The California Energy Commission will stick to the path of electrifying buildings despite a legal challenge filed against it by the nation’s largest natural gas utility, the agency’s chair said Wednesday.
CEC Chair David Hochschild | California Energy Commission
“Directionally, at the Energy Commission, we are going to keep fidelity to the state’s goals” of reducing greenhouse gases, including by electrifying buildings, increasing energy efficiency and procuring renewable energy, as required by landmark laws and executive orders signed by former Gov. Jerry Brown, Chair David Hochschild said.
“And along with that, we do care a great deal … about health,” Hochschild said. “And one of the things that recent research has uncovered is that the health impacts, even among homes that have gas, that have the same appliances, are not equal. Low-income homes are more likely to have heavier burdens” because they lack adequate ventilation for emissions from gas appliances, he said.
Hochschild made his remarks after hearing from dozens of environmental activists, physicians and residents who called for the CEC to require new buildings in California to be all-electric starting with the commission’s 2022 update to its building energy efficiency standards, which it plans to approve next year. Many of the speakers cited health impacts associated with methane emissions.
Local Electrification Measures
Cities and counties can pass ordinances that exceed the 2019 standards with the CEC’s approval. Nearly three dozen local governments have done so by requiring new or existing buildings to have electric furnaces, water heaters and cooktops in place of gas appliances.
San Luis Obispo was the latest city to adopt an electrification measure. On Wednesday, the CEC approved a city ordinance requiring all new buildings to be electric or, if using mixed fuels, to achieve heightened energy efficiency standards.
San Luis Obispo, Calif.
The CEC also approved a Davis city ordinance mandating rooftop solar and increased efficiency standards for high-rise and nonresidential buildings. State law already requires rooftop solar on new low-rise residential structures, though the CEC has approved exceptions to the rule. (See Calif. Energy Commission Relaxes Rooftop Mandate.)
Nearly all the public speakers at Wednesday’s hearing began by backing the proposed city ordinances but quickly segued into calling for statewide electrification rules.
SoCalGas Lawsuit
Hochschild acknowledged the comments and said the CEC would stay the course on electrification even though “now [the effort is] going to continue in court, because [Southern California Gas] elected to sue us … over this issue.”
SoCalGas, which serves nearly 22 million customers, filed a lawsuit in state court July 31 arguing that the CEC had failed to consider natural gas as a cleaner alternative to other fossil fuels, as it was required to do by a bill Brown signed in 2013.
“Natural gas and renewable gas are clean, affordable, resilient and reliable sources of energy on which millions of California consumers and businesses depend,” the company said in its lawsuit. “Natural gas has played a significant role in reducing greenhouse gas emissions and improving air quality, and natural gas and renewable gas remain critical to meeting California’s energy goals.”
The move was the latest pushback by natural gas companies concerned that California’s environmental and energy regulations will leave their assets stranded and worthless in the coming decades.
Senate Bill 100, signed by Brown in 2018, calls for load-serving entities to provide 100% carbon-free energy to retail customers by 2045. An executive order by Brown requires the state to achieve carbon neutrality by 2045.
In addition to legal challenges, gas companies are advocating for their pipelines to carry up to 30% hydrogen produced using excess renewable energy. (See NARUC Panel: ‘Green’ Hydrogen Could Lower GHGs.)
The COVID-19 pandemic is having little impact on Bonneville Power Administration operations or financial health, with fiscal year 2020 net income projected to easily exceed a “bad case” scenario outlined last quarter, agency officials said Tuesday.
“Even though we’ve had some unusual times, with disciplined cost management and favorable market conditions, we are forecasting hitting all of our financial targets for this year,” CFO Michelle Manary said during BPA’s third-quarter business review (the federal power marketing administration follows an October-September fiscal calendar).
Having weathered a highly uncertain third quarter, BPA now forecasts fiscal year net income could hit $152 million, up sharply from a second-quarter “baseline” case prediction of $110 million and well above the pandemic worst-case figure of $44 million. The latest estimate also puts BPA far ahead of its rate case target of $12 million for the year, Manary noted.
While reduced expenses account for some of the increase, the largest share stems from a big boost in net operating income, which is predicted to ring in at $65 million, compared with the $8 million estimate in the second-quarter outlook.
“This increase comes from power [generation], with higher secondary sales” of surplus power, Manary said. “Secondary sales have benefited from higher market prices and a good runoff pattern. Shape is everything,” indicating that hydroelectric surpluses happened to coincide with intervals of higher demand.
“While we’re seeing local reductions with certain customers due to COVID-19, we’re seeing increases in other areas, with a net result of no drop in aggregate load,” she added.
BPA now expects its FY 2020 net income to hit $152 million, far exceeding the rate case figure of $12 million and a Q2 pandemic “bad case” scenario of $44 million. | BPA
BPA’s power generation business is expected to yield more than $2.76 billion in total revenues, compared with the rate case estimate of $2.71 billion. That business line is also projected to incur expenses of nearly $2.6 billion, about $65 million below the rate case, in part because of delays in fish and wildlife project work stemming from social distancing measures. An amortization accounting adjustment related to the Columbia Generating Station nuclear plant in Washington state will additionally reduce expenses from the rate case level.
