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FERC issues policy statement on carbon pricing in organized wholesale markets

April 20, 2021

by Paul Ciampoli
APPA News Director
April 20, 2021

The Federal Energy Regulatory Commission (FERC) last week issued a policy statement clarifying how it will consider market rules proposed by regional grid operators that seek to incorporate a state-determined carbon price in organized wholesale electricity markets.

“Carbon pricing has emerged as an important market-based tool in state efforts to reduce greenhouse gas emissions, including in the electricity sector,” FERC noted in a related news release.

The policy statement, which was released at FERC’s April 15 monthly open meeting, takes effect immediately.

FERC in October 2020 proposed a policy statement to clarify that it has jurisdiction over organized wholesale electric market rules that incorporate a state-determined carbon price in those markets. The proposed policy statement also sought to encourage regional electric market operators to explore and consider the benefits of establishing such rules. In September 2020, FERC convened a technical conference at which panelists expressed support for the idea of a carbon dioxide pricing regime for organized wholesale power markets.

Twelve states now impose some version of carbon pricing, with numerous additional states considering them, the final policy statement said. Various entities, including regional grid operators, are examining approaches to incorporating state-determined carbon prices into wholesale electricity markets.

The policy statement explains that wholesale market rules incorporating a state-determined carbon price can fall within the Commission’s jurisdiction under section 205 of the Federal Power Act (FPA).

The policy statement presents a framework for the Commission to exercise its jurisdiction when it reviews any future proposals under FPA section 205 while making clear that the Commission will evaluate any proposal based on the facts and circumstances presented in each proceeding, FERC said.

At the same time, the policy statement does not indicate a preference for carbon pricing over any other state policy. It affirms that whether and how a state chooses to address greenhouse gas emissions is a matter exclusively within that state’s jurisdiction, FERC said.

Danly, Christie weigh in

FERC Commissioners James Danly and Mark Christie concurred in part and dissented in part from the policy statement.

Commissioner Danly noted that any party with a rate on file can submit a Federal Power Act section 205 filing at any time. “I therefore cannot oppose the policy statement’s effective acknowledgement that section 205 has yet to be repealed and thus the Commission is obligated to consider such filings, including those related to carbon pricing initiatives,” he wrote.

“So, as seemingly unnecessary as it may be to announce a policy of ‘non-binding . . . potential considerations,’ I see no basis upon which to oppose that aspect of the policy statement.”

He noted that “non-binding” is the majority’s view of FERC’s jurisdictional powers as they memorialize them in the policy statement. 

“I accordingly dissent from the policy statement to the extent it attempts to prejudge the jurisdictional merits of any future section 205 proposals. Congress grants our jurisdiction, and the courts decree its limits when we overstep it. Anyone considering a section 205 filing following this issuance would be well-advised to read the courts’ decisions in order to inform themselves as to the proper bounds of a legitimate tariff proposal; interested parties should do the same when formulating protests,” he said.

Christie concurred that any filing under section 205 proposing some form of carbon pricing will be evaluated on the facts and circumstances attendant to that filing.

“I dissent from those parts of the Policy Statement to the extent those provisions may be interpreted to appear to invite proposals for carbon pricing that are inconsistent with the following general principles,” he wrote.

He said it is important “to be straightforward with the public about what is being considered in this proceeding. For a government to retain the trust of the people, it is imperative to avoid what George Orwell criticized as language that disguises the truth about government actions behind euphemisms and other distortions.”

Christie said the term carbon “price” as used in this docket “and by many commenters advocating for it, is a carbon tax. This is not just a matter of semantics. Using terms accurately will not only better serve and inform the public, but is essential to clarify, and avoid obfuscating, the legal – including constitutional – questions regarding this Commission’s authority.”

Christie emphasized “that simply labeling a carbon tax proposal accurately does not determine whether it is good or bad public policy, at either federal or state levels. Indeed, that’s not for an administrative agency to decide.”

He said that the broader question providing context for this and future proceedings goes to the heart of democratic government itself and, that is — Who should have the power to tax? 

