past. I’m tremendously excited about the position this company is in,” Brown said. He listed the addition of new directors bringing “fresh perspective and fresh passion and fresh accountability to our governance” and SPP’s incoming leaders as having successfully placed the organization to take on future challenges.
Brown said the RTO is “firmly, firmly positioned” to implement the Holistic Integrated Tariff Team’s recommendations and to develop a new strategic plan.
“Our current plan is nearing four years in age,” he said. “I think it’s going to be a tremendous time for me to observe all of the efforts this organization is going to undertake over the next year. I leave this meeting with a full heart about the position SPP is in to move forward. I look forward to April and your opportunity to listen to my two-hour sermon.”
Oversight Committee Chair Joshua Martin III reported that SPP once again received an “unqualified opinion” following its latest system and organization controls 1 audit, its 10th such opinion in a row.
Danly Re-nomination Could be Months Away
Patrick Clarey, FERC’s liaison to SPP and MISO, said that James Danly’s nomination to the commission will likely be sent back to the Senate within the next couple of months.
Danly, FERC’s general counsel, was nominated last year to fill the vacancy left by Kevin McIntyre’s death. However, the Senate failed to act on his nomination before the session ended last year. According to Senate rules, the White House must once again send Danly’s nomination to Capitol Hill during a regular session.
Since then, Commissioner Bernard McNamee said he would not seek another term when his current term expires June 30, though he said he would not leave until a replacement is confirmed to his seat. (See McNamee Declines to Seek Reappointment.)
Google Loving RTOs
Jeff Riles, Google Energy’s global energy policy and markets lead, said during a presentation to members that his mammoth company “loves” RTOs and ISOs. Google, already SPP’s largest corporate buyer with 1,135 MW of purchase power agreements, only joined SPP last year. (See Google Searches, Finds Membership in SPP.)
“Quite honestly, we wish they were in every corner of the country,” he said. “There are critical policy questions in front of you, but we think power markets are absolutely essential to achieve our corporate objectives.”
MISO tossed a curveball at stakeholders Tuesday when it said it will now consider two types of solutions to mitigate its Midwest-South transmission constraint before the original term of the settlement agreement facilitating transfers draws to a close.
The 2016 agreement with seven joint parties — including SPP — limits transfers between MISO Midwest and South to 3,000 MW southbound and 2,500 MW northbound. The deal is set to expire next year, leaving MISO and its members to confront escalating costs under a new arrangement.
Speaking during a conference call Tuesday, economic studies engineer David Severson revealed more details about the original solution, saying that MISO is focusing on three proposed projects to alleviate the constraint.
But Severson also posed a new option: MISO could avoid building new transmission by instead exploring ways to purchase firm capacity to supplant the settlement agreement. The revelation caused consternation among some members on the call.
Joint parties to the settlement agreement | MISO
Three Projects…
Severson explained that each of three proposed projects under consideration would create a new 345-kV line terminating at the Jim Hill substation in southeastern Missouri. Costs for the proposals range from $152 million to $262 million, with cost-benefit ratios from 2.04:1 to 1.1:1. Two of the projects would increase the existing 1,000-MW contract path by 2,574 MW, while the most expensive proposal would increase it by 2,302 MW.
MISO requires projects to demonstrate at least a 1:1 benefit-to-cost ratio over 20 years to be considered under its Market Congestion Planning Study. It used an economic model from its 2019 Transmission Expansion Plan (MTEP 19) to estimate benefits for the proposals.
“Going forward, we plan on doing some refinement, getting stakeholder feedback and doing some external outreach,” Severson said of the project ideas.
MISO had been focusing on nine possible projects after receiving 35 proposals last summer to alleviate traffic on the constraint or even eliminate the need for the settlement agreement altogether.
RTO staff extended its analysis of the projects beyond the MTEP 19 approval deadline in December. (See MISO Studying Projects to Cut North-South Tx Reliance.) That work will be completed in the first half of this year, MISO executives have said.
During Tuesday’s call, MISO staff said the three projects will now enter a more rigorous testing that includes alternative components. WPPI Energy’s Steve Leovy said MISO should examine combining elements of the three different projects.
