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California PUC realigns energy efficiency to increase equity and long-term focus

June 2, 2021

by Peter Maloney
APPA News
June 2, 2021

The California Public Utilities Commission (CPUC), in a late May decision, reformed its approach to energy efficiency programs to better align them with greenhouse gas (GHG) emissions reduction, support for customer equity, and long-term grid stability.

The decision, Docket #: R.13-11-005, changes how the goals for energy efficiency programs in the state are set and evaluated and the processes for setting those metrics.

The CPUC released the proposed decision in April.

The decision calls for a shift in energy efficiency goals to long-term GHG reductions and grid benefits and away from setting goals based on savings of kilowatt-hours, kilowatts, and therms. The new “total system benefit” metric, expressed in dollar value, takes lifecycle energy, capacity into account to better target “high value” load reduction and “longer-duration energy savings while being fuel agnostic,” according to the decision.

The decision also changes the way energy efficiency programs are measured, shifting cost effectiveness evaluations away from an assessment of energy efficiency portfolio-wide economic benefit to an approach that segments the portfolio into categories and evaluates each category based on the primary purpose of the program. The new method is aimed at supporting the continuation of programs that “serve important functions but whose benefits are not appropriately captured by cost effectiveness ratios.”

In terms of process, the decision replaces the 10-year business plan and yearly utility filings with the CPUC with a 4-year application that includes a strategic planning component.

The decision calls for Investor-owned utilities to file new energy efficiency program applications in February 2022 that will take effect by January 2024.

The CPUC said that this summer it would continue to work to improve energy efficiency programs through the consideration of new energy efficiency goals and the addition of details to the changes implemented in the new decision.

“This decision helps to continue California’s leadership in energy efficiency by reducing the conflict between cost-effectiveness and other equally or more important policy objectives that address equity and provide market support for our energy efficiency programs,” Commissioner Genevieve Shiroma said in a statement. “It further maximizes energy efficiency measures for longer duration greenhouse gas reductions in support of our integrated resource plan and in delivering grid benefits.”

Retail electric sales to rise this summer led by commercial, industrial demand: EIA

June 2, 2021

by Peter Maloney
APPA News
June 2, 2021

Retail U.S. electricity sales will be 1.5 percent higher this summer than last summer with much of the growth coming from the commercial and industrial sectors, according to new estimates from the Energy Information Administration (EIA).

The projections reflect an improving economy following the pandemic-related downturn in 2020, the EIA said in its Summer 2021 Electricity Industry Outlook, a supplement to the agency’s Short-Term Energy Outlook.

Based on economic forecasts from IHS Markit, the EIA expects U.S. 2021 GDP to grow by 6.2 percent. The EIA forecasts the rebound in economic activity will push retail sales to the industrial sector in June, July, and August to be 4.5 percent higher than in the same period last year.

The EIA also sees increased economic activity boosting commercial sector demand for electricity. The agency forecasts retail electricity sales to the commercial sector this summer will be 2.6 percent higher than last summer but still 3 percent less than in 2019.

At the same time, the EIA projects a small decline in residential sector retail electricity demand this summer with sales 0.9 percent lower than last summer, mostly because of milder weather forecasts from the National Oceanic and Atmospheric Administration. The projected decrease in retail sales will be offset somewhat by growth in the number of residential customers and by more people working from home than in past years, the EIA noted.

The EIA forecasts a 1.6 percent increase in the number of residential electricity customers in 2021 because of a rebound in household formation after the economic slowdown of 2020, but also forecasts a decline in the amount of electricity consumed by a typical home. The EIA expects electricity use per residential customer to average 1,090 kWh per month between June and August 2021, which would be 2.5 percent less than last summer.

Between June and August 2020, retail electricity sales across all sectors totaled 1,055 billion kilowatt hours (kWh), the lowest level since the summer of 2015. Retail electricity sales to the commercial and industrial sectors showed an even steeper decline, totaling 357 billion kWh last summer, the lowest level since 2004. While retail sales to the industrial sector last summer totaled 239 billion kWh, the lowest level since the 2009 recession.

