FERC Dismisses Net Metering Jurisdiction Petition On Procedural Grounds
July 16, 2020
by Paul Ciampoli
APPA News Director
Posted July 16, 2020
The Federal Energy Regulatory Commission on July 16 dismissed on procedural grounds a petition that asked it to find that it has jurisdiction over energy sales from rooftop solar facilities and other distributed generation located on the customer side of the retail meter whenever the output of these resources exceeds the customer’s demand.
The American Public Power Association on June 15 argued that FERC should dismiss the petition without reaching the merits, saying that the matters on which the New England Ratepayers Association (NERA) sought a declaratory order were neither the source of controversy nor uncertainty (Docket No. EL20-42-000). APPA contended that NERA failed to identify any particular case or controversy from which the issues addressed in the petition arose, and that the petition improperly sought a broad, generic jurisdictional ruling untethered from any meaningful discussion of particular statutes or programs that implement net metering.
In response to the NERA petition, FERC determined that the issues presented in the petition “do not warrant a generic statement from the Commission at this time,” said FERC Chairman Neil Chatterjee at FERC’s monthly open meeting.
“In the order, we also note that the manner in which the Commission addresses a petition for a declaratory order depends on the specific facts and circumstances presented to the Commission,” Chatterjee said.
“Here, we find that the petition does not identify a specific controversy or harm that the Commission should address in a declaratory order,” he said.
Details on NERA petition
In its April petition, NERA sought a declaratory order from FERC that there was exclusive federal jurisdiction over energy sales from distributed generation located on the customer side of the retail meter whenever the output exceeds the customer’s demand or the energy from such a generator is designed to bypass the customer’s load.
The petition argued that a wholesale sale occurs when the output from behind-the-meter generation exceeds demand, and the rates for such sales must be priced in accordance with section 210 of the Public Utility Regulatory Policies Act (PURPA), or sections 205 and 206 of the Federal Power Act (FPA), as applicable.
NERA also asked the Commission to “find unlawful, and therefore reject, state net metering laws which assert jurisdiction over such wholesale sales and establish a price in excess of what PURPA or the FPA allows for wholesale sales subject to this Commission’s exclusive jurisdiction.”
APPA said public power net metering programs could be jeopardized
In its June filing, APPA noted hundreds of self-regulated public power utilities across the country accommodate their customers’ behind-the-meter resources through retail net metering programs.
Local control over these programs allows public power utilities to structure retail net metering approaches that respond to the policy preferences of their states and local communities, while seeking to ensure that the costs and benefits associated with distributed generation deployment are appropriately reflected in retail rates.
“Although the petition does not specifically address the use of net metering by public power utilities, the declarations requested by NERA, if granted, could jeopardize public power net metering programs in addition to the state laws that NERA asks the Commission to ‘reject,’” APPA said.
Granting the petition could render the distributed generation output of hundreds of thousands of public power utility customers subject to federal regulation, under the FPA or PURPA, APPA told FERC.
FERC should dismiss the petition without reaching the merits, APPA argued, saying that the matters on which NERA seeks a declaratory order are neither the source of controversy nor uncertainty.
It pointed out that the Commission’s policy with respect to authority over retail net metering programs has been well-settled for years and was recently reaffirmed in FERC Order Nos. 841 and 841-A, relating to storage resources.
“Granting the petition and upsetting the regulatory certainty that the Commission has fostered would be a recipe for creating, not terminating, controversy and regulatory uncertainty. The petition is potentially sweeping in scope and broadly applicable, yet it is not grounded in any concrete proposal or specific facts and circumstances, nor does the petition include sufficient information for the Commission to analyze and address the requested declarations,” APPA said.
Challenging Costs: Public Power Hedges Transmission Expenses
July 15, 2020
by Susan Partain
APPA News
Posted July 15, 2020
Energy prices might be going down, but public power utilities — and customers — are seeing transmission costs go up and are facing policies and regulations that might lead to further increases.
Rising costs
Randy Howard, general manager of the Northern California Power Agency, a joint powers agency serving 16 public power utilities in California, said that transmission costs are the fastest growing component of members’ and customers’ bills. Over the past decade, NCPA members have seen transmission costs increase more than 10% per year. In real terms, Howard said that means some California customers have seen transmission costs go up from about 8%-12% of their bill to about 25%-30% of their bill.
Customers in Oklahoma have also seen transmission costs become the fastest-growing component of their bill, said Dave Osburn, general manager of the Oklahoma Municipal Power Authority. He estimated that the joint action agency has seen average annual increases of about 9%-10% per year since 2012. For OMPA, Osburn said, that amounts to about $12 million per year in new transmission expenses, and it has not seen an equivalent offset from decreased energy costs.
“That has certainly got our attention, because over that same period, we have seen virtually no load growth, because of energy efficiency programs and natural improvements in energy efficiency,” said Osburn.
In Missouri, Jeff Knottek, director of transmission planning and compliance at City Utilities of Springfield, also reported an average increase in transmission costs of about 10% per year for the last seven years, although he expects those increases to level off for the next several years.
Factors affecting costs
Osburn and Knottek both pointed to the robust transmission build-out that has occurred in the Southwest Power Pool, to which both entities belong, which has totaled about $10 billion in expansion costs in recent years.
Osburn said the buildouts have allowed for a vast amount of wind power to move around the region, have relieved congestion, and have supported some of SPP’s economic projects.
Tom Kent, president and CEO of the Nebraska Public Power District, described the cyclical nature of transmission development, where the system expands to support increased load, improvements need to be made, and then capacity grows to the point where system capabilities need to expand again.
NPPD is the largest transmission owner and operator in Nebraska, overseeing more than 5,000 circuit miles. Kent said that NPPD is in an expansion phase with its transmission system, most of which has been done under SPP’s transmission planning and expansion process. He estimated that about $750 million in recent transmission system investments has gone toward new facilities.
“Utilities located in western wind-rich areas, where many of the transmission upgrades have occurred, generally experience more benefits than utilities located along the eastern edge of the footprint,” said Knottek.
