Senate Committee Advances Nomination of Phillips To Be FERC Commissioner

November 3, 2021

by Paul Ciampoli
APPA News Director
November 3, 2021

The Senate Energy and Natural Resources Committee on Nov. 2 voted to advance the nomination of Willie Phillips, Jr. to be a member of the Federal Energy Regulatory Commission (FERC).

Phillips, a Democrat, is currently Chairman of the Public Service Commission (PSC) of the District of Columbia.

Phillips’ nomination will require confirmation by the Senate and, if confirmed, Phillips would return FERC to its full complement of five commissioners after the departure of Commissioner Neil Chatterjee on August 30, 2021. 

He would also give Democrats a 3-2 majority on the Commission. 

The committee approved moving the nomination of Phillips to the Senate floor by voice vote.

The Energy Authority, Northwest Public Power Utilities In Strategic Partnership

November 2, 2021

by Paul Ciampoli
APPA News Director
and Peter Maloney
APPA News
November 2, 2021

The Energy Authority (TEA) recently announced its participation in the next phase of the Northwest Power Pool Western Resource Adequacy Program (WRAP) in partnership with seven public power utilities.

TEA will join the WRAP as the load responsible entity, pooling the loads and resources of the seven PUDs, which are Benton PUD, Clark Public Utilities, Cowlitz PUD, Emerald People’s Utility District, Franklin PUD, Grays Harbor PUD, and Lewis County PUD. All of the PUDs are based in Washington State, with the exception of Oregon-based Emerald.

The aggregated group of utilities represents over 440,000 retail electricity customers with a combined average peak load of over 2,700 MW. TEA said its public power ownership and existing relationships make this a logical extension of the portfolio management and scheduling services that TEA already provides.

The PUDs “are seeking to continue their proven track record of providing cost-effective and reliable services to customers in the face of new complexities and an ever-changing industry. Standing up a resource adequacy program is a critical next step as the region undergoes transformative changes in the coming years,” TEA said.

Established in 1997, TEA is headquartered in Jacksonville, Florida. TEA’s West Region Office, located in Bellevue, Washington, provides a full range of power and portfolio management services for public power utilities located in the Bonneville Power Administration balancing area as well as in the state of California.

NWPP Completes Design Phase of Western Resource Adequacy Program

NWPP began planning the WRAP to prepare for the scheduled decommissioning coal plants in the region and increasing renewable integration. The program includes a comprehensive review of resource adequacy in NWPP’s territory.

NWPP is now gearing up to implement the first stage of WRAP in which participants will commit to meeting a common resource adequacy planning standard. Agreements in the first stage of the program will be non-binding, meaning there will be no penalties if participants do not meet their adequacy obligations.

The first stage also will not include the operational component of the program that would allow participants to pool and share resources during times when grid operating conditions are constrained.

Later stages of the program will layer on additional requirements and functions and evaluate further design changes that may be needed. The full program is expected to be in operation in 2024.

“We have reached a major milestone in our effort to stand up a resource adequacy program in the West,” Frank Afranji, president of NWPP, said in a statement. “A common resource adequacy planning standard will increase coordination and visibility with respect to adequacy in the region and is a positive step toward enhancing regional reliability.”

The next phase of the WRAP project will include evolving the NWPP’s corporate structure to house an independent board so NWPP can serve as the administrator of the program and filing with the Federal Energy Regulatory Commission (FERC).

NWPP said it would continue to work with Southwest Power Pool (SPP) to develop and implement the WRAP project. NWPP has hired SPP as the operator of the WRAP project. The scope of SPP’s services as a program operator include performing forward showing functions, modeling and system analytics, real-time operational program development, continual technical improvement, and IT systems work.

The next phase of the WRAP project also includes new participants Black Hills Power and Clatskanie Public Utility District.

In total, there are 20 participants in WRAP, representing approximately 57,300 megawatts of load and spanning nine states and one Canadian province committed to the program’s next phase. NWPP said it expects additional participants to join the program in the coming weeks.