Residential electricity sales, meanwhile, reached a record high, hitting 457 billion kWh between June and August 2020. Near record warm temperatures contributed to the rise, as did the fact that more people were working from home and spending more time in their homes as a result of COVID-19 stay-at-home orders and social distancing guidelines, the EIA said.

DOE releases interactive tool for tracking microgrids installed throughout the U.S.

June 1, 2021

by Paul Ciampoli
APPA News Director
June 1, 2021

The U.S. Department of Energy (DOE) on May 26 announced the release of a new, interactive tool for tracking microgrids installed throughout the U.S.

The DOE noted that a microgrid is a local grid with an independent source of energy capable of disconnecting or “islanding” from the utility grid. Microgrids improve resilience by allowing critical facilities to continue operating in the event of a utility-grid outage. For manufacturers and industrial facilities, microgrids can also help ensure delivery of the high-quality, reliable electricity necessary to maintain today’s increasingly digitized operations, DOE said.

The Microgrid Installation Database includes a comprehensive listing of the country’s 461 operational microgrids that provide a total of 3.1 gigawatts of electricity. The information, which is updated on a monthly basis, is presented in a tabular format to help users easily access and sort data, DOE said.

The site features an interactive map of microgrid installations across the U.S., he ability to filter and search for sites by technology, end-user application, generation and storage capacity, and operating year, and downloadable data files.

The database is available here.

The new Microgrid Installation Database is co-located with a Combined Heat and Power (CHP) Installation Database, which captures the nation’s CHP installations. CHP technologies allow facilities to generate on-site electric power and useful thermal energy from a single fuel source.

Public power utilities and microgrids

A number of public power utilities are actively pursuing or have completed microgrid projects.

Washington State Gov. Jay Inslee, a Democrat, recently visited a Snohomish County PUD (Everett, WA) microgrid site. The Arlington microgrid is currently undergoing testing and commissioning and should be fully operational in a few months.

Meanwhile, the first phase of the Virgin Islands Water and Power Authority’s (WAPA) plan to develop an 18-megawatt (MW) microgrid, complete with a battery storage system, for the west end of St. Croix, Virgin Islands, has received an initial allocation of federal funding, WAPA said on April 9.

Also in April, Chattanooga, Tenn., Mayor Andy Berke, EPB President and CEO David Wade, Chattanooga Police Chief David Roddy, and Chattanooga Fire Chief Phil Hyman confirmed that construction would soon begin on a new collaborative microgrid project between the City of Chattanooga and EPB. The project aims to increase resilience and redundancy of power supply to the city’s public safety agencies via on-site solar arrays, traditional backup generation, battery storage and a microgrid controller.

And in January 2021, Lincoln Electric System in Nebraska reported that it put a 29-megawatt (MW) microgrid in service at virtually no cost.

FERC orders firm to respond to FTR manipulation allegations

June 1, 2021

by Paul Ciampoli
APPA News Director
June 1, 2021

The Federal Energy Regulatory Commission (FERC) recently ordered GreenHat Energy LLC and its owners to explain why they should not pay a total of $229 million in civil penalties and disgorge nearly $13.1 million in unjust profits for alleged electric market manipulation.

In a report attached to FERC’s May 20 order to show cause, FERC’s Office of Enforcement staff alleges that the GreenHat parties violated the Federal Power Act and the PJM Interconnection LLC’s tariff and operating agreement by engaging in a manipulative scheme in the financial transmission rights (FTR) market.

The order directs GreenHat, John Bartholomew and Kevin Ziegenhorn to show why they should not be assessed civil penalties of $179 million, $25 million, and $25 million, respectively.

GreenHat, Bartholomew, Ziegenhorn and the estate of Andrew Kittell, who was the third owner of the company, also must explain why they should not be required to disgorge $13.1 million in unjust profits, plus interest. Issuance of the order does not indicate Commission adoption or endorsement of the staff report.

