Minnesota Public Power Utility Focuses On Bolstering Reliability

February 15, 2022

by Paul Ciampoli
APPA News Director
February 15, 2022

Minnesota public power utility Blue Earth Light & Water is pursuing a number of projects that will bolster its reliability.

In an interview with Public Power Current, Tim Stoner, General Manager of the Blue Earth, Minn., utility offered details on the projects.

One project involves a transformer upgrade. A second project is a reconductoring of a feeder, while the third project involves building out a looping project for two existing distribution transformers.

“The whole reason for all three of these projects” is for reliability purposes, Stoner noted.

Blue Earth Light & Water is a Diamond level Reliable Public Power Provider (RP3) as designated by the American Public Power Association (APPA). Diamond level is the highest level under the RP3 program.

APPA’s RP3 program is based on industry-recognized leading practices in four important disciplines: Reliability, safety, workforce Development and system Improvement.

Supply chain issues remain a concern for Stoner as it relates to the projects. “I don’t think we have a quote for a single transformer right now that’s under 52 weeks,” he said.

APPA and the Large Public Power Council recently provided comments including recommendations to the Department of Energy (DOE) in response to a request for information that DOE issued on energy sector supply chain issues.

Additional information about the utility is available here.

California Regulators Approve Plans For Reliability, Emissions Reductions

February 12, 2022

by Paul Ciampoli
APPA News Director
February 12, 2022

The California Public Utilities Commission (CPUC) recently approved plans that it said will ensure long-term sufficient electricity resource investments, including transmission, and the reduction of greenhouse gas (GHG) emissions.

The CPUC, per Senate Bill 350, developed an integrated resource planning (IRP) process to ensure that California’s electric sector meets its GHG reduction goals while maintaining reliability at the lowest possible costs.

The Feb. 10 decision adopts a 35 million metric ton (MMT) 2032 electric sector GHG planning target, which is more stringent than the 46 MMT GHG target that was adopted previously and equates to 73 percent renewables portfolio standard resources and 86 percent GHG-free resources by 2032.

The decision adopts a portfolio of cost-effective preferred resources that includes approximately 25,500 megawatts (MW) of new supply-side renewables and 15,000 MW of new storage and demand response resources by 2032.

This preferred system plan portfolio differs from the one previously adopted in that it includes more solar and battery storage, as well as new long-duration storage, out-of-state wind, and offshore wind resources. The inclusion of offshore and out-of-state wind resources demonstrates their increased viability as cost-effective resources to help meet state goals, it said.

The CPUC said its modeling and independent analysis conducted by the California Energy Commission demonstrates that the portfolio meets stringent reliability standards.

The CPUC’s preliminary analysis of the preferred system plan portfolio of the load serving entities (LSEs) indicates there is sufficient space for all of these new resources on the existing transmission system, with only limited transmission upgrades needed by 2032.

This finding will be validated at a more granular level by the California Independent System Operator (CAISO) in its 2022-2023 transmission planning process, which is an evaluation of the CAISO transmission grid to identify grid upgrades needed to address reliability, meet state policy goals, and provide economic benefits.

LSEs that submitted filings were investor-owned utility, community choice aggregators, electric service providers and electric cooperatives.

The CPUC decision also orders utility procurement of two battery storage projects that were identified by the CAISO as alternatives to transmission upgrades in the previous transmission planning process cycle.

IRP is a multi-year process. The first half of this IRP cycle analyzed and adopted an optimal portfolio of electricity resources as a guide for LSEs to use for meeting their GHG, reliability, and cost objectives.

The second half of the IRP cycle, which is the subject of the Feb. 10 decision, is designed to consider the portfolios and actions that each LSE proposes for meeting these goals, to allow the CPUC to review each LSE plan and aggregate LSE portfolios to develop a preferred system plan portfolio, and to consider whether further action by the LSEs is needed to meet state goals.

The Preferred System Plan adopted on Feb. 10 completes the second half of the 2019-21 IRP cycle. 

For the upcoming cycle of IRP, the CPUC will again focus on analysis of the individual LSE plans to be filed in November 2022, which will include plans to procure the 11,500 MW of capacity required for mid-term reliability in the CPUC’s June 2021 decision.