Some MISO stakeholders warned that approval of just one of the projects might not be a panacea for all subregional transfer constraints. They called for more analysis on the nearby system.
Veriquest Energy’s David Harlan asked MISO to take a closer look at how the projects could alter flow patterns on nearby lines or tax existing substations, impacting either SPP or the joint parties to the settlement agreement.
“I would hate to see us lose all of our settlement payments … only to hit a constraint with SPP,” WEC Energy Group’s Chris Plante added.
The agreement requires MISO to make monthly payments for usage based on a capacity factor. At a 20% or less capacity factor, MISO pays $1.33 million per month, while a 20 to 70% capacity factor sends the price to $2.25 million per month. A factor higher than 70% results in a $3.17 million monthly payment.
Those payments are set to escalate annually beginning next month — by an additional 2% for up to a 70% capacity factor and 4% for capacity factors above 70%.
The agreement’s initial term ends on Jan. 31, 2021, when it automatically converts into yearly extensions which can be terminated with a 12-month written notice by any of the settlement’s seven joint parties, which include MISO, SPP, Tennessee Valley Authority, Southern Co., LG&E and KU Energy, Power South Energy Cooperative and Associated Electric Cooperative Inc. If that happens, the parties enter a four-month renegotiation period. If no agreement can be reached, MISO’s rights on the transmission systems of the other parties are terminated, leaving it once again subject to paying SPP unreserved transmission-use penalties for flows above MISO’s 1,000-MW contract path capacity.
Senior Adviser Jack Dannis said MISO is currently discussing next steps of the settlement agreement with the other parties.
…or Buy Firm Service?
Dannis emphasized that MISO has three options for increasing its contract path post-settlement agreement: building new transmission, adding a new transmission-owning member that connects the regions, or obtaining firm transmission service from another company connected to both regions.
“We’re in frequent communication with SPP and the joint parties,” Dannis said. The parties are currently “performing transmission planning analyses to identify cost-effective solutions for providing MISO firm transmission rights,” he said. Those solutions may involve upgrades to SPP or neighboring systems in order to offer MISO new firm rights.
Dannis said for every 1 MW of increased capacity on the contract path, MISO’s payment is reduced by $667/MW-month.
That MISO is considering purchasing firm transmission rights from its neighbors came as a surprise to some stakeholders.
LS Power’s Pat Hayes said MISO last year only asked that transmission developers propose solutions that could increase capacity on the transfer limit — and didn’t let on that firm service purchases were also an option under consideration.
“This is a pretty big transparency issue, and we should be able to participate, and we’re not right now,” Hayes said. “I know that there are other parties in the room that feel this way.”
Hayes said it also isn’t clear whether MISO stakeholders would have another opportunity to propose projects that would increase transfer capacity between the regions through a coordinated system plan between MISO and SPP. The RTOs will decide this spring whether to embark on a study that could result in an interregional project. MISO officials said it was too early to speculate on what type of projects would be examined under such a study.
SPP continues to add fresh blood to its leadership ranks, announcing on Thursday that two new officers will join its senior leadership team from within the RTO’s ranks.
Sam Ellis | SPP
The grid operator said its Board of Directors had elected Sam Ellis as chief information security officer and vice president of information technology, and Antoine Lucas to serve as the organization’s vice president of engineering, effective Feb. 1. The two were recommended by CEO-elect Barbara Sugg and COO Lanny Nickell, SPP said, filling the positions left vacant by their earlier promotions. (See SPP Names Nickell COO, Adds Board Member.)
“Some of SPP’s greatest opportunities for advancement will depend on our ability to build and manage relationships with our stakeholders and to innovate,” Sugg said in a statement. “Both Sam and Antoine are exactly the kind of people we need leading us into the future.”
Ellis, the organization’s director of cybersecurity and controls, will assume oversight of the IT department from Sugg. He will be responsible for technology development and deployment, monitoring, support and cybersecurity for SPP and its members, and for establishing IT strategy and policies. Ellis joined the RTO in 2003 from Empire District Electric and has 26 years of industry experience in transmission and generation operations and electricity and natural gas trading.