“These reductions were partially offset by power purchases, which were higher than rate case due to higher spill conditions that took place this summer. We saw average inventory in water … but we’re spilling at higher levels,” Manary said.
BPA’s transmission business should take in revenues of about $1.085 billion, just a million shy of the rate case. At nearly $1.01 billion, transmission expenses are projected to be about $25 million below the rate case, “primarily driven by lower interest rates and capital spending,” Manary said.
The latest FY 2020 capital expenditure forecast of $613 million is below the second-quarter baseline forecast of $656 million (and well below the rate case estimate of $847 million), but “substantially higher” than the COVID-19 “bad case” of $412 million “due to a restart of our capital program in June. We basically saw only a $20 million hit from COVID throughout the capital program,” she said.
Last Waltz for Mainzer
BPA also took steps early this summer to relieve the economic burden on its customer base of publicly owned utilities, including suspending collection of a surcharge implemented last year to buttress its financial reserves. That move is expected to save those utilities a combined $3 million per month for the rest of this fiscal year and a total of $30 million next year.
“At Bonneville, we remain very sensitive to the economic challenges facing our customers — and the communities they serve — as a result of the pandemic,” BPA Administrator Elliot Mainzer said. “We truly understand the hardship and uncertainty that many of you are facing.”
Mainzer said BPA would also “streamline” the process by which its customer utilities can request payment extensions if they’re facing financial hardship from the pandemic.
“This is not a waiver of the bill, but it extends the payment out, with interest, for up to three years,” he said.
Mainzer noted that the “vast majority” of staff continue to work from home in light of the pandemic and will continue “to do so for the foreseeable future,” while field staff are ramping up their work “consistent with social distancing requirements.”
“While we have not had any interruptions to service delivery, the coronavirus numbers in our service territory have remained challenging, and we’ve asked our workforce to be ever diligent in protecting the health and safety of their co-workers and their families,” he said.
“I hope you’ve found these meetings to be informative and useful as we’ve defined clear metrics for BPA’s business performance and hold ourselves accountable to you for delivering results,” Mainzer said. “I know that Michelle and our leadership team are committed to this process going forward and will stay connected as we evolve and progress together. I’d like to thank you for all of your support along the way.”
NYISO on Monday told stakeholders that it supports most of its consultants’ proposed parameters and assumptions for the installed capacity (ICAP) demand curves for capability years 2021/22 through 2024/25.
In their quadrennial review for the demand curve reset (DCR), Analysis Group and Burns & McDonnell recommended that General Electric’s 7HA.02 turbine be selected as the peaking plant for the ICAP demand curves for all of the state.
The consultants determined preliminary reference points — which equal the clearing price at 100% of the minimum capacity requirement — ranging from $7.74/kW-month for the New York Control Area (without selective catalytic reduction (SCR) emissions controls) to $21.36/kW-month for New York City, with SCR.
| NYISO
Capacity Market Design Manager Zachary Smith, who presented the draft staff recommendations to the Installed Capacity/Market Issues Working Group, said ISO staff are continuing to evaluate certain of the consultants’ recommendations, including the maximum clearing price, which is set at 1.5 times the estimated monthly value of the cost to develop a new peaking unit.
Both the reference point price and the maximum clearing price calculations require translating annual values into monthly values.
But while the translation of the annual reference value — also known as the net cost of new entry (CONE) — to the monthly reference point value uses a translation factor to account for excess conditions and seasonal differences in capacity availability, the factor is currently not applied when determining the monthly value of gross CONE.
As a result, NYISO said, there is a potential for the different methodologies to produce a reference point price that exceeds the maximum clearing price, with a greater risk of such outcomes in smaller regions. To avoid such an outcome, the ISO is considering whether to applying a translation factor in determining the monthly gross CONE value used to determine maximum clearing prices.
“Obviously, most of the focus in this process has been on the reference point; however, we are required to come up with a maximum price, as well as the zero crossing point [the point at which the value of marginal capacity declines to zero] for each locality and the NYCA,” Smith said.
Staff said they preliminarily agreed with the consultants’ proposed handling of scaling factors used to adjust the historic prices used for estimating net energy and ancillary services (EAS) revenues to the Tariff-prescribed level of excess conditions assumed for the DCR.
These scaling factors — the level of excess adjustment factors — did not take into account proposed retirements identified in compliance plans for the state Department of Environmental Conservation’s “Peaker Rule,” new NOx regulations that go into effect May 1, 2023. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
NYISO said it agreed with excluding the impact of the Peaker Rule because only four months of market prices impacted by the rule’s 2023 requirements would be used in the net EAS model. This would occur as part of the annual update for the 2024/25 capability year, for which the historic data period ends Aug. 31, 2023.