NWPP released a report in August that detailed the design of the WRAP project.

Salt River Project Issues All-Source RFP For New Power Generation Resources

October 29, 2021

by Paul Ciampoli
APPA News Director
October 29, 2021

Arizona public power utility Salt River Project (SRP) has issued a request for proposals (RFP) for additional power generation resources of all types to meet summer peak capacity needs. 

SRP on Oct. 29 said that it continues to experience significant increases in customer electricity demand as Phoenix and Maricopa County lead the nation in population growth and economic development. 

SRP is seeking competitive proposals for up to 400 megawatts (MW) of peak generating capacity by summer 2024, and another 600 MW by summer 2026, for a total up to 1,000 MW by summer of 2026. 

Resources selected through this all-source RFP process will also support SRP’s 2035 Sustainability Goals and SRP’s goal to add 2,025MW of new utility-scale solar by 2025. 

The requested generation is needed in addition to SRP’s recently announced contracts for new renewable resources and plans to expand its Coolidge Generating Station.  

SRP said it will consider all technologies and currently serves customer energy needs from generation produced with a diverse fuel mix including nuclear, coal, hydroelectric, natural gas, battery storage and renewable resources including solar, wind, biomass, and geothermal. 

This summer SRP announced agreements for four new utility-scale solar plants, as well as the commissioning of Arizona’s largest standalone battery storage system which began operating on SRP’s system this September. 

Respondents to the all-source RFP can view the details and register here: srp.net/all-source-rfp. Registration enables access to all RFP-related documents.

SRP is seeking bid proposals by Jan. 11, 2022 and anticipates short list selection in April 2022. 

FERC Rejects Bid To Require TVA To Provide Open Access Transmission Service

October 25, 2021

by Paul Ciampoli
APPA News Director
October 25, 2021

The Federal Energy Regulatory Commission (FERC) on Oct. 21 denied a request by local power companies (LPCs) that the Commission require the Tennessee Valley Authority (TVA) to provide open access transmission service to the LPCs pursuant to section 211A of the Federal Power Act (FPA).

In January 2021, Tennessee-based Athens Utilities Board, Gibson Electric Membership Corporation, Joe Wheeler Electric Membership Corporation and Volunteer Energy Cooperative filed a request seeking a Commission order requiring TVA to provide transmission service under section 211A of the FPA and interconnection service under section 210 of the FPA (Docket Nos. EL21-40-000, TX21-1-000).

In late August 2021, Joe Wheeler Electric Membership Corporation filed a notice seeking to withdraw its participation in the petition and indicating that it had reached an agreement on a new power supply arrangement with TVA. It is therefore no longer a petitioner in the proceeding.

The LPCs currently purchase their full power supply and delivery requirements from TVA under bundled full requirements power supply contracts.

They said in their petition that they were seeking unbundled transmission service from TVA, which they said is the only transmission provider that can feasibly serve them, in accordance with the Commission’s longstanding open access principles.

In response, TVA argued that that the Commission lacks statutory authority under section 211A of the FPA to grant the request of the LPCs. TVA said that while section 211A authorizes the Commission to require government-owned utilities to provide the type of service the LPCs sought, TVA asserted that FERC’s authority to require TVA to provide transmission service under section 211A is limited by another provision of the FPA – section 212(j).

TVA further argued that section 211A gives the Commission discretionary authority to oversee the rates and non-rate terms and conditions for transmission service that is already being provided, but not to order new wheeling service.

TVA also said that the interpretation of section 211A by the LPCs would destroy TVA’s ability to meet its broad statutory mandate to support the physical, economic, and social welfare of the TVA region and balance its varied missions to achieve that mandate.

Moreover, TVA argued that the Commission’s exercise of its authority under section 211A is discretionary, extremely rare, and must advance the public interest. TVA therefore asserted that there is no basis for exercising any such authority in the LPC proceeding.

In considering the public interest, TVA asserted that, due to a statutory “Fence,” stranded costs resulting from the loss of LPC load could not be mitigated and would shift to remaining LPCs.