“And we don’t have to answer that question because the Constitution already has. It makes it clear that only those elected by the people to the legislative branch have this power. Congress can legislate to grant this power to an administrative agency through a clear and specific statute – and take accountability for its decision – but in the case of taxing carbon no one has made a convincing case that Congress has granted this power to FERC,” he wrote.

Christie outlined general questions that he said are pertinent to the proceeding and implicitly raised by the Policy Statement and which have been alluded to by the many commenters:

Another question is whether FERC can allow an RTO/ISO to impose a carbon tax on wholesale sales of power.

“To a certain extent, this question implicates the broader question about the nature of RTOs/ISOs. Some argue that they are merely private utilities and FERC’s only role is to review a rate filing from an RTO/ISO and to approve the filing unless FERC finds it to be ‘unjust, unreasonable or unduly discriminatory,’” Christie said.

“Rather than being little more than private utilities, however, RTOs/ISOs in their present incarnation were essentially created by FERC, as part of the ‘restructuring’ era of the late 1990s/early 2000s, to carry out FERC-driven rate policies,” he said. 

RTOs and ISOs “have evolved to resemble somewhat more the hybrid entities that the British not so lovingly call ‘QANGOs’ (quasi-autonomous non-governmental organizations) than they do purely private utilities. This is especially true with regard to multi-state RTOs/ISOs, in which utilities from many different states participate and in which the interests and policies of those multiple states are implicated. Over the past two decades these organizations have taken on various regulatory roles that are more governmental in nature than private, in some cases literally displacing state regulatory authority,” wrote Christie.

“So, just as FERC cannot directly impose a carbon tax without a clear grant of congressional authorization, arguably it would be a distinction without a difference for FERC to approve a proposal from an RTO/ISO to impose a carbon tax.”

This would include efforts by a multi-state RTO/ISO and its market participants to address “leakage” by penalizing resources in states within the RTO that have not imposed a carbon tax, such as, for example, attempting to levelize the costs of state-imposed carbon taxes by imposing a higher offer floor on untaxed resources from the non-conforming “leakage” states in the RTO/ISO, he said. 

A fourth question is whether FERC can allow an RTO/ISO to recognize carbon taxes imposed by one or more states.

“If a state has used its sovereign authority to impose a carbon tax, directly or indirectly, and that tax is simply incorporated into the production costs of a resource from that state offered into the RTO/ISO markets, there is no reason for FERC to intervene. State-imposed regulatory costs, which of course differ from state to state, are already “baked in” to a bidder’s costs and present no cause for FERC’s concern,” Christie said. 

“Just as with proposals to accommodate other state policies, however, consideration of each specific proposal will be highly fact-intensive and one key question will be to determine whether the line has been crossed between simply recognizing an individual state’s carbon tax versus imposing that state’s tax on generating resources – and consumers – in other states that have not consented to be taxed, an especially salient question in multi-state RTOs/ISOs.”

All future proceedings under Section 205, 206 or other statutory provisions “will, of course, come with their own individual evidentiary records and will be judged individually at that future time. To the extent, however, the Policy Statement may be interpreted to invite proposals inconsistent with the general principles stated above, I respectfully dissent.”

DOE moves to modernize cybersecurity defenses and secure energy sector supply chain

April 20, 2021

by Paul Ciampoli
APPA News Director
April 20, 2021

The U.S. Department of Energy (DOE) on April 20 launched an initiative to enhance the cybersecurity of electric utilities’ industrial control systems (ICS) and secure the energy sector supply chain.

The plan is a coordinated effort between DOE, the electricity industry and the Cybersecurity and Infrastructure Security Agency (CISA).

Over the next 100 days, DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER), in partnership with electric utilities, will continue to advance technologies and systems that will provide cyber visibility, detection, and response capabilities for industrial control systems of electric utilities, DOE said in a news release.

DOE said the initiative modernizes cybersecurity defenses and:

RFI

In addition, DOE released a request for information (RFI) to seek input from electric utilities, energy companies, academia, research laboratories, government agencies, and other stakeholders to inform future recommendations for supply chain security in U.S. energy systems.