Lucas, formerly director of transmission planning, replaces Nickell and will oversee the transmission expansion plan’s ongoing development, tracking expansion projects, administering generator interconnection processes, engineering studies and supporting SPP’s real-time operations functions. He joined the organization in 2007 after five years with Entergy Services as an engineer and system operator.
Both Ellis and Lucas have played prominent roles recently in front of stakeholders. Ellis was program director of the day-ahead market’s successful implementation in 2014, while Lucas has served as the point person for SPP’s Integrated Transmission Planning process.
MISO’s first storage-as-transmission proposal has drawn several protests from stakeholders who say the plan gives transmission owners an unfair advantage in developing the resources.
Multiple entities said the ruleset, filed with FERC on Dec. 12, is geared to providing incumbent TOs an effective monopoly on storage assets functioning as transmission, harming competition. Several urged FERC to reject the filing (ER20-588).
The proposal limits storage-as-transmission assets to transmission-only functions operated by TOs. As such, MISO labeled these resources storage-as-transmission-only assets (SATOA), and they would be barred from simultaneous participation in its energy markets — for now. (See Despite Pushback, MISO Pursuing TO-only SATA.) The RTO has said its 802-page plan will avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.
MISO’s 2019 Transmission Expansion Plan (MTEP 19) includes just one SATOA project proposed for Wisconsin, but the RTO doesn’t have a cost-recovery mechanism for such assets. (See MTEP 19 Could Yield First MISO SATA Project.) Its Board of Directors is slated to hold a special vote on approval of the project once FERC gives the go-ahead on the rules, including cost recovery.
Invenergy’s Grand Ridge Battery Storage Facility in Illinois | BYD
In comments filed with FERC, LSP Transmission Holdings said the proposal “as presented would effectively create a storage project monopoly for MISO’s incumbent transmission owners, just as this promising technology is in its infancy.”
A group of nearly 20 entities — including environmental nonprofits, consumer groups and utilities such as DTE Energy — said the ruleset was unlawful because it creates unduly discriminatory preference for MISO’s TOs.
The group also said the plan ignores FERC’s requirement that RTOs remove barriers to the participation of electric storage resources, arguing that Order 841 and MISO’s SATOA definition cannot be considered in isolation. It also contends that MISO’s Planning Advisory Committee originally wanted non-TOs and TOs alike to propose and construct SATOA, but that MISO ultimately favored the wishes of the latter.
“MISO’s decision to ignore the PAC’s recommendation in favor of the SATOA proposal demonstrates a lack of independence from the will of its TO members,” the groups wrote.
DTE representatives had promised to protest the filing during December’s board meeting, where directors voted unanimously to approve MTEP 19, which contains American Transmission Co.’s Waupaca area energy storage project meant to ease transmission reliability issues in central Wisconsin. In stakeholder meetings, DTE has repeatedly said the TO-only provision amounts to preferential treatment because generation owners cannot operate SATOA.
Not ‘Comparable’
MISO officials have said storage developers and owners who are not classified as TOs could still propose projects under existing rules on selecting non-transmission alternatives (NTAs) in the place of transmission projects. The RTO last year placed several mentions of storage resources into BPM 20, the business practices manual managing NTAs.
But storage owners and developers said the treatment remains unequal because NTAs must first clear MISO’s approximately three-year generation interconnection queue, which is not a requirement for TOs proposing SATOA, who instead submit their projects for study through the annual MTEP process.
Invenergy Storage Development complained the NTA option doesn’t offer “comparable opportunities.”
“Unlike SATOA, companies proposing NTA projects must first proceed through the multiyear generator interconnection queue, and unlike SATOA, those projects would be required to pay transmission charges with respect to the delivery of energy when the storage facility is charging from the MISO transmission grid. As a result, even though an NTA might present the very same storage solution as a SATOA, it cannot effectively compete against a SATOA, and transmission owners will maintain a monopoly on owning storage projects serving as a transmission asset,” Invenergy said in its protest.