The ISO said applying Peaker Rule retirements to all years covered by the DCR “does not fairly reflect the expected system that will be reflected in the historic data periods used for determining net EAS revenue offset estimates for this period.”
MMU Review
Potomac Economics, the Market Monitoring Unit for the ISO, said it also supported most of the consultants’ methodology and recommendations but called for revising three assumptions that “are not supported by market data or reasonable economic considerations,” all of which result in inflating net CONE.
Day-ahead reserve offer data provided by the MMU for dual-fuel units in Zones J and K suggest that previous assumptions may overstate the cost of providing reserves, particularly for dual-fuel units, which can operate on secondary fuel if converted to energy in real time. | Analysis Group
“This is particularly harmful at this time given that NYISO is substantially oversupplied, and inefficiently high demand curves will serve to impede efficient retirements and perpetuate the current capacity surpluses,” it said.
Potomac called for:
reducing the cost of debt to a range of 6 to 6.5% from the proposed 6.7%. The MMU said the rate should be “based on a broader view of the available data that does not overemphasize the recent COVID-19-related financial market turbulence.”
replace the fuel-procurement cost for the sale of operating reserves with a cost of $2/MWh for dual-fuel units, which it said “would more accurately reflect the fuel reservation costs of reserve providers in New York with oil backup that would not likely incur large gas-procurement costs when selling reserves.” Todd Schatzki of Analysis Group said that based on data provided by the MMU, the consultants agree with its recommendation to adjust the day-ahead cost of offering to provide operating reserves for dual-fuel units.
increase the amortization period to 20 years from 17, which it said was “unreasonably low and ignores publicly available information on how the power system will adapt to the zero-emission provision of the Climate Leadership and Community Protection Act.”
Kieran McInerney of Burns & McDonnell, who presented portions of the consultants’ interim final report, noted that they had seen a wide range of land lease costs in Zone J, used in developing the estimated CONE, but left those costs unchanged as the current assumption is within the observed range.
The consultants previously reviewed market transactions, property tax values and stakeholder feedback, and also considered quoted values obtained through discussions with property owners in the potential acquisition of land.
Stakeholders expressed concerns about modeling values for land lease costs having been adjusted for inflation only.
Timeline
NYISO staff will issue its final DCR report to stakeholders and the Board of Directors on Sept. 9. Stakeholders will have until Oct. 9 to provide written comments to the board, which will hear presentations and debate on Oct. 19. The ISO will file the approved outcomes with FERC by Nov. 30.
NERC has posted its draft 2021-2023 Reliability Standards Development Plan (RSDP) for an informal comment period ending Sept. 9. The organization will consider stakeholders’ comments when drafting the final version of the RSDP to be presented at next month’s Standards Committee meeting.
The RSDP must be presented every year to FERC, along with Canadian and Mexican government authorities, following approval by NERC’s Board of Trustees in November. Each plan includes schedules and anticipated resource needs for each project under development or expected to begin, as well as a progress report on achievement of goals set in the previous year’s RSDP.
The draft RSDP shows there were four outstanding FERC directives being resolved through the standards process as of June 30. All projects from the previous RSDP are either complete or expected to be completed this year, except for the following projects that will continue into 2021:
Project 2016-02: Modifications to Critical Infrastructure Protection (CIP) standards (virtualization);
Projects slated for completion this year include Project 2015-09 (Establish and communicate system operating limits), which according to NERC’s Project Tracking Spreadsheet is the oldest standard drafting project still in progress. One reason the project schedule has slipped several times is the decision to expand its remit beyond the original mandate, leading to both an increased workload for the standard development team and concern from industry about overreach. (See April Ballot Planned for SOL Standards.)
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Project 2019-02 (BES Cyber System Information Access Management) and Project 2019-03 (Cyber Security Supply Chain Risks) are projected to finish this year as well. Both projects, along with Project 2015-09, are planned for presentation at the November board meeting.
Phase 2 of NERC’s Standards Efficiency Review project, focusing on reviewing CIP standards and data retention efforts, is also expected to continue into 2021. (See SER Phase 2 Targets Data Retention, Consolidation.) The effort began in 2017 to identify reliability standards that “may no longer be necessary to support reliability” in the BPS and has resulted in the complete retirement of 10 standards, along with the elimination of a number of requirements for other standards. (See “Standards Efficiency Review Retirements OK’d,” NERC Standards News Briefs: May 8-9, 2019.)
No standards are currently scheduled for periodic review in 2020, though emerging risks or action by FERC may result in new projects this year. In addition, the standards grading process — currently suspended because of the COVID-19 pandemic — is expected to resume in 2021.
With no end in sight to the COVID-19 pandemic, NERC announced on Thursday that the ERO Enterprise will extend the expansion to its self-logging program implemented in May and further defer on-site activities such as audits and certifications. Both policies will now continue through the end of 2020 “to allow registered entities to … focus their resources on keeping their workforces safe and the lights on.”