Knottek said that City Utilities faces high congestion costs and higher locational marginal prices. He estimated that City Utilities pays about $5 per megawatt-hour more than the average SPP transmission customer, and almost $10/MWh more than some members in the western part of SPP.
“We’ve been on the short end of the stick of the transmission buildout,” said Knottek, who explained how the costs have compounded. “We’re paying for these assets over 40 years. Annual new construction projects get added to your prior year, so the total end cost continues to grow and multiply; it keeps going up each year.”
In California, Howard pointed to the uptick in wildfires as contributing to added transmission costs in a number of ways.
“One in 10 wildfires are started by power lines, but 10 out of 10 are damaging our infrastructure,” he said. The cost to replace and recover these assets has been expensive, and he estimated that wildfire insurance costs have also gone up about 500% over the past few years. On the operations side, NCPA members also have implemented enhanced vegetation management efforts, which Howard said have doubled or sometimes tripled those costs. Members have also taken a hit when the public safety power shutoffs have occurred at the transmission level, cutting off entire communities.
“While we have taken a number of measures to try to mitigate costs occurring year after year, the expectation is that we will see transmission cost adders of 15%-25% increases per year for the next few years due to wildfires,” he said.
Mitigating costs
Howard said that most of his members are principally dependent on transmission assets owned by Pacific Gas and Electric. As such, the investor-owned utility’s transmission cost structure has a major impact on the public power utilities’ rates.
Howard believes that IOUs have turned to transmission as a key component of gaining a rate of return on investments, especially since many have divested from generating assets and instead rely on power purchase agreements that don’t offer a rate of return.
“We see what appears to be gold plating and a transfer of capital structure to transmission — probably more so than necessary,” he explained.
In 2016, NCPA made a claim with the Federal Energy Regulatory Commission in regard to about $1.8 billion of annual capital expenditures that do not go through any stakeholder process. Although the initial claim did not turn out favorably for NCPA, an appeal to include NCPA members as part of a stakeholder process over transmission expenses received a favorable decision. However, due to backlogs at FERC, Howard said that there are currently three outstanding rate proceedings (NCPA has since made the same case in subsequent years), which have yet to be approved.
“It’s quite frustrating that with these rate cases, they have been able to collect the rates, even though we have shown that they aren’t prudent rates, there are over-collections and our members are due these refunds,” said Howard. “It is quite problematic, because it gives an incentive for a transmission owner to seek more than they know they are going to get, just because they have the ability to derive the revenue for several years before they have to give some of it back.”
Howard said that NCPA members are due several hundred million dollars in refunds if FERC approves the rate case settlements, which, given PG&E’s current status, means that they might have to pursue the funds through a bankruptcy proceeding, adding another layer of complication.
Osburn said that OMPA has been “pretty aggressive” in finding ways to offset rising transmission costs. OMPA filed a complaint with FERC to lower the return on equity, which was successful in lowering some of its transmission costs. He said that it is helpful to be able to challenge the high rates of return that transmission owners receive, which he said can be about 10%-12%. Economic effects from the Tax Cuts and Jobs Act of 2017 also helped to slightly lower OMPA’s transmission costs, according to Osburn.
“We’re not always successful, but it helps to be engaged,” said Osburn. “A lot of it gets down to the transmission planning models used, and what assumptions are used. Try to get input on those assumptions.”
He said that having staff engaged or working through a joint action agency or at the national level is important, particularly if there are any committees or working groups that focus on cost allocation.
OMPA has also implemented robust energy efficiency programs, which Osburn said has helped to lower its peak by anywhere from 12 megawatts to 18 MW.
Despite the costs City Utilities has seen from transmission expansion over the past decade, Knottek said the utility continues to push for further builds along SPP’s eastern seam as a way to relieve congestion and increase customer benefits. “The way you can do that is by building additional lines or increasing the ratings of facilities,” he said. “Obviously, there’s a cost to do that, but part of the beauty of being in an RTO is that you’ll have 18 or 19 other transmission owners that are also contributing. You don’t have to bear all of the cost of trying to build the transmission and plan it all.”
Cost allocation
“The underlying goal is to ensure that everyone who is using the system is paying their fair and appropriate share of costs,” said Kent. “The challenge can come from the different view of the same coin.”
In 2019, Kent led an effort among SPP members called the “holistic integrated tariff team,” which examined SPP’s transmission planning process and cost allocation, as well as other issues. He noted that the team provided SPP with several recommendations on cost allocation.
In SPP, members are divided into pricing zones, and costs are allocated on a license plate basis within each zone.
“As new entities come into those pricing zones or as zones change, sometimes you can get unintended cost shifts that can be problematic,” Kent said. He mentioned that the holistic tariff team made some recommendations for how SPP could ensure that changes to pricing zones were more equitable.
“The rules may be slightly different from region to region, but the underlying fundamentals are very similar — to put the costs on who is benefitting from the expansion,” said Kent. “For new generation, if the developer wants to build, and if a study determines that transmission needs to be upgraded to reliably support that generation, then the beneficiary is the generation developer, so they are tasked with the cost.”
Changing landscape
“We built generation so that we didn’t really rely on others to provide our resources, but it seems that those days are long gone,” said Knottek. “It is cost prohibitive. You need to take advantage of a pool where you have more access to a diverse mixture of resources.”
OMPA explored the possibility of building its own transmission assets but found that the rules, which Osburn said have been established in large part by major transmission owners, have made the effort difficult.
When it comes to transmission development, “there’s sort of a double standard,” said Osburn, who explained that there doesn’t seem to be uniform criteria for when projects get built for reliability purposes, and when costs can be shared. He also noted the risk of developing assets that might become stranded due to increased development of distributed generation.
“If more and more load is going to be served at the local level, who is going to pay for the transmission system?” asked Osburn.
He brought up FERC’s recent notice of proposed rulemaking regarding transmission incentives, which suggests increases to incentives for transmission owners to build.
“We’re very concerned by that — you don’t need to incentivize folks to build more transmission or to gold-plate it,” said Osburn, who noted that such a move would further increase transmission expenses.