The proposal voted on is available here.

NERC Report Sees Potential Reliability Issues Tied To Weather, Renewables

January 2, 2022

by Peter Maloney
APPA News
January 2, 2022

Reserve margins could fall below recommended levels sooner than previously expected, the North American Electric Reliability Corp. (NERC) reported in its 2021 Long-Term Reliability Assessment (LTRA).

In the Midcontinent Independent System Operator (MISO) region, anticipated reserves fall below the Reference Margin Level (RML) beginning in 2024 instead of 2025 as previously estimated. MISO could be facing the retirement of over 13 gigawatts (GW) between 2021 and 2024 based on its annual survey of members.

The potential retirements include 10.5 GW of coal-fired capacity and 2.4 GW of natural gas-fired capacity. Those projected retirements are not confirmed, NERC noted, but if they were to take place without new generation beyond the 8 GW already in development coming online MISO could be short over 560 megawatts (MW) in 2024, NERC said.

The NERC report also singled out California, specifically the California-Mexico (CA/MX) part of the Western Electricity Coordinating Council (WECC) where the planned retirement of the 2,200-MW Diablo Canyon nuclear plant in 2024 and 2025 could contribute to a capacity shortfall beginning in 2026.

“However, energy risks are present today as electricity resources are insufficient to manage the risk of load loss when wide-area heat events occur,” the NERC report warned. The risk is most acute in late afternoon when solar photovoltaic resource output diminishes, creating a sharp rise in demand. Analysis shows up to 10 hours of potential in-day load loss beginning in 2022 and as much as 75,000 megawatt hours (MWh) of unserved energy in extreme conditions in 2024, NERC said.

Furthermore, the amount of flexible generation sources needed to meet demand have fallen in California, as well as in Texas and the Northwest to the point that projected peak demand cannot be met without some combination of weather-dependent wind and solar generation along with external imports.

“Changes in climate that drive extreme weather conditions raise the likelihood for one or more of these resources to fall short of forecasts, leaving other resources to make up the gap, or load will need to be shed,” NERC said.

The increasing amounts of variable generating resources in the Northwest and Southwest are raising the risk of energy shortfalls, according to the LTRA. There were 23 load-loss hours in the Northwest in 2022, and the Southwest faces potential load-loss hours beginning in 2024, NERC said.

“As resource planners in parts of the Western Interconnection turn increasingly to external transfers for sufficient capacity and energy to meet demand, the need for regional coordination and resource adequacy planning is growing,” NERC said.

The LTRA also identified the vulnerabilities created by the shortcoming of natural gas delivery infrastructure. Many generators in New England, California, and the Southwest rely on gas, making them vulnerable to gas supply disruptions that could affect winter reliability, NERC said.

Extreme cold weather in areas not accustomed to it, such as parts of MISO, the Southwest Power Pool (SPP) and Texas, also presents “significant” risks to winter reliability until new winterization requirements highlighted in NERC’s February 2021 Cold Weather Outages Report are in effect, NERC said.

The threat of extreme cold weather is exacerbated by the “increasing volatility and uncertainty” of electricity demand that makes “accurate load forecasting a challenge,” NERC said.

“Extreme weather is a core condition to consider in resource planning,” NERC said, advocating for a “comprehensive resource planning construct” that focuses attention on “energy sufficiency with the understanding that capacity alone does not provide for reliability unless the fuel behind it is assured even in extreme weather.”

Variable energy resources, meanwhile, continue to grow, NERC said, noting that since its 2020 LTRA, the capacity of solar projects in all stages of development has increased from 390 GW to 504 GW for the next 10 years and wind power capacity is projected to total 360 GW over the next 10 years, up from 250 GW since the 2020 LTRA projection. Battery energy storage installations have also grown with 113 GW in development through 2024, a sharp rise from the 47 GW reported in the 2020 LTRA.

Solar photovoltaic distributed energy resources (DER) also continue to grow and are expected to reach 60 GW over the next 10 years, with some regions doubling their solar DER footprint by 2031, NERC said.

The growth of DERs underscores the need for generation operators to have “flexibleresources, including adequate dispatchable, fuel-assured, and weatherized generation, at their disposal,” NERC said.