FERC noted that between 2015 and 2018, GreenHat acquired the largest FTR portfolio in PJM.  In June 2018, it defaulted on the portfolio, leaving other PJM members, including many utilities serving retail customers, to cover more than $179 million in losses over the next three years. At the time of its default in 2018, GreenHat had only $559,447 in collateral on deposit with PJM.

FERC Enforcement staff alleges that GreenHat’s conduct was unlawful in several ways. Among them are that GreenHat sent false price signals into the PJM market by purchasing FTRs based not on expected profitability but on which FTRs it could acquire with minimal collateral, GreenHat made deliberately false statements to PJM to try to avoid a collateral call and GreenHat rigged FTR auctions by using inside information about Shell Energy North America (US) LP’s offers (on the seller side of the auction) in designing its own bids for the same FTRs (on the buyer side of the auction). 

Although the alleged scheme generated enormous losses that were borne by all other PJM members, it was highly profitable for GreenHat’s owners, FERC said. 

Kittell, Bartholomew and Ziegenhorn realized that although GreenHat’s enormous portfolio was unprofitable overall, it included some “winners,” that is, FTRs that increased in value after GreenHat bought them.  GreenHat made four deals in which it sold winners to third parties for a total of $13.1 million in cash.

According to the Enforcement staff report, this alleged scheme is an example of a type of fraud in which perpetrators acquire assets with no intent to pay for them, and then try to turn the assets into immediate cash for themselves.

The GreenHat parties have 30 days to respond to the Commission’s order.

Commissioner Danly concurrence

In a concurrence on the FERC order, Commissioner James Danly said that he supports the Commission’s issuance of an Order to Show Cause. “As the primary regulator of PJM’s FTR market, the Commission has the responsibility to make an official public determination as to whether or not GreenHat’s default was the result of fraud or manipulation,” he wrote.

“But my support for the issuance of the Order to Show Cause is based solely on my belief that the Commission has the responsibility to issue an official pronouncement as to whether GreenHat engaged in fraud or manipulation. My support of this order should not be read as an indication that I have reached any conclusions at this time on the ultimate question of GreenHat’s liability.  I am issuing this concurring statement to provide some guidance to the parties as to what I believe would be helpful for them to address in their submissions in response to the show cause order,” he said.

Based on his review of the Enforcement Staff Report and Recommendation, Danly said he has questions and concerns about both Enforcement’s and GreenHat’s positions, which he details in his concurrence, which is available here.

FERC Chairman says Commission cannot keep changing ROE methodology

June 1, 2021

by Paul Ciampoli
APPA News Director
June 1, 2021

The Federal Energy Regulatory Commission (FERC) cannot keep changing its return on equity (ROE) methodology, FERC Chairman Richard Glick recently said in comments at a Commission meeting, adding that companies need to have some level of regulatory certainty if they are going to continue to make multi-million and, in some cases, multi-billion dollar investment decisions.

Glick made his remarks at FERC’s monthly open meeting on May 20 in the context of a Commission order that set a ROE for an Entergy unit power sales agreement.  The order employs the same methodology the Commission used when establishing the ROE for Midcontinent Independent System Operator, Inc.’s (MISO) transmission owners in Opinion Numbers 569-A and 569-B. 

Glick noted that when FERC issued Opinion Numbers 569-A and 569-B, he expressed concern about the Commission’s decision to add the risk premium model “because the first MISO ROE order had thoroughly explained why the risk premium model is not an appropriate tool for assessing a just and reasonable ROE.” While he continues to have his concerns, he also believes that FERC cannot keep altering its ROE methodology. 

FERC in May 2020 revised its method for analyzing the base ROE used in setting cost-based public utility transmission rates.  FERC’s reference to “public utility” refers to utilities that are subject to FERC’s rate jurisdiction under the Federal Power Act.

The changes adopted by the Commission through the issuance of Opinion No. 569-A are likely to result in higher allowed ROEs than would have resulted from the method outlined in Opinion No. 569 issued in November 2019 and could also make it more difficult to challenge existing ROEs as unjust and unreasonable. 