“I personally don’t see a lot of need for incentives for a transmission owner to be in an RTO/ISO or a lot of need for incentives to build new transmission,” said Howard. “Where incentives are needed is with transmission owners to optimize the utilization factor of their transmission assets.”
“If we can have more megawatt-hours flowing over the lines during more hours of the day, we could reduce the cost and provide benefit to our end use customers directly in doing so,” added Howard.
Staying engaged
“It’s rarely just one issue that drives the need to expand transmission,” said Kent. “Usually, you have a combination of economic benefits or reduced congestion, as well as reliability benefits or some other quality benefit, such as more renewable generation that could be added.”
Knottek described the cost-benefit analysis of transmission projects as subjective and noted that societal or environmental benefits, such as gaining access to more clean energy, can be weighed differently from community to community.
Kent agreed that evaluating costs and benefits of transmission builds is complex and nuanced, which is why, he said, it is important for utilities to actively participate in the process. “At the end of the day, the just and reasonable standard has gray in it.”
He added that the planning process is helpful in identifying the economic value of projects and the cost-benefit ratio to system users, and that having a planning process helps ensure regional transmission organization funds are being used appropriately to benefit the consumers of the area.
Kent acknowledged that NPPD is a large public power utility, and therefore has the ability to be more engaged within the RTO. He advised that smaller utilities voice their concerns through a state association or joint action agency that can give the issue attention and represent any concerns about transmission costs or planning.
Knottek echoed that many complaints stem from those who do not have a role in transmission planning. “If you are small, you might not have the wherewithal to build transmission or generation; there’s a real benefit to being part of an RTO.”
To stay engaged with a lot of the activity happening at the regional or national levels, Howard said that NCPA is part of the Transmission Access Policy Study group and is an active member of the American Public Power Association. He noted that he’d like to see more involvement by other joint action agencies in the proceedings, and he commended APPA for its efforts to bring various public power parties together and get in front of the Commission.
“Our voice needs to be heard; we need to be at the table. And many times at FERC, we’re not well represented on these cases,” said Howard. “FERC proceedings are complicated and expensive, and the extent to which we can join in with TAPS or APPA is critical.”
“We have to tell these stories and to talk about these costs,” said Osburn. “Not all of these investments come through RTOs. Quite often, they are built by the transmission owner with no oversight, no rate case.”
A Seat At The Trading Table: Public Power And The Energy Imbalance Markets
July 15, 2020
by John Egan
APPA News
Posted July 15, 2020
The emergence of energy imbalance markets, and their ability to bring a variety of benefits to public power utilities, is a sign of strategic change in the electricity business.
The public power entities that have moved to join or have already begun participation in these markets have determined that the projected benefits outweigh the costs and recognize how these marketplaces can support other goals.
Introducing the EIMs
Energy imbalance markets provide a platform for participants to voluntarily trade surpluses or deficits in generation in real-time. If there’s a gap between generation and demand, that energy is traded in the EIM, typically on a five-minute or 15-minute basis.
The California Independent System Operator’s Western Energy Imbalance Market was launched in 2014. Its current and future participants represent about 82% of the load in nine states: Arizona, California, Colorado, Idaho, Montana, Nevada, Oregon, Utah, and Washington.
Public power utilities including the Sacramento Municipal Utility District in California (as part of the Balancing Authority of Northern California), Salt River Project in Arizona, and Seattle City Light in Washington have begun participating in the WEIM. Other public power entities, including Colorado Springs Utilities, the Los Angeles Department of Water and Power, Platte River Power Authority, Turlock Irrigation District, and Tacoma Public Utilities, are scheduled to join the CAISO WEIM in the next few years. A second phase of BANC’s participation will include the Modesto Irrigation District, the City of Redding, the City of Roseville, and WAPA-Sierra Nevada Region.
The Southwest Power Pool’s Western Energy Imbalance Service is scheduled to launch in early 2021, pending approval by the Federal Energy Regulatory Commission. Public power entities planning to join SPP’s service include the Municipal Energy Agency of Nebraska and the Wyoming Municipal Power Agency.
Participation in an EIM does not require membership in the larger organizations that operate those real-time markets, but it does require signing an agreement with either the CAISO or SPP.
Cost Savings
Since its founding, CAISO estimates that participants have received $920 million in cumulative gross benefits, mainly through providing them with access to lower-cost energy.
“We estimate that our first year of participating in the WEIM generated about $7.1 million of net benefits, which is about 71% more than we originally projected,” said Jim Shetler, general manager of BANC, which joined the WEIM in April 2019 on behalf of SMUD, one of its members.
BANC and SMUD thought it would take about two years to recover their outlays needed for BANC’s participation in the WEIM, but better-than-expected benefits in their first year of participation have shortened the payback period.
BANC and SMUD incurred about $8.9 million in first-year costs to participate in the WEIM, which included a $4.4 million fee for annual operating costs.
Shetler said most of the benefits derive from avoided costs, such as not turning on higher-cost generators to meet peak demand when lower-cost resources are available. In addition, BANC/SMUD also have had some incremental sales through the EIM.
SRP, which began participating in the WEIM in April 2020, thinks that participation will save the utility and its customers about $4.5 million per year, Sara McCoy, SRP’s director of EIM implementation, said in an interview. In SRP’s service area, where energy costs rise sharply during the broiling summer months, participating in the WEIM is an opportunity to purchase lower-cost energy elsewhere.
“We incurred more than $20 million in implementation costs, and we’re estimating $4.5 million of net benefits per year — or about a five-year payback,” she said.
Colorado Springs Utilities, which serves about 235,000 electric customers in Colorado, expects to have first-time costs of between $100,000 and $300,000 to participate in CAISO’s WEIM, and the utility expects net annual benefits of between $500,000 and $1.5 million, according to its CEO, Aram Benyamin.
SPP hopes its WEIS can duplicate the success of a sibling wholesale market, the Integrated Marketplace, which SPP opened in 2014. The SPP estimates its Integrated Marketplace has saved participants over $3.5 billion since 2014.
