NYISO’s proposed modifications to capacity market rules are rejected by FERC
September 11, 2020
by Paul Ciampoli
APPA News Director
September 11, 2020
The Federal Energy Regulatory Commission on Sept. 4 issued an order rejecting changes proposed by the New York ISO (NYISO) to the buyer-side mitigation rules in its capacity market.
FERC’s decision drew a stinging rebuke from FERC Commissioner Richard Glick, who argued in a dissent that the order is “just the latest in the Commission’s ever-growing compendium of attempts to block the effects of state resource decisionmaking.”
The NYISO’s proposal, which the grid operator said received full stakeholder and market monitor support, would revise the process by which the NYISO determines exemptions from buyer-side mitigation when capacity prices are forecast to exceed certain thresholds following the entry of the new resource, which is referred to as the “Part A” exemption (Docket No. ER20-1718-001).
These provisions are intended to allow for the possibility that a new resource may be entering service at a time of tight capacity, and therefore would not need to have its offer price mitigated.
The NYISO said that the modifications were designed to better reflect the expected expansion of renewable resources and storage resulting from state laws and regulations.
The proposed tariff changes would increase the likelihood that such “Public Policy” resources would qualify for the Part A exemption, primarily by changing the order of preference for the exemption from resources with the lowest project cost to Public Policy resources, among other modifications.
The project cost is no longer the main factor determining which resources will be constructed, the grid operator said. The NYISO said that resources that meet public policy needs are likely to be built and become operational, even if they do not have the lowest Net Cost of New Entry because such resources are “favored by new laws and policies that govern siting and operation of these resources. They are thus more likely to have firm off-takers and receive favorable financing terms from private lenders.”
The NYISO’s proposed change to the Part A exemption to give preference to Public Policy resources would not reduce capacity prices, and only would change which specific resources receive an exemption.
FERC decision
FERC determined that the NYISO proposal is unduly discriminatory because it does not provide sufficient justification for prioritizing the evaluation of Public Policy Resources before non-Public Policy Resources, independent of cost.
“Further, our finding that NYISO’s proposal is unduly discriminatory is dispositive; we need not reach NYISO’s arguments that its proposal would not cause price suppression,” the Commission said.
In contrast to its orders on the PJM MOPR expansion, in which FERC sought to avoid what it terms “price suppression” from the participation of state-sponsored resources in the capacity market, in the NYISO order FERC focused only on this differential treatment between Public Policy resources and other types of capacity resources.
Commissioner Glick’s dissent
In his dissent, Glick argued that the Commission “has perverted NYISO’s buyer-side market power mitigation rules into a mind-boggling series of unnecessary and unreasoned obstacles aimed at stalling New York’s efforts to transition the state toward its clean energy future. As a result, those rules have become an unprincipled regime that has little to do with buyers or the exercise of market power.”
Responding to the other Commissioners’ reason for rejecting the proposal, Glick said that Public Policy Resources are not similarly situated for the purposes of the Part A Exemption Test “because they are subject to relatively favorable siting regimes and, as a result of their status under New York law, are more likely to secure the customers and financing that help ensure that they get developed successfully.”
He said that given that the purpose of the Part A Exemption Test “is to facilitate the entry of resources when capacity margins are getting tight and additional resources are needed, the likelihood that the exempted resources actually appear is a highly relevant and distinguishing feature that would support differential treatment.”
Glick said that until recently, the Commission “has long asserted an interest in balancing the effects of state policies with measures to address how those policies affect capacity market prices. While reasonable minds can disagree over how effectively the Commission struck that balance in years gone by, it is hard to argue that today’s order does anything but confirm that the era of respect for state decisionmaking is over.”
And that, in turn, puts regional transmission organizations and independent system operators “in an impossible position, forcing them to juggle the Commission’s ideological antipathy toward state efforts to shape the resource mix with the realities that Congress gave states responsibility over resource decisionmaking and that the physical system will ultimately, and rightfully, reflect those state choices.”
The NYISO’s filing “sought to strike a balance between those concerns by taking into account the effects of New York law while avoiding any of the ‘price suppression’ concerns on which the Commission has been so focused. And NYISO appeared to have done so admirably,” Glick said.
The proposal received a super-majority of votes in the stakeholder process and not a single party protested this issue before the Commission, he noted, including any of the generator groups “that have cheered on the Commission’s slew of recent buyer-side mitigation orders. But, of course, the Commission thinks it knows better than NYISO’s stakeholders, better than NYISO’s Market Monitoring Unit, better than the New York State Public Service Commission, and better than the people of New York.”
In rejecting the NYISO’s proposal, “the Commission makes clear how little it cares about stakeholder compromise or the consequences its actions will have for the practical reality of running an organized wholesale market,” wrote Glick.
This decision comes in the midst of a New York Public Service Commission proceeding, launched last August to consider how to reconcile the NYISO resource adequacy programs with the State’s renewable energy and environmental emission reduction goals.
Power mostly restored to Vinton, La. after public power utility crews pitched in
September 11, 2020
by Paul Ciampoli
APPA News Director
September 11, 2020
Power has been largely restored to Vinton, La., after the city was hit hard by Hurricane Laura last month. Crews from several public power utilities have played a key role in helping to bring power back to the city in an expedited fashion.
Crews from Louisiana public power utility Lafayette Utilities System (LUS), Florida public power utility Gainesville Regional Utilities (GRU) and Alabama public power utilities deployed in late August to assist with restoration efforts after Vinton was hit by Laura.
