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California, Texas grid operators respond to soaring temperatures, resulting stress on supplies

June 16, 2021

by Paul Ciampoli
APPA News Director
June 16, 2021

Power grid operators in California and Texas this week responded to soaring temperatures and the resulting spike in power demand through a number of steps. The California Independent System Operator (CAISO) called for the deferral of scheduled maintenance on generators or transmission lines, if possible, while the Electric Reliability Council of Texas (ERCOT) issued a call for energy conservation at the start of the week.

With extreme heat expected to break temperature records and linger over much of California and the West for the remainder of the week, the California Independent System Operator (ISO) on June 15 said that it is asking consumers to be prepared to conserve energy to help avoid the possibility of rotating power outages.

Those steps would include setting thermostats to 78 degrees or higher, if health permits, avoiding use of major appliances and turning off unnecessary lights.

CAISO said that if it issues a Flex Alert calling for voluntary conservation between the hours of 4 p.m. to 9 p.m. on Wednesday and possibly Thursday, consumers would be encouraged to take other steps to manage their electricity usage to maintain comfort prior to an alert taking effect.

The grid operator said that an abnormally strong ridge of heat is forecast to bring temperatures as high as 115 degrees to the California interior that could last until the weekend. “Because of the extreme heat and nighttime lows expected to cool off only between 78 and 83 degrees, the state’s electric grid will be straining to meet evening demand when air conditioners are in heavy use and solar energy generation is waning.”

The ISO’s own projections currently show electricity demand exceeding power supplies that are guaranteed under the state’s Resource Adequacy (RA) requirements for several days this week. The biggest deficit is projected for Thursday between 8 p.m. and 9 p.m. when demand is forecasted to be 43,261 megawatts (MW), including required contingency reserves, or 3,374 MW more than expected to be available under the RA program.

The ISO noted it has steps it can take to close that gap, including demand response programs that utilities use to provide incentives for customers to conserve, but one regularly relied on asset — imported electricity from neighboring states — could be affected.

“That’s because the National Weather Service is now forecasting that extreme heat is expected to engulf much of the Western United States. Triple-digit heat is forecast from the deserts east of Los Angeles all the way north to the Canadian border, resulting in tight energy supplies over a large geographic area,” CAISO said.

To help prepare for the heat and heightened stress on the grid, the ISO declared a grid Restricted Maintenance Operation for noon to 10 p.m. for June 15 through Friday. The directive cautions energy generators that all available resources are needed, and to defer scheduled maintenance on generators or transmission lines, if possible.

If a Flex Alert is called this week, consumer conservation can make a big difference, as it has during past heat waves when such concerted action helped avoid grid emergencies, including rotating outages, the grid operator said.

Texas

Meanwhile, the Electric Reliability Council of Texas (ERCOT) on June 15 said that when it issued a call for conservation on Monday, Texans responded strongly by reducing electric demand during the late afternoon. ERCOT continues to encourage Texans to conserve power each afternoon during the peak hours of 3 to 7 p.m. through this Friday.

“The grid is operating exactly as it was designed and intended. The issuance of conservation notices is a common practice and prevents ERCOT from entering emergency conditions. Conservation efforts combined with the changes in procedures and processes implemented by ERCOT and the PUC following the winter storm prevented the possibility of rotating outages yesterday and ensured that no Texans lost power,” ERCOT said.

ERCOT said it has been leveraging every resource at its disposal, including activating all available generating units to help serve customer demand before calling for conservation. Approximately 1,200 MW of power was regained overnight Monday when some repairs were completed.

On June 14, ERCOT set a new June record for electricity demand. Based on preliminary data, the new record is 69,943 MW, which exceeds the 2018 June record by approximately 820 MW.

Power plant owners continue repairs of unexpected equipment failures, “and ERCOT is using all the tools in its toolbox to maintain reliability in the face of potential record-setting electricity demand,” it said.

“All of our local plants are up and running, and virtually all of them are at full capacity,” said Rudy Garza, Chief Customer & Stakeholder Engagement Officer for San Antonio, Texas public power utility CPS Energy, on June 14. “We’re asking our other customers to help even further by conserving energy to support the grid.”