New COVID-19 cases reported each day in the U.S. since the beginning of the outbreak | CDC
Monthly Filing to Continue for Minor Issues
The self-logging program allows utilities, with permission of their regional entities, to log some instances of potential noncompliance with NERC reliability standards for future review by the ERO Enterprise rather than submitting self-reports for each incident. Events logged in this manner are typically resolved as compliance exceptions and are not included in a registered entity’s compliance history for penalty purposes.
Under normal circumstances, only events that pose minimal risk to the bulk power system are eligible for self-logging. NERC’s updated guidance expands the program’s application to instances of noncompliance that pose either a minimal or moderate risk to the BPS and are caused by “actions to address coronavirus impacts [that] alter the normal course of business operations.” (See NERC Expands Self-logging During Pandemic.)
In addition, while the expansion is in effect, all registered entities, regardless of whether they are already part of the program, will be allowed to self-log relevant noncompliance events with their REs. However, utilities that were not already part of the program will not be able to do so for instances of noncompliance that are not pandemic-related and will not be considered enrolled in the program when the guidance expires on Dec. 31.
Deferred Actions Seen as Necessary Evil
NERC and FERC, NERC Relax Compliance in Light of COVID-19.) The package required REs to consider the coronavirus an acceptable reason for failing to obtain and maintain personnel certification, and to perform periodic actions required by reliability standards on a case-by-case basis.
FERC also agreed in April to a request by NERC to defer the implementation of seven reliability standards scheduled to take effect this year, including standards related to supply chain cybersecurity, personnel training, coordination of protection systems, disturbance monitoring and reporting, and generator relay loadability. (See FERC Agrees to Defer Standards Implementation.)
The further extension of relief measures indicates that NERC and the ERO Enterprise expect the pandemic’s burdens on utilities to continue for the foreseeable future. According to NERC’s 2020 Summer Reliability Assessment, released in June, the organization expected the coronavirus to pose a significant challenge to the reliable operation of the BPS through the end of the season and beyond. (See COVID-19, Hurricanes Among Biggest Summer Threats.)
NERC’s concerns partially stemmed from the relaxation of mitigation measures by state and local governments that could lead to a “resurgence in virus activity” requiring sequestration of staffers at utilities, supporting services and supply chains. Data from the Centers for Disease Control and Prevention may bear this prediction out, with the seven-day average for new cases in the U.S. rising from about 20,000 in mid-June to nearly 67,000 in late July.
Utilities’ efforts to protect staff from the outbreak, such as deferring facility maintenance and upgrades, and retirement of existing facilities, are also expected to cause headaches later on because of “higher-than-expected forced outages” during peak demand periods.
PPL is looking to sell its U.K.-based utility business and focus on its U.S. operations, company officials announced Monday during a second-quarter earnings call.
CEO Vincent Sorgi said in his presentation that the decision to sell Western Power Distribution (WPD) — the distribution utility for parts of England and Wales — followed a “comprehensive strategic review” by the company’s board of directors.
Sorgi said PPL believes the divestment of WPD will streamline the company and provide more “financial flexibility,” allowing it to concentrate on domestic infrastructure projects and growing clean energy technologies.
“We believe WPD represents the premier asset group with an extremely high-performing management team in the best energy subsector in the U.K., i.e., electric distribution,” Sorgi said. “We are more confident than ever that the road to net-zero carbon emissions in the U.K. will flow through electric distribution. And significant investment will be required in that sector if the U.K. is going to achieve its net-zero goals.”
WPD consists of four distribution network operators serving around 8 million customers in central and southwest England and South Wales. Sorgi said a near-term sale would provide the new owner of WPD the opportunity to affect its business plans for the U.K.’s next five-year price control period, which sets the revenue that electric distribution companies can earn from charges on consumer energy bills.
“The decision to sell WPD is in no way a negative reflection on our WPD team or the WPD business; in fact, it’s quite the opposite,” Sorgi said. “We are extremely proud of the financial and operational results that WPD has achieved over the past two decades, and we are confident they will continue to deliver in the future.”
PPL’s headquarters in Allentown, Pa.
Sorgi said PPL believed WPD that is undervalued by investors and that its sale price should be “higher than the sum of the parts” incorporated into the company’s stock price. He also said the sale will allow PPL to target an earnings-per-share growth rate “more in line with our U.S. utility peers.”
The company said it expects to begin evaluating offers for WPD’s sale, including deals involving all cash or a combination of cash and U.S. utility assets. PPL has chosen J.P. Morgan Securities to serve as its financial advisor to assist with the sale, intending to announce a deal sometime in the first half of 2021.
Sorgi said PPL has been “very transparent” with its investors that the company would not engage in mergers and acquisitions activities unless they could be completed in a way to create value for shareholders. He said the possibility of a WPD deal provided a perfect opportunity.