Alex Antonowitsch, an LUS spokesman, noted in a Sept. 10 email that Vinton is 80 percent restored. The remainder are due to structural or electrical damage that would require the resident to have resolved, he said.
LUS and GRU installed a 5,000 kV transformer to step down the voltage from investor-owned utility Entergy’s lower 35.5 kV line to feed Vinton. “Entergy’s 138 kV transmission lines are still down so we are waiting for Entergy to rebuild the lines. There is no timeline from Entergy as to when these will be rebuilt,” Antonowitsch said.
Antonowitsch noted that LUS currently has one five-man crew traveling every day to Vinton to assist in any additional work.
Two days after Laura made landfall and after completing restoration work in Lafayette, Greg Labbe’, Electric Operations Manager at LUS, was asked by the mayor of Vinton to oversee the restoration in Vinton.
“The damage was much worse than when we went to help out after Rita,” said Labbe’. “We are committed to see it through to the end.”
Labbe’ is a member of the American Public Power Association’s Mutual Aid Working Group.
Kevin Bihm, General Manager for the Louisiana Energy and Power Authority, noted that there were “so many facets of mutual aid that were displayed in Vinton.” Lafayette and Vinton are both member cities of LEPA.
Bihm cited the “neighbor helping neighbor” story seen through LUS personnel helping Vinton to assess damage to the system and assist city leaders in the coordination effort to restore power, as well as
APPA mutual aid line crews from various states “putting boots on the ground to restore and in some cases rebuild” the distribution system.
In addition, he noted that APPA and LEPA worked with state and federal governments to fast track needed equipment and facilities to get the lights back on as expeditiously as possible.
On a normal day, Vinton’s main substation is fed via a 138 kV transmission line, Bihm pointed out. This 138 kV line was damaged in the storm and Entergy was estimating several weeks for restoration.
“APPA and LEPA were working on both the federal and state levels to secure a generator for Vinton so that they could power critical infrastructure” in Vinton, he said.
These efforts led to the installation of a temporary transformer that was interconnected to an energized 34.5 kV transmission line near Vinton in order to supply up to 5 MW of the total 8 MW load of Vinton.
Labbe’ and his team led the effort to construct the necessary substation structures for the installation of this transformer, Bihm said.
LADWP employees use emergency training to respond to automobile fire
September 10, 2020
by Paul Ciampoli
APPA News Director
September 10, 2020
Two employees of the Los Angeles Department of Water and Power,Sergio Morelos and Javier Hernandez, this summer utilized their training for emergency situations to quickly extinguish an automobile fire.
The event took place in July in San Francisquito Canyon near LADWP Power Plants 1 and 2.
Morelos and Hernandez noticed a car pulled to the side of the road that was emitting smoke. Morales noticed that the car tire had blown out, causing a small fire.
He recalled his recent training about proper fire extinguisher use, and immediately worked to put out the blaze. The two men then waited with the driver until the Fire Department was on the scene to ensure the situation was safe.
Morelos is a Utility Pre-Craft Trainee and Hernandez is a Maintenance Laborer.
“My crew members and I attend daily tailgates, which remind us what to do in case of an emergency,” said Hernandez. “The daily training helps you remain composed and focused when an emergency does occur. The situation was unexpected, but our training prepared us to handle the unexpected.”
“By listening to information given at tailgate and safety meetings, I was prepared mentally for the dangers I may face on the job and on a daily basis,” said Morelos.
“Having had training where we actually use tools such as a fire extinguisher is vital when real life emergency situations happen,” he said.
“In the case of the incident, it was a scary situation, but we remained calm and knew how to assist the driver with the spreading fire because we had been trained on properly using fire extinguishers—PASS (pull the pin, aim the extinguisher, squeeze the trigger and sweep side to side),” Morelos said.
SRP Substation Troubleman helps save the life of a car crash victim
In another example of frontline public power workers quickly responding to dangerous situations in the field, Salt River Project Substation Troubleman John Boyle recently helped to save the life of a car crash victim in Mesa, Ariz.
California offshore wind could help flatten duck curve, study finds
September 10, 2020
by Peter Maloney
APPA News
September 10, 2020
Offshore wind resources along the central California Coast are well suited to meet demand when it is most needed, according to a new study by researchers at California Polytechnic State University in San Luis Obispo.
California leads the nation in solar power with over 28 gigawatts (GW), but as the sun sets, consumer demand rises, creating a sudden need for other forms of energy to meet daily peak needs, a phenomena that has come to be known as the “duck curve.”
“The alignment between potential offshore wind power production and demand highlights the important role that offshore wind energy could play in meeting California’s ambitious renewable energy goals,” Yi-Hui Wang, the research scientist who led the Cal Poly team, said in a statement.
Instead of taking a conventional approach to identifying areas with promising wind resources by using mean wind speeds, the researchers said they compared the diurnal and seasonal patterns of offshore wind power production to diurnal and seasonal patterns of power demand across California and to power production from other renewable resources, such as solar and land-based wind power.
They then used the relative alignment between the power production of the various renewables and demand to calculate a demand-based value and, looking at the daily and seasonal fluctuations in recent wholesale power prices, they generated an estimate of the wholesale dollar value of power produced.
Solar power generation in California peaks in June at noon while the peak in the value of power demand occurs in July and August at about 4:00 pm, the researchers noted, adding that land-based wind power generation peaks in June at midnight while the value of power demand peaks in August at about 10:00 pm.