The comments received in response to the RFI will enable DOE “to evaluate new executive actions to further secure the nation’s critical infrastructure against malicious cyber activity and strengthen the domestic manufacturing base,” it said.

Accordingly, DOE expects that, during the period of time in which further recommendations are being developed, “utilities will continue to  act in a way that minimizes the risk of installing electric equipment and programmable components  that are subject to foreign adversaries’ ownership, control, or influence.”

The RFI is available on the DOE Office of Electricity’s web page, www.energy.gov/oe/securing-critical-electric-infrastructure.

“Ensuring the cyber and physical security of our nation’s electric grid is a top priority for APPA and its industry and government partners. As threats to our electric system continue to evolve, we are encouraged to see the Administration take action to engage industry in an effort to continuously improve our collective posture,” the American Public Power Association (APPA) said.

“We see this action as complementary to the existing partnership between APPA and DOE-CESER to help smaller public power utilities improve their security by implementing hardware, firmware and software to detect and respond to adversarial activity through information sharing; provide advanced analytics for pinpointing when and where a system was compromised; and employ autonomous defense at remote endpoints,” APPA said.

Glick discloses that FERC is in discussions with state regulators on transmission issues

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

The Federal Energy Regulatory Commission (FERC) is in discussions with the National Association of Regulatory Utility Commissioners (NARUC) to develop a formal approach between the states and FERC “that will allow us to jointly tackle” transmission issues head on, FERC Chairman Richard Glick said on April 15.

At the Commission’s monthly open meeting, Glick said he believes that FERC must make changes to its regulations and policies “to improve the way electric transmission is planned, paid for and operated.”

At the same time, “we also need to improve the process for interconnecting new generation to the transmission grid,” he said.

In addition, he said it is time to revisit the Commission’s oversight of transmission investment to “make certain captive customers aren’t paying for unneeded or unwise transmission projects.” 

He said he plans “to sit down with my colleagues over the coming weeks to finalize a plan of action for moving forward with these much-needed changes” on transmission policy.

“It is also important that we recognize that the states are also going to play a very important role in building out the grid to accommodate the transition to the clean energy future,” Glick said.

He noted that FERC is currently in talks with NARUC to develop a more formal approach between the states and FERC that will allow FERC and the state utility commissions to jointly tackle transmission issues.

He hopes to have an announcement on the FERC-NARUC collaboration soon.

At the same time, he said that although substantial investments in new transmission capacity are needed, “we also must focus on making more efficient use of the existing grid.”

He argued that the current approach to utility regulation “often incentivizes more capital-intensive investments” in new steel in the ground “when more economical investments aimed at increasing the efficiency of the existing facilities could offer substantial benefits.”

Therefore, Glick announced a workshop on a shared savings approach for incentivizing technologies that will help increase the use of the existing grid.

“This is an idea presented in an earlier technical conference,” he noted.

“I am glad the Chairman has decided to hold a workshop on grid-enhancing technologies to further explore whether a shared savings type approach is viable,” said Commissioner Neil Chatterjee.

“That’s a step in the right direction when it comes to needed grid reforms,” Chatterjee said.

On April 19, FERC issued a notice establishing September 10, 2021 as the date of the workshop. 

According to the notice, the workshop “will discuss issues related to shared savings approaches for transmission technologies seeking incentives under Federal Power Act section 219.”

Additional details concerning topics of discussion at the workshop are included in the notice.

FERC proposes to modify plan to revise its transmission incentives policy

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

The Federal Energy Regulatory Commission (FERC) proposed to modify a March 2020 plan to revise its electric transmission incentives policy meant to stimulate infrastructure development.

The supplemental Notice of Proposed Rulemaking (NOPR) proposes to codify FERC’s current practice of granting a 50-basis-point increase in return on equity (ROE) as an incentive for utilities that join a transmission organization, but also proposes to limit the duration of the adder.  

FERC currently allows a transmission utility in a transmission organization to collect the ROE adder for as long as the utility remains a member of the transmission organization.  Under the supplemental NOPR, a utility only would be eligible for the incentive for the first three years after the utility transfers operational control of its facilities to the transmission organization (Docket No. RM20-10).

The action took place at FERC’s April 15 monthly open meeting.