Earnings down
CFO Joseph Bergstein Jr. announced net income of $344 million ($0.45/share) for the quarter, a 22% decrease from its earnings of $441 million ($0.60/share) in the same period last year.
The company, however, posted a $83 million ($0.10/share) special-item loss “primarily from unrealized losses on foreign currency economic hedges and certain impacts related to COVID-19.” Adjusted earnings were actually up slightly for the quarter, from $422 million in 2019 to $427 million this year.
Total revenue for the quarter was $1.73 billion, a 3.5% year-over-year dip. PPL maintained its earnings-per-share guidance for 2020 of $2.40 to $2.60.
MISO’s much debated first rule set for storage resources functioning as transmission assets passed muster with FERC on Monday, though Commissioner James Danly opposed the plan (ER20-588).
The commission approved the proposal, effective immediately, subject to MISO providing more explanation on storage-as-transmission resources’ impact on the interconnection queue, special commercial pricing nodes for the resources and instances when storage wouldn’t be used to solve transmission reliability issues.
Danly dissented, saying the plan “impermissibly blur[s] the line between generation and transmission.”
The rules limit storage-as-transmission assets to transmission-only functions operated by MISO-defined transmission owners. Such assets will be called storage-as-transmission-only assets (SATOAs) and will be barred from simultaneous participation in the RTO’s energy markets, with SATOA owners responsible for the resources’ states of charge. SATOAs would be selected using MISO’s annual Transmission Expansion Plan (MTEP).
FERC accepted and suspended the plan in March, suggesting that some aspects could be unjust and unreasonable. MISO defended the plan in front of FERC in May at a technical conference on the proposal. The grid operator said the plan is intended to be an interim measure while it designs a more comprehensive approach to allow storage resources to simultaneously participate in the energy markets while providing transmission solutions. (See MISO Plugs SATOA Plan at FERC Conference.)
The RTO has repeatedly argued that the short-term plan will avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services. The grid operator has promised to hold stakeholder discussions beginning in 2021 on dual-mode participation of storage in both markets and on the transmission system.
Many in the MISO stakeholder community have said the rules would give incumbent TOs an effective monopoly on storage assets functioning as transmission, harming competition. (See MISO SATOA Proposal FacesOpposition.) DTE Energy has been especially outspoken against the plan, maintaining it will create unduly discriminatory preference for TOs over generation owners with comparable projects.
| Enel X
FERC was not swayed by those claims.
“We are not persuaded by protesters’ arguments that MISO’s proposal is unduly discriminatory toward non-transmission owners seeking to develop storage for transmission uses. As protesters assert, a SATOA is most likely to qualify as a baseline reliability project or other project, and Order No. 1000 allows transmission owners to maintain a right of first refusal for such categories of transmission projects,” the commission said.
FERC said that because SATOA would be bound to the same requirements as other transmission projects, the protesters’ concerns seemed to be about the RTO’s existing Tariff rules, which were not under scrutiny.
The commission also determined that MISO’s rules for SATOA evaluation under the annual MTEP process and its proposal to develop unique operating guides for each asset were fair.
“MISO’s proposed evaluation criteria will result in MISO choosing SATOAs that are properly characterized as transmission assets eligible for cost recovery in transmission rates,” FERC said. “The proposal ensures that SATOAs will be subject to adequate scrutiny in order to ensure that the SATOA is the preferred solution to an identified transmission need.”
Some protesters argued that MISO should treat SATOAs the same as non-transmission alternatives (NTAs), which must first clear the RTO’s approximately three-year generation interconnection queue before being placed in operation. SATOAs, meanwhile, would only have to clear the RTO’s annual MTEP studies. But the commission noted that the RTO is only required to consider proposed NTAs as alternatives to transmission solutions, while SATOAs will be considered as transmission solutions themselves. “MISO’s SATOA proposal does not change MISO’s existing process to consider transmission and NTAs on a comparable basis,” it said.
Some Revisions Needed
FERC said MISO’s plan sets reasonable limitations on SATOAs’ activity; however, it ordered the RTO to further detail the special commercial pricing nodes it will create for energy injection or withdrawals. The RTO needs to make plain that no other energy trading activities will be allowed at the new nodes, FERC said.
The commission also said MISO, for the most part, built in adequate protections so that SATOAs don’t affect generators seeking to interconnect. But it said the plan lacked detail on how the RTO will evaluate the impact of a SATOA on the interconnection queue and ordered the RTO to document the process in a new filing.
Finally, FERC directed MISO to clarify that it doesn’t intend to use SATOAs to correct routine reliability transmission issues that could instead be solved by a market solution.
Danly: Discrimination Claims Inevitable
Commissioner Danly said MISO’s proposal improperly conflated generation and transmission.
“No matter how our order characterizes the function of energy storage facilities, the service contemplated by [MISO’s] filing is accomplished through the discharge of energy from storage units into the MISO transmission system. That, in my view, is a generation function, not a transmission function,” he wrote in dissent.