MEAN, which provides wholesale power and related services to 69 utilities in four states (Nebraska, Colorado, Iowa, and Wyoming), expects to pay about $500,000 in first-year costs to participate in SPP’s WEIS market, said Brad Hans, director of wholesale electric operations for MEAN.
Cutting Carbon
Participating in an EIM can also help entities to achieve carbon-reduction goals.
Platte River Power Authority, situated in north-central Colorado, has a long-term generation plan that includes retiring a coal-fired unit and achieving a zero carbon energy mix by 2030. The plan to reach this goal relies in part on being able to join an EIM.
“Participation with the WEIM amounts to another significant step on the path to reach our 100% noncarbon energy goal,” said Jason Frisbie, general manager and CEO of Platte River. “We determined that the WEIM provides the best opportunity to manage and access additional noncarbon resources while lowering our cost profile, which amounts to a win-win for our owner communities.”
Steve Roalstad, communications and marketing manager for Platte River, explained that its location allows the joint action agency to interact with counterparts in the Western transmission interconnection, meaning it can take advantage of the wind generation east of the Rockies and the solar generation west of the Rockies.
“Wind and solar complement each other, and we can take advantage of different renewable resources,” Roalstad continued. “For us, wind generation is plentiful in the morning, while solar output peaks in the afternoon, just when wind output is falling.”
Platte River and Colorado Springs Utilities participate with investor-owned utilities Xcel Energy and Black Hills Electric Colorado in a joint dispatch agreement. The utilities hired a consultant to weigh the potential costs and benefits of joining either the WEIM or the SPP EIS market.
An analysis by The Brattle Group said joining CAISO’s WEIM would save the utilities about $2 million per year.
“Participating in an energy imbalance market is a more economical solution, and in this business, it all comes down to economics,” said Colorado Springs Utilities’ Benyamin.
He added that while the cost savings were the most important reason to participate in the EIM, the decarbonization potential was also attractive. The utility’s integrated resource plan calls for retiring the use of coal-fired generation and cutting its carbon emissions 80% by 2030 compared to 2005 levels.
“The industry is moving to a low-carbon future, and we don’t intend to stand still,” Benyamin said. “Participating in an EIM helps us complete our resource equation … It means we don’t need to build additional peaking generation.”
“If you have surplus low-cost generation,” Hans said, “or if you have higher-cost generation that can be backed down in favor of lower-cost resources, you should definitely investigate participating in an EIM.”
Participants said there’s plenty of room at the table for other public power utilities, and that the benefits and costs of participating in an EIM scale with size.
“Smaller utilities will have smaller benefits,” said Benyamin. “If you have some generation to contribute, even if it’s only 5 megawatts, that is better than having no generation to contribute.” Springs Utilities has about 1,000 MW of generation and a peak electric demand of about 965 MW.
“The benefits are directly proportional to how much generation and transmission you can commit to a market,” added BANC’s Shetler. He noted that utilities with less than 1,000 MW of generating capacity would have a harder time justifying stand-alone membership. “But if smaller utilities join together to form a larger virtual group, that could allow sharing of costs, which would make joining more cost effective.”
That kind of group could be similar to the joint dispatch agreement between Platte River, Springs Utilities, Xcel Energy and Black Hills.
Utilities that can’t commit generation to an EIM may still be able to participate if they have price-responsive dispatchable demand response programs, according to Mark Rothleder, vice president of market policy and performance at the CAISO.
“The EIM will facilitate demand response participation,” said Rothleder. “We have had large industrial facilities participating in EIM that were dispatched based on their bids.”
Other Benefits
All sources interviewed indicated they were happy with their respective EIM journeys so far. The public power utilities that only recently began participating — SRP and Seattle City Light — reported no negative experiences. Other public power utilities, whose participation is scheduled to begin in 2021 or 2022, said they were comfortable with the way their onboarding has progressed.
SRP’s McCoy said there was another benefit from the EIM participation process: The journey was an opportunity for the organization to improve its processes and drive toward operational excellence.
Hans said MEAN joined SPP’s EIS because it wanted a seat at the decision-maker’s table.
“The governance structure of SPP’s EIS was very appealing to us,” Hans said. “Each participant will have a seat on the board. That’s the way MEAN operates — each of our members has a seat on the organization’s board. They may not make it to every meeting, but there’s a seat for them if they do.”
There’s yet another reason for public power utilities to consider participating in these markets: the increased migration of entities to the CAISO WEIM has had the effect of removing potential intra-hour (i.e., five-minute or 15-minute) trading counterparties, and the same outcome will likely result as entities join the WEIS..
“The reality is that among entities that have not joined a real-time market like the WEIM or the WEIS, there are less potential trading counterparties,” commented Shetler. “That’s an important reason for public power utilities to participate in an organized real-time market.”
Homework Required
The rules of the CAISO and SPP marketplaces are different, and in many cases, the devil’s in the details. To better understand the costs, benefits and rules of each, prospective participants can talk to current participants — including other public power utilities, electric cooperatives and investor-owned utilities — or consider hiring a consultant that can quantify and detail the likely costs and benefits for that participant.
“Actively investigate the benefits and costs of participating in an EIM. Pay attention to details and timelines,” said Hans. “Don’t rush into it, but don’t run away from it, either. Not participating in an energy imbalance market could mean your power costs stay level while others’ are declining.”
Appeals Court Rules On FERC’s Use of “Tolling Orders” To Delay Acting On Rehearing Requests
July 15, 2020
by Paul Ciampoli
APPA News Director
Posted July 15, 2020
The U.S. Court of Appeals for the District of Columbia Circuit recently issued a ruling that addresses the Federal Energy Regulatory Commission’s use of “tolling orders” to delay ruling on rehearing requests under the Natural Gas Act (NGA).
The case, Allegheny Defense Project v. FERC, involved several consolidated appeals challenging a FERC order that issued a certificate of public convenience and necessity for a gas pipeline expansion project under section 7 of the NGA.
The parties challenging the pipeline project (including several landowners located in the proposed route) requested rehearing of FERC’s initial certificate order, which is a prerequisite for appealing a FERC order under the NGA.