The TVA Fence refers to the non-physical boundary that the U.S. Congress placed around TVA’s service territory in 1959.

FERC Order

In an order approved at its Oct. 21 open meeting, FERC noted that Section 211A of the FPA provides that “the Commission may, by rule or order, require an unregulated transmitting utility to provide transmission services.” Thus, FERC’s authority under section 211A is discretionary.

“In this case, we decline to issue a rule or order requiring TVA to offer unbundled transmission service to petitioners or to outside power suppliers to serve load within the TVA Fence under section 211A, and thus we deny the petition,” FERC said.

FERC clarified that, contrary to claims that unregulated transmitting utilities must “abide by” section 211A, there are no established requirements under section 211A that an unregulated transmitting utility must meet, so there can be no “violation” of section 211A by an unregulated transmitting utility.

The Commission’s jurisdiction under section 211A(b)(1) is not invoked automatically upon action by an unregulated transmitting utility, it said.

Rather the Commission “has the discretion to choose to exercise, or as relevant here to instead choose to not exercise, this authority.”

FERC Chairman Richard Glick issued a separate statement concurring in the decision, as did Commissioners Mark Christie and James Danly.  Commissioner Allison Clements dissented from the order.

FERC Commissioners Weigh In On Southeast Energy Exchange Market Vote

October 25, 2021

by Paul Ciampoli
APPA News Director
October 25, 2021

Commissioners at the Federal Energy Regulatory Commission (FERC) recently weighed in with their views on a proposed agreement for a Southeast automated, intra-hour energy exchange. The agreement recently took effect as a result of a deadlock on the Commission.

In an Oct. 13 notice, FERC noted that pursuant to section 205 of the Federal Power Act (FPA), in the absence of Commission action on or before Oct. 11, 2021, the proposed Southeast Energy Exchange Market (SEEM) agreement became effective by operation of law.

The Commission did not act on the proposed SEEM agreement “and concurrences thereto because the Commissioners are divided two against two as to the lawfulness of the change,” the notice said.   Under a provision added to the FPA in 2018, each Commissioner must provide a statement explaining the Commissioner’s views on any filing that goes into effect as a result of such a deadlock. 

Chairman Glick

“Expanding regional electricity markets is one of the single most important steps that the Commission can take to save customers money, enhance reliability, and integrate intermittent resources most efficiently,” said FERC Chairman Richard Glick. He believes regional transmission organizations (RTOs) and independent system operators (ISOs) “are, by far, the best way to achieve these benefits.”

“From my perspective, utilities and other stakeholders in this region should be working to establish an RTO/ISO in the Southeast for the benefit of consumers and to promote grid reliability.  But that is not the proposal presented to us in this docket,” he said in an Oct. 20 statement.

Glick said he believes that much of the SEEM proposal arguably satisfies the standard for FERC approval under Section 205 of the FPA.  “However, I voted no in large part because the filing parties’ proposal to apply the Mobile-Sierra public interest presumption to the Southeast EEM Agreement violates well-established Commission precedent.  When Mobile-Sierra applies, the Commission must presume that the relevant agreement meets the statutory just-and-reasonable standard, so the agreement can only be changed if it seriously harms the ‘public interest,’ a significantly higher evidentiary hurdle,” he wrote.

“Considering the history of entrenched resistance to organized markets in the Southeast, the Southeast EEM represents at least a positive step forward,” Glick said. “Currently, several large incumbent utilities serve most of the consumers in the Southeast as bundled retail customers. Delivering power across multiple balancing authority areas in the region requires multiple transmission reservations and payment of pancaked transmission rates. A centralized and competitive wholesale market in the Southeast, or at least something closer to that model, is a step in the right direction.” 

 But finding a proposal just and reasonable and not unduly discriminatory or preferential under Section 205 of the FPA requires that it be more than just a step in the right direction, he said.  The filing parties initially proposed to apply Mobile-Sierra to the entire SEEM agreement and later narrowed that to a smaller subset of “enumerated provisions.” 