Until storage technology is fully developed and deployed at scale, which NERC sees as beyond the 10-year scope of the 2021 LTRA, gas-fired generation will remain a necessary balancing resource to provide increasing flexibility needs, NERC said.

With increasing reliance on gas-fired generation will come the need to “deeply understand natural gas and electric system interdependencies,” and to improve the coordination between natural gas and electricity.

The natural gas system was not built or operated with electric reliability as the first concern,” NERC asserted.  The lack of coordination between the two industries was a “major contributor to the devastation” in the Electric Reliability Council of Texas (ERCOT) during winter storm Uri in 2021, NERC said. “

The “regulatory structure and oversight of natural gas supply for electric generation needs to be rethought to assure reliable fuel supply for electric generation to support the reliable operation” of the bulk power system, NERC said.

NERC also recommended that further work is necessary to improve the modeling needed to reliably integrate interconnecting inverter-based resources (IBRs), such as wind and solar power and batteries, into the bulk power system.

Industry planners also should update interconnection agreements to address the performance specifications for IBRs, NERC said, adding that the Federal Energy Regulatory Commission should update its pro forma interconnection agreement for large and small generators to include IBR performance specifications.

Texas Utility Regulators Adopt Rule For Coordination Between Gas And Electric Industries

December 7, 2021

by APPA News
December 7, 2021

The Public Utility Commission of Texas (PUC) recently adopted a rule related to critical natural gas facilities that supply fuel to electric generators.

This joint effort with the Railroad Commission of Texas (RRC) will increase the coordination between the electric and gas industries during energy emergencies.

Based on legislation from the Texas Legislature, the new PUC rule creates a new designation for critical natural gas facilities that supply the majority of natural gas in Texas.

The rule also requires a critical natural gas facility to provide information to the utility from which it receives electric delivery service.

The electric utility must use this information to prioritize natural gas in energy emergencies. The PUC rule and corresponding RRC rule will be in effect this winter.

The rule adoption complements work being done to map the supply chain between the natural gas and electric industries, the PUC said.

Natural gas facilities have already registered critical status with their electric delivery utility in much greater numbers than last winter, it noted. “Now electric utilities can plan and respond much more accurately to keep natural gas facilities energized during an emergency,” the PUC said.

In February 2021, the Electric Reliability Council of Texas entered emergency conditions and initiated rotating outages in the state in the wake of an arctic blast.

Texas public power utilities took a number of actions to help protect customers financially in the wake of the arctic blast.

The American Public Power Association in November 2021 applauded the joint efforts of the Federal Energy Regulatory Commission, the North American Electric Reliability Corporation (NERC), and NERC’s Regional Entities to analyze the February 2021 cold weather event in Texas and the South-Central U.S. 

NERC Winter Report Says Extreme Cold Weather Could Cause Reliability Shortfalls

November 29, 2021

by APPA News
November 29, 2021

Certain regions of the country, particularly those vulnerable to extreme weather, natural gas supply disruptions and low hydro conditions, are at risk for electricity supply disruptions this winter, according to the North American Electric Reliability Corp. (NERC).

In its 2021–2022 Winter Reliability Assessment, NERC advises the industry to prepare by taking steps for generator readiness, fuel availability and sustained operations in extreme conditions.

Although anticipated reserve margins meet or surpass the NERC’s margin levels in all areas, the organization warned that “extreme or prolonged cold temperatures over a large area could create “unique challenges in maintaining grid reliability in many parts of North America.”

Responses NERC solicited from grid stakeholders indicate that they have taken preparations to enhance reliability during cold weather events, but “some plant vulnerabilities can be anticipated for the upcoming winter.”

To reduce the risk of shortfalls, NERC is recommending:

• Grid operators and generator operators review NERC’s Level 2 cold weather alert and take the recommended steps prior to winter;
• Grid operators should prepare their operating plans to manage potential supply shortfalls and take steps for generator readiness, fuel availability, and sustained operations in extreme conditions. And balancing authorities should poll their generating units in advance of approaching severe weather to assess their readiness for normal and extreme conditions;
• Balancing authorities and reliability coordinators should conduct drills on alert protocols, and balancing authorities and generator operators should verify protocols and operator training for communications and dispatch;
• Distribution providers and load-serving entities should review non-firm customer inventories and rolling black out procedures to ensure that no critical infrastructure loads such as natural gas or telecommunications would be affected and rehearse protocols that prepare customers for the impacts of severe weather.