The NGA requires FERC to act upon rehearing requests within 30 days, or they are deemed denied, at which point a party can appeal the challenged order.
For a long time, FERC has almost universally issued tolling orders that “grant” rehearing for the limited purpose of giving FERC more time to consider rehearing requests.
The Commission issued a tolling order in the Allegheny Defense Project v. FERC case, deferring consideration of the rehearing requests filed by parties objecting to the pipeline project.
A pipeline company that receives a certificate under NGA section 7 is given eminent domain authority for the approved pipeline route. Because filing of a request for rehearing does not stay the effectiveness of a FERC order, pipelines can move forward with eminent domain proceedings while opponents’ rehearing requests — and their right to appeal — remain subject to further FERC action, delayed by the issuance of a tolling order.
Also, FERC has frequently even allowed pipeline construction to begin while rehearing requests of a certificate order remain pending, as was the case in this proceeding.
FERC recently modified its rules to prohibit pipeline construction activities until it rules on the merits of any rehearing request.
Seeking to bypass the usual FERC process, a number of parties challenging the pipeline project filed an appeal soon after FERC issued its tolling order in this proceeding, arguing that FERC did not have authority to extend the 30-day deadline to act on rehearing through a tolling order, and, thus, FERC’s approval of the pipeline expansion project could be appealed without waiting for further FERC action on the rehearing requests.
Although the challengers also filed appeals once FERC denied their rehearing requests nine months later, the tolling order issues remained open in the case.
Details on court’s ruling
The court’s ruling focused on the section of the Natural Gas Act (15 U.S.C. § 717r) governing rehearing requests and judicial review under the statute. The Federal Power Act (FPA) includes a virtually identical provision.
The central issue in the case was whether, in issuing a tolling order, FERC “acts upon” a rehearing request within the meaning of NGA section 717r, such that any appeal at that point would be premature.
The court concluded that issuance of a tolling order does not amount to “acting upon” a rehearing application. Therefore, a tolling order is insufficient to prevent the deemed denial of a rehearing application or to deprive aggrieved parties of the right to seek judicial review following such deemed denial.
The court reasoned that, to act upon a rehearing application, FERC must either (i) grant rehearing, (ii) deny rehearing, (iii) abrogate the order without further hearing; or (iv) modify the order without further hearing.
The court turned aside FERC’s arguments that its tolling orders fall within the statute because they technically “grant” rehearing for the purpose of giving FERC more time to consider the rehearing requests.
The court determined instead that tolling orders “amount only to inaction on the application, which would trigger the possibility of judicial review as a deemed denial.”
Among the reasons for this conclusion, the court observes that a “grant” of rehearing, as opposed to inaction on an application for rehearing, requires at least some substantive engagement with the application. A grant of rehearing cannot consist solely of a grant of additional time to decide whether to grant rehearing, the court said.
In response to FERC’s arguments that it needs more than 30 days to address rehearing requests, the court said “that the only question we decide is that the Commission cannot use tolling orders to change the statutorily prescribed jurisdictional consequences of its inaction. That is not the same thing as saying the Commission must actually decide the rehearing application within that thirty-day window.”
The court said that in this regard it is not deciding “how Section 717r(a), the ripeness doctrine, or exhaustion principles might apply if the Commission were to grant rehearing for the express purpose of revisiting and substantively reconsidering a prior decision, and needed additional time to allow for supplemental briefing or further hearing processes.”
The court also points to language in section 717r that allows FERC to modify or set aside an order at any time up until the record of the FERC proceeding is filed in a federal court of appeals. Since the record is usually filed in court 40 days after an appeal is filed and served on FERC, the court observes that, in practice, FERC will have at least 70 days to act on rehearing requests (the original 30 days plus the 40 days before the record is filed in federal appeals court).
The court considered and rejected arguments that it should stand by previous D.C. Circuit rulings upholding the use of tolling orders.
The court concluded that after thirty days elapsed from the filing of a rehearing application without Commission action, the tolling order “could neither prevent a deemed denial nor alter the jurisdictional consequences of agency inaction.”
Having addressed the tolling order issues, the court denies the substantive challenges to FERC’s approval of the pipeline project.
FERC on July 6 filed a request with the D.C. Circuit asking it to delay the mandate (i.e., the formal judgment in the case for 90 days.)
FERC said there was good cause for a stay of the mandate, citing the need for time for the Commission to assess how to implement the opinion into the Commission’s “decades-old, judicially-sanctioned rehearing process.”
Chatterjee, Glick issue joint statement
Following the court’s ruling, FERC Chairman Neil Chatterjee and Commissioner Richard Glick on July 2 issued a joint statement in which they asked Congress to consider providing FERC with a reasonable amount of additional time to act on rehearing requests involving orders under both the NGA and FPA.
“We believe that any such legislation should make clear that, while rehearing requests are pending, the Commission should be prohibited from issuing a notice to proceed with construction and no entity should be able to begin eminent domain proceedings involving the projects addressed in the orders subject to those rehearing requests,” Chatterjee and Glick said.
In comments made at the American Public Power Association’s Wholesale Markets Virtual Summit on July 14, Glick said that “in my view, I think Congress should just revise the Natural Gas Act and the Federal Power Act to give us slightly more time – 45 days, 90 days, 120 days – you could argue what that might be. I tend to think 90 days is a good number, but different people might have different views on it.”
FERC “would have more time,” but it would still need to “move forward and get these orders out in a relatively timely fashion,” he said.
“In addition, I think we need to reconsider what we do on rehearing. In a lot of cases, rehearing requests are filed by parties that essentially repeat the same arguments they made before the original order went out and then we end up saying that these are the same arguments, but we’re going to address all these arguments and it takes forever,” he said.
In cases where nothing new has been said or argued in a rehearing request, FERC should say, “you know what, we’re just going to let it slide. Under the law, after 30 days, if we don’t act on it, the rehearing request is deemed automatically denied. We’ll let that happen, will go to court with the original order and to me that will solve a lot of our administrative issues from not having enough staff and resources to address all the rehearing requests we get in thirty days,” Glick said.