Invenergy added that MISO’s proposed ruleset “ignores the fact that any expertise that transmission owners are assumed to have as to their respective transmission systems or in developing and owning traditional transmission, is inapplicable to SATOA — it is developers, like Invenergy, that have the relevant experience in owning and operating storage projects.”
The Michigan Public Service Commission said it was similarly “compelled” to oppose the filing because MISO isn’t proposing equal treatment for TOs’ and non-TOs’ storage projects. “No storage project should have an unfair advantage over any other project. Since the SATOA proposal discriminates against non-TO storage projects in favor of TO projects, the MPSC urges the commission to reject the proposal and direct MISO to collaborate with interested stakeholders to prepare a truly nondiscriminatory proposal,” it said.
Storage developer GlidePath said MISO’s proposal “completely misses the mark” and called it a “rushed solution.” Instead of “encouraging the development of single-use storage devices limited only to supporting the transmission system,” GlidePath said the RTO should create a more comprehensive compensation mechanism for storage resources and other generators that can support the transmission system.
GlidePath also said there are “clear competitive concerns inherent in permitting” SATOA to circumvent MISO’s interconnection process.
MISO Director of Planning Jeff Webb has predicted that the RTO will early this year begin addressing the issue of allowing storage functioning as transmission to simultaneously function in the energy market.
FERC on Wednesday accepted NERC Notices of Penalty against the Bonneville Power Administration, Idaho Power and the Niles Light Department. There were no monetary penalties.
The commission said it would not review NP20-5 regarding BPA or NP20-6, a spreadsheet NOP. The spreadsheet included 16 critical infrastructure protection (CIP) violations against unnamed entities reported by the Western Electricity Coordinating Council and ReliabilityFirst, which were redacted to protect sensitive information about how the entities implemented controls to address security risks. Five of the violations included financial penalties totaling $525,000.
Bonneville Power Administration
BPA was cited for two incidents, the first in September 2015, when it discovered that the rating on one of its current transformers (CT) was lower than the facility ratings of two associated transmission lines. The CT should have been rated as the most limiting element when BPA established the facility ratings. However, the utility’s rating methodology assumed CT equipment “to be sized such that it would never be the most limiting element in a facility.”
According to a NOP filed Dec. 30, after BPA reported the discovery to WECC, the regional entity performed an analysis that revealed similar issues in at least 52 facilities, at least six of which were part of one or more of WECC’s major transfer paths (NP20-5). The widespread failure to effectively determine facility ratings violated the FAC-009-1 standard. Although WECC found that the violation “posed a serious risk to the reliability of the bulk power system,” BPA is not subject to monetary penalties, in accordance with a D.C. Circuit Court of Appeals ruling that FERC and NERC cannot impose such penalties against federal governmental entities.
The RE noted that the incident constituted BPA’s first violation of the standard in question; BPA self-reported the violation and cooperated during the enforcement action; there was no evidence of any attempt to conceal the violation or intent to do so; and the violation did not cause or extend a loss of load. BPA typically operates its system conservatively, and the affected facilities were never in danger of exceeding a system operating limit.
Workers upgraded the Bonneville Power Administration’s Pacific Direct Current Intertie in 2016. | Bonneville Power Administration
In addition, BPA has since implemented a mitigation plan approved by WECC to prevent future incidents. In a separate incident, BPA submitted a self-report in May 2017 saying it may have failed to comply with six transmission operator (TOP) and interconnection reliability operations and coordination (IRO) requirements resulting from an outage on Nov. 30, 2016. BPA implemented the outage as part of its boundary remedial action scheme (RAS), which includes line-loss logic for three transmission lines.
BPA did not correctly implement the study limit information memo (SLIM) required by its operating plan, which specified that a 650-MW system operating limit (SOL) should be set at the one boundary’s flowgate.
Although a dispatcher limited output of the main generating station on the lines to 650 MW, BPA did not lower the boundary SOL from 1,300 MW to 650 MW.
Because the lower SOL was not entered in the control system, the alarm monitoring did not alert to three SOL exceedances between 2:15 and 2:45 p.m.
WECC said the incident, which posed a “moderate” risk, resulted because the dispatcher mistakenly relied on a dispatch standing order rather than the SLIM.