Offshore wind power generation, on the other hand, aligns well with daily peak demand, which occurs between 7:00 pm and 8:00 pm, depending on the month, the researchers said.
Regarding the wholesale value of offshore wind, the researchers report that due to strong variations in pricing, these values show more extreme daily and seasonal changes than power production. The wholesale value of power is close to zero on a typical spring noon because of the solar overgeneration and peaks during evening hours when solar generation is low and demand is high.
“The framework by which we assess spatial and temporal patterns in offshore wind energy production and its value can be applied to other regions where offshore wind is being considered,” the researchers wrote.
The federal Bureau of Ocean Energy Management, which funded the study, is considering California’s central coast region for the location of the state’s first offshore wind farm and has proposed priority areas for leasing by energy companies.
“Looking at this wind data in relation to maps of fisheries, whale and seabird activity will help identify locations where offshore wind farms could add the most value and yet have the least impact on local economies and marine wildlife,” biology professor Crow White, a member of the Cal Poly research team, said in a statement.
The researchers noted that the greatest wind speeds, which would produce the most energy, are found farther from the coast. And while most existing offshore wind farms are installed close to shore in waters less than 160 feet deep, floating wind farms in deeper waters have begun operation in Europe.
“Floating offshore wind farms are now a proven technology and game-changer in many respects,” physics professor and team member Ryan Walter said in a statement.
The Cal Poly study did not include a full economic analysis because of a lack of data on the costs of building and operating offshore wind farms and the losses associated with transmitting the power back to shore.
“Ultimately, we hope this information and our ongoing work will inform the conversation, helping the policymakers and citizens of California decide if, how and where to prioritize renewable offshore wind energy,” biology professor and team member Ben Ruttenberg, said in a statement.
As a next step, the Cal Poly team is looking at a study that would estimate the total amount of electricity wind farms in the area could produce and how those wind farms might affect the broader economy of San Luis Obispo County.
The study is available here.
Redwood Coast Energy Authority taps consortium for offshore wind partnership
The Redwood Coast Energy Authority, a California local government Joint Powers Agency, in 2018 selected a consortium of companies to enter into a public-private partnership to pursue the development of an offshore wind energy project off the Northern California coast.
In 2019, Monterey Bay Community Power, a California community choice aggregator, and Castle Wind LLC said that they signed a memorandum of understanding that outlines the mutual interests and intent of both parties to enter into future long-term power purchase agreements for approximately 1,000 megawatts of energy from an offshore wind project being developed by Castle Wind.
Navigating the complex waters of competitive power markets
September 9, 2020
by Peter Maloney
APPA News
September 8, 2020
The complexity of wholesale power markets can seem daunting, especially for smaller players without a deep bench of analysts and traders. But public power utilities looking to navigate those markets can find help in the form of partners such as The Energy Authority (TEA).
Wholesale power markets operated by Regional Transmission Organizations and Independent System Operators use auctions to sell power and other services at the lowest cost, but over time the variety of auctions needed for the various attributes of electric power and its delivery have evolved, creating a bewildering array of rules and regulations.
In addition to day-ahead and real-time spot energy markets, wholesale power markets also often have auctions for products such as capacity and financial transmission rights (FTRs).
The risks of trading in some of those markets were underscored in 2018 when GreenHat Energy defaulted on $150 million of FTRs in the PJM Interconnection market.
GreenHat’s default highlighted some of the complex issues involved in trading in wholesale power markets.
TEA, which is headquartered in Jacksonville, Fla., provides public power utilities with access to resources and technology that enables them to respond competitively in the changing energy markets.
First and foremost, TEA listens to the goals of the utility, and seeks to understand their focus and goals, Joanie Teofilo, CEO of TEA, said. “We look holistically at their portfolio whether it is solar, gas – whatever those assets are – and how best to optimize their assets and manage risk.”
TEA was founded 23 years ago when it executed its first trade on behalf of its founding members, JEA of Florida, Santee Cooper of South Carolina, and Municipal Electric Authority of Georgia (MEAG Power).
The company was formed in the wake of two landmark orders from the Federal Energy Regulatory Commission, 888 and 889, that were designed to create a competitive market for trading electricity.
Recognizing the “existential threat and unique opportunity” those orders created for public power, the founders came up with a business model that uses economies of scale to give community-owned utilities access to the financial expertise, advanced technology, and operational experience needed to compete in the new environment, according to TEA.
Any one of the founding partners could have done their electricity trading in house, but they realized the economies of scale that belonging to a much larger organization would confer, Jamie Mahne, TEA’s chief client officer, said.
Since its founding, TEA has evolved from a bilateral power trading firm to a company offering public power utilities a range of products and services that include wholesale market management and trading, portfolio management, power supply management, natural gas management, and advisory services.
TEA’s ownership has also expanded, from its three founding member-owners in the Southeast to seven member-owners in locations throughout the country, including American Municipal Power, City Utilities of Springfield, Missouri, Gainesville Regional Utilities, and the Nebraska Public Power District.
TEA now serves about 60 public power utilities and represents over 30,000 megawatts (MW) of generation across all fuel types. The company also consistently ranks as the top power trader by volume among community-owned utilities with approximately 200,000 transactions per year.
While it started in the Southeast, TEA now operates in the wholesale markets of the PJM Interconnection, the Midcontinent Independent System Operator, the Southwest Power Pool, the Electric Reliability Council of Texas, and the California ISO, as well as in bilateral power markets in the Southeast, Northwest and West.