Extreme Heat Over The Weekend Drives New SRP Records For Energy Demand
July 14, 2020
by Paul Ciampoli
APPA News Director
Posted July 14, 2020
Salt River Project (SRP) on Saturday, July 11, and Sunday, July 12, delivered a record amount of energy to its Phoenix-area retail customers, the Arizona-based public power utility reported on July 13.
Between 5 and 6 p.m. on Saturday, SRP delivered an estimated retail peak demand of 7,395 megawatts (MW). That peak topped SRP’s previous system peak of 7,305 MW, which occurred on July 25, 2018.
Then on Sunday, SRP shattered both figures by delivering an estimated retail peak-demand record of 7,615 MW between 5 and 6 p.m. One megawatt is enough energy to power about 225 average homes.
SRP reported that strong customer demand is the result of several factors, including a series of extreme daytime temperatures, higher overnight temperatures and an increase in the number of SRP electric customers. The high temperature recorded on Saturday was 115 and was 116 on Sunday.
“We were able to meet the increased customer demand thanks to a robust electrical grid maintained year-round to provide reliable service and our dedicated employees who continue to rise to the challenge despite the circumstances we face due to the COVID-19 pandemic,” said Barbara Sprungl, SRP’s Manager of Power Supply and Trading.
Scott Harelson, an SRP spokesman, on July 14 said that SRP on Monday, July 13, peaked at an estimated 7,051 MW.
On the morning of July 14, SRP was already tracking a little bit under Monday’s demand and the expected high was around 109, so SRP was not likely to enter into record energy demand territory.
BrightRidge Holds Electric Rates Flat For A Second Year, Continues Coronavirus Aid
July 14, 2020
by APPA News
Posted July 14, 2020
Directors of Tennessee public power utility BrightRidge recently approved a Fiscal Year 2021 budget for the utility that holds electric rates flat for a second year in a row.
In addition, BrightRidge customers are realizing lower power bills due to lower than budgeted Tennessee Valley Authority fuel cost adjustment surcharges. TVA’s fuel cost adjustment accounts for the relative market cost of electricity depending on generation sources.
Meanwhile, Johnson City, Tenn.-based BrightRidge noted that it continues to realize $3.6 million in annual power cost savings thanks to a new TVA Partners program that provides reduced wholesale power costs as well as latitude to generate power locally outside of TVA in exchange for a 20-year power supply contract with TVA.
“Our Board of Directors keenly understand our regional economy has a long way to go before we achieve a full recovery,” BrightRidge CEO Jeff Dykes said. “We will continue ongoing efforts to assist customers as best we can while remaining positioned to power the region as recovery continues.”
COVID-19 assistance
In all, a healthy financial position has allowed BrightRidge to temporarily suspend non-payment disconnections of customers since March amid several coronavirus related measures adopted to assist customers in response to the global pandemic.
BrightRidge and TVA partnered to double the level of assistance available to residential customers who may be struggling with their power bills due to economic uncertainty, providing up to $200,000 in funding for the Heisse Johnson Hand Up Fund. BrightRidge assisted 874 customers in 2019 through the Fund. BrightRidge also made 13,390 payment arrangements in 2019 to help customers pay overdue power bills.
BrightRidge, which recently invested $100,000 to assist local small businesses through the RegionAHEAD program, will also partner with TVA this fall for a $400,000 Home Uplift program that will help low- and moderate-income homeowners make energy efficiency improvements to their homes.
FY2020 electric sales revenue is projected to miss budget by $6.97 million due to mild weather and pandemic impacts, a 2.4 percent drop. BrightRidge is projecting FY2021 total operating revenue of $204.7 million, a 2.36 percent drop from FY2020. Average retail kilowatt hour charges are projected at $.10787 compared to $.10995 in FY2020.
Nonetheless, BrightRidge remains on target to fully fund ongoing capital reinvestment and maintenance of the electric system, scheduled at $8.9 million in FY2021, while payments in lieu of taxes to local governments are slated at $5.8 million. BrightRidge is by far the largest single taxpayer in Johnson City and Washington County.
“BrightRidge remains well positioned to continue powering the regional economy through expansion of essential electric and broadband networks,” Dykes said. “Obviously, given economic uncertainty, we expect staff to redouble efforts to manage costs while we continue to support our customers as much as possible.”
BrightRidge Broadband FY 2021 budget funds big push to add serviceable locations
Meanwhile, entering the third year rollout, BrightRidge Broadband has more than 17,000 serviceable locations and the company is undertaking a major push in the next 12 months to add 13,000 serviceable locations in its 2021 budget approved by the BrightRidge Board of Directors in late June.
Boones Creek and Gray will see in the biggest expansion of fiber in the next 12 months under the new budget.
BrightRidge Broadband has placed Washington County, Johnson City and Jonesborough at the forefront nationally of 10 GB served communities, with only a handful of US cities having 10 GB service widely available, BrightRidge noted.
In addition, the Town of Jonesborough was recently recognized by PC Magazine as a top 15 affordable community for remote workers thanks to BrightRidge Broadband.
The article also found that BrightRidge Broadband services among the most affordable among small towns with 1 GB speed services available.
The BrightRidge Broadband product is redundant with three connections to the Internet backbone just outside of Washington D.C. and Atlanta.
So far, BrightRidge has invested $38 million in its hybrid system, with fiber services offered in more dense urban areas and high-speed wireless service in more rural areas.
BrightRidge Broadband is projected to generate $3.3 million in operating revenue in FY 2021, with the company on target to achieve positive net income by FY 2024.
Moody’s Affirms Ratings for CMEEC, Transmission Entity; Outlook Remains Stable
July 14, 2020
by Paul Ciampoli
APPA News Director
Posted July 14, 2020
Moody’s Investor Services recently affirmed the Aa3 ratings for the Connecticut Municipal Electric Energy Cooperative’s (CMEEC) outstanding 2012 series A transmission services revenue bonds, and 2013 series A power supply system revenue bonds, as well as the outstanding 2012 series A transmission system revenue bonds of its sister organization, the Connecticut Transmission Municipal Electric Energy Cooperative.