The Commission’s March 2020 NOPR had also proposed to increase the incentive for membership in a regional transmission organization (RTO), an independent system operator (ISO) or other FERC-approved transmission organization from 50 basis points to 100 basis points, but the supplemental NOPR proposes to hold the line at 50 basis points. 

The supplemental NOPR would also require utilities that have received the incentive for three or more years to submit, within 30 days of the effective date of a final rule, a compliance filing to eliminate the incentive from its tariff.  

Utilities currently receiving the incentive must either revise their tariffs to eliminate the incentive or to terminate the incentive three years from the date that they turned over operational control of their transmission facilities to a transmission organization.

The supplemental NOPR seeks comment on whether the incentive should be available solely to transmitting utilities that join a transmission organization voluntarily.  If so, the Commission wants to know how it should apply that standard and, in particular, how to determine whether the decision to join was voluntary. Some have challenged the incentive adder in cases where a utility’s participation in a transmission organization is not voluntary, such as where state law requires that a utility participate in a transmission organization.

In comments on the March 2020 proposed rule and an early FERC notice of inquiry, the American Public Power Association had urged FERC to scale back the ROE adder incentive awarded to utilities that participate in transmission organizations.

At FERC’s April monthly meeting, FERC staff estimated that the proposed rule changes could save ratepayers $350 million annually.

Comments are due 30 days after publication in the Federal Register. Reply comments are due 15 days after that.

Chatterjee, Danly dissent

FERC Commissioners Neil Chatterjee and James Danly dissented from FERC’s decision.

Section 219 of the Federal Power Act (FPA) requires FERC to offer incentives to a utility “that joins a Transmission Organization.”  Chatterjee said that the supplemental NOPR “mischaracterizes the plain language” of this provision in order to strip utilities of a transmission organization incentive, “even though the utility RTO/ISO membership has led to substantial consumer benefits and is vital to the energy transition and the development of much-needed transmission in the RTO/ISO regions.”

He said that the supplemental NOPR “does not even attempt to grapple with any of the Commission’s well-reasoned prior holdings. Rather, the majority merely offers a conclusory statement that a new interpretation is reasonable.”

Chatterjee said he could understand the majority’s proposal “to eviscerate the transmission organization incentive if doing so accomplished an important or even articulable policy objective. But the proposal is—bafflingly—contrary to the current Administration’s federal clean energy goals.”

To meet such aggressive goals, “we will need both robust organized markets and an enormous amount of investment in transmission, and we will need to put Americans to work building the grid of the future. If this Commission hopes to run fast toward these energy transition goals, it must not shoot itself in the foot by eliminating the transmission organization incentive,” wrote Chatterjee.

For his part, Danly said it is not FERC’s role to second guess Congress. “It is irrelevant whether the majority ‘believes’ the RTO adder is no longer necessary as an incentive for a utility ‘that joins’ an RTO to stay in the RTO. If the majority or anyone else has a problem with the statute, their sole recourse is through Congress.”

He said that “just as the statutory text is not limited to an incentive for a utility ‘to join’ an RTO, it also is not limited to a utility that ‘voluntarily’ joins a transmission organization. That word does not appear in the statute. I oppose inserting this further limitation into the statutory text.”

Danly also argued that the majority “also fails to consider the effects of its proposed change on utilities that have not yet joined an RTO.”

He said that there are large portions of the country that have no RTO. “Recent events suggest that utilities in these regions are contemplating joining an existing RTO or forming a new one. The Commission should be taking actions to encourage such decisions. Instead, we are proposing to reduce the benefits to utilities that join RTOs based on a strained, erroneous interpretation of the statute.”

Utilities considering RTO participation “are sure to take note not only of the reduction in benefits attendant to RTO participation that the Commission proposes today, but also of the Commission’s willingness to take extraordinary steps to reduce those benefits. This is not the signal we should be sending to utilities that, to date, have resisted RTO participation,” wrote Danly.