Danly said the order flies in the face of FERC’s precedent of unbundling transmission services provided by generation facilities from transmission rates. He said it’s only natural that “similarly situated,” non-transmission-owning parties want a better explanation as to why they can’t own SATOAs.
“I am concerned that, once the door is opened, it can swing in only one direction, and we soon will be faced with proposals seeking to widen the opening ever further,” he said. “The further we expand the definition of transmission by including facilities that inject energy into the system, the more difficult it will be to prevent yet further expansion. And the commission will find it challenging to justify its actions in the face of the discrimination claims that inevitably will be raised by generators seeking the same full cost-of-service treatment afforded to transmission assets.”
Danly said generation assets, like storage, should be limited to providing ancillary services to preserve the bright line between transmission and generation. He said FERC should reverse its 2010 decision that allowed storage developer Western Grid to classify its resources as transmission for cost-based recovery in CAISO.
Development of new high-voltage transmission lines could provide myriad benefits for the U.S. electricity system, including improved reliability, greater sharing of resources across regions and a means for states to achieve environmental policy goals, FERC said in a recent report to Congress.
But such a transmission buildout also faces significant obstacles, given the patchwork of federal and state regulations developers must navigate to develop projects, including in existing rights of way.
The report is a product of the 2020 Further Consolidated Appropriations Act, which directed FERC to provide the appropriations committees of both houses of Congress with a study “outlining the barriers and opportunities” for high-voltage transmission in the U.S. Although the report was dated June, it was apparently sent to Congress last week.
While the report offers no concrete steps for policymakers to take, its findings offer a boon to renewable advocates, buttressing the case for building transmission to tap resources in remote areas with an argument favoring the accompanying reliability benefits.
“High-voltage transmission can improve the reliability and resilience of the transmission system by allowing utilities to share generating resources, enhance the stability of the existing transmission system, aid with restoration and recovery after an event, and improve frequency response and ancillary services throughout the existing system [while also] providing greater access to location-constrained resources in support of renewable resource goals,” the report says.
“Americans for a Clean Energy Grid is excited to see the strong endorsement of large-scale regional and interregional transmission,” said Rob Gramlich, the organization’s executive director and president of Grid Strategies. “The report begins an important national discussion about making much greater use of highway and rail corridors as a way around some of the well known barriers to transmission.”
Reliability and Resilience
FERC’s study defines “high-voltage” transmission as AC lines 345 kV or above and DC lines of at least 100 kV, including overhead and underground networks. It notes the land-use efficiency of transmitting power at higher voltages, which reduces line losses, ensuring that a greater volume of power generated will reach its destination.
“For example, one 765-kV line on a 200-foot-wide right of way can carry the same amount of power as 15 double-circuit 138-kV lines with a combined right-of-way width of 1,500 feet,” the report says.
The report addresses four key reliability and resilience benefits of high-voltage transmission:
Sharing of resources across regions by improving interregional power transfer capability. FERC points out that high-voltage transmission can allow a region to access additional generation when local resources become unavailable. The report notes that during the 2014 and 2019 polar vortex events, the East and Midwest experienced high generator unavailability in concert with demand spikes. During the 2019 event, imports served 9% of load, compared with 3% during the 2014 event. But FERC cautions that “the potential benefits provided by proposed and existing high-voltage transmission are not uniform and need to be studied and verified with detailed simulation modeling of the transmission grid prior to integrating any proposed high-voltage transmission solution.”
Aiding with restoration and recovery after an event. FERC said that during a wide-area blackout, system restoration can benefit from neighboring in-service transmission facilities to restore generation, lines and electrical service, especially in cases where local black start units become unavailable.
Improving frequency response. The report notes that HVDC lines between neighboring interconnections can provide frequency support in cases of a large loss of generation.
Enhancing the stability of the interconnection transmission system. Citing the operation of the Pacific DC Intertie linking the Pacific Northwest with Los Angeles, FERC notes that active modulation of the line has been used effectively to maintain system stability in the Western Interconnection “by dampening interarea modes of oscillation.”
The report also cites the recent CapX2050 study by 10 Midwestern utilities, which found that “retirements of dispatchable generation and the movement toward non-dispatchable wind and solar generation will change transmission congestion patterns and introduce more variability in power flows, thus requiring new solutions to mitigate congestion and ensure reliability.” (See CapX2050 Calls for More Tx, Dispatchability in Midwest.)
Opportunities, Obstacles
The “opportunities” section of the report points to trends that could fuel the development of new high-voltage transmission, including states’ renewable portfolio standards.
“These regulatory mandates and voluntary targets are contributing to the buildup of renewable energy resources (e.g., solar, wind, hydropower and geothermal) that are often located in remote areas far from population centers. Transmission developers have proposed numerous high-voltage transmission projects in the United States that could integrate renewable energy resources onto the grid and connect them to regions with high electricity demand,” the report says.