CPS Energy also provided a set of actions that residential and business customers can take to conserve energy.

Austin, Texas public power utility Austin Energy on June 14 noted that its staff works year-round to maintain and monitor a diverse mix of power generation plants to ensure peak performance during extreme conditions. The utility also employs various demand response programs that help lower electric use during strained grid conditions.

In 2020, Austin Energy rolled out Weekly Electricity Update and High Bill Alert emails providing customers with electricity usage details and energy-efficiency tips. These emails help customers learn more about their electricity usage patterns and trends. They also contain insights and tips to help customers lower their electricity usage and save on their bills.

The Weekly Electricity Updates email compares energy usage rates from week to week, while the High Bill Alerts email lets customers know when their usage is higher than compared to the same monthly cycle from the previous year.

These notifications are a free and optional service automatically provided to eligible City of Austin customers with an advanced meter at their location and an email address on file. Customers can unsubscribe at any time.

Austin Energy this week also provided tips for Austin Energy customers to help conserve energy.

Members of Southeast energy exchange market say proposed changes will boost transparency

June 15, 2021

by Paul Ciampoli
APPA News Director
June 15, 2021

Members of the Southeast Energy Exchange Market (SEEM) recently offered changes to an automated, intra-hour energy exchange proposal the group previously submitted to the Federal Energy Regulatory Commission (FERC) that they said will create greater oversight ability for FERC and more transparency for all participants.

The group said that the greater oversight ability for FERC will come via weekly, confidential submissions of significant data on the SEEM market operation. The increased transparency for all participants comes from commitments and clarifications around public posting of auditor reports and responses to regulatory inquiries, the group said.

SEEM members initially sought FERC approval of the automated, intra-hour energy exchange in a Feb. 12, 2021 filing.

The SEEM platform is an extension of the existing bilateral market in the Southeast. Its design will facilitate sub-hourly, bilateral trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission.

Founding members of SEEM are expected to include:

Participation in SEEM is open to other entities that meet the appropriate requirements and some utilities will make decisions about whether to commit following FERC approval. 

The founding members represent nearly 20 entities in parts of 11 states with more than 160,000 megawatts (summer capacity) across two time zones. They serve the energy needs of more than 32 million retail customers.

FERC staff releases white paper on hybrid resources, seeks feedback

June 5, 2021

by Peter Maloney
APPA News
June 5, 2021

Staff at the Federal Energy Regulatory Commission (FERC) on May 26 issued a notice inviting comments on hybrid resources, such as solar power combined with energy storage, and, at the same time, released a white paper on the subject.

The deadline for submitting comments to FERC is Aug. 18, 2021.

The white paper discusses the hybrid resources technical conference FERC held in July 2020, as well as the information garnered from comments.

Interest in hybrid resources has accelerated in recent years, in part because of recent growth in electric storage resources, the white paper noted.

Hybrid resource deployment has increased in both Regional Transmission Organization (RTO) and Independent System Operator (ISO) and non-RTO/ISO regions, with growth concentrated in certain areas, most notably in the California Independent System Operator Corporation (CAISO) region, according to the white paper.

As recently as two years ago, there were virtually no hybrid resources in interconnection queues, and there are now 102 gigawatts (GW) of solar paired with storage, and 11 GW of wind paired with storage in interconnection queues across the country, including both RTO/ISO regions and non-RTO/ISO regions, the FERC paper said.

The white paper cited comments from the American Wind Energy Association (AWEA) stating that 10 percent of resources in RTO/ISO interconnection queues nationwide are hybrid projects.

In California, CAISO reports that 47.6 percent of active interconnection requests are for hybrid resources. For requests submitted to CAISO in 2020, the number rises to 58 percent.

The vast majority of announced hybrid projects are solar photovoltaic (PV) combined with battery electric storage, but project developers have also announced wind combined with electric storage, natural gas-fired generation combined with electric storage, and solar power combined with wind and electric storage projects, the white paper said.