In Opinion No. 569, FERC said it will use the discounted cash flow (DCF) methodology and capital asset pricing model (CAPM) to determine if an existing base ROE is unjust and unreasonable, and, if so, what replacement ROE is appropriate. Applying the new methodology in a pair of complaints against MISO transmission owners, Opinion No. 569 determined that their base ROE should be 9.88 percent.

FERC’s order on rehearing revised the methodology established in Opinion No. 569 and found that the MISO transmission owners’ base ROE should be set at 10.02 percent.

In response to FERC’s decision, Glick concurred in part and dissented in part.

Commissioners offer dissent, concurrence

FERC Commissioner Mark Christie offered a concurrence to FERC’s May 20 order, while Commissioner Allison Clements dissented from the decision.

In his concurrence, Christie said that while the order “correctly applies the Commission’s ROE methodology set forth in Order No. 569 and its progeny, I believe that the Commission’s policy is flawed to the extent it replaces judgment with rote application of pre-set formulae and should be reviewed in a general proceeding to consider possible changes to that methodology.  Second, I believe the Commission can, and should, issue ROE orders much more expeditiously in the future and matters of procedure, including setting strict procedural deadlines for FERC itself to follow, should be part of any such future proceeding on the ROE issue.

Clements said that she agrees that the order reasonably applies the Commission’s return on equity ROE policy established in Order 569-A to the facts in these proceedings. “I dissent because I do not believe our existing methodology for setting ROEs in jurisdictional cost-based rates fully carries out our consumer protection responsibility under the Federal Power Act.  As a result, I cannot conclude that the ROE established in these proceedings is just and reasonable,” she wrote.

She said that FERC should revisit its existing ROE policy. “I appreciate that this policy has been unsettled for years, a state that increases investment uncertainty and extends litigation. To be sure, I share the goal of a stable ROE policy that will speed rate proceedings and allow for timely ROE updates as market conditions change. But we should not double down on the desire for near-term stability to strong detriment of consumer protection, and I worry our current ROE policy does just that.”

Poll finds strong support for the creation of a consumer-owned utility in Maine

May 31, 2021

by Paul Ciampoli
APPA News Director
May 31, 2021

Newly conducted public opinion polling shows that 75% of registered voters from across the state of Maine say they support the idea of replacing Central Maine Power and Versant with a local non-profit consumer-owned utility, according to research conducted by SurveyUSA.

According to SurveyUSA, 38% strongly support the idea; 37% say they somewhat support. Just 10% are opposed to the idea, while 7% somewhat oppose and 3% strongly oppose.

The research was conducted by SurveyUSA for a group call Our Power, which supports the creation of a consumer-owned utility in the state.

Support is strongest among 35-to-49-year-olds (85%). Support is higher in urban parts of Maine (81%) than in suburban (72%) or rural (62%) portions of the state. Even among those rural Maine residents with 62% support, the lowest support for the idea among any subgroup, 28% strongly support and 34% somewhat support the idea of creating a consumer-owned utility.

According to the poll, 82% of Versant customers and 74% of Central Maine Power customers say they support the idea.

“Opposition to the concept, while weak in general, does have a significant correlation with both age and with ideology,” SurveyUSA said. While just 4% of those under age 50 are opposed, 14% of those 50+ are opposed, and opposition among conservatives, at 16%, is notably higher than among moderates (6%) or liberals (5%).

SurveyUSA said that a few of the major reasons Maine residents may be so strongly supportive of the consumer-owned utility concept are:

Ursula Schryver, Vice President, Strategic Member Engagement and Education, at the American Public Power Association (APPA) recently appeared before a hearing held by Maine state lawmakers related to the bill.

She noted that there has been an increase in the number of communities exploring the public power option, a trend that has been driven by a number of factors including reliability, the desire for renewable energy options and increased economic development. Schryver, who made her comments at a May 20 hearing held by the Maine Legislature’s Energy, Utilities, and Technology Committee, also detailed the resources that APPA offers when it comes to municipalization.

