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Bureau of Ocean Energy Management To Conduct Review Of N.C. Offshore Wind Project

August 10, 2021

by Paul Ciampoli
APPA News Director
August 10, 2021

The Department of the Interior recently announced that its Bureau of Ocean Energy Management (BOEM) will conduct an environmental review of a proposed wind energy project offshore North Carolina.

BOEM published a Notice of Intent (NOI) to Prepare an Environmental Impact Statement (EIS) in the Federal Register on July 29, which opens a 30-day public comment period.

BOEM will review a construction and operations plan submitted by Kitty Hawk Wind LLC, a wholly owned subsidiary of Avangrid Renewables, for a commercial-scale, offshore wind energy project consisting of up to 69 total wind turbine generators, one offshore substation, inter-array cables, and up to two transmission cables that will make landfall in Virginia Beach. 

This is the first project within the Kitty Hawk Wind Energy Area (WEA) of Avangrid Renewables. The project consists of nearly 50,000 acres located over 27 miles off the coast of the Outer Banks, due East of Corolla, N.C., with a capacity of at least 800 megawatts (MW). When the entire 122,405-acre Kitty Hawk WEA is developed, it is expected to support a total generation capacity of up to 2,500 MW.

North Carolina has set goals to develop 2.8 gigawatts (GW) of offshore wind energy off of the state’s coast by 2030 and 8 GW by 2040. Roy Cooper, North Carolina’s governor, recently issued an executive order highlighting the state’s commitment to offshore wind power and setting a target to procure 8 GW of offshore wind energy by 2040.

Virginia enacted the Virginia Clean Economy Act in 2020, which sets a target of to produce its electricity from 100% renewable sources by 2045, with 5.2 GW of offshore wind energy by 2034. 

If approved, the Kitty Hawk project will contribute towards each of the state’s offshore wind goals. 

As part of BOEM’s environmental review, the agency must first identify what should be considered in the EIS, such as important resources and issues, potential impacts to the environment, reasonable alternatives, and mitigation measures.

During the 30-day public comment period, BOEM will hold three virtual public meetings in August.

Biden Administration approves first major offshore wind project in U.S. waters

Secretary of the Interior Deb Haaland and Secretary of Commerce Gina Raimondo on May 11 announced the approval of the construction and operation of the Vineyard Wind project, the first large-scale, offshore wind project in the U.S.

The 800-MW Vineyard Wind energy project will be located approximately 12 nautical miles offshore Martha’s Vineyard and 12 nautical miles offshore Nantucket in the northern portion of Vineyard Wind’s lease area.  

 Vineyard Wind is a joint venture between Avangrid Renewables, a subsidiary of AVANGRID, Inc., and Copenhagen Infrastructure Partners.

The Departments of Interior, Energy and Commerce on March 29 announced a shared goal to deploy 30 GW of offshore wind in the U.S. by 2030.

SPP Board Of Directors Approves Western RTO Expansion Terms And Conditions

August 10, 2021

by Paul Ciampoli
APPA News Director
August 10, 2021

Southwest Power Pool’s (SPP) board of directors and its strategic planning committee approved the submitted policy-level terms and conditions for regional transmission organization (RTO) expansion in the Western Interconnection during its quarterly joint stakeholder meeting in late July.

Arkansas-based 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.

Prospective western participants include Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Wyoming Municipal Power Agency and the Western Area Power Administration (WAPA).

WAPA’s evaluation of full RTO participation in the Western Interconnection includes its Upper Great Plains-West region, Colorado River Storage Project and Rocky Mountain region.

All these organizations except Colorado Springs Utilities joined SPP’s Western Energy Imbalance Service (WEIS) market on its Feb. 1, 2021, launch before announcing their intent to explore full western RTO participation. SPP said that Colorado Springs Utilities anticipates joining the WEIS market in 2022 and is also exploring RTO membership as part of this group of entities.