Citing data from Lawrence Berkeley National Laboratory, the white paper noted that solar combined with energy storage made up about 85 percent of the capacity of hybrid resources in the interconnection queues nationwide at the beginning of 2020.

In its definition of “hybrid,” the white paper included co-located resources that are modeled and dispatched as two or more separate resources that share a single point of interconnection and integrated hybrid resources that share a single point of interconnection and are modeled and dispatched as a single resource.

One driver of the increase in hybrid resources is that some configurations allow the electric storage component to qualify for increased financial incentives, including the federal Investment Tax Credit and certain state incentives for electric storage resources that charge from renewable resources, the white paper said.

Those incentives, combined with the potential for wholesale market revenues could attract further investment in hybrid technologies and projects, potentially leading to increased competition and market efficiency, the white paper said, noting that at the beginning of 2020, the six RTOs and ISOs under FERC jurisdiction had more than 62 GW of hybrid projects in their interconnection queues.

FERC noted that in comments several participants emphasized the need for flexibility at all stages of the co-located hybrid and integrated hybrid project lifecycle, including with respect to whether a hybrid project will operate as a single or multiple resource type, changes during the interconnection process, and assessing how the resource can operate in the market most economically.

FERC also noted that some commenters stressed the need for hybrid resources to be able to provide all services that they are capable of providing and said that market power mitigation approaches may need to be modified.

In its analysis in the white paper, FERC said the record in its hearings to date demonstrate “co-located hybrid and integrated hybrid resources can add value to the electric grid” by allowing intermittent or duration-limited resources to achieve a higher combined capacity factor, facilitate more efficient transmission system operation by reducing congestion and curtailment in areas with high penetrations of intermittent resources, and provide transmission providers with more controllable ancillary services than standalone intermittent resources. Combining resource types also allows for the sharing of permitting, siting, equipment, and interconnection costs.

Nonetheless, FERC noted that the rapid growth of hybrid resources presents challenges to RTOs and ISOs and other FERC-jurisdictional transmission providers and federal and state regulators to keep up with the pace of technological change. And while RTOs and ISOs have begun to make changes to their wholesale electric markets, much remains to be addressed, FERC said in the white paper.

With additional experience RTOs, ISOs and transmission providers “will be better able to address issues including a potential need to modify interconnection rules, modeling approaches in interconnection and reliability models, market participation rules such as bidding and modeling, and capacity valuation methods,” FERC said.

The notice seeking comments is available here.

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.

Colorado Springs Utilities to join Southwest Power Pool’s Western Energy Imbalance Service Market

May 12, 2021

by Paul Ciampoli
APPA News Director
May 12, 2021

Public power utility Colorado Springs Utilities on May 12 said it will join Southwest Power Pool’s (SPP) Western Energy Imbalance Service (WEIS) Market in April 2022 and join other western utilities in evaluating membership in SPP’s regional transmission organization (RTO).

“Our current portfolio of solar compliments SPP well,” said Colorado Springs Utilities CEO Aram Benyamin in a statement. “We expect to save customers money by optimizing the dispatch of different utilities’ generating resources within each hour of the day. Our employees will also benefit from increased market intelligence, better integration of our new solar projects and being one step closer to meeting our clean energy goals.”

In June 2020, the Colorado Springs Utilities Board approved a new sustainable energy plan, which calls for Colorado Springs Utilities to reduce carbon emissions at least 80% by 2030 and 90% by 2050. Additionally, the plan increases renewable energy and incorporates storage resources. It benefits customers by maintaining competitive and affordable rates and advances energy efficiency, the utility notes.

SPP launched its WEIS market Feb. 1, 2021. The wholesale electricity market balances regional supply and demand of electricity in real-time. Colorado Springs Utilities will join eight other western utilities already participating in the WEIS.

SPP is already coordinating an effort by several western utilities — all current participants in the WEIS market — that are evaluating membership in its RTO, and Colorado Springs Utilities will join this effort too.

While SPP administers the WEIS market on a contract basis to non-members, it provides RTO members an entire suite of valuable services including market administration, transmission planning, reliability coordination and more. A recent SPP-Brattle study estimated the WEIS participants’ move to RTO membership would produce $49 million in benefits and those would grow with additional western members.