Christie offers concurrence

In a concurrence, FERC Commissioner Mark Christie said the Commission “has previously enumerated the benefits of RTO/ISO participation to both public utilities and consumers, so the costs and benefits of such membership are not at issue here. At a time, however, when transmission costs are already a significant and rising part of consumers’ retail bills, ROE adders needlessly burden consumers with substantial additional costs without demonstrable evidence that they actually incentivize the particular action they are aimed at incentivizing.”

He said he agrees with certain commenters that the RTO adder provides an unnecessary windfall with no nexus to utilities’ decisions to join or remain in a RTO.

“It may also be the case that such adders are duplicative of other Commission incentives already granted to public utilities by virtue of their participation in an RTO/ISO,” Christie wrote.

While section 219 of the FPA requires the Commission to provide certain incentives—such as an incentive for joining an RTO/ISO—it also requires that resulting rates continue to be just and reasonable, Christie said.

“As noted by the Delaware Division of Public Advocate and the Office of the People’s Counsel for of the District of Columbia, ‘Congress did not intend for [FPA section 219], or the rules promulgated pursuant to it, to unjustly enrich utilities and RTO members at the customers’ expense.’ I agree.”

He also agrees with the supplemental NOPR’s conclusion that section 219 of the FPA does not require an incentive for RTO/ISO participation to take the form of an ROE adder and with its request for commenters to propose alternative, non-ROE incentives that would qualify under section 219.

“Absent a clear declaration from Congress that a FERC-authorized incentive must take the form of an ROE adder — which it did not require for RTO participation incentives — awarding an ROE adder for any length of time as a “reward” for joining an RTO/ISO may be inconsistent with FPA section 219’s concurrent mandate that rates must be just and reasonable and not unduly discriminatory or preferential,” wrote Christie.

“Because this supplemental NOPR proposes to limit the use of ROE adders for RTO/ISO membership to three years after joining — a welcome first move — I respectfully concur. I look forward, however, to commenters’ responses regarding non-ROE incentives.”

In a recent episode of the American Public Power Association’s Public Power Now podcast, Christie discussed transmission issues.

FERC orders PacifiCorp to respond to allegations of reliability violations

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

The Federal Energy Regulatory Commission (FERC) on April 15 ordered PacifiCorp to explain why the company should not be assessed a proposed civil penalty of $42 million for violating FERC reliability standards on its bulk electric system.

PacifiCorp is a subsidiary of Berkshire Hathaway Energy.

In a FERC Staff Report attached to FERC’s order, FERC Office of Enforcement (OE) staff alleges that PacifiCorp violated the Federal Power Act and regulations by failing to comply with a Commission-approved reliability standard developed by the North American Electric Reliability Corporation (NERC) involving transmission line facility ratings methodology.

Specifically, PacifiCorp adopted a facility ratings methodology that required the consideration of clearance measurements consistent with the National Electric Safety Code (NESC), FERC said.

FERC enforcement staff found that clearance measurements on a majority of PacifiCorp’s bulk electric system transmission lines were incorrect under the NESC. As these clearance measurements were used to calculate PacifiCorp’s facility ratings, PacifiCorp’s facility ratings were thus inconsistent with its facility ratings methodology, FERC said. 

Moreover, FERC enforcement staff alleges that PacifiCorp was generally aware of incorrect clearances on its bulk electric system since at least 2007, when FERC’s reliability standards became mandatory, but failed to specifically identify all of the clearance problems and remedy them in a timely manner.

Enforcement staff alleges that PacifiCorp’s violations began on August 31, 2009, when the company implemented its facility ratings methodology policy, and that at least some of the violations continued until August 2017, when PacifiCorp completed remediation of all of its incorrect clearances to make them consistent with its facility ratings methodology.

Enforcement staff’s investigation into PacifiCorp’s incorrect clearances began in 2012 after learning of the Wood Hollow wildfire that lasted from June 23 to July 1, 2012 in Sanpete County, Utah. 

FERC enforcement staff alleges that the inadequate clearance involved in the fire was just one example of clearance violations prevalent on PacifiCorp’s bulk electric system.

FERC noted that its order makes clear that issuance of the decision does not indicate Commission adoption or endorsement of the Staff Report. 

PacifiCorp has 30 days to respond to the Commission’s order.