“WAPA anticipates additional value in increasing energy transfers between the East and West through the SPP RTO, providing benefits and mitigating risk for existing and prospective RTO members along with our customers,” said WAPA Interim Administrator Tracey LeBeau in a statement.

If the utilities join or add additional facilities in SPP, they will become the first members of SPP’s RTO to participate in SPP’s Integrated Marketplace in the Western Interconnection. This would extend the reach and value of SPP’s services — including day-ahead wholesale electricity market administration, transmission planning, consolidated balancing authority, resource adequacy and more — and the synergies they provide when bundled under the RTO structure, SPP said.

A recent SPP Brattle study found that WEIS participants’ membership in the SPP RTO would produce approximately $49 million in savings annually for SPP’s current and new members. The western utilities joining SPP would receive $25 million a year in adjusted production cost savings and revenue from off-system sales, and SPP’s members in the east would benefit from $24 million in savings resulting from the expansion of SPP’s market, transmission network and generation fleet.

In the Eastern Interconnection, SPP formed in 1941, implemented operating reserve sharing in 1991, became a certified reliability coordinator in 1997 and earned its RTO designation from the Federal Energy Regulatory Commission (FERC) in 2004. It launched its first real-time balancing market in 2007 then transitioned to a day-ahead market and became a single, consolidated balancing authority in 2014.

SPP began serving customers in the west in October 2015. SPP subsequently expanded its services in the west in December 2019 when it launched its Western Reliability Coordination service on a contract basis and in February 2021 with the successful launch of the WEIS market.

SPP said that the next step to expand the RTO into the Western Interconnection is resolving the outstanding terms and conditions, including cost allocation for the direct-current ties between the Eastern and Western Interconnections. The remaining terms and conditions are expected to be resolved by the October 2021 SPP board of directors meeting. Prospective participants will also need to complete stakeholder processes.

Once accomplished, prospective participants plan to execute a financial commitment agreement in April 2022 to initiate the western RTO expansion. SPP then plans to file tariff modifications with FERC in October 2022 with approval expected sometime in early 2023.

Once approved, SPP anticipates extending its RTO into the west in early 2024.

Federal Legislation Calls For Nuclear Power Purchase Agreement Program

August 10, 2021

by Paul Ciampoli
APPA News Director
August 10, 2021

Reps. Elaine Luria, D-Va., and Dan Newhouse, R-Wash., introduced legislation that establishes an up to 40-year-long nuclear power purchase agreement program at the Department of Energy (DOE) and directs the Secretary of Energy to enter into one or more agreements to purchase nuclear power from reactors licensed after January 2020.

The bill, H.R.4834, also requires the Secretary of Energy to enter into one national security-related nuclear power purchase agreement prior to 2026 to provide reliable and resilient power in remote off-grid and emergency scenarios.

Luria and Newhouse were joined by Reps. Anthony Gonzalez, R-Ohio, and Scott Peters, D-Calif., in sponsoring the bill, which was introduced in late July.

The Nuclear Power Purchase Agreements Act has been endorsed by the U.S. Chamber of Commerce, Clear Path, the U.S. Nuclear Industry Council, the American Nuclear Society, the Nuclear Energy Institute, NuScale Power and the Nuclear Innovation Alliance. 

In May 2021, NuScale Power and Washington State’s Grant County Public Utility District on announced the signing of a memorandum of understanding to evaluate the deployment of NuScale’s small modular reactor (SMR) technology in Central Washington State.

In January, Utah Associated Municipal Power Systems and NuScale Power signed agreements to facilitate the development of the Carbon Free Power Project that would deploy NuScale’s SMR design at the Idaho National Laboratory. Energy Northwest has the option to operate the SMR plant.

California Community Choice Aggregators Form Financing Authority

August 9, 2021

by Paul Ciampoli
APPA News Director
August 9, 2021

Four California community choice aggregators (CCAs) have jointly formed the California Community Choice Financing Authority (CCCFA), a joint powers agency that was created with the goal of reducing the cost of power purchases through a pre-payment structure.