The Maine committee hearing focused on a bill, LD 1708, which would create a consumer owned utility that would take over the electric service now provided by Central Maine Power and Versant Power. Central Maine Power Company and Versant Power (formerly known as Emera Maine), are majority owned by Iberdrola of Spain and Emera of Canada, respectively.

At the hearing, Schryver noted that her comments were neither for or against the legislation “primarily because APPA doesn’t weigh in on decisions made by individual communities.” APPA, she noted, serves as a resource and APPA believes that every community needs to make a decision that is right for itself.

Bill allows public power to receive refundable direct payment for energy tax credits

May 27, 2021

by Paul Ciampoli
APPA News Director
May 27, 2021

The Clean Energy for America Act (CEA), which includes a provision to allow public power to receive refundable direct payment for energy tax credits, is headed to the Senate floor after debate and amendment on May 26 by the Senate Finance Committee.

As amended, the CEA provides $260 billion in tax relief over the next decade and would replace the current investment tax credit (ITC) and production tax credit (PTC) with technology neutral ITCs and PTCs. As part of these revisions, the bill would allow merchant power generators, investor-owned utilities, public power utilities, rural electric cooperatives and Indian tribal governments to receive refundable direct payments of the ITC and PTC. The Joint Committee on Taxation estimates that roughly $50 billion of such payments would be made over the next decade.

The original bill would have denied access to refundable tax credits to public power utilities, rural electric cooperatives, and Indian tribal governments.

However, the American Public Power Association, the Large Public Power Council (LPPC), and National Rural Electric Cooperative Association (NRECA) joined in advocating for their inclusion. As a result, committee member Sen. Michael Bennet, D-Colo., offered a direct pay amendment that was eventually adopted as part of a broader package of amendments to the original version of the bill.

“We should make these tax incentives accessible to electric coops, public power companies, and tribes,” Bennet said during markup of the bill. “They are doing yeoman’s work to transition to clean energy and drive opportunity in rural America and we should support them.”

In a May 26 letter to Bennet, Joy Ditto, President and CEO of APPA, Jim Matheson, CEO of NRECA, and John Di Stasio, President of the LPPC, praised his amendment.

As drafted, the CEA “allowed some utilities to immediately receive the benefit of certain energy tax credits. With the inclusion of your amendment, it now also would allow public power utilities, rural electric cooperatives, and Indian tribal governments to do so. That would mean more local projects, with local jobs, under local control. Having direct ownership as an option also will help our members develop a generation mix that best suits the needs of the customers,” wrote Ditto, Matheson and Di Stasio.

Inclusion of refundable direct payment tax credits in the CEA means that leading proposals in the House (H.R. 848, the GREEN Act) and Senate are now in agreement on the issue. If enacted into final law, this would be the first time in the history of energy-related tax credits that public power utilities would truly have equal access to such credits.

Bennet’s amendment retains current law prohibitions on receiving tax credits for projects receiving “subsidized” financing, including tax-exempt financing. While final legislative text is not available, it appears the intention is to preclude the use of tax-exempt financing for a project that also receives energy-related refundable tax credits. But analysis done by APPA and others shows that the value of the investment tax credit and production tax credit substantially exceeds the cost of losing the ability to issue tax-exempt debt to finance such projects.

In addition, “Chairman’s Modifications” to the CEA from Sen. Ron Wyden, D-Ore., Chairman of the Senate Finance Committee, struck a provision that would have allowed public power utilities and rural electric cooperatives to issue taxable direct payment Clean Energy Bonds (CEBs). While such bonds could have been highly valuable for long-lived assets, many of the assets that utilities will invest in in the near term – including battery storage and wind turbines – have shorter useful lives.

North Iowa Municipal Electric Cooperative Association to offtake power from wind farm

May 27, 2021

by Paul Ciampoli
APPA News Director
May 27, 2021

North Iowa Municipal Electric Cooperative Association (NIMECA), power supplier to 13 public power utilities in northern Iowa, will offtake power from a wind farm in South Dakota that has been operational since September 2020.