“I cannot support this part of the proposal because I believe that application of the Mobile-Sierra presumption here violates Commission precedent. Under that well-settled precedent, the Mobile-Sierra presumption applies to a contract ‘only if the contract has certain characteristics that justify the presumption,’” Glick said.

He argued that the SEEM agreement fails this test. Applying the Mobile-Sierra public interest presumption to at least the enumerated provisions of the SEEM agreement departs from FERC’s precedent without justification, he said. 

“We must always tread cautiously when determining whether a presumption that an agreement satisfies the statutory ‘just and reasonable’ standard is applicable,” wrote Glick. 

Had the Commission been able to reach agreement on the Mobile-Sierra issue, “I believe that our existing statutory protections against undue discrimination would have been sufficient to address protestors’ concerns about the Southeast EEM and to protect consumers and market participants in the region.  Applying the Mobile-Sierra presumption in these circumstances will make it more difficult for third parties or even the Commission to mount legitimate challenges in the future to the justness and reasonableness of the Southeast EEM.  Put simply, there is no need (and no basis) to apply the Mobile-Sierra presumption here — and there is considerable risk to the public in doing so.” 

Aside from his disagreement on the Mobile-Sierra issue, Glick was willing to support the SEEM proposal, as modified by the filing parties’ June 7 and August 11 responses to Commission deficiency letters, because he believes the modified proposal otherwise meets the “just and reasonable” standard of section 205 of the FPA.

Glick said the stated benefits of this platform, “though unverified, appear to be meaningful: The filing parties project over $100 million per year in market-wide savings by 2037 assuming higher renewable and energy storage penetration across the region, or $40 million per year relative to the current bilateral market under a more conservative estimate.”   

For customers to realize such benefits, however, “market outcomes must be the product of genuine competition, not market manipulation. For this reason, I share the concern of many that the Southeast EEM Agreement may present opportunities for the participants to engage in manipulation.”

He noted that the SEEM parties made commitments, in their responses to deficiency letters, to provide additional transparency safeguards.

“While the original filings, not those subsequent responses, go into effect by operation of law, I urge the parties to stand by their additional commitments on transparency,” wrote Glick.

“Beyond what the parties have offered, the Commission has the tools — and stands ready — to investigate any potential fraudulent or manipulative conduct and take any corrective action as needed, including imposing civil penalties. As I have often stated, guarding against market manipulation remains one of the core obligations vested in this agency by Congress. I intend for the Commission to continue to remain vigilant on this front.”

Commissioner Clements

“To be very clear, my lack of support for the instant proposal is not because I would prefer a different market structure or that I fail to appreciate the parameters of the legal inquiry that Section 205 prescribes,” said Commissioner Allison Clements.

“I am cognizant of Section 205’s requirements that we not let perfect be the enemy of the good and that we can only review the proposal in front of us. But legal insufficiency must foreclose Commission approval.  In my view, the Southeast EEM, as proposed, contains infirmities that compel the Commission to find that the Filing Parties have not satisfied their legal burden,” she wrote in a statement.

She voiced concern that the SEEM may expose participants to unjust and unreasonable rates and said she agreed with Glick’s conclusion that applying the Mobile-Sierra standard to the generally applicable SEEM Agreement provisions, even the “enumerated provisions” identified in the response to the first deficiency letter from FERC, would violate Commission precedent.

By failing to reject the SEEM as proposed, FERC “compromises its fundamental principles of transparency, oversight and fair and open market access,” Clements said. “Failing to apply these principles to this market is dangerous not only because of the discriminatory and unjust rate impacts it may impart in the region, but because it may inhibit the Commission’s ability to ensure that other organized markets, existing or forthcoming, are just and reasonable and not unduly discriminatory.”

She argued that failing to reject the proposal “is likely to invite future attacks on the Commission’s fundamental market design safeguards in existing and future markets across the country.”

Commissioner Christie

Commissioner Mark Christie said that the SEEM proposal meets the standard for approval under section 205 of the FPA.