The outlook remains stable.
Moody’s also assigned the Aa3 rating to the forward delivery refunding bonds that were priced by CMEEC and the Connecticut Transmission Municipal Electric Energy Cooperative in late April, which will be used to refund existing debt and will result in more than $9 million in net present value savings on interest payments over the life of the debt, and will also have a positive impact on transmission revenues.
The Connecticut Transmission Municipal Electric Energy Cooperative was created by CMEEC in 2009. As a separate joint action agency, it acquired local transmission assets in order to provide transmission services required by CMEEC for its members and customers. It is governed by the same body as CMEEC. The management and staff of CMEEC operate the Connecticut Transmission Municipal Electric Energy Cooperative and oversee its operations.
In its review, Moody’s noted that CMEEC “benefits from its ability to provide reliable power supply and transmission services under reasonably competitive rates in comparison to similar service providers in the region. These credit supportive traits remain intact as CMEEC transitions under the leadership of a new CEO appointed in December 2019 which further distances itself from [previous] credit negative governance related issues.”
CMEEC and the Connecticut Transmission Municipal Electric Energy Cooperative were also given a rating outlook of stable, which “reflects the smooth transition to a new CEO and effective strategies implemented to cope with [recent] shifts in supply responsibilities.”
Kevin Barber, Chairperson of the CMEEC Board of Directors, said that “this is another affirmation of the positive steps the CMEEC Board has recently taken to strengthen corporate governance and controls,” and that he is “pleased with this ratings affirmation by Moody’s.”
Dave Meisinger, CMEEC Chief Executive Officer, added that “this helps to ensure that CMEEC and its member municipal electric utilities will have competitive access to financial markets, which further positions the CMEEC members to maintain their low retail electric rates.”
Fitch Ratings in May upgraded the CMEEC Issuer Default Rating from “A+” to “AA-“. Fitch also upgraded the ratings of the outstanding bonds of CMEEC and its sister organization, the Connecticut Transmission Municipal Electric Energy Cooperative, from ‘A+’ to ‘AA-’. In addition, Fitch assigned the “AA-“ rating to the forward delivery refunding bonds
CMEEC’s member municipal electric utilities include the Jewett City Department of Public Utilities, Norwich Public Utilities, Groton Utilities, Bozrah Light & Power, Third Taxing District of the City of Norwalk and South Norwalk Electric and Water.
EPA Says That It Plans To Retain Primary, Secondary Ozone National Ambient Air Quality Standards
July 13, 2020
by Paul Ciampoli
APPA News Director
Posted July 13, 2020
The Environmental Protection Agency (EPA) on July 13 announced a proposal to retain the primary and secondary ozone National Ambient Air Quality Standards (NAAQS).
The standards, established in 2015, are currently set at 70 parts per billion (ppb), in terms of a three-year average of the annual fourth-highest daily maximum 8-hour average ozone concentrations.
The Clean Air Act requires EPA to set national ambient air quality standards for “criteria pollutants.”
Currently, ozone and related photochemical oxidants, and five other major pollutants are listed as criteria pollutants. The others are carbon monoxide, lead, nitrogen oxides, particulate matter and sulfur oxides.
The Clean Air Act also requires EPA to periodically review, at least every five years, the relevant scientific information and the standards and revise them, if appropriate, to ensure that the standards provide the requisite protection for public health and welfare.
In the prior review of the ozone standards, which was completed in 2015, EPA increased the stringency of the levels of the ozone standards to 70 ppb from the 2008 standard of 75 ppb.
Emissions from sources such as cars, trucks, buses, industries, power plants, and products such as solvents and paints are among the major man-made sources of ozone-forming emissions.
According to the EPA, from 2017 to 2019, ozone concentrations fell four percent and since the beginning of the Trump Administration it has also re-designated 13 nonattainment areas for the 2008 eight-hour ozone standards to attainment.
EPA will accept comment on its proposed decision for 45 days after it is published in the Federal Register.
Additional information on the proposed decision is available here.
Virginia To Become Newest And The Southernmost Member of RGGI
July 13, 2020
by Peter Maloney
APPA News
Posted July 13, 2020
Virginia is set to become the newest member of the Regional Greenhouse Gas Initiative (RGGI) cap-and-trade program.
An announcement on Wednesday by Ralph Northam, the state’s governor, hailed Virginia as the southernmost state to join RGGI. Joining the group sends “a powerful signal that our Commonwealth is committed to fighting climate change and securing a clean energy future,” Northam said in a statement.
Current RGGI members are Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont.
The groundwork for joining RGGI was set as far back as 2017 when Virginia regulators unanimously approved draft power plant emissions trading regulations that established an initial 2020 carbon dioxide emissions cap at either 33 million tons or 32 million tons. The cap then falls by 3 percent a year for a decade.
On April 12, Northam signed the Virginia Clean Economy Act and amending the Clean Energy and Community Flood Preparedness Act that requires the state to join RGGI.
The Clean Economy Act also replaced the state’s voluntary Renewable Portfolio Standard with a mandatory RPS under which Dominion Energy’s Virginia operations will have to produce electricity from 100 percent renewable energy by 2045, and American Electric Power’s Virginia operations will have to produce electricity from 100 percent renewable energy by 2050.
On June 25, David Paylor, director of the state’s Department of Environmental Quality, signed the final Virginia Carbon Rule. The rule became effective July 1, and Virginia becomes a full participant in RGGI on Jan. 1, 2021.
RGGI is composed of individual carbon dioxide trading programs that each participating state draws up based on the RGGI Model Rule. Within each RGGI state, fossil-fuel generating plants with a capacity of 25 megawatts (MW) or greater are required to hold allowances equal to their CO2 emissions over a three-year control period.
One allowance represents authorization to emit one short ton of CO2. Regulated power plants can use a CO2 allowance to demonstrate compliance in any RGGI state.
Generators may acquire allowances by purchasing them at regional auctions or through secondary markets.