Central Coast Community Energy, East Bay Community Energy, Marin Clean Energy and Silicon Valley Clean Energy are the founding members of CCCFA. CCCFA membership is open to CCAs in California that are interested in utilizing the joint powers agency for prepayment transactions.

Member agencies will be able to save 10% or more on power purchase agreements entered into under this structure, the four CCAs said.

The prepayments will allow CCAs to reduce customer costs, retain the green attributes of the renewable energy contract, and increase funding available for local programs, according to the CCAs.

Formation of CCCFA assists the member CCAs by undertaking the financing or refinancing of energy prepayments with tax-advantaged bonds. The prepay structure enables publicly owned utilities, including CCAs, to effectively leverage the difference between tax-exempt and taxable debt rates to fund the reduction in the cost of power purchases, they noted.

Prepayment transactions have been used in the United States for the last 30 years primarily for natural gas transactions. Over 90 municipal prepayment transactions totaling over $50 billion have been completed in the US, with over 95% of them for natural gas.

Prepayment transactions are codified in U.S. tax law and Congress enacted legislation specifically allowing for such transactions as part of the National Energy Policy Act of 2005. CCCFA will take advantage of this structure to increase the amount, and reduce the cost, of clean energy on the California grid, combating climate change and fulfilling customers’ needs for non-polluting resources, the CCAs said.

Energy prepayment transaction agreements undertaken by CCCFA must be approved by the Board of Directors of the member CCA proposing the prepayment. Then the CCCFA Board will have the opportunity to fully consider the benefits, obligations, and risks of each prepayment transaction prior to approving any bond issuance. CCCFA is governed by a Board of Directors consisting of one director representing each founding CCA.

The creation of CCCFA follows the formation of California Community Power earlier this year as a way to help CCAs across the state reduce costs.

Additional information about CCCFA is available here.

The American Public Power Association has initiated a new category of membership for community choice aggregation programs.

Northwest Power Pool Releases Details Of Proposed Resource Adequacy Program

August 9, 2021

by Peter Maloney
APPA News
August 9, 2021

The Northwest Power Pool (NWPP) and participating member utilities have released a design of a proposed resource adequacy (RA) program.

The report details elements of the program, including a “forward showing” program and an operational program, as well as a proposed governance framework. The report also provides details on how stakeholders affected by the program can participate.

The release of the report clears the way for the next phase of NWPP’s proposed resource adequacy effort. NWPP is preparing to launch the next phase in which a forward showing program will provide informational, non-binding resource adequacy requirements for the winter of 2022. NWPP said it would accept participation agreements for the next stage of the program beginning Aug. 16 and running through Sept. 30, which will serve as a beta test for the proposed program design.

The integrated regional power system is in transition, NWPP said in the report. The impending retirement of several thermal generators within and outside the region, which includes the Western U.S. and Canada, mixed with increasing variable energy resources, has led to questions about whether the region will continue to have an adequate supply of electricity during critical hours, according to the report.

In the past four years, several studies have identified an urgent and immediate challenge to the regional electricity system’s ability to provide reliable electric service during high demand conditions.

“These developments threaten to upset the balance of loads and resources within the region and, if not properly addressed, will increase the risk of supply disruptions during winter and summer, increase financial risk for utility customers, and hinder the ability of the system to meet environmental goals and legal requirements,” the report said.

The resource adequacy effort began early in 2019 when the NWPP and a coalition of NWPP members initiated the program. The contemplated resource adequacy program “seeks to enhance and increase reliability for the footprint while maintaining existing responsibilities for reliable operations and observing existing frameworks for planning, purchasing, and delivering energy,” the report said.

“We believe the resource adequacy program will provide multiple benefits to the region as well as participants, including reliability, cost savings and improved visibility and coordination,” Frank Afranji, NWPP president, said in a statement.