Colorado Springs Utilities plans to work with the Western Area Power Administration (WAPA), a current SPP WEIS participant, to act as its balancing authority.

A balancing authority is required to enter WEIS as they are responsible for operating a transmission control area. They match generation with load and maintain consistent electric frequency to the grid, even during extreme weather conditions or natural disasters.

The evaluation of membership is expected to conclude in early 2022, with the terms and start dates of any interested parties’ membership agreement to be announced then.

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

SPP recently received a letter from WAPA’s Colorado River Storage Project (CRSP) expressing interest in evaluating membership in the organization.

In November 2020, Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, 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.

Maine legislators announce plan to convert state’s IOUs to consumer ownership

April 26, 2021

by Peter Maloney
APPA News
April 26, 2021

A bipartisan group of legislators in Maine last week announced plans to introduce legislation that would create a consumer owned utility that would take over the electric service now provided by Central Maine Power (CMP) and Versant Power.

Together, the two investor-owned utilities serve 96.2 percent of the state’s residential load and have 963,187 residential customers, according to state regulators. The remaining residential load is served by public power utilities – or consumer-owned utilities, as they are known in Maine – and electric cooperatives.

“Our new bill, ‘An Act to Create the Pine Tree Power Company,’ will allow us to control our own money and our own energy destiny — to advance fast and fairly toward our own clean energy and connectivity future,” Democratic Rep. Seth Berry, sponsor of the bill and House Chair of the Energy, Utilities and Technology Committee, said in a statement.

The bill will likely be printed in late April and have its first legislative hearing in May, Berry said via email. If the bill is passed later this year, the conversion would likely take three or four years. Unlike many successful conversions Pine Tree Power would face few legal hurdles and would bear no separation cost, Berry said.

The effort to convert Maine’s electric service to consumer ownership is supported by Our Power, a coalition of ratepayers, business leaders, energy experts, and conservationists. Proponents cite high electric rates, high outage rates, and the foreign ownership of CMP and Versant.

“Maine’s for-profit, investor-owned utilities — CMP and Versant — are charging Maine households 58% more than our consumer-owned utilities,” Democratic Rep. Nicole Grohoski, a member of the legislature’s utilities committee, said in a statement. If CMP and Versant charged the same average rate as consumer-owned utilities, Mainers would save $155 million/year, she said.

“Right now, foreign governments and foreign corporations own Maine’s major utility monopolies,” Republican Senator Rick Bennett, said in a statement. “This ownership model has been a disaster, leaving Maine with the most outages, the longest outages, the worst customer service, and among the highest rates in the country.”

Central Maine Power is a subsidiary of Avangrid, which owns eight electric and gas utilities in New York and New England. Avangrid is part of Spanish energy company Iberdrola Group.

Versant Power, formerly Emera Maine, was formed when Bangor Hydro Electric and Maine Public Service merged in 2014. Versant is owned by Enmax, based in Calgary, Alberta.

The conversion proposal, as it now stands, calls for Pine Tree Power to be governed by an elected board of directors, as well as four expert advisory members chosen by the elected officials, Berry said.

The board and management staff would solicit bids for executives to replace CMP’s and Versant’s current executive leadership and to oversee the utility’s day-to-day operations. All other CMP and Versant workers would retain their jobs and pensions. The new utility would also be subject to regulation by Maine’s regulatory commission, Berry said.

The current plan calls for Pine Tree Power to pay between net book value and 1.5 times net book value for CMP’s and Versant’s assets, “far less than the IOUs suggest,” Berry said.

Looking ahead, future costs would be lower because Pine Tree Power could use tax-exempt revenue bonds to finance its infrastructure at interest rates of 2 to 3 percent, compared with 8 to 14 percent for the IOUs, reducing future capital expenditures and saving $9 billion over 30 years, according to Our Power’s website.

The current proposal is not the first time a conversion proposal has been floated in Maine. In early 2019, Berry sponsored a bill that would have created Maine Power Delivery Authority that would have bought CMP and Versant. That bill died at the conclusion of the legislative session in November 2020.