“To be resilient in extreme weather, we are counting on our grid operators to proactively monitor the generation fleet, adjust operating plans and keep the lines of communication open,” Mark Olson, manager of reliability assessments at NERC, said in a statement.

NERC referenced last February’s cold weather that caused outages in Texas and other states, and said that peak demand or generator outages that exceed forecasts, such as have occurred in previous winters, “can be expected to cause energy emergencies” in the Midcontinent Independent System Operator (MISO), Southwest Power Pool (SPP), and Electric Reliability Council of Texas (ERCOT) regions.

While both New England and the Southwest have sufficient planning reserves, NERC warned that fuel supplies to generators in those areas can be vulnerable during cold weather conditions.  NERC also highlighted New England and California for their vulnerability to weather related natural gas supply disruptions. Specifically, Southern California and the Southwest have limited natural gas storage and lack redundancy in supply infrastructure, so generators there also could face fuel supply curtailment or disruption from extreme winter weather.

In New England, the capacity of natural gas transportation infrastructure can be constrained when cold temperatures cause peak demand for both electricity generation and consumer space heating needs, exacerbating the risks for fuel-based generator outages and reductions, NERC noted.

In the Pacific Northwest, resources are sufficient but higher demand from extreme temperatures could cause shortfalls, particularly if the region’s drought continues and causes low hydro conditions, reducing electricity supply for transfer throughout the area, NERC warned.

APPA Applauds FERC, NERC Efforts To Analyze Winter Cold Weather Event

November 17, 2021

by Paul Ciampoli
APPA News Director
November 17, 2021

The American Public Power Association (APPA) recently applauded the joint efforts of the Federal Energy Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC), and NERC’s Regional Entities to analyze the February 2021 cold weather event in Texas and the South-Central U.S. 

“The event put grid reliability for millions of Americans at risk and left many utilities and their customers facing billions of dollars of additional costs they will be repaying for years to come,” wrote Joy Ditto, President and CEO of APPA, in a letter to FERC Chairman Richard Glick and NERC President and CEO James Robb.

The detailed analysis by FERC and NERC staff in their final report issued on Nov. 16 “provides invaluable information about what went wrong — and what went right — as electric utilities in the affected regions worked to keep the lights on in face of significant challenges during the event,” she said in the letter.

“We have been working with our members to prevent a recurrence of the circumstances that arose during the event, including through legislative and regulatory approaches. One key to responding, however, has been a definitive investigation of the core causes of the event. The report will be a critical resource in this effort.”

Ditto said that APPA looks forward to working with FERC, NERC, and other energy stakeholders to use the report “and our own findings to ensure that similar events never recur.”

In September 2021, staff from FERC and NERC provided a report that included preliminary findings and recommendations related to the February 2021 cold weather event that impacted the Electric Reliability Council of Texas (ERCOT), Southwest Power Pool (SPP), Midcontinent Independent System Operator (MISO), and other regions.

LIPA And PSEG Long Island Reach Agreement On New Reformed Contract

November 10, 2021

by Paul Ciampoli
APPA News Director
November 10, 2021

The Long Island Power Authority (LIPA) on Nov. 9 announced a revised management services contract and settlement with PSEG Long Island that LIPA said includes reforms designed to drive performance and accountability, while providing an unprecedented level of oversight of PSEG Long Island’s operations.

The new contract, which meets all of the terms tentatively agreed to by the parties in June, “will support customers on Long Island and the Rockaways in receiving top-tier performance, reliability, and customer service,” LIPA said.

“Today’s announcement includes all of the reforms LIPA demanded after Tropical Storm Isaias to increase oversight and accountability and put our customers’ interests at the forefront of PSEG Long Island’s operations. This contract is the strongest in LIPA’s history and represents a real win for LIPA’s customers,” said LIPA CEO Tom Falcone.