“The opposition to this proposal stems from one core issue:  the goal of many interest groups to force the Southeastern states into a Regional Transmission Organization (RTO) or at least into a halfway-house to an RTO now, with full submission later,” Christie asserted.

Christie said he would have voted to accept the SEEM proposal as a package. The filings “unquestionably meet the statutory criteria for acceptance under section 205 and should have been approved by majority vote of this Commission,” wrote Christie in his statement. He said he would have voted to approve the SEEM proposal as a package within the deadline of August 6, 2021 created by a May 4 FERC deficiency letter.

He said that “any claim in this record that an RTO would provide ‘more’ benefits than those offered by the Southeast EEM is purely speculative and unpersuasive.” The issue of RTO benefits versus costs and disadvantages, “in terms of both reliability and consumer protection, are complex and multi-faceted.” 

The only proposal before the Commission is the SEEM “and under section 205 the Commission’s analysis is limited to whether this proposal is just and reasonable and not whether some other proposal is more just or more reasonable,” he wrote in his Oct. 20, 2021 statement.

Commissioner Danly

For his part, Commissioner James Danly said that the Commission’s “deficient notice is just one more in a line of improper procedural maneuvers that have unjustifiably delayed the establishment of this market and delayed the issuance of a merits order by half a year.”

Danly said that “in the face of all of the potential benefits that could be realized by the creation of the Southeast EEM, and the fact that there is virtually no downside to its implementation, there is simply no lawful basis upon which to reject this submission.”

While protestors raise concerns with various aspects of the SEEM proposal, “we should have found that the filing parties have satisfied their burden under FPA section 205, and we should have ruled on the proposal before us and not upon protestors’ alternatives.”

He noted that FERC will get a second chance to issue a merits order in response to requests for rehearing. “I sincerely hope that wisdom prevails, and that the Southeast EEM proposal is ultimately accepted,” he said in his statement.

However, should this matter eventually come to the court under FPA section 205(g), “the court should remand it back to FERC for an order in the first instance. Failing that, if the court chooses to issue a decision on the merits, it should deny the petitions for review and remand with instructions that every aspect of the filers’ submission — in all related dockets — be accepted,” Danly said.

Background on SEEM

On Feb. 12, 2021, Southern Company Services, Inc., as agent for Alabama Power Company, filed the SEEM agreement on behalf of itself and the other prospective members of the SEEM. In addition, seven prospective SEEM members on Feb. 12, 2021 submitted certificates of concurrence to the SEEM agreement.

Over the summer, SEEM members offered changes to the proposal that they said would create greater oversight ability for FERC and more transparency for all participants.

APPA’s Delia Patterson, ElectriCities of North Carolina’s Jay Morrison Return As members Of DOE Panel

October 18, 2021

by Paul Ciampoli
APPA News Director
October 18, 2021

Delia Patterson, Senior Vice President of Advocacy and Communications and General Counsel at the American Public Power Association, and Jay Morrison, Chief Legal Officer at ElectriCities of North Carolina, are returning as members of the U.S. Department of Energy’s (DOE) Electricity Advisory Committee (EAC).

Each member of the EAC is appointed by the U.S. Secretary of Energy for a two-year term. The group works with the DOE’s Assistant Secretary for Electricity and meets three times a year to advise DOE on a variety of electricity issues.

The members of the EAC are from state governments, regional planning entities, utility companies, cyber security and national security firms, the natural gas sector, equipment manufacturers, construction and architectural companies, non-governmental organizations, and other electricity-related organizations.

During their term, the EAC members will advise DOE on current and future electric grid reliability, resilience, security, sector interdependence, and policy issues.

They will periodically review and make recommendations on DOE electric grid-related programs and initiatives, including electricity-related R&D programs and modeling efforts.

Members will also identify emerging issues related to electricity production and delivery and advise on Federal coordination with utility industry authorities in the event of supply disruptions and other emergencies.

A complete list of new and returning EAC members is available here.