Despite its broad reach, TEA is “agnostic” when it comes to the relative benefits of different regional power markets, Teofilo says. For the most part a utility’s market participation is guided by their geographic location, though some utilities have load and/or generation in multiple markets, she said. “We help utilities derive the most value from whatever market they are in.”
In addition to expanding its geographic scope, TEA has also moved beyond trading for its partners. TEA does portfolio management for some clients, advising them on issues such as when to run their gas-fired generation and when to buy power in the wholesale market or how to hedge their exposure to natural gas price volatility.
The underlying idea is, “What’s the most cost-effective way to deliver lowest cost electric power with minimal risk?” Mahne says. He compares it to “meeting with your financial advisor.”
TEA was built to capture economies of scale, Mahne says, but “now we have this analytical engine that we can point at new problems that have nothing to do with wholesale markets.”
“We are seeing tremendous disruption” in the utility industry, even before COVID-19, in the form of decentralization, digitization and decarbonization, Teofilo says. “Our focus is working together with utilities to take advantage of those opportunities.”
As examples, she noted that TEA has worked with clients to help them decipher and act on the oceans of data generated from Advanced Metering Infrastructure (AMI) and to help clients streamline their requests for proposals (RFPs) process to be able to “see across the board what different developers are quoting.”
TEA can also help clients navigate the more arcane corners of the wholesale markets, for example, virtual products such as FTRs. The use of those products has attracted new players and ignited controversy about the appropriate role, if any, of financial players in wholesale power markets.
Despite failures like the GreenHat default, financial products can be valuable tool in competitive markets, Teofilo says. “They support a well functioning market,” Mahne adds. “It comes down to a liquidity discussion. The more buyers and sellers there are, the more efficient those markets are going to be,” he says.
One of those financial players is TPC Energy Fund, a privately funded power trading firm based in Washington, D.C., that focuses on FTRs.
TPC began trading FTRs in PJM in 2016 and now also trades similar products in the New York ISO and ERCOT.
By providing market liquidity and price discovery, TPC Energy and similar firms allow companies like TEA “to more effectively and efficiently transact in these markets to benefit their clients,” Noha Sidhom, TPC’s CEO, says. “We are the creditworthy counterparties.”
While the GreenHat default has shed a negative light on financial players in the FTR market, “The discussion we should be having is, ‘Do we have rules in place to protect market participants from any type of default?’” Sidhom said.
“PJM has made significant improvements, and we continue to work with them to refine the rules and set up a more secure infrastructure,” Sidhom says. “It’s important for them to have proper collateral requirements and to know their customers’ practices.”
Intense heat, power demand stress California electric grid; DOE issues emergency order
September 8, 2020
by Paul Ciampoli
APPA News Director
September 8, 2020
Several days of intense heat and a spike in power demand has stressed the California power grid, with the California Independent System Operator issuing calls for conservation and the Secretary of Energy issuing an emergency order to help preserve the reliability of the state’s grid.
Despite temperatures of 100 degrees or more over the weekend and the increase in power demand in the state, CAISO was able to avert the need for implementing rotating outages, which it had to turn to last month.
On Saturday, Sept. 5, CAISO reported that consumer conservation helped avoid rotating power outages that day. The grid operator had declared a Stage 2 Emergency, when wildfires took 1,600 megawatts of resources off the grid, but conservation helped avoid further emergencies, including rolling outages.
The ISO issued a Flex Alert to urge consumers to conserve energy during the statewide heatwave that drove up energy consumption.
On Sunday, Sept. 6, CAISO issued a statewide Flex Alert and later in the day declared a statewide Stage 2 emergency due to excessive heat driving up electricity use and putting strain on the grid.
The ISO called the emergency after a transmission line carrying power from Oregon to California reduced its capacity by 900 MW due to the heat and an generation totaling 260 MW tripped offline unexpectedly. The cause of the outages was not immediately known.
The emergency declaration allows the grid operator to use reserve power and to tap into emergency assistance from neighboring balancing authorities.
Ultimately, CAISO said it was able to avoid rotating power outages on Sept. 6 thanks to consumer conservation.
On Labor Day, Sept. 7, CAISO again issued a statewide Flex Alert, noting that temperatures were expected to be above normal statewide for the third consecutive day, driving up electricity demand, primarily from air conditioning use.
The ISO also said that day that it was monitoring several serious wildfires throughout the state threatening power lines. “Weather forecasts show wind will pick up beginning late tonight through Wednesday, increasing fire danger. Wildfires can trip or destroy power lines, reducing transmission and shrinking energy supplies,” CAISO said in a news release.
California governor signed emergency proclamation
California Gov. Gavin Newsom on Sept. 3 signed an emergency proclamation to free up additional energy capacity amid extreme temperatures across California.
The proclamation permits power plants to generate more power by suspending certain permitting requirements, helping to alleviate the heat-induced demands on the state’s energy grid.
Facilities are required to report any violations of these suspended permitting requirements to relevant local and state regulatory bodies. The proclamation also contains provisions related to the use of generators and auxiliary ship engines.
The text of the Governor’s proclamation can be found here and a copy can be found here.
DOE emergency order
On the evening of Sept. 6, the Department of Energy issued an emergency order under section 202(c) of the Federal Power Act to preserve the reliability of the bulk electric power system. The order was issued in response to a request from the CAISO for authorization for “specific electric generating units located within the CAISO balancing authority area to operate at their maximum generation output levels when directed to do so by the CAISO, notwithstanding air quality or other permit limitations.” These generating units, totaling up to 100 megawatts, are referred to as “specified resources.”