There are many forms of resource adequacy – capacity, energy and flexibility – but NWPP’s program focuses on creating a capacity resource adequacy program. Additional adequacy programs may also be necessary following the implementation of the capacity program, the report said. “If additional programs are desired, a similarly discrete decision and implementation process would need to be undertaken to design and implement such programs,” the report said.

The report also noted that the proposed resource adequacy program does not replace or supplant the resource planning processes used by states or provinces or the regulatory requirements of the Federal Energy Regulatory Commission (FERC), North America Electric Reliability Corporation, or the Western Electricity Coordinating Council, but is designed to supplement and complement those processes and requirements.

The resource adequacy program design and implementation will have two components: a forward showing program and an operational program. The forward showing program is designed to ensure that the NWPP footprint has enough demonstrated capacity, well in advance of required performance, to meet the established reliability metrics. It establishes regional metrics for the NWPP footprint, the qualified capacity contribution and effective load-carrying capability of various resources, as well as deliverability expectations, and determines the periods for demonstrating adequacy.

The operational program seeks to achieve a balance between planning while providing flexibility in order to protect customers from unreasonable costs. It creates a framework to provide participants with pre-arranged access to capacity resources in the program footprint during times when a participant is experiencing an extreme event.

Under the current proposal, NWPP would become a public utility as defined by the Federal Power Act.

NWPP would also need to meet independence requirements established by FERC so that the power pool would have financial independence from individual participants in order to ensure there is no undue discrimination for the NWPP.

NWPP members include a number of public power entities.

Bonneville Power Administration To Decrease Power Rates By An Average Of 2.5 percent

August 4, 2021

by Paul Ciampoli
APPA News Director
August 4, 2021

The Bonneville Power Administration (BPA) will decrease power rates by an average of 2.5% and slashed its proposed transmission rate increase in half to an average of 6.1%, the federal power marketing administration (PMA) said in late July.

The new rates were announced as BPA released the final record of decision for its BP-22 power and transmission rate case as well as a tariff proceeding (TC-22).

The tariff proceeding adopted new language in BPA’s open access transmission tariff that will enable the power marketer to participate in the Western Energy Imbalance Market (EIM) if BPA chooses to do so. The decision of whether to join the Western EIM is a separate process outside of the tariff proceeding and is anticipated to be made by the end of the fiscal year.

In 2019, BPA issued a record of decision that addresses numerous policy issues and topics related to its participation in the EIM. BPA also signed a Western EIM Implementation Agreement with the California Independent System Operator that signaled the beginning of work on projects that need to be completed before BPA could start EIM operations.

Under a settlement adopted by the BP-22 record of decision, firm power tier 1 rates will decrease by 2.5% for fiscal years 2022 and 2023. Looking back over the previous decade, BP-22 will cap a 10-year period during which BPA’s power rate trajectory increased by less than 2% annually, which is in line with historical inflation rates.

“Rates that have matched inflation – not just in a single rate case, but over a sustained period – is proof of BPA’s commitment to bending the cost curve and driving down rate pressures on our power rates,” said BPA Administrator John Hairston in a statement. BPA’s announcement “demonstrates we are financially strong, competitive and responsive to our customers’ needs,” he said.

With respect to transmission, the settlement provided for a 6.1% average effective rate increase across the rate period, a number roughly half of what was proposed in an initial proposal.

“We’ve landed in a spot where BPA will be able to continue to keep its transmission commitments and re-invest in the value of BPA’s transmission infrastructure in a fiscally sound and responsible manner,” Hairston said.

Beyond rates, the BP-22 record of decision also establishes revenue financing for up to $40 million for both the power and transmission business lines. This financing will allow BPA to issue less debt and decrease upward rate pressures in subsequent rate cases.

As part of the settlement, BPA has committed to holding workshops on various topics of interest to customers, including revenue financing, EIM costs and benefits, balancing services, the Eastern Intertie, and transmission losses.