CPS Energy’s Paula Gold-Williams Named As New Member Of Secretary of Energy’s Advisory Board

October 6, 2021

by Paul Ciampoli
APPA News Director
October 6, 2021

Paula Gold-Williams, President and CEO of San Antonio, Texas-based CPS Energy, has been named as a new member of the Secretary of Energy’s Advisory Board (SEAB).

The members of the SEAB are appointed for a two-year term and represent academic institutions, nuclear security experts, labor unions, utility companies, energy equipment manufacturers, low-income consumers, and non-governmental organizations.

The SEAB meets quarterly to advise the Secretary of Energy on how best to achieve the priorities of the Department of Energy, help identify emerging issues related to the DOE’s activities, and offer suggestions for improvements to its operation. For the first time ever, the SEAB is majority women. 

“I am honored to be appointed to the Secretary of Energy Advisory Board and extremely humbled to join my esteemed colleagues,” said Gold-Williams. “I am looking forward to working with them and to providing input on how best to achieve the Department of Energy priorities,” she said.

“As a leader of a municipally owned utility, this opportunity also allows me to further share the perspectives of public power providers and the communities they passionately serve. I want to thank Secretary Granholm and Dr. Arun Majumdar for their confidence in me and for allowing me the opportunity to make a real impact on our nation as our broad industry makes significant progress in transitioning to a clean energy future,” Gold-Williams said.

Majumdar, who previously served on the SEAB from May 2014 to January 2017 and was the first Director of the Advanced Research Projects Agency – Energy, will serve as Chair. Madelyn Creedon, who previously served as Principal Deputy Administrator of the National Nuclear Security Administration, will serve as Vice-Chair.  

The terms of the appointed members of the SEAB expire on August 30, 2023.

A list of the other SEAB members is available here.

ElectriCities of North Carolina CEO Highlights Supply Chain, Resource Mix Reliability Challenges

October 6, 2021

by Paul Ciampoli
APPA News Director
October 6, 2021

Roy Jones, CEO of ElectriCities of North Carolina, recently addressed reliability challenges facing the bulk electric system at a Federal Energy Regulatory Commission (FERC) technical conference.

Jones focused on supply chain concerns, the industry’s evolving resource mix and its impact on resource adequacy, and the criticality of industry/government coordination with the North American Electric Reliability Corporation’s (NERC) Electricity Information Sharing and Analysis Center (E-ISAC).

At the Sept. 30 FERC Commissioner-led reliability conference, Jones participated in a panel that focused on bulk power system reliability and security. He appeared at the conference on behalf of the American Public Power Association, the Large Public Power Council and the Transmission Access Policy Study Group.

With respect to the supply chain, Jones highlighted that FERC must assist industry in pressing for additional government assistance in influencing supplier cybersecurity practices. Specifically, FERC must push for the development of a third-party certification program — administered by the Department of Energy (DOE) and the Department of Homeland Security (DHS) — to secure vendor-supplied high and medium impact bulk electric system cyber components. FERC and NERC can play a role in convening vendors to develop the program.

Jones said that vendors must take supply chain security on as a fundamental responsibility. If that is to happen, the electric industry, the Commission, and governmental partners at DOE and DHS “must bring the vendors to the table to discuss certification criteria and a consensus-based approach to participation,” said Jones in his statement for the conference.

With respect to the changing resource mix, Jones said that “We all acknowledge it. We know it’s coming. But we also need to acknowledge the critical role that natural gas and the existing nuclear fleet is going to play in this transformation.”

Jones also pointed out that the country’s rapidly evolving resource mix presents challenges to resource adequacy and grid reliability. The challenge is attributable to the rapid shift away from centralized generation to non-synchronous resources, including renewables, battery storage and other technologies. As this shift accelerates, industry and regulators must keep a close eye on resource adequacy and coordinate on flexible ramping and load-following resources, along with energy-assured generation.

Jones stressed that while public power utilities continue to reduce their greenhouse gas emissions FERC must work concurrently to monitor and maintain grid reliability.