Secretary of Energy Dan Brouillette “concurs with the California Independent System Operator Corporation that a grid reliability emergency exists which demands immediate federal intervention,” said DOE spokeswoman Shaylyn Hynes.
CAISO anticipates that the DOE order may result in exceedance of National Ambient Air Quality Standards under the Clean Air Act and notes that specified resources are located in different communities within California and should not result in any disproportionate impact on a single community, Bruce Walker, the DOE’s Assistant Secretary for Electricity, said in the order.
“To minimize adverse environmental impacts, this order limits operation of dispatched units to the times and within the parameters determined by the CAISO for reliability purposes.”
From September 6 to September 13, “in the event that the CAISO determines that generation from the Specified Resources is necessary to meet the exceptional levels of electricity demand that the CAISO anticipates in California, I direct the CAISO to dispatch such unit or units and to order their operation only as needed to maintain the reliability of the power grid in California between the hours of 14:00 Pacific Daylight Time and 22:00 Pacific Daylight Time on days when the demand on the CAISO system exceeds expected energy and reserve requirements,” wrote Walker.
The order also said that CAISO should select the combination of units that meets the reliability emergency and minimizes environmental impact. “Consistent with good utility practice, the CAISO shall exhaust all reasonably and practically available resources, including demand response and identified behind-the-meter generation resources to the extent that such resources provide support to maintain grid reliability, prior to dispatching the Specified Resources.”
The petition that CAISO sent to the DOE and the emergency order are available here.
Public Power Safety Shutoffs
Meanwhile, investor-owned Pacific Gas and Electric Company (PG&E) on Sept. 8 confirmed that customers in the Sierra Foothills, Northern Sierra and elevated North Bay terrain who were notified of an impending Public Safety Power Shutoff (PSPS) were without power.
The PSPS event was affecting approximately 172,000 customers in 22 counties: Alpine, Amador, Butte, Calaveras, El Dorado, Humboldt, Lake, Lassen, Mariposa, Napa, Nevada, Placer, Plumas, Shasta, Sierra, Siskiyou, Sonoma, Tehama, Trinity, Tuolumne and Yuba, PG&E reported.
The process to turn off power to these counties was completed between approximately 9 p.m. Monday evening and 6 a.m. Tuesday morning. Power was scheduled to be shut off in Kern County at approximately 2 p.m. Tuesday.
“PG&E only undertakes a PSPS as a last resort, when it is necessary to do so to protect public safety from extreme wildfire threat,” it said.
The PSPS decision was based on forecasts of dry, hot weather with strong winds that pose significant fire risk. The National Weather Service has placed most of Northern and Southern California, including 1.5 million PG&E customers, under Red Flag Warnings for fire danger.
Forecasts indicate that the peak period of winds should end Wednesday morning, the utility said.
LADWP experienced power outages over the weekend
The Los Angeles Department of Water and Power reported experiencing power outages over the weekend.
On the evening of Monday, Sept. 7, LADWP reported that crews continued to make progress throughout the day, restoring power to over 22,000 customers since that morning. As of 9 p.m., 23,000 customers remained without power as crews continued working 16-hour shifts around the clock, it reported in a news release.
CMUA details how public power utilities helped CAISO respond to heat wave, stress on grid
In a recent letter to a California state lawmaker, the California Municipal Utilities Association (CMUA) details how public power utilities in the state took a number of actions on the supply and demand side to help CAISO manage stress placed on the California power grid last month due to soaring temperatures.
California last month experienced a record setting heat wave that caused CAISO to initiate at least two Stage 3 emergencies that led to load shedding events, commonly referred to as rolling blackouts.
WAPA, U.S. Bureau of Reclamation tapped hydro to help response to Calif. energy emergency
The Western Area Power Administration and the U.S. Bureau of Reclamation joined forces between Aug. 14 and 19 to generate and transmit roughly 5,400 megawatt-hours in response to California’s energy emergency, the two federal agencies reported in late August.
Energy storage Q2 deployments sees second-highest quarterly total on record
September 8, 2020
by Peter Maloney
APPA News
September 8, 2020
A total of 168 megawatts (MW) were deployed in the second quarter, a 72% increase from the previous quarter and a 117% increase over the same quarter last year.
The increase in year-over-year energy storage installations is the second highest quarterly total recorded, falling just behind the 186.4 MW installed in fourth-quarter 2019, according to Wood Mackenzie and U.S. Energy Storage Association’s (ESA) third quarter 2020 US Energy Storage Monitor report.
The increases came amidst lockdowns and slower business activity as a result of the COVID-19 crisis.
At the outset of the COVID-19 crisis, Wood Mackenzie and ESA lowered their energy storage outlook for 2020, forecasting a 44% decline in commercial and industrial installations and a 39% decrease in residential installations compared with pre-pandemic expectations.
The non-residential energy storage market did decline by 7% quarter-over-quarter, to 29.5 MW, but still booked its fifth-highest level of quarterly deployments because of a surge of installations in Massachusetts, according to the report.
The residential storage sector, however, exceeded expectations in the second quarter with 48.7 MW (112 megawatt-hours) installed in the second quarter, a 10% increase from the previous quarter and a 28% year-over-year increase, which shows that California and Hawaii are moving ahead with installations through coronavirus lockdowns, according to the report.
The increase in residential storage installations is notable because home batteries are almost always sold as an add-on to rooftop solar, and the leading rooftop solar installations fell in second quarter.