The tariff proceeding updated language in BPA’s tariff, including addressing the terms and conditions that will apply to transmission service if BPA decides to participate in the Western EIM. The adoption of this language enables the potential participation of BPA in the Western EIM without committing BPA to that path.  

This proceeding also addressed Southern Intertie studies, transmission planning process, real power loss return, the removal of an exception for designation of Seller’s Choice agreements, ministerial edits to service agreement templates, generator interconnection procedures and requirements, and credit standards.

The changes captured by the final records of decision for BP-22 and TC-22 will be effective October 1. Specific to rates, BPA will file the case with the Federal Energy Regulatory Commission, requesting interim approval to start on that date while awaiting final FERC approval.

The Public Power Council (PPC) said that BPA’s final record of decision in the BP-22 rate proceeding largely advances the proposed approach from members of the PPC.

 “The Northwest public power community came together with a unified voice to focus on a core set of high-impact issues with BPA on its upcoming power and transmission rates,” said Scott Simms, PPC’s Executive Director.  “To come to agreement in the BPA rate case, we knew we needed a strategy that delivered meaningful savings to public power and was reasonable for BPA to run its operations.”

The PPC, established in 1966, is an association that represents over 100 consumer-owned electric utilities in the Pacific Northwest.  PPC’s mission is to preserve and protect the benefits of the Federal Columbia River Power System for consumer-owned utilities. PPC is a key forum to identify, discuss and build consensus around energy and utility issues. 

Shrewsbury Electric & Cable Operations Adopts Accelerated CO2 Reduction Goals

August 4, 2021

by Peter Maloney
APPA News
August 4, 2021

Shrewsbury Electric & Cable Operations (SELCO) in Massachusetts has adopted a plan with even more aggressive carbon dioxide (CO2) emission reductions than those set by the state.

Earlier this year, Massachusetts established guidelines for all utilities to reach net-zero emissions by 2050. At its July 26 meeting, the SELCO Commission, which approves budgets and sets rates for the public power utility, voted unanimously to adopt a power supply policy that provides a roadmap to 100 percent CO2 free power by 2032.

SELCO provides electric, cable, telephone, and internet services to residential and commercial customers in the Town of Shrewsbury.

The policy establishes a greenhouse gas emission standard for the utility and provides a framework for future power supply contracts, as well as acquisition and retirement of Renewable Energy Certificates (RECs) in pursuit of net-zero emissions.

“We believe this accelerated schedule is in alignment with customer priorities, meets or exceeds community goals for net-zero emissions, and helps establish SELCO as an industry leader,” Christopher Roy, SELCO’s general manager, said in a statement.

The accelerated emissions reduction timeline positions SELCO to serve as the bedrock for a clean energy transition across all other sectors within the town of Shrewsbury and “balances both fiscal and environmental responsibility, resulting in the average customer seeing a monthly bill impact of around $1 in 2021 and increasing to about $5.60 in 2032,” Roy said.

SELCO’s power supply policy will be reviewed annually by the SELCO Commission to confirm the utility is meeting benchmarks in alignment with established goals. The annual review also aims to ensure market fluctuations, industry trends, changes in regulatory requirements and/or public policy are reflected in the utility’s roadmap to net-zero carbon emissions.

After vetoing climate change legislation in January, Charlie Baker, Massachusetts’ Republic governor, in late March signed comprehensive climate change legislation that commits to reaching net zero emissions in 2050.

The law, Senate Bill 9, An Act Creating a Next Generation Roadmap for Massachusetts Climate Policy, establishes interim goals for emissions reductions, significantly increases protections for environmental justice communities across Massachusetts, authorizes the governor to implement a new, voluntary energy efficient building code for municipalities, and allows the commonwealth to procure an additional 2,400 megawatts of offshore wind energy by 2027.