In his statement, Jones said that “Keeping the lights on during a dramatic change in the nation’s resource mix may be the single most important challenge of the mid-21st century for utility managers and state and federal regulators,” he said.

Finally, Jones made the case for greater coordination between the E-ISAC and government partners in order to maximize the E-ISAC’s effectiveness and, as a result, the security of the bulk electric system.

Along with his role as CEO of ElectriCities of North Carolina, Jones also serves as Vice Chairman of the Member Representatives Committee of NERC.

ElectriCities is a not-for-profit membership organization of municipally-owned electric utilities that are spread across North Carolina, South Carolina, and Virginia.

FERC Chairman Sees Two Main Threats To Grid Reliability

In his opening remarks at the conference, FERC Chairman Richard Glick said that there are two main threats to grid reliability.

The first is climate change and extreme weather, he said. “Extreme cold, extreme heat, wildfire seasons that start earlier and end later, massive droughts that are getting longer and having greater impact –obviously hurricanes that are much more ferocious. This is a serious issue. This is happening more and more and it’s having a big impact on the reliability of the electric grid.”

Glick said the second major threat to grid reliability comes from potential attacks — whether they be cyber or physical — against the grid.

Nation-states are growing ever more sophisticated “in their ability to attack our computer systems, whether it be in the electric industry, the natural gas industry or elsewhere and it’s something we need to pay attention to,” he said.

In addition, “cyber gangs are out there with ransomware. We saw that with the Colonial Pipeline incident and that’s certainly a threat to the electric grid as well.”

Other panels at the conference addressed extreme weather risks and challenges, managing cyber risks in the electric power sector, and maintaining electric reliability with a changing resource mix.

FERC And NERC Offer Recommendations In Preliminary Report On Cold Weather Event

September 29, 2021

by Paul Ciampoli
APPA News Director
September 29, 2021

Staff from the Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) recently provided a report that includes 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. 

FERC and NERC staff offered details on the report at FERC’s monthly meeting on Sept. 23.

The report reviews what happened during the freeze and outlines a series of recommendations, including mandatory electric reliability standards, to prevent its recurrence.

Following the staff presentation, FERC Chairman Richard Glick noted that 2011 FERC/NERC report released after a prior cold weather event that recommended mandatory weatherization requirements for electric generation facilities. 

“But somehow that recommendation was eventually watered down to guidelines that few generators actually followed,” he said.

“Today’s report again recommends that generation facilities be required to winterize with a number of specific related recommendations,” Glick noted.

“I guarantee you that this time FERC will not permit these recommendations to be ignored or watered down,” he said.

Glick also said that it is “becoming increasingly apparent that electric grid reliability depends heavily on the reliability of natural gas production and delivery systems.”

Noting that the electric sector has been operating under a mandatory reliability regime since 2005, Glick said that “it is worth exploring whether additional actions may be necessary to enhance the reliability of the natural gas sector to address threats posed by both extreme weather and cyber or physical attacks to pipelines and other gas facilities.”

The February freeze triggered the loss of 61,800 megawatts of electric generation, as 1,045 individual generating units experienced 4,124 outages, derates or failures to start. It severely reduced natural gas production, with the largest effects felt in Texas, Oklahoma and Louisiana, where combined daily production declined to an estimated 20 billion cubic feet per day, FERC noted. That is a reduction of more than 50 percent compared to average production from February 1-5. 

The FERC/NERC assessment points to freezing of generator components and fuel issues as the top two major causes of generator outages, derates or failures to start.

The identified causes in the preliminary report affected generating units across all fuel types.  Of the 1,045 generating units affected, 57 percent were natural gas-fired units that primarily faced fuel-supply challenges.

What Went Right

In terms of what went right during the event, the preliminary report said that SPP, MISO and ERCOT reliability coordinators (RCs) coordinated and communicated well with each other.

It noted that beginning February 8, SPP and MISO begin management-level discussions about the upcoming severe cold weather forecast and natural gas fuel restrictions expected, and beginning February 14, they kept an open communication channel between control rooms throughout the event.