Several leading installers saw solar deployments drop by 20% from the first quarter to the second quarter, the report noted. “Even as the solar market has slowed down slightly, the pairing rate for storage continues to grow,” Daniel Finn-Foley, energy storage director at Wood Mackenzie and an author of the report, said in a statement.
The biggest increase in quarterly energy storage installations came from the front-of-the-meter (FTM) sector, which includes utility scale storage projects. The US FTM market grew more than fourfold compared with the first quarter, hitting its fifth-best quarterly total, 89.8 MW, and the largest second quarter total, the report found.
The authors of the report noted that the FTM sector tends to be volatile because large projects can contribute disproportionately to totals. The second quarter was no exception. A single FTM project came partially online in California, accounting for more than two-thirds of the total FTM installations in the quarter.
The first phase of LS Power’s Gateway energy storage project in the East Otay Mesa community in San Diego County came online in June, adding 62.5 MW to the grid. The full 250 MW capacity of the project is expected online in the third quarter, which should help boost total installations for the year. “We expect the rest of the year to come in strong as growing interest in residential storage, emerging new markets for C&I and massive FTM systems are set to break quarterly records,” Finn-Foley said.
“The year is going to close out in a big way,” Finn-Foley said. “We’re going to top a gigawatt of storage deployed annually for the first time in the U.S. market.”
The authors of the report expect the FTM sector will continue to make up the bulk of the market through 2025, driven by investments from vertically integrated utilities in regulated markets and by developers taking advantage of wholesale market opportunities and incentives.
The authors also expect the residential sector will continue to grow, beating 2020 installations by a factor of six in 2025, and they expect the non-residential sector will be eight times larger than the 2020 market by 2025.
The American Public Power Association has launched the Public Power Energy Storage Tracker, a resource for association members that summarizes energy storage projects undertaken by members that are currently online.
APPA says cybersecurity incentive program is not needed, could hike transmission costs
September 4, 2020
by Paul Ciampoli
APPA News Director
September 4, 2020
An incentive program for cybersecurity investments outlined in a recent Federal Energy Regulatory Commission staff White Paper is not needed to encourage investment in cybersecurity measures and could lead to investment that raises transmission costs for customers without providing meaningful cybersecurity benefits in return, the American Public Power Association recently said.
APPA on Aug. 17 submitted comments at FERC in response to the White Paper, which proposed a new framework for providing transmission incentives to utilities for cybersecurity investments. FERC staff cited “the evolving and increasing threats to the cybersecurity of the electric grid” as the impetus for the Cybersecurity Incentives Policy white paper (Docket No. AD20-19-000).
APPA said that it recognizes that today’s electric grid faces increasing cybersecurity risks, adding that it appreciates FERC staff’s efforts to evaluate how the Commission might facilitate utility investment that could mitigate these risks.
“APPA respectfully submits, however, that the incentive program outlined in the White Paper is not needed to promote prudent public utility investment in cybersecurity measures,” the trade group said.
“On the contrary if adopted, the White Paper framework could result in investment that raises transmission costs for customers without providing meaningful cybersecurity benefits in return,” APPA said.
APPA sees several threshold problems
APPA said that there are several threshold problems with the incentive approaches described in the White Paper.
First, neither generic application of North American Electric Reliability Corporation (NERC) critical infrastructure protection (CIP) reliability standard requirements to lower impact Bulk Electric System (BES) cyber systems that are not currently subject to those requirements, nor broad adoption of National Institute of Standards and Technology (NIST) framework security controls “would necessarily result in a meaningful increase in cybersecurity, as the White Paper appears to assume,” APPA said.
“This is not to say that use of these approaches in certain circumstances would not have cybersecurity benefits, but APPA questions the assumption that widespread adoption of these approaches as contemplated in the White Paper would be a cost-effective way of achieving meaningful cybersecurity outcomes.”
Second, APPA argued that even in circumstances where more robust cybersecurity investment might be beneficial, new incentives or cost recovery mechanisms should not be necessary to promote it.
It said that the record from a March 2019 technical conference convened by the Commission and the Department of Energy strongly supports this conclusion. “Awarding incentives where they are not needed would contravene longstanding requirements for just and reasonable incentive rates,” APPA said.
Moreover, as the White Paper notes, it is not clear that incentives – particularly the proposed 200 basis point return on equity adder – would prompt utilities to make the investments that the White Paper describes, APPA told FERC.
“This lack of response would not be a problem to the extent that investments would not have substantially reduced cybersecurity risk, but if the Commission’s goal is to revise its policies to encourage prudent and cost-effective cybersecurity investment, ROE adders may not be an effective way to accomplish the goal.”
Rising transmission costs
APPA said that FERC must be cognizant of the fact that customers continue to incur rising transmission costs.
While the trade group supports prudent expenditures to help secure the transmission system against cyber threats, it said that rate incentives that are unnecessary or even counter-productive will needlessly increase customer costs without providing commensurate consumer benefits.
Unjustified incentives could be particularly problematic for public power utilities, many of which are dependent on public utilities for transmission service, APPA pointed out. The costs of incentives paid by public power utilities in their transmission rates might be on top of infrastructure security costs incurred by public power utilities on their own systems to guard against growing cyber risks, it said.
APPA says FERC should adopt changes if it moves forward with White Paper proposal
If FERC decides to move forward with the White Paper proposal, it should adopt a number of changes and clarifications, APPA said.