The wind farm is Willow Creek Wind, a 103-megawatt project located in Butte County, South Dakota, and joins several other wind farms in NIMECA’s power supply portfolio.

The Hancock County Wind Project is owned by NextEra Energy Resources and is located near Britt, Iowa. The project has 148 Vestas turbines with a capacity of 97.7 MW. NIMECA purchases 3.96 MW of the output of this project. NIMECA has a purchase power agreement to purchase energy from the Hancock County Wind Project.

Crosswinds Energy Project was one of Iowa’s first locally owned wind farms. The project consists of 10 farmer-owners pooling their investments for a 10-turbine wind farm totaling 21 MW. NIMECA purchases 4.4 MW from the project. NIMECA has a purchase power agreement to purchase energy from the Crosswinds Energy Project.

NIMECA is a municipal joint action agency serving 13 municipal electric utilities located in Iowa.

TVA unveils solar facility partnership with Facebook, RWE Renewables

May 27, 2021

by Paul Ciampoli
APPA News Director
May 27, 2021

The Tennessee Valley Authority recently announced a Green Invest partnership with Facebook and RWE Renewables that will result in the construction of a 150-megawatt (MW) solar facility. Facebook will use 110-MW of the solar energy to support their data center operations in Gallatin, Tenn., and the broader Tennessee Valley.  

Through its Green Invest program, TVA matches demand for green power from large business and industrial customers with renewable projects that TVA puts together with its development partners. The utility says the program confers to commercial customers the benefits of TVA’s scale and negotiating expertise in building power projects.  Since 2018, TVA’s Green Invest program has attracted nearly $2.7 billion in solar investment and procured over 2,100 megawatts of solar on behalf of its customers.

TVA is partnering with RWE to develop the $140 million solar farm. RWE, through a long-term power purchase agreement with TVA, will own and operate the plant, which will be located near Millington, Tenn.

In April, Facebook announced that its operations are now supported by 100% renewable energy. To support that goal, in the last year, Facebook has signed Green Invest agreements for 475 MW of new solar to be built in Tennessee, Mississippi, and Kentucky.

Since 2018, Facebook has agreed to purchase a total of 852 megawatts of power generated by multiple solar farms linked into the TVA electric grid.  

Since October, TVA has increased its contracted solar capacity by 60%.   

Jeff Lyash, President and CEO of TVA, discussed the Green Invest program in a recent episode of the American Public Power Association’s Public Power Now podcast.

NERC summer assessment warns of potential energy shortfalls

May 26, 2021

by Paul Ciampoli
APPA News Director
May 26, 2021

Parts of North America are at elevated or high risk of energy shortfalls this summer during above-normal peak temperatures, the North American Electric Reliability Corporation (NERC) warns in its 2021 summer reliability assessment, which it released on May 26,

While NERC’s risk scenario analysis shows adequate resources and energy for most of North America, Texas, New England, the Midcontinent Independent System Operator and parts of the West are at an elevated risk of energy emergencies, NERC said.

In the high risk category is California, which relies on large energy imports during peak demand scenarios and when solar resource output retreats in the evening hours. While more than 3 gigawatts of additional resources are expected in California this summer compared to 2020, most will be solar photovoltaic (PV) generation, NERC said.

While these plants can provide energy to support peak demand, solar PV output falls off rapidly in late afternoon while high demand often remains, NERC noted. “Reliance on imports during these periods is an increasing reliability risk,” NERC said.

While actions taken by the California Public Utilities Commission, California Independent System Operator and utilities to procure additional resources will help, the Western Interconnection’s increase in demand and decline in resources may reduce the amount of surplus capacity available when California is in shortfall, according to NERC.

As identified in the assessment, abnormal conditions that lead to elevated risk include prolonged above-average temperatures, low wind and solar scenarios, reduced transfers due to wildfire-related transmission outages.

The assessment’s other key findings include:

To download the summer reliability assessment, click here.