The new reformed contract includes the following elements:

Top-tier Performance for Customers

• The majority of PSEG Long Island compensation is now at risk: The reformed management contract increases the amount of PSEG Long Island’s annual compensation at risk from $10 million to $40 million, including automatic reductions for failures to meet minimum emergency response, customer satisfaction, and reliability standards, and a new New York Department of Public Service (DPS) investigative process for failures to provide safe, adequate, and reliable service to customers;
• Strengthened Long Island-based management team: The President and Chief Operating Officer of PSEG Long Island will have full and final operational decision-making authority and the local executive team will be strengthened with new positions in information technology, cybersecurity, emergency response, business services, and human resources. To avoid the lack of accountability for local operations that was evident in the company’s response to Tropical Storm Isaias, all Long Island employees will report to managers on Long Island. Additionally, the compensation for all PSEG Long Island employees will be linked to the performance of Long Island operations;
• Rigorous annual performance goals: PSEG Long Island will be subject to detailed performance requirements set annually by the LIPA Board and DPS, to ensure the company meets industry best practices across all the services provided to LIPA and its customers; and
• Strengthened long-term planning, budget development, and cost management: New standards require greater long-term planning, transparency, and accountability for delivering projects and services on time and within budget that meet the needs and deliver value for customers.  

 Unprecedented Oversight Protections for LIPA and DPS 

• New requirements for independent verification and validation of information technology systems: The reformed contract provides new rights to LIPA to independently test and validate the performance of mission-critical information technology systems, such as those that failed during Tropical Storm Isaias. The agreement also requires PSEG Long Island to separate information technology platforms from New Jersey-based systems to ensure better accountability and oversight;  
• Requires timely and accurate disclosure of significant operational issues: The reformed contract requires timely, affirmative disclosure to LIPA and DPS of issues, such as those that occurred before and during Tropical Storm Isaias, that significantly impair PSEG Long Island’s ability to provide reliable service, emergency response, cybersecurity, financial impairment, noncompliance with laws, or circumstances that may endanger public health, safety, and welfare;
• New requirements to fix known operational issues in a time-sensitive manner: The reformed contract requires PSEG Long Island to implement plans to fix known operational issues identified by LIPA management or the DPS, with oversight by the LIPA Board of Trustees;
• Transparency around decisions to hire PSEG Long Island affiliates to provide services to LIPA: New provisions ensure that PSEG Long Island’s decisions to hire affiliates to perform services at customer expense will deliver better quality and lower costs than competing vendors. 

PSEG Long Island Forfeits $30 Million for Tropical Storm Isaias Failures

The settlement also resolves pending litigation related to PSEG Long Island’s management failures during Tropical Storm Isaias and includes $30 million in payments and credits towards the cost of upgrading the information technology and communication systems, reimbursements to customers for food and medicine spoilage, and contributions to Long Island-based charities. 

The LIPA Board of Trustees will accept virtual public comments on the revised contract and settlement at LIPA’s November 17 and December 15 Board meetings. LIPA has scheduled an additional public comment session for the evening of December 2. 

The LIPA Board is expected to consider the contract and settlement at LIPA’s December 15, 2021 Board meeting.

If approved, the reformed contract will subject to review and approval by the New York State Attorney General and Comptroller prior to the terms taking effect.

Groups Support NERC Proposed Revisions Submitted To FERC

November 8, 2021

by Paul Ciampoli
APPA News Director
November 8, 2021

The American Public Power Association (APPA), the Large Public Power Council (LPPC) and the Transmission Access Policy Study Group (TAPS) said in joint comments submitted to the Federal Energy Regulatory Commission (FERC) that several of the changes resulting from proposed rules of procedure (ROP) revisions would appropriately implement the North American Electric Reliability Corporation’s (NERC) risk-based Compliance Monitoring and Enforcement Program (CMEP).

The groups urged FERC to approve the proposed changes.

At issue are ROP revisions filed by NERC and its six regional entities. As NERC explains in its filing, the proposed revisions to the ROP are designed to enhance NERC’s risk-based approach to monitoring and enforcing compliance with the NERC reliability standards and to enhance the ROP to add clarity and simplify unduly burdensome administrative business practices.

APPA, LPPC and TAPS noted that they have long supported a risk-based approach to NERC’s compliance monitoring and enforcement program, and said the proposed revisions to the ROP are appropriately aimed at reducing unnecessary burdens on NERC and registered entities while enhancing the effectiveness of the risk-based compliance monitoring and enforcement program approach.