WAPA’s Colorado River Storage Project to explore membership in SPP

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

The Southwest Power Pool (SPP) recently received a letter from the Western Area Power Administration’s (WAPA) Colorado River Storage Project (CRSP) expressing interest in evaluating membership in the organization.

 CRSP is the sixth electric service provider in the West to publicly commit to exploring regional transmission organization (RTO) expansion in the Western Interconnection, SPP noted.

In November 2020, Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska (MEAN), Tri-State Generation and Transmission Association, and WAPA’s Upper Great Plains-West and Loveland Area Projects notified SPP of their intent to evaluate membership in the RTO. The entities’ letters indicate they will work with SPP to evaluate the terms, costs and benefits of putting western facilities under the RTO’s tariff.

 If these utilities pursue membership, they would become the first members of SPP’s RTO to place facilities in the Western Interconnection under the terms and conditions of SPP’s open access transmission tariff.

 The interested parties currently receive at least one of SPP’s contract-based Western Energy Services in the Western Interconnection. CRSP participates in two –Western Reliability Coordination and the Western Energy Imbalance Service Market.

Basin Electric, MEAN, Tri-State and WAPA’s UGP-East Region are already members of SPP, having joined the RTO in 2015 when they placed their respective facilities in the Eastern Interconnection under SPP’s tariff.

A Brattle study commissioned by SPP found that the move would be mutually beneficial and produce $49 million a year in savings for SPP’s current and new members.

The western utilities joining SPP would receive $25 million a year in adjusted production cost savings and revenue from off-system sales, and SPP’s members in the east would benefit from $24 million in savings resulting from the expansion of SPP’s market, transmission network and generation fleet.

SPP noted that its prior calculations of the value of RTO membership suggest that these benefits are only a portion of those current and new members will derive.

There is additional value not considered by the Brattle study in five-minute real-time economic dispatch, achievement of public policy goals, lowered reserve-margin requirements, consolidation and regionalization of planning and other processes and more, SPP said.

 Additionally, SPP said it anticipates its wholesale electricity market, resource adequacy program and other regionalized services can help western members achieve renewable-energy goals and reinforce system reliability.

Construction to start soon on collaborative microgrid project between Chattanooga, EPB

April 19, 2021

by Paul Ciampoli
APPA News Director
April 19, 2021

Chattanooga, Tenn., Mayor Andy Berke, EPB President and CEO David Wade, Chattanooga Police Chief David Roddy, and Chattanooga Fire Chief Phil Hyman on April 15 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.

The project start date is April 28, 2021 and the scheduled completion date is October 30, 2021.

While the Tennessee Valley Authority and EPB “already provide some of the greatest energy reliability in the country, an ever-increasing potential for natural and man-made disruptions requires investment in additional fortification for our most critical services,” an April 15 news release related to the on ‘Power to Protect” microgrid project said.

The total project cost is approximately $1.8 million, with $732,000 coming from EPB in the form of a battery and microgrid controller and circuit modifications. The balance will be funded by the City of Chattanooga’s capital budget.

Wade said that the project is a next-generation microgrid that benefits the whole community by adding additional resilience to police and fire services while also helping to keep the overall cost of electricity a bit lower for all customers.

“What sets this microgrid apart is that on-site solar generation, high-capacity battery storage and diesel generators are fully integrated with Chattanooga’s advanced smart grid infrastructure which has the ability to automatically re-route power around damaged power facilities to reduce the incidence of outages,” said Wade. “In addition to this extra layer of resiliency for our community’s emergency services, we will be able to utilize this microgrid as a resource to help reduce peak demand charges which keeps costs lower for all of our customers.”

Project specifications include 430-kilowatts (kW) total solar generation once complete, a 175-kW diesel generator, a 100-kW natural gas generator, 275-kW/1100-kWh battery storage, microgrid controller and interconnection.

OPPD signs PPA for output of 81-MW solar farm

April 16, 2021

by Peter Maloney
APPA News
April 16, 2021

The Omaha Public Power District (OPPD) has signed a power purchase contract with Community Energy for an 81-megawatt (MW) solar farm.