Specifically, APPA argued that applicants under either of the two incentive approaches described in the Whiter Paper should be required to demonstrate how the investments will directly result in significant cybersecurity benefits for Commission-jurisdictional transmission facilities, with reference to quantifiable metrics for the expected enhanced cybersecurity benefits.
APPA took issue with the White Paper’s proposal to presume that extending the application of CIP reliability standards to lower impact BES cyber systems will result in significant benefits.
In addition, an entity seeking an incentive should be required to show that there is at least a rational relationship between each incentive sought and the decision to invest in the project, consistent with the requirements of just and reasonable incentive rates.
APPA offered a number of other suggested changes including:
- Incentives should be limited to the portion of the overall project investment that the applicant demonstrates is necessary to produce significant reliability benefits beyond those provided by the CIP reliability standards;
- ROE adders should be limited to the cost of the project used in the application for incentives;
- ROE adders on cybersecurity investment should be subject to any overall basis point cap on a utility’s ROE incentives; and
- Any new incentive rules or policy grounded in FPA section 219 would need to be limited to cybersecurity investments that enhance the reliability of transmission facilities
Reply comments
In reply comments filed on Sept. 1 at FERC in the proceeding, APPA said that if the Commission ultimately proceeds with an incentive program for cybersecurity investments, it should not accept calls to expand the program beyond the framework described in the White Paper.
FERC staff correctly recognizes that an incentive framework must include an approach for identifying the cybersecurity investments that FERC seeks to incentivize, APPA said.
An incentive program that allows utilities to request incentives for any activity or investment that provides a benefit to the reliability and security of the transmission system, or that allegedly constitutes an application of the NIST Framework, “does not clearly identify which investments are eligible for incentives.”
Such an approach would increase the likelihood that utilities would seek incentives for routine cybersecurity measures that are simply good utility practice, and it would exacerbate the already considerable challenges that would be presented in trying to assess “compliance” with the NIST framework under the White Paper’s proposal, APPA argued.
APPA went on to note that incentives under Federal Power Act section 219 are limited to those that promote investments in transmission facilities or technologies.
However, a number of commenters in the proceeding argued that the Commission should require transmission customers to fund incentives for enterprise-wide cybersecurity investments, or even cybersecurity expenditures by merchant generators.
“The commenters urging such broad eligibility for transmission incentives make no effort to reconcile their positions with the text of FPA section 219, even though the White Paper specifically requested input on this issue.”
Even if section 219 were not limited to incentives that promote transmission investment, cost causation principles would preclude requiring transmission customers under cost-based rates to subsidize cybersecurity investments benefitting other corporate businesses or functions, APPA said.
Thinking big in software transition pays off for Concord, Mass., utility
September 4, 2020
by Peter Maloney
APPA News
September 4, 2020
When Concord Municipal Light Plant (CMLP) received notice that its financial and accounting software would no longer be supported, it turned out to be a good thing.
When a vendor stops supporting an application, it can create quite a headache for an organization, setting off a time-consuming and disruptive process that involves finding and testing a new software package and then transitioning to the new program, migrating data and retraining employees.
That is why organizations do not make the decision to switch software lightly, let alone switching the software platform across the entire enterprise.
Originally, the Massachusetts public power utility was just looking to replace its financial software, but as CMLP explored its options, “we quickly realized the value of what an enterprise system could do for us,” Dave Wood, the utility’s director, said.
The Concord utility had multiple software systems, but they did not talk to each other. That meant they did not have access to a service order system to track projects and their progress. It also meant CMLP had to maintain two separate databases, one for the town’s electric and broadband customers, the other for its water and sewer customers.
CMLP’s customer service representatives had to log out of one database to see the information on the other. In addition, the customer information was not always in harmony. A customer’s information in one system, such as an address, could be different in the other system. It was a source of confusion and inefficiency. And, despite the fact that information was being stored and processed digitally, many back-office functions were still being recorded and managed on paper or by email.
In addition, CMLP was in the midst of a program to transition to advanced metering infrastructure (AMI). Even though the utility had already installed smart meters for about 10% of its customers, the data had to be entered manually into the customer information system, an inefficient and error-prone process.
As CMLP did its homework, Wood began to see the benefits of looking at the larger picture. An enterprise solution could unite the utility’s accounting, customer service, metering, purchasing, engineering and operations, and water service functions on one platform. It also became clear to Wood and his team that the necessity of finding a new financial and accounting software package was an opportunity to realize two other goals the utility had set for itself: to have all customer information in a single database and to have one point of contact for customers for all the town’s services.
One of the biggest factors driving the decision to go with an enterprise software solution was the ability to combine customer service and billing into one department, Carole Hilton, the utility’s customer service administrator, said. “That required one database for all the town’s utilities, and there were not a lot of vendors who would convert our existing separate databases into one,” she said.
After a year of deciding on goals, mapping out the scope of work, reviewing offers from various vendors, and talking to utilities that had been through a similar transition, CMLP chose National Information Solutions Cooperative (NISC) to supply an enterprise solution to serve all its needs. “NISC was very attractive,” Wood said. “It handled everything,” from combining the utility’s separate databases and bridging previously separate departments within the utility, to guidance on the transition process itself.
CMLP had its own project management team for the software transition, but also signed on to use NISC’s assistance in the form of an enterprise project manager to help guide the utility through the transition.
Although it was more expensive than just replacing the financial software, an enterprise solution also had the advantage of bringing CMLP into the “new era” and preparing it for coming technological changes, Wood said.