The report also points out that high-voltage transmission developers could benefit from the effort of states and localities to increasingly electrify transportation and building heating to reduce carbon emissions. It cites a 2019 Brattle Group study that finds “the U.S. will need an average investment of $3 billion to $7 billion per year through 2030, in addition to investments needed to maintain existing transmission systems and integrate renewable energy generation to meet existing load, to meet the changing needs of the system due to electrification.”
Another upshot of increased transmission buildout: improved competitiveness in wholesale markets through reduced congestion and the increased ability of low-cost resources to participate. To support the claim, FERC cited 2017 and 2019 reports from ISO-NE showing how new transmission could help New England integrate low-cost resources, decrease congestion and uplift costs, and reduce renewable energy curtailments.
The report delves into how transmission development could benefit from the existence of federal and state laws that support co-location of lines along transportation corridors, including highways, pipelines, railroads (both existing and retired) and canals.
“In some cases, the co-location of transmission in transportation corridors could reduce both the negative effects caused by a project and the cost of project development. Siting transmission in transportation corridors could minimize the creation of new rights of way on undisturbed lands, which could result in reduced effects on private landowners and environmental, cultural and visual resources,” the report says.
The report additionally points to FERC’s own efforts to encourage interregional transmission development, including issuing Order 1000 in 2011, which aimed to address deficiencies in the transmission planning and cost allocation requirements, including participation by nonincumbent developers in regional planning processes, interregional coordination, and methods to allocate the costs of new regional and interregional transmission facilities.
But FERC acknowledged that transmission development still faces significant barriers in the post-Order 1000 world, especially the number of new projects being developed outside the competitive processes envisioned in the order. Those include the continued ability of incumbent transmission owners to maintain a federal right of first refusal for local projects and upgrades, as well as the existence of threshold limits (such as costs and voltage levels) and other exceptions to Order 1000 requirements in regional planning processes.
“Some entities have suggested that incumbent transmission owner utilities may have a preference for developing projects outside of regional competitive transmission planning processes, which may obviate the need for longer-term solutions that might qualify for these processes,” the report says. “Others argue that the transmission development occurring post-Order No. 1000 is focused on reliability and local needs, with only a modest increase in regional projects to address market efficiency and public policy needs.”
The report also addresses barriers to development in co-location corridors. FERC points to the example of development along highways, where the Federal Highway Administration (FHWA) and state transportation agencies share joint authority. The state agencies develop the standards they will use to approve applications from utilities, which FHWA must review to ensure consistency with federal guidelines.
“Some states’ utility accommodation policies expressly prohibit transmission and other longitudinal utility facilities in highway rights of way. Others restrict the co-location of transmission in highway rights of way based on various factors (e.g., transmission voltage or specific highway features),” the report notes.
Siting of high-voltage transmission in other areas generally falls under state jurisdiction, requiring developers to negotiate multiple state processes, as well as those at the federal and local levels — and all this after navigating regional transmission planning procedures, FERC notes.
“The time required to develop a high-voltage transmission facility that meets mandatory reliability standards, maximizes system benefits and strikes a balance among interested stakeholders (including states) can be in excess of a decade,” the report says.
PJM stakeholders unanimously endorsed deadline changes for adjustments associated with finalizing the zonal network service peak load (NSPL) values in Manual 14D and Manual 27.
Ray Fernandez, PJM manager for market settlements development, reviewed updates to the generator operational requirements in Manual 14D and the Open Access Transmission Tariff Accounting section of Manual 27. The Manual 27 revisions were endorsed at Wednesday’s Market Implementation Committee meeting, while the related Manual 14D revisions were endorsed the following day at the Operating Committee meeting.
The revisions are related to the border yearly charge (BYC) — the charge for long- and short-term point-to-point transmission service for points of delivery at PJM’s border, which goes into effect on Jan. 1 of each year.
Fernandez said deadline dates in both manuals conflicted with the deadline dates of the BYC, including ones for the NSPL verification and zonal adjustments.
In Manual 14D, the behind-the-meter generation business rules had a Dec. 1 deadline for a load-serving entity to request a downward adjustment to its NSPL or obligation peak load. PJM proposed revising the deadline from Dec. 1 to Oct. 31.
Changes in Manual 27 included adding clauses to section 5.2 stipulating adjustments that need to be provided to PJM Market Settlements by Nov. 10. Any adjustments provided after the deadline will not be included in the NSPLs for the next calendar year and won’t be used in the BYC calculation.
The manual changes were originally up for endorsement at the July MIC meeting, but Fernandez said stakeholders raised objections with language contained in Manual 14D relating to BTM generation. Fernandez said PJM met with stakeholders to address the issue and were able to reach an agreement on compromise language.
ARR/FTR Market Task Force Poll
Members voted to put the ARR/FTR Market Task Force on hiatus until an independent consultant completes a review of PJM’s auction revenue rights and financial transmission rights market constructs.