Renewable energy sources are central to OPPD’s Power with Purpose project, which includes a commitment to its board of directors to add up to 600 MW of utility-scale solar to OPPD’s fleet, along with modernized natural gas backup generation at its Turtle Creek and Standing Bear Lake stations, according to The Wire, the utility’s online newsletter.

The planned Platteview Solar project will be one of several solar facilities supporting OPPD’s 13-county service territory, according to The Wire. OPPD also plans to grow its renewable energy portfolio, which includes wind, hydro, landfill gas, and a 5-MW community solar facility, from its current 38.4 percent of retail sales as of 2020.

 OPPD is striving to be a net-zero carbon utility by 2050 under a strategic directive set up by its board of directors. Power with a Purpose came out of the board’s directive. OPPD has also begun a broader study, Pathways to Decarbonization, that is looking at the utility’s generation portfolio, internal operations, buildings, fleet and inventory, as well as community engagement regarding customer-owned generation, OPPD spokesman Cris Averett said. “We want to be part of that conversation,” he said.

The study is slated to continue for the rest of the year. OPPD would then report back to its board, which would then make recommendations to the utility.

The Platteview Solar project is sited on about 500 leased acres south of Yutan, Neb., in eastern Saunders County. It will be owned and operated by Radnor, Penna., based Community Energy, which was chosen for the project through a competitive bidding process.

Community Energy is in the process of securing a conditional use permits for the solar project. Pending approval, construction of the solar project would begin early in 2022 and take nine to 12 months to complete. “We are hoping for a green light by the summer,” Averett said.

In February, Saunders County passed a solar ordinance, stipulating required setbacks and a plan for funded site decommissioning at the end of the solar farm’s useful life, approximately 30 years.

The project will employ more than 150 people for up to a year. Longer term, up to three full-time employees would operate and maintain the site and Saunders County would receive around three decades of tax revenue with little to no effect on local services and infrastructure, according to The Wire. “It will be an economic boon for the county,” Averett said.

CPS Energy unveils pilot programs that incentivize EV home charging during off-peak hours

April 16, 2021

by Paul Ciampoli
APPA News Director
April 16, 2021

Texas public power utility CPS Energy on April 15 said it is introducing two pilot programs that incentivize electric vehicle home charging during off-peak energy demand hours and that help address drivers’ range anxiety.

CPS Energy said the addition of the two new programs for customers who charge their EV at home is in line with its Flexible Path strategy.

With the introduction of its FlexEV brand, “the utility recognizes the need to improve the environment by being a major supporter of EV adoption. CPS Energy is therefore unveiling new products and services to encourage drivers to consider alternative vehicles,” it said.

Under the FlexEV Smart Rewards program, participants will receive a one-time $250 enrollment credit on their utility bill. The customer will also receive a $5 monthly credit, equivalent to about 120 miles of driving, for allowing CPS Energy to remotely connect and carefully manage the customer’s charging device, as needed.  This would only occur when energy demand is high, between the hours of 2 p.m. and 9 p.m., Monday through Friday.  Specifically, if needed, CPS Energy would manage the flow of energy to the charger to help take pressure off the grid, the utility said.

Under the FlexEV Off-Peak Rewards program, a participant will receive a one-time $125 enrollment credit on their utility bill. The customer will also receive a $10 monthly credit for voluntarily choosing to limit charging to no more than two times a month between the hours of 4 p.m. and 9 p.m., Monday through Friday.

CPS Energy noted that it has 76 local ChargePoint charging stations in its FlexEV Public Charging program. In support of public charging, the utility’s program includes a flat-rate pilot program. This program has an annual fee of $96 for unlimited access to charging stations at any time of day or night.

If customers do not subscribe to the flat rate pilot program, they can still use the charging stations on a pay-as-you-go basis.

Public power utilities recognized for their efforts to shift to modern, carbon-free energy systems

April 15, 2021

by Paul Ciampoli
APPA News Director
April 15, 2021

Five public power utilities have been recognized by the Smart Electric Power Alliance (SEPA) for their efforts to transition to a modern and carbon-free energy system.