And after factoring in the cost of the maintenance agreement for the previous financial software, the enterprise approach proved to be “very favorable and, from a budget standpoint, not a heck of a lot of difference,” Wood said. “We are paying a little more but are getting so much more.”
Originally, CMLP was going to begin the transition by switching over its finance department, but with guidance from NISC, the utility began the process with its billing department. “We were a little nervous at first, but at the end of the day what they suggested was the right move for us,” Wood said. “I’m glad we followed their advice.”
Since signing on with NISC about two years ago, CMLP is nearing the finish line with its software transformation.
Although some details still remain, the customer piece of the installation has been in place for about a year, Hilton said. The accounting and business solution portions were installed about six to eight months ago, and the installation of software to handle engineering and operations was begun about three or four months ago and is still under way.
CMLP was in the midst of implementing the transition for engineering and operations when the COVID-19 pandemic hit, which slowed implementation progress because staff had broken into groups that worked on alternating days and were focused on providing essential services only.
Overall, switching to a single enterprise solution was “an enormous project for our team,” Wood said, but “the effort has paid off.”
Switching its engineering and operations software, for instance, particularly for processing service orders, required redefining tasks and workflows, in part, because work orders could now be issued more quickly and precisely. “It was a very big step for us” and a “game changer,” Wood said.
NISC’s integrated solutions are also a boon for CMLP’s broadband offerings. Network provisioning and billing enabling technicians to play the roles of account administrator, customer service rep and network support tech, all on one screen.
“NISC has been a terrific partner in every sense of the word,” Hilton said. “Their project resources guided us through our implementation with expert knowledge of the utility industry plus sharing their own extensive experience as subject matter experts.” The process was also helpful in understanding the capabilities of iVUE and NISC’s other modules, as well as informing the redesign of CMLP’s best practices, she said.
NISC’s user interface for employees is iVUE. The interface draws together data from billing and collections, customer histories, bill adjustments and service orders and allows employees to communicate directly between different departments, such as engineering and meter crews and the water department.
NISC also offers iVUE Connect—which ties into and uses the data from the iVUE system—and SmartHub, an interface that allows customers to manage their accounts, pay their bills, track their energy usage and communicate with their utility from a computer or mobile device.
“The iVUE experience has made my tasks simpler, quicker, more organized, and researching is easier since everything is all in iVUE,” CMLP Purchasing Administrator Rhonda Buscemi said. And even though the installation phase of CMLP’s project is nearing completion, Buscemi is pleased with the continuing support NISC offers. “If you are stumped on how to do something, being able to go into the NISC Community, NISC’s online communications platform for Members and employees, to find information on the issue or adding a question is a great resource for help.”
For more information about NISC, visit NISC’s website.
Gas-fired generation hit a record on July 27, EIA says
September 3, 2020
by Paul Ciampoli
APPA News Director
September 3, 2020
Natural gas-fired generation in the lower 48 states hit an all-time high of 316 gigawatts (GW) on July 27, according to data from the Energy Information Administration (EIA).
The EIA noted that the record coincided with a record level of natural gas consumed by generating plants, so-called gas burn, set on the same day as reported by S&P Global Platts.
Platts estimates put gas burn at 47.2 billion cubic feet (Bcf). The previous record, 45.4 Bcf, was set on Aug. 6, 2019. In addition to beating the previous record, gas-burn exceeded 45.4 Bcf per day on seven days in July 2020 and one day in August.
The record level of gas-fired generation is the result of a combination of factors, namely, high demand in response to searing summer temperatures, relatively low natural gas prices, the start-up of new gas-fired capacity and increased natural gas consumption in the power sector, EIA said.
The use of natural gas for power generation has been rising for years. Earlier this month, the EIA noted that gas-fired generation in the lower 48 states increased nearly 55,000 gigawatt hours (GWh), or 9%, in the first half of 2020 compared with the first half of 2019 despite a 5% decline in total electricity generation as a result of COVID-19 mitigation efforts.
The increased use of gas-fired generation is fueled by persistently low gas prices. The EIA noted that natural gas prices at the benchmark Henry Hub in Louisiana averaged $1.73 per million British thermal units (MMBtu) for gas delivered on July 27. And, from June 1 to July 30, Henry Hub prices averaged $1.64/MMBtu, 30% lower than the prices during the same period in 2019. Adjusted for inflation, the average price is the lowest for that period since at least 1993, the EIA said, citing data from Natural Gas Intelligence.
Of the electricity generated on July 27 in the lower 48 states, natural gas held the largest share at 45%, followed by coal with a 24% share, nuclear power had a 17% share, renewable energy a 12% share, and other sources a 3% share, the EIA noted.
Low gas prices are also prompting utilities and developers to convert coal-fired plants to burn gas. A total of 121 coal plants were repurposed to burn other types of fuels between 2011 and 2019. Most of those plants, 103, were converted to burn natural gas or replaced by a gas-fired plant.
Natural gas is also the leading fuel for new fossil fuel generation. Between January 2019 and May 2020, the United States added 13.8 GW of gas-fired capacity and retired 5.4 GW for a net gain of 8.4 GW, making gas-fired generation second only to the 12.6 GW of onshore wind power built in the same period, according to EIA’s Preliminary Monthly Electric Generator Inventory.
Most of the new gas-fired capacity is in the form of combined-cycle plants that use the latest technology to achieve high efficiency ratings, the EIA said, adding that the retired gas plants were less efficient steam plants or combustion turbines.