Dave Anders, PJM director of stakeholder affairs, reviewed the results of the task force poll taken in July and discussed its recommendation to go on hiatus.
The nonbinding poll had 140 respondents, with 124 voting (89%) to put the group on hiatus until the consultant completes its work.
Anders said PJM is “in the final throes” of awarding the contract for the consultant and close to completing the final negotiation for the scope of work. He said stakeholders should expect an announcement “shortly” on the hiring.
Erik Heinle, of the D.C. Office of the People’s Counsel, asked Anders if stakeholders will have an opportunity to meet with the consultant as they’re working on the report or after it’s completed. Anders said plans are being finalized, but he expects there will be some interaction between the consultant and stakeholders.
Market Suspension Settlements
PJM is exploring the development of business rules to address a market suspension from an emergency or some other incident.
Tim Horger of PJM provided a first read of a problem statement and issue charge to develop business rules. The RTO is looking for approval of the issue charge at the September MIC meeting.
Horger said PJM has been contemplating scenarios of a market suspension with no day-ahead or real-time LMP results and realized that it had limited guidance on how to handle settlements during a suspension.
PJM has never experienced a market suspension event and doesn’t anticipate that it would occur, Horger said, but the RTO feels it needs to create business rules to apply to all possible scenarios.
The key work activities and scope for the issue include:
reviewing instances for which a market suspension may occur;
reviewing consequences to the market associated with a suspension;
reviewing PJM’s existing business rules, along with procedures of other RTOs/ISOs in the event of a suspension; and
reviewing options for how settlements can be determined in the event of a suspension.
Horger said work on the issue is estimated to take about three months and could start as early as October if the issue charge is approved next month.
Sharon Midgley of Exelon asked if the problem statement and issue charge only relate to the energy market or if it could also apply to all of PJM’s markets.
Horger said the “obvious” market seemed to be energy, but it could apply to all markets and would be determined in the key work activities.
Midgley said she thought the duration of the work needs to be considered because of the complexity of the issue. “I don’t think it’s going to get done in three months unless there’s already a solution in mind,” she said.
WEC Energy Group managed a 2-cent earnings per share improvement in the second quarter over last year, with several factors offsetting the COVID-19 pandemic’s economic consequences.
The Wisconsin utility recorded net income of $241.6 million ($0.76/share) compared to $235.7 million ($0.74/share) in the same period in 2019.
“Despite the negative margin impact in this year’s second quarter related to the pandemic, we were still able to achieve quarter-over-quarter earnings-per-share growth,” WEC CFO Xia Liu said during an Aug. 4 earnings call. She said “significantly warmer-than-normal weather,” an increase in the return on equity for WEC’s American Transmission Co. and execution of the utility’s five-year capital spending plan helped blunt the impacts of lower energy demand.
“We remain optimistic and confident in our ability to create value despite the challenges presented by the pandemic,” Executive Chairman Gale Klappa said.
WEC said it has about 11,000 more electric and 27,000 more natural gas customers compared to a year ago. The utility serves 4.5 million customers in Wisconsin, Illinois, Michigan and Minnesota. Compared to the second quarter of 2019, residential electricity sales were up 17.1%, small commercial industrial electric sales were down 8.6% and large commercial and industrial sales were down 12.9%.
WEC predicts continued economic recovery through the end of the year; however, COO Scott Lauber said the company has a plan in place if recovery proves more sluggish.
“We are prepared if the level of recovery would drop back to what we saw in the second quarter. We estimate that the additional impact to the pre-tax margin would be approximately $10 million to $15 million. We believe we could absorb this margin compression through efficiency measures already in place,” he said.
Lauber also said that the Wisconsin Public Service Commission’s April decision to allow utilities to track and defer uncollectible expenses and pandemic-related costs helps the company’s bottom line.
Tatanka Ridge wind farm | Acciona
Klappa said WEC’s $15 billion capital investment plan from 2020 through 2024 remains unchanged.
“We have ample liquidity and no need to issue new equity,” he told investors.
Klappa said WEC’s announcement late last month that it will pay $235 million to acquire an 85% ownership interest in the 155-MW Tatanka Ridge wind farm in South Dakota is part of the capital plan.
However, he reported that construction at the 300-MW Thunderhead Wind Farm in Nebraska hit a snag that will likely delay it “several months” beyond its 2020 year-end in service date. WEC will have a 90% stake in the project.
“We now project a several-month delay because the local utility has paused construction of a substation that’s needed to connect the Thunderhead project to the transmission network. We continue to work with all the relevant parties to minimize the delay,” Klappa said.
CEO Kevin Fletcher said WEC still has designs on more utility-scale solar generation. He said work continues on two solar projects totaling 200 MW for Wisconsin Public Service.
In addition, subsidiary We Energies will still invest — along with Madison Gas and Electric — in construction of the delayed $194.9 million Badger Hollow II solar farm, which is now expected to be in service by the end of 2022.