NREL Helps GSA Make Its Buildings More Grid Interactive And Efficient

August 4, 2021

by Peter Maloney
APPA News
August 4, 2021

The National Renewable Energy Laboratory (NREL) has created a plan to help the General Services Administration (GSA) transition its huge real estate portfolio to a more grid interactive and efficient operation.

The GSA, which procures and manages office space for federal buildings, has an annual budget of a nearly $21 billion. The agency owns and leases over 376.9 million square feet of space in 9,600 buildings in more than 2,200 communities nationwide.

The Blueprint for Integrating Grid-Interactive Efficient Building Technologies into U.S. General Services Administration Performance Contracts developed by a team of NREL researchers provides the GSA with a guide to using federal energy performance contracting to transform GSA properties into grid-interactive efficient buildings (GEBs) that can interact with the electric grid, using smart technologies to reduce, shed, shift, modulate, or generate electricity load as needed.

A grid-interactive efficient building is able to optimize its energy use in a continuous and integrated way for demand flexibility, grid services, occupant needs and preferences, cost reductions, and increased resilience, NREL says.

The NREL blueprint seeks to expand the GSA’s deployment of its National Deep Energy Retrofit program, by incorporating demand flexibility and grid integration strategies that can lead to additional energy and cost savings, increased resilience, and leading to deeper greenhouse gas reductions.

The blueprint offers guidance in using energy performance contracts, such as energy savings performance contracts and utility energy service contracts that provide a means of financing projects for government customers who do not benefit from the energy efficiency and renewable energy tax incentives available to private sector customers. Instead, some or all of the energy upgrades are paid for by contractors or the utility, with the costs recouped through energy savings over the life of the project.

The GSA is putting performance contracting to work implementing GEB at multiple sites. For instance, the agency won multiple Department of Energy grants to help co-fund solar-plus-battery-storage projects at six Land Port of Entry facilities in Texas and New Mexico, and at four courthouses and a parking garage in Oklahoma. Through its Green Proving Ground program, GSA is also preparing to test the effectiveness of various grid-interactive efficient buildings technologies at other facilities in its portfolio.

APPA, NRECA Urge FERC Not To Revoke Demand Response Opt-Out Mechanism

August 3, 2021

by Paul Ciampoli
APPA News Director
August 3, 2021

The Federal Energy Regulatory Commission (FERC) should not revoke a demand response opt-out mechanism because such a move would intensify concerns of state and local regulators that the Commission does not sufficiently accommodate their policy decisions, the American Public Power Association (APPA) and the National Rural Electric Cooperative Association (APPA) said in response to a notice of inquiry (NOI) issued by FERC earlier this year.

In their July 23, 2021, comments, APPA and NRECA urged the Commission not to rescind its regulations that require a regional transmission organization (RTO) or independent system operator (ISO) not to accept bids from an aggregator of retail customers (ARC) that aggregates the demand response of the customers of utilities that distributed more than four million megawatt-hours (MWh) in the previous fiscal year, in instances where the relevant retail regulatory authority (RERRA) prohibits such customers’ demand response to be bid into organized markets by an ARC (Docket No. RM21-14).  RERRAs include public power regulators.

APPA and NRECA said that the regulation, referred to as the Demand Response Opt-Out, remains valid and necessary for all of the reasons that it was initially adopted. “Moreover, elimination of the Demand Response Opt-Out at this time will likely cause adverse consequences and impose undue burdens on individual states and other RERRAs, as well as exacerbate the concerns of state and local regulators that the Commission does not sufficiently accommodate their policy decisions,” the trade groups argued.

 Therefore, the Demand Response Opt-Out should continue to apply as adopted in FERC’s Order No. 719, issued in 2008.  APPA and NRECA also argued that the Demand Response Opt-Out should apply to demand response resources included in “heterogenous” aggregations, i.e., distributed energy resource (DER) aggregations that are made up of different types of resources including demand response.