RGGI’s regional cap, as set forth in its model rule amendments, is 75,147,784 tons of CO2 in 2021, which is set to decline by 2.275 million tons of CO2 per year thereafter, resulting in a total 30% reduction in the regional cap from 2020 to 2030.
Virginia’s CO2 Budget Trading Program base budget for 2021 is 27.16 million tons of CO2, falling to 19.6 million tons in 2030. For 2031 and each succeeding year, Virginia’s CO2 base budget is 19.60 million tons unless modified as a result of a program review and future regulatory action.
States sell nearly all emission allowances through auctions and invest proceeds in energy efficiency, renewable energy, and other programs. Under the law passed in April, Virginia will use its RGGI proceeds for community flood preparedness, coastal resilience, and energy efficiency programs benefitting low-income residents of the state.
The Department of Housing and Community Development, in coordination with the Department of Mines, Minerals and Energy, will administer approximately 45 percent of the proceeds to community flood prevention and coastal resilience programs, and three percent will be used by the Department of Environmental Quality to further statewide climate planning efforts.
In October, Pennsylvania Gov. Tom Wolf (D) signed an executive order directing the state’s Department of Environmental Protection to join RGGI.
Pennsylvania House lawmakers last week approved legislation that would require legislative authorization before the state could enter RGGI, but Wolf is expected to veto the measure.
Court Denies Appeal of FERC Orders On Energy Storage Participation In Markets
July 11, 2020
by Paul Ciampoli
APPA News Director
Posted July 11, 2020
The U.S. Court of Appeals for the District of Columbia Circuit on July 10 issued an opinion that denied an appeal filed by the American Public Power Association and several other parties that challenged certain aspects of Federal Energy Regulatory Commission Order Nos. 841 and 841-A, which established rules for the participation of electric storage resources (ESRs) in regional transmission organization (RTO) and independent system operator (ISO) markets.
In 2019, APPA, the Edison Electric Institute (EEI), the National Rural Electric Cooperative Association (NRECA) and American Municipal Power (AMP) challenged FERC’s conclusion that state and local regulators may not “broadly prohibit” ESRs located on a distribution system or behind a retail meter — what the court refers to as “local ESRs” — from participating directly in wholesale markets.
While the Federal Power Act (FPA) gives FERC jurisdiction over wholesale sales, the FPA leaves regulation of distribution facilities to state and local regulators.
APPA and the others primarily argued that FERC exceeded its jurisdiction in Order Nos. 841 and 841-A by concluding that state and local regulators could not exercise their jurisdiction over distribution facilities to prohibit local ESRs from participating in RTO/ISO markets.
APPA and the other groups also asserted that FERC acted arbitrarily and capriciously by not applying to ESRs the same “opt-in/opt-out” framework that FERC adopted for demand response in Order Nos. 719 and 719-A, under which a relevant electric retail regulatory authority can restrict aggregated retail customer participation in wholesale demand response programs.
The National Association of Regulatory Utility Commissioners (NARUC) filed an appeal raising similar issues, which was consolidated with the appeal made by APPA, EEI, NRECA and AMP.
Court addresses jurisdictional issues
As framed by the court, the primary question in dispute was whether Order No. 841 unlawfully regulates matters left to the states. On this issue, the court concludes that, in allowing local ESRs to access wholesale markets, FERC is not directly regulating distribution facilities. The fact that local ESRs will use the distribution system “is the type of permissible effect of direct regulation of federal wholesale sales that the FPA allows,” the court said.
The court turned aside arguments that authority over distribution facilities allows state and local regulators “to close their facilities to local ESRs seeking to transport electric energy to the wholesale markets,” citing principles of federal preemption under the Supremacy Clause of the U.S. Constitution.
The court said that the argument that a local ESR does not participate in the federal wholesale market — and therefore cannot fall within FERC’s authority — until after it navigates through state-regulated facilities falls short.
Any state effort that aims directly at “destroying” FERC’s jurisdiction by necessarily dealing with matters which directly affect the ability of the Commission to regulate comprehensively and effectively over that which it has exclusive jurisdiction invalidly invades the federal agency’s exclusive domain, the court said.
While agreeing that state and local regulators cannot broadly prohibit wholesale market participation by local ESRs, the court points out that, under Order No. 841, states retain their authority to prohibit local ESRs from participating in the interstate and intrastate markets simultaneously, “meaning states can force local ESRs to choose which market they wish to participate in.”
The court also emphasized that state and local regulators retain authority to impose restrictions on local ESR participation in wholesale markets, short of broadly prohibiting such participation, even if such requirements hinder FERC’s efforts to facilitate wholesale market participation by local ESRs.
Thus, for example, states retain their authority to impose safety and reliability requirements without interference from FERC, the court said.
The court also noted that states “will be free to challenge” Order Nos. 841 and 841-A as applied to their own state regulations or imposed conditions.
The court also responded to the argument made by APPA, EEI, NRECA and AMP that allowing state and local regulators to broadly prohibit local ESR participation would be preferable to the inevitable litigation over which state restrictions on local ESRs are permissible and which are not.
The court said that “Petitioners are likely correct that litigation will follow as states try to navigate this line, but such is the nature of facial challenges.”
The court also rejected the argument that FERC acted arbitrarily and capriciously by not applying to local ESRs the “opt-in/opt-out” framework that FERC applies to demand response resources. The court said that FERC’s decision to treat local ESRs different from demand resources was “neither unexplained nor unsupported.”
Order No. 841 was issued in February 2018
Order No. 841, issued in February 2018, adopted rules aimed at removing barriers to the participation of ESRs in wholesale power markets operated by RTOs and ISOs. At the time, several organizations, including APPA, asked FERC to reconsider some aspects of Order No. 841, arguing that FERC was overstepping its jurisdictional authority and encroaching on state and local authority over distribution utilities and networks.
APPA also argued that FERC should have given state and local authorities the ability to opt out of allowing ESRs in their jurisdictions from participating in wholesale markets, as the Commission did for demand response aggregation in Order Nos. 719 and 719-A. FERC largely rejected these arguments in Order No. 841-A, issued in May.