The ROP revisions included in the September 29, 2021 filing were informed by substantial industry input.

APPA, LPPC and TAPS submitted detailed comments on NERC’s initial draft ROP changes, expressing general support for improved risk-based compliance, while providing a number of proposed changes, clarifications, and questions.

“The Public Power Trade Associations appreciate NERC’s consideration of these comments, and the alterations made to the proposed ROP in response. While not incorporating every comment in full, NERC responded meaningfully to the issues raised by the Public Power Trade Associations,” APPA, LPPC and TAPS said.

Such collaboration ultimately enhances the compliance monitoring and enforcement program by minimizing disputes over the CMEP’s rules, and by fostering confidence that industry perspectives on risk-based compliance are being heard, the groups said.

They highlighted the change reflected in a revised ROP section that would grant the relevant Compliance Enforcement Authority discretion as to when to conduct compliance audits rather than requiring an audit every three years, regardless of reliability or security justification.

APPA, LPPC and TAPS endorsed this change as advancing the risk-based approach to the compliance monitoring and enforcement program “and we urge the Commission to accept NERC’s proposed ROP revisions on this issue.”

They also endorsed NERC’s proposed changes to the evidence retention period for compliance audits.

Consistent with the recommendations of NERC’s recently concluded Standards Efficiency Review initiative these revisions would ensure adequate evidence to support compliance reviews, while reducing registered entities’ administrative burden and costs, the groups said. The proposed evidence retention change, as well as the other ROP revisions included in the September 29 filing, should be approved, they added.

AMP Transmission Breaks Ground For Construction Of New Substation

October 20, 2021

by Paul Ciampoli
APPA News Director
October 20, 2021

AMP Transmission (AMPT) recently broke ground for the construction of its new Bellard Substation. 

The 138/69 kilovolt (kV) substation will provide a fourth source for the City of Bowling Green, Ohio, an AMP member, and is AMPT’s first greenfield substation. Construction is scheduled for May 2022 completion.

AMPT was formed by the AMP Board in 2018 to provide cost-effective transmission, related services, and a competitive alternative for the benefit of AMP members to enhance reliability and ensure comparable service. 

AMPT is a transmission owner in the PJM Interconnection and has a Federal Energy Regulatory Commission-approved formula rate applicable to the entire PJM footprint. AMPT is currently active in the American Electric Power and American Transmission Systems Inc. transmission zones. 

AMPT owns one 138 kV station, one 138/69 kV substation, six 69 kV stations, and 21.4 miles of 69 kV transmission line. AMPT has completed two relay upgrades and is in the process of acquiring right of way for 0.3 miles of 138-kV transmission line.

“Breaking ground at Bellard is a major milestone for AMPT,” said Pamala Sullivan, AMPT’s President.  “This is our first new construction project, and will bring great benefits to AMP’s member, the City of Bowling Green.”

“It’s exciting to now be in the construction phase,” said Kim Magovac, Director of Transmission Project Management.  “Watching a project come to fruition validates the hard work contributed by the entire team; a true testament to the collaborative process.” 

Utilities Can Be Recognized For Proper Tree Care Standards

October 7, 2021

by Paul Ciampoli
APPA News Director
October 7, 2021

The Arbor Day Foundation has opened applications for utilities to be recognized for their commitment to safe and reliable electric service by demonstrating best practices in public and private utility arboriculture.

Last year, almost 150 utilities across the U.S. attained the foundation’s Tree Line USA status.

The foundation, which is based in Nebraska, said that Tree Line USA utilities benefit from lower line clearance costs from proper pruning, lower peak energy demand and more public exposure by meeting Tree Line USA requirements.

To receive Tree Line USA recognition, eligible utilities must meet the following core standards:

• Perform quality tree care
• Report annual worker training
• Conduct yearly tree planting and public education opportunities
• Have a tree-based energy conservation program
• Hold an Arbor Day celebration

Recognized utilities will receive a plaque, emblem, decals and other promotional materials to increase public exposure of their Tree Line USA recognition.

For more information about the Tree City USA program or to apply, visit www.arborday.org/TreeLineUSA.

Applications are available through the end of the year depending on the state.