FERC Issued Order No. 2222-A, NOI in March

At its monthly open meeting in March 2021, FERC issued an order (Order No. 2222-A) that responded to requests for rehearing and clarification of FERC Order No. 2222, which addresses the participation of DER aggregations in markets administered by RTOs and ISOs. FERC approved Order 2222 in September 2020. Among the important features of Order No. 2222, FERC provided an “opt-in” mechanism for small distribution utilities — including most public power utilities.   This opt-in mechanism is not at issue in the NOI on the Demand Response Opt-Out.

At the meeting, FERC also issued the notice of inquiry on the potential impacts of eliminating the ability of states to choose whether demand response resources should participate in RTO/ISO wholesale markets.

FERC asked whether the circumstances relevant to this demand response opt-out have changed since the opt-out was established in Order Nos. 719 and 719-A, and what are the potential benefits or burdens of removing it.

The NOI sought comment on the following three general areas:

In Order No. 2222-A, FERC also found that demand response resources included in heterogenous aggregations would not be subject to the Demand Response Opt-Out.  FERC later retreated from this finding, saying it would consider the comments in the NOI proceeding before deciding the issue. 

As a number of parties pointed out in response to Order No. 2222-A, failing to apply the opt-out any time demand response resources are included in an aggregation with even one other type of DER would effectively negate the Demand Response Opt-Out and result in adverse consequences, NRECA and APPA told FERC in their NOI comments.

APPA, NRECA Warn of Adverse Consequences

In their comments, APPA and NRECA said that revoking the Demand Response Opt-Out will lead to the adverse consequences that Order No. 719 sought to avoid.

The trade groups said that the rationales for the Demand Response Opt-Out remain applicable today and should continue to be recognized by the Commission.

In Order No. 719, the Commission adopted the Demand Response Opt-Out in order to avoid interference with successful retail demand response programs, APPA and NRECA pointed out.

“The removal of the Demand Response Opt-Out at this time would likely threaten or upend existing demand response programs, in violation of the Commission’s assurance in Order No. 719 that its intent ‘was not to interfere with the operation of successful demand response programs,’” they went on to say.

“Notably, in the years since Order No. 719 was adopted, there has been growth in retail demand response programs, and participation in those programs,” APPA and NRECA said.

According to the Commission’s annual Assessments of Demand Response and Advanced Metering, retail demand response programs and/or customer enrollment in retail demand response programs has increased in the years since Order No. 719 was issued.

“These programs stand to be adversely impacted if the Commission removes the Demand Response Opt-Out at this time. This is a particular concern if demand response ARCs can ‘cherry-pick’ the loads or customers that will best advance their aggregation goals, such as industrial customers. Successful retail programs that are providing benefits to all end-use customers might be relegated to residual programs, with larger loads opting for the wholesale demand response programs through an ARC. Such an outcome would be an unjustified departure from the Commission’s stated intent not to interfere with successful demand response programs,” the trade groups told FERC.

APPA and NRECA said that these existing programs should be accommodated and respected in the Commission’s policies.

Impact On RERRAs

APPA and NRECA said that FERC’s rationale for the Demand Response Opt-Out, to avoid placing an undue burden upon state and local regulatory entities, also remains a valid concern. “The removal of the Demand Response Opt-Out at this time would reintroduce the concerns over displacing state and local authority and imposing undue burdens on retail regulators. With demand response as the most prevalent form of distributed energy resource, managing the impact of demand response aggregators could impose a significant burden on state and local regulatory authorities, after the Commission expressly stated it would not do so.”

If the Demand Response Opt-Out is abandoned now, the burden will be placed on state and local authorities and other RERRAs to take affirmative action to address the myriad regulatory issues that may be raised by ARCs, the groups said.

FERC has previously determined that RERRAs should have the authority if they so choose, to decide whether existing retail aggregation programs provide benefits and whether retail customer participation in wholesale demand response programs, individually or through an ARC, would adversely affect those programs and, if so, whether and how to permit such participation. “APPA and NRECA submit that there are no changed circumstances that justify depriving state and local regulators of this authority by eliminating the Demand Response Opt-Out.”