“BPA was already operating its system with the RAS in a degraded state. If BPA were to have lost another line, the RAS could have caused a loss of load and potentially opened the remaining lines entirely,” WECC said.
It credited BPA for discovering the mistake during a routine monitoring activity nine days after the incident and said the 650-MW limit on the generating station reduced the risk.
Idaho Power
Idaho Power submitted a self-report on July 24, 2018, saying it may have failed to comply with PRC-005-2(i) R3 by failing to maintain a battery used to power communications equipment during an emergency outage at a 230-kV substation for two 18-month intervals.
The vented lead acid battery was maintained in June 2014, but the company missed its 18-month maintenance interval on Jan. 1, 2016, and did not correct the error until July 2017.
WECC said the problem resulted when a transmission and distribution engineer disabled the battery maintenance trigger because he thought the utility’s communications group was responsible for tracking the maintenance and testing. The communications group had not been notified of the change in responsibility, the RE said.
The violation posed a minimal risk because the battery voltage was continuously monitored by the energy management system, which would have produced an alarm had a battery failure occurred.
WECC said the company’s PRC-005 compliance history was an aggravating factor in the incident but imposed no monetary penalty.
Niles Light Department
During a compliance audit in spring 2018, ReliabilityFirst determined that the Niles Light Department, the distribution provider for the Ohio city, had violated COM-002-4 R3 by failing to conduct initial training for each of its operating personnel who can receive oral two‐party operating instructions.
The city did not train three individuals until March 1, 2018, although they had been receiving operating instructions from FirstEnergy before then. The training requirement was effective July 1, 2016.
The risk of harm to the grid was partially reduced because Niles’ personnel only receive operating instructions in the presence of FirstEnergy operators with written switching orders. “Although entity personnel had not been formally trained on how to receive an oral two‐party, person‐to‐person operating instruction, the entity indicated that personnel performed three-part communication in practice when receiving operating instructions,” ReliabilityFirst said.
Niles misinterpreted the standard, believing that its established communication process with FirstEnergy meant it did not need to train its own personnel.
The audit also found Niles in violation of PRC-005-2(i) R3 for failing to conduct all required testing for a battery and charger. Niles failed to perform an unintentional ground test (required every four months); a battery terminal connection resistance test (required every 18 months); a battery intercell or unit-to-unit connections resistance test (18 months); and load tests (every 18 months and every six years).
RF said Niles failed to update its protection system maintenance program with the new tests as required.
“The risk is partially reduced because the entity was performing quarterly tests and monthly tests on the protection system equipment and that testing would likely indicate to the entity any battery degradation before failure occurred,” RF said, noting the city’s peak load is only 68 MW.
The team working on NERC’s proposed standard for cold-weather preparedness is revising the draft standard authorization request (SAR) and expects to post the updated document for another round of comments by the middle of February (Project 2019-06).
Debate at this week’s standard drafting team meeting primarily revolved around the cool reception the proposal received last year, with Sam Dwyer of Ameren noting that about 60% of respondents felt a new standard was unnecessary. Even many of the commenters who supported requirements around cold-weather preparedness urged the team to re-evaluate its scope. (See Gen Operators Cool to Winter Preparedness Standard.)
Geographic Splits
The strongest opposition to the proposal came from operators in northern areas, who argued that they already prepare for extreme cold as a matter of course, and that only operators in areas where winters are typically mild need guidance on how to handle extreme events. This argument made little headway with the drafting team, although it acknowledged that regional variations would likely need to be written into the standard.
“My take on that would be that standards should always be stuff you’re already doing. So, to the extent that you’re already doing it, great — it shouldn’t be hard for you to meet the standard,” Kenneth Luebbert of Evergy said. “[On the other hand], I think it’s going to be key [to] allow a lot of variations. … The approach that different plants take will be quite a bit different, whatever requirement we put into place.”
Some members suggested that the team address the geography-based objections by expanding its focus beyond low temperatures to cover any kind of extreme weather such as droughts or hurricanes, with Don Urban of ReliabilityFirst calling the new standard a “golden opportunity” to consider the impact of extreme weather in general.