On Feb. 12, SPP began coordinating with ERCOT about which balancing authority would rely on switchable generation that both BAs depend on as capacity resources, the preliminary report went on to say.

“The RCs recognized that all three footprints were simultaneously having emergencies and cooperated to alleviate the most critical conditions first.”

Recommendations

The report offers 28 preliminary recommendations including nine key recommendations. Those key recommendations include changes to mandatory reliability standards that build upon the recently approved standards developed in the wake of a 2019 joint inquiry into a prior cold weather event.

The report also includes five preliminary recommendation areas for further study:

• Black start unit reliability;
• Additional ERCOT connections;
• Potential measures to address natural gas supply shortfalls;
• Potential effect of low-frequency events on generators in the Western and Eastern Interconnections; and
• Guidelines for identifying critical natural gas infrastructure loads

The recommendations also include proposed timeframes for implementation, most of which are either prior to Winter 2022/2023 or Winter 2023/2024.

The presentation of the preliminary findings and recommendations is available here.

The final report will be released in November.

BPA On Path To Join Western Energy Imbalance Market In March 2022

September 27, 2021

by Paul Ciampoli
APPA News Director
September 27, 2021

After more than three years of rigorous review and analysis, the Bonneville Power Administration (BPA) has decided to join the Western Energy Imbalance Market (EIM) in March 2022, BPA said on Sept. 27.

Participation in the California Independent System Operator’s (CAISO) Western EIM is expected to further enhance the value of the Northwest’s federal power and transmission system, BPA noted.

“This decision aligns with Bonneville’s strategic plan and opens up an opportunity to increase revenues through additional sales of surplus power and to reduce costs through greater efficiencies,” said BPA Administrator John Hairston in a statement. “As the West moves rapidly to decarbonize the grid, Western EIM participation will help us navigate future challenges and leverage opportunities to benefit our customers and the Northwest.”

BPA will now sign a Western EIM Entity Agreement as well as the remaining participation agreements with CAISO. CAISO will file the signed agreements with the Federal Energy Regulatory Commission for approval. BPA plans to begin its final testing stage — parallel operations — on Dec. 1, 2021.

BPA is currently completing the work to implement new systems and processes to enable participation in the Western EIM beginning March 2022. The internal preparations are on-track and testing with the ISO has already begun.

Beginning in fall 2021, BPA will continue to hold implementation workshops to work through changes for customers, which will include informal and formal settlements training, and provide updates on BPA’s implementation efforts.

“Western EIM participation is a great introduction to emerging markets in the west,” said Hairston. “We hope to build on this experience to assess future market-based opportunities.”

As BPA assessed participation in the Western EIM, discussions about other industry improvements and market opportunities also emerged, BPA noted.

BPA plans to take part in the development of other markets and opportunities and will make decisions about its participation in these efforts through additional public processes.

One such opportunity is the Western Resource Adequacy Program organized by the Northwest Power Pool.

BPA proposed in a draft decision posted August 20 to participate in the next non-binding phase of this effort in which parties will test the design concepts, determine the program’s viability and shape its final design.

This is a first step at establishing common resource adequacy measurements and definitions.

In addition to participating in the Western Resource Adequacy Program, BPA is closely monitoring the potential formation of day-ahead markets in the West.

Both CAISO and Southwest Power Pool (SPP) have presented initial concepts that could provide additional opportunities and benefits for BPA and its customers, BPA said.

SPP manages the electric grid across 17 central and western U.S. states and provides energy services on a contract basis to customers in both the Eastern and Western Interconnections.

Information on BPA’s decision to join the Western EIM can be found at www.bpa.gov/goto/eim.

The Western EIM footprint currently includes portions of Arizona, California, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington, and Wyoming, and extends to the border with Canada.

CAISO on Sept. 15 signed an implementation agreement with the Western Area Power Administration Desert Southwest region to participate in CAISO’s real-time energy market in 2023.