Costs For End-Use Consumers

APPA and NRECA said that as they “have often reminded the Commission, the focus in all of these efforts must remain reasonable costs to end-use consumers.”

FERC determined in Order No. 719 that RERRAs are in the best position to make determinations whether retail versus wholesale demand response programs are effective, and the role aggregation should play.

“APPA and NRECA submit that the RERRAs remain in that position. The fact that the Commission has in the interim determined in other instances not to abide by this policy of cooperative federalism does not render it inapplicable or not useful in ensuring just and reasonable rates for end-use customers.”

The Commission “should not yet again seize from RERRAs their authority to balance new technologies, maintain grid reliability, and protect consumers from unaffordable costs, particularly since the Commission specifically preserved that authority with the Demand Response Opt-Out.”

EPA Plans to Revise Power Plant Wastewater Limits

August 3, 2021

by Paul Ciampoli
APPA News Director
August 3, 2021

The U.S. Environmental Protection Agency (EPA) formally unveiled its plans to initiate a new rulemaking to revise the 2020 Steam Electric Effluent Limitation Guidelines (ELG) for certain wastewater discharge limits for coal power plants.

EPA on July 26 noted that it undertook a science-based review of the 2020 Steam Electric Reconsideration Rule under Executive Order (E.O.) 13990, finding that there are opportunities to strengthen certain wastewater pollution discharge limits.

For example, treatment systems using membranes continue to advance as an effective option for treating a wide variety of industrial pollution, including from steam electric power plants rapidly, it said. EPA expects this technology to continue advancing, and the agency will evaluate its availability as part of the new rulemaking.

However, during the 2020 ELG rulemaking process, EPA specifically rejected membranes as the “best available technology economically achievable” for flue gas desulfurization (FGD) wastewater because not a single facility in the United States had adopted the technology for anything beyond small-scale pilots. As of October 2020, some information in the rulemaking record suggests that coal-fired facilities in China may have installed membranes to treat FGD wastewater, but there was no actual data on the short- or long-term performance of these particular systems.

While the agency pursues this new rulemaking process, current regulations will be implemented and enforced.

The 2020 rule modified only certain aspects of the 2015 Steam Electric Effluent Limitation Guidelines (ELGs) rule, such that requirements promulgated in 2015 and 2020 are currently in effect.

EPA said that the current requirements provide significant environmental protections relative to a 1982 rule that would otherwise be in effect.

EPA, on July 26, signed a Federal Register notice to announce its intent to initiate this rulemaking process. Because this rulemaking could result in more stringent ELGs that are the subject of petitioners’ claims in litigation pending in the Fourth Circuit Court of Appeals, the Department of Justice, in coordination with EPA, is filing a request with the court to hold the litigation in abeyance. The court is expected to grant EPA’s recommendation.

The agency intends to issue a proposed rule for public comment in the fall of 2022.

The American Public Power Association filed comments supporting the proposed 2020 ELG Reconsideration rule and creating the low utilization boiler subcategory.

To read EPA’s notice and learn more about Steam Electric ELGs, click here.

On September 30, 2015, EPA finalized a rule revising the regulations for the Steam Electric Power Generating category. The rule set the first federal limits on the levels of toxic metals in wastewater that can be discharged from power plants.

On August 31, 2020, the agency finalized a rule revising the 2015 requirements for two specific waste streams produced by steam electric power plants — flue gas desulfurization wastewater and bottom ash transport water.

On January 20, 2021, President Joe Biden signed E.O. 13990, which directed the EPA to review all regulations and policies undertaken by the Trump Administration and rescind or revise any that do not protect public health and the environment. Accordingly, the EPA conducted a review of the 2020 Steam Electric Reconsideration Rule.