This idea had little support from the majority of the team, however. Chair Matthew Harward of SPP reminded members that the impetus for the project was a joint FERC-NERC report on the Jan. 17, 2018, cold-weather event in the South Central U.S. Harward warned that trying to tackle too wide a remit could bog down the team and prevent it from reaching a meaningful result.
At the same time, members backed off from attempts to narrow the scope too much, as with Luebbert’s suggestion to focus on coal- and natural gas-fired generators, which accounted for 97% of performance issues cited in the joint report. Michael Brytowski of Great River Energy pointed out that when temperatures in the Upper Midwest dropped to -30 degrees Fahrenheit in early 2019, MISO lost almost 10 GW of wind generating capacity for 36 hours because of cold hydraulics, indicating that any form of generator can suffer from extreme temperatures.
NERC Guidelines Debated
Another topic of disagreement was what role the existing NERC cold-weather guidelines should play in the SDT’s work. Several industry respondents had said that the guidelines were sufficient and that no further requirements were needed; several team members favored simply adopting the guidelines as the new standard in whole or in part.
However, others felt more work was needed. For example, NERC Senior Standards Developer Jordan Mallory observed that “out of the past 12 years, there have been six blackouts [from extreme cold] — that is a problem. … Obviously, the NERC guidelines may not be enough.”
Responding to Mallory, Venona Greaff of Occidental Chemical cautioned that extreme weather events, by definition, are hard to predict and that it is impossible for even the best standard to cover all conceivable scenarios.
“You can do everything right all the time … you [can] look at where the wind blows from [historically] and how low the temperature gets, [but] you can have a one-off [where] the wind blows from a different direction and your wind blocks aren’t there,” she said. Greaff added that issues are more likely to arise at backup facilities, which aren’t used often, than at baseload generators.
“It’s like if you have a car that sits for a month and doesn’t drive — there’s no guarantee it’s going to start when you need it to.”
Observers from FERC urged the team to making their recommendations with the actual working conditions that utilities deal with in mind. Even when generator owners can point to their own cold-weather preparedness plans, they must be prepared to follow through and execute on them, they said.
“They’ve all got plans, and they’re good. … The generator operators [and] owners are very professional about getting plans out,” said Nick Henry of FERC. “The issue would be, after a period of time with moderate winters, and then another one hits you about five or six years later — now your pants are back down around your ankles because you just quit executing.”
U.S. renewable investments jumped 28% to a record $55.5 billion in 2019, showing the clean energy revolution is thriving despite the federal government’s failure to enact climate policies.
“We’ve seen renewable energy capacity double [in the U.S.] since the beginning of the decade,” said Ethan Zindler, Americas chief for BloombergNEF (formerly Bloomberg New Energy Finance), who released the data during a webinar by the American Council on Renewable Energy (ACORE) on Wednesday. “Solar capacity is probably 40 times what it was a decade ago.”
Renewable generation has increased about 75% to 761 TWh in 2019. Renewables now represent 18% of U.S. generation nameplate capacity. Including nuclear power, 38% of the country’s generating capacity is carbon-free.
U.S. renewable investments 2004-19 | BloombergNEF
Zindler said the biggest reason for the results in the U.S. was “a bit of a frenzy ahead of [the] anticipated step downs in tax credits.”
Globally, investment grew to $282 billion, a $1 billion increase from 2018, as the U.S.’ strong performance overcame a slowdown in China. The peak was $315 billion spent in 2017.
Although global spending was virtually flat in 2019 from 2018, Zindler said, declining costs meant developers were able to add 180 GW of generating capacity, up about 20 GW from the prior year. Wind edged out solar slightly in total investment worldwide, rising 6% to $138 billon while solar dipped slightly to $131 billion.
Growth was fueled in part by corporate power purchases, which totaled 50 GW, most of them in the Americas. The RE100 — 221 companies that have committed to 100% renewable electricity — have total electric demand about equal to that of South Africa, Zindler said.
Zindler said Congress’ one-year extension of the production tax credit is likely to result in a 1.5- to 2-GW increase in wind growth through 2025. Bloomberg projects 28.5 GW of new renewables in 2020, which would be the largest ever “by a pretty decent amount,” Zindler said.