SEPA noted on April 14 that it launched the inaugural Utility Transformation Challenge to make a comprehensive, honest assessment of U.S. electric utilities’ progress towards a modern, carbon-free energy system.

SEPA said it conducted and analyzed multiple surveys designed to measure meaningful progress across multiple dimensions of utility infrastructure, programs, strategy and operations. Insights derived from these survey results form the basis for a new report: the 2021 Utility Transformation Profile.

SEPA received survey responses from 135 individual utilities, representing more than 83 million customer accounts, or approximately 63% of all U.S. electric customer accounts.

The report examines the utility industry’s transition to a clean and modern energy system by exploring four dimensions of utility transformation: clean energy resources, corporate leadership, modern grid enablement, and aligned actions and engagement.

With respect to what was learned from evaluating the utilities leading the clean energy transition, SEPA listed the following:

Utility Transformation Leaderboard

SEPA also unveiled the 2021 Utility Transformation Leaderboard, which SEPA said recognizes the ten utilities that have demonstrated the greatest progress in the transition.

Five of the 10 utilities on the leaderboard (in alphabetical order) are public power utilities (bolded):

“I am grateful for this prestigious recognition from the Smart Electric Power Alliance and appreciate the hard work of HG&E employees,” said James Lavelle, Manager of Holyoke Gas & Electric.

“As a municipal public power utility, HG&E is committed to providing innovative and sustainable energy solutions to our community through investments in a diverse power supply portfolio, energy storage, efficiency and conservation programs, as well as development of emerging clean energy technologies,” he said. “The State of Massachusetts has established a road map to net-zero by 2050 and HG&E is well positioned to meet this goal, as well as the incremental targets set for 2030 and 2040.”

“We are honored to be a part of SEPA’s Utility Transformation Challenge,” Seattle City Light General Manager and CEO Debra Smith said. “I think we all recognize the need to transform is a constant in our lives, businesses, and society. Creating a carbon-free energy system is never truly complete. City Light will continue to lead these efforts as our region moves toward a cleaner energy future.”  

“We’re proud to be leading the way in decarbonizing our economy,” said SMUD CEO and General Manager Paul Lau. “We’re at a point where we must commit to ambitious goals in order to achieve meaningful carbon reductions that benefit our community and the world.  Creating an inclusive, clean, green economy will improve economic, health and environmental outcomes, as well as drive a new, clean workforce and that’s something everyone can be excited about,” said Lau.

“We are honored to be on SEPA’s 2021 Utility Transformation Leaderboard,” said Jackie Sargent, Austin Energy General Manager. “Austin Energy is committed to grid modernization and affordable, carbon-free energy as approved by the Austin City Council. Inclusion on this list reinforces how important it is for the utility to continue these efforts and remain an industry leader.”

SEPA offers recommendations

SEPA provided recommendations for utilities of all sizes, types and geographies as they pursue their own path of transformation.

SEPA recommended utilities strengthen carbon reduction commitments by setting ambitious, science-based targets with interim goals and detailed plans to achieve them.

It also recommended that utilities address the transformation comprehensively across the organization through changes to processes, programs and structures that will accelerate clean energy adoption. 

Examples include pursuing integrated distribution planning, interconnection processes, evaluating non-wires alternatives (energy efficiency, demand flexibility, storage, etc.) to meet demands, developing a transportation electrification strategy and efficiently integrating and leveraging distributed energy resources.

Utilities should also embrace the clean energy transformation as a core element of the utility mission and culture. “This will require changes, such as linking executive compensation to reduced carbon emissions, establishing transparent emissions tracking and reporting programs and pursuing internal sustainability and carbon reduction programs (e.g., fleet electrification and supply chain programs),” SEPA said.

SEPA also recommended that utilities engage customers, technology partners, peer utilities and regulators early and often. “Common understanding and shared vision of new initiatives and technology deployments is critical to facilitate innovation,” it said.

In addition, SEPA said that utilities should integrate equity considerations and goals into efforts and programs to ensure all community members are able to participate in and benefit from the clean energy transformation.

The 2021 Utility Transformation Profile report and Utility Transformation Leaderboard are available here. Download the executive summary here.