Separately Wednesday, the American Wind Energy Association reported that 2019 was the U.S. wind industry’s third strongest year, with developers adding 9,143 MW of capacity. An additional 44 GW of wind projects, totaling more than $62 billion, are under construction or in advanced development, AWEA said.
Global corporate purchase power agreements (2009-19) | BloombergNEF
Challenges
Other panelists on ACORE’s “Outlook for Growth & Investment in 2020” webinar discussed industry trends and challenges.
“The conversations taking place today are slightly different than they were a couple years ago,” said Craig Gordon, vice president of government and regulatory affairs for Invenergy. “Companies like Invenergy aren’t just doing wind. They’re doing wind, solar and storage in the renewables space.”
Gordon cited the challenges of developing new generation at a time of record low power prices and flat demand. “We’re pushing new megawatts onto a grid that’s already oversupplied. That’s very apparent in places like PJM,” he said.
New production tax credit (PTC) schedule for onshore wind projects | BloombergNEF
Gordon also complained of “regulatory uncertainty” in New York, citing Gov. Andrew Cuomo’s Jan. 24 budget address.
“He said he would like the state government to begin doing the siting and transmission and development and then bring in developers after the fact to build the projects that they’ve cleared the way for,” Gordon said. “That’s really not helpful in a state where we’ve already seen significant regulatory burdens in getting projects done.”
He also slammed FERC’s Dec. 19 order directing PJM to expand its minimum offer price rule.
“If FERC was really hoping to just allow coal, I think they miscalculated … big time,” he said. “I think they may have taken a sledgehammer when a scalpel would have been more appropriate to deal with the issues around the capacity market.”
On the one-year anniversary of its bankruptcy filing, Pacific Gas and Electric appeared to be closing in on its goal of exiting Chapter 11 reorganization, while lawyers representing shareholders, fire victims and the government wrangled in court to secure a share of the multibillion-dollar pot the utility will have to pay out.
At the same time, California Gov. Gavin Newsom persisted in his threats to take over PG&E if it doesn’t leave bankruptcy “transformed.”
“If PG&E can’t do it, we’ll do it for them,” Newsom told an audience at the Public Policy Institute of California in Sacramento on Wednesday.
In San Francisco, lawyers argued in U.S. Bankruptcy Court over the division of a $13.5 billion trust that PG&E has promised fire victims. Because the details of the trust have yet to be made public, some potential beneficiaries were concerned they might not get their share.
Santa Rosa’s Coffey Park neighborhood was leveled in the Tubbs Fire in October 2017.
Attorneys representing more than 1,000 victims of the Camp Fire — which killed 86 people and destroyed 18,800 structures in the town of Paradise in November 2018 — tried unsuccessfully to convince bankruptcy Judge Dennis Montali to unseal terms of PG&E’s settlement with some victims of the Tubbs Fire, which killed 22 people and leveled a large part of the city of Santa Rosa in October 2017.
The lawyers argued that the confidential settlement with 19 elderly and infirm victims of the Tubbs Fire could jeopardize payments to Camp Fire victims because all must draw on the same fixed amount that PG&E has promised to put in the trust account.
Camp Fire victims “will soon be asked to vote on a restructuring plan that purports to provide $13.5 billion in funds for wildfire victims, including themselves. But that $13.5 billion figure is literally meaningless if an outsized portion has already been set aside for a select few claimants, the lawyers argued in a court filing.
Montali overruled their objection Wednesday, saying it was outweighed by PG&E’s agreement to settle the entire Tubbs case, which otherwise had been set to go to trial this month with an uncertain outcome. State investigators found a private landowner’s faulty wiring, not PG&E equipment, had started the fire.
A group of PG&E shareholders who had filed a securities fraud class-action lawsuit against PG&E argued they had been denied sufficient notice of the claims procedure in the bankruptcy case. Montali seemed skeptical of the argument, while agreeing with PG&E attorney Stephen Karotkin that a decision in the shareholders’ favor could “gum up” the case.
Montali heard briefly from lawyers representing federal and state agencies that are trying to recoup nearly $4 billion in funds dispersed to deal with catastrophic fires ignited by PG&E equipment in recent years. The agencies, primarily the Federal Emergency Management Agency, are concerned that their payment may come from the $13.5 billion to be set aside for fire victims and are asking the judge to help sort out the situation. (See FEMA Wants $4 Billion from PG&E in Bankruptcy.)
Montali said he would hear more from the government lawyers at the next bankruptcy hearing Feb. 4.
Newsom Repeats Takeover Threat
As the bankruptcy hearing played out in San Francisco, Newsom repeated his threat of a state takeover and said he had been talking with legislative leaders, readying a plan, several news outlets reported.
“It has to be a completely reimagined, transformed company,” Newsom said, according to the Associated Press. “Its culture has to change; its mindset has to change; its framework away from short-termism and situational thinking has to be replaced with a culture that focuses on you and me, not just shareholders.”
The governor said his staff had been in talks with PG&E to work out a solution, Bloomberg reported. He has called for PG&E to replace its entire board, adding more Californians, and to provide the state a mechanism for a quick takeover, should it be needed.
If a deal can’t be reached within the next few weeks, Newsom said he will lay out a detailed plan for a takeover.
PG&E filed for bankruptcy on Jan. 29, 2019, following two years of devastating blazes caused by its equipment. In recent months, the company has reached settlement agreements with most fire victims, insurance companies and local governments.
The utility most recently settled with bondholders that had offered their own reorganization plan for PG&E, amounting to a hostile takeover bid. The bondholders, led by several hedge funds, agreed to drop their plan in exchange for PG&E agreeing to pay or refinance its long- and short-term debts. (See PG&E Settles with Bondholders; Governor Objects.)
SANTA FE, N.M. — The SPP Cost Allocation Working Group (CAWG), composed of regulatory staff from across the RTO’s footprint, told their state regulators Monday that they plan to establish a narrow byway facility cost allocation review process, rather than just evaluate the process as first directed.
CAWG Chair John Krajewski, a consultant with the Nebraska Power Review Board, explained to the Regional State Committee that the group determined the Holistic Integrated Tariff Team’s recommendation that it evaluate a process through which costs for specific 100- to 300-kV projects can be fully allocated on a regionwide basis was not sufficient.
“‘Evaluate’ really means ‘go out and do it,’” Krajewski said. “The consensus of the group was that HITT’s intention was for us to put together a process for how this will look.”
Krajewski said the CAWG is “working towards having language” the RSC can adopt in the form of a white paper. The HITT’s timeline has the group completing its work in July, a schedule he called “aggressive.”
The CAWG is also recommending that projects eligible for the byway cost-allocation review process should include both new and existing Schedule 11 facilities. The recommendation excludes directly assigned upgrades.
RSC Approves Renewables’ Capacity White Paper
The RSC unanimously approved a staff white paper proposing a methodology for prioritizing and allocating the available effective load-carrying capability (ELCC) from wind and solar generating facilities that qualify as capacity in SPP’s balancing authority area.
Staff last year completed the study, which revealed that while wind resources’ total capacity increased with penetration, the accredited percentage of capacity related to the nameplate of each individual resource decreased.
The committee also approved Landmark Certified Public Accountants’ selection to audit its 2019 financial statement and the Business Practices Working Group’s revisions (BPWG RR369) to a business practice (BP 7060) that establishes cost-estimating processes and reporting requirements if project costs are projected to go outside an established bandwidth.
The changes close oversight gaps for projects that receive base plan funding but are not issued a notification-to-construct; clarify when oversight begins; and provides that the project owner is required to submit certain information as part of closeout processes.
Louisiana PSC’s Francis Joins Committee
The meeting marked NPRB Member Dennis Grennan’s first as RSC president and Louisiana Public Service Commissioner Mike Francis’ first as a member. Francis replaces Foster Campbell, who made a memorable appearance during October’s RSC meeting in Little Rock, Ark. (See “Louisiana’s Campbell: SPP Spending ‘Extravagant’,” SPP Regional State Committee Briefs: Oct. 28, 2019.)