In explaining the previous bill’s failure, Berry said, “due diligence takes time,” noting that the legislative session was adjourned early because of the COVID-19 pandemic. He also noted the differences introduced in the new proposal, namely, a directly elected board of directors, added benefits to workers and communities, and a clarified mission.

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.”

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.

Public power utilities begin participating in CAISO’s Western Energy Imbalance Market

April 13, 2021

by Paul Ciampoli
APPA News Director
April 13, 2021

A number of public power utilities recently began participating in the California Independent System Operator’s (CAISO) Western Energy Imbalance Market (EIM).

The Turlock Irrigation District (TID) and the Balancing Area of Northern California (BANC) Phase 2, comprised of the Modesto Irrigation District (MID), the City of Redding, the City of Roseville, and the Western Area Power Administration (WAPA) Sierra Nevada Region, began participating in the West’s first real-time energy market on March 25.

“Joining the EIM provides MID continued access to the market’s diverse, readily-available power resource mix. Access to this low-cost, growing pool of resources will also further ensure and enhance service reliability to our customers,” Melissa Williams, Public Affairs Manager at MID, told Public Power Current.

“In addition, the EIM offers participants an increased ability to integrate renewable energy needed to meet California’s aggressive environmental goals, provides additional sources of real-time supply to augment reliability resources and, because it’s a voluntary market, allows participants to demonstrate support for regional markets while retaining local control,” she said.

“As participants in the EIM, we have the opportunity to further capitalize on the generation infrastructure TID has developed over the years,” said TID General Manager Michelle Reimers.

TID said its participation in the Western EIM will enable it to economically balance supply and demand within the market area in real-time by scheduling power deliveries every five minutes.

“The Western EIM will provide TID with access to a wider market and allow us to optimize our resources on a more granular scale,” said Dan Severson, TID Assistant General Manager, Power Supply.

“We’re excited that our leadership in the Western EIM successfully demonstrated enough success for our partners to join and expand participation,” said BANC General Manager Jim Shetler in a statement.  “This means greater reliability, lower costs and improved renewable generation for our customers.”

This move affects only WAPA’s Sierra Nevada Region in northern California and Nevada, which operates a sub-balancing authority within BANC.

WAPA is a power marketing administration within the Department of Energy responsible for selling and delivering federal hydropower across high-voltage transmission lines to customers in 15 Midwest and Western states. It is organized in five regions and a management center. 

The Western EIM will help the Sierra Nevada Region “better manage real-time supply and demand on a more frequent basis, harness market efficiencies, improve cost-effectiveness and mitigate the loss of bilateral trading partners in real-time energy transactions,” said Senior Vice President and Sierra Nevada Regional Manager Sonja Anderson.

Having a sub-balancing authority puts “us in a unique position to join the Western EIM; our status required innovative coordination and solutions for market economics, generator dispatch and grid reliability.”

BANC is a Joint Powers Authority consisting of the Sacramento Municipal Utility District (SMUD), MID, Roseville Electric, Redding Electric Utility, Trinity Public Utility District and the City of Shasta Lake as its founding members. SMUD became the first BANC member to join the Western EIM on April 3, 2019.

LADWP

Meanwhile, Los Angeles Department of Water and Power (LADWP) and the Public Service Company of New Mexico, an investor-owned utility, began participating in the EIM on April 1.

Participating in the Western EIM will be “a win-win proposition for the City of Los Angeles and the Western grid in terms of fostering the integration of renewable energy while maintaining power reliability, as the City of Los Angeles moves ahead with our goal of 100% renewables as well as assisting all California utilities in meeting the state target of 60% renewables by 2030,” said Reiko Kerr, LADWP Senior Assistant General Manager-Power System Engineering, Planning, and Technical Services, in a statement.

Among other benefits, LADWP said that participating in the Western EIM will help both LADWP and the state address the challenge of maintaining power reliability and reducing greenhouse gas emissions while optimizing the use of renewable energy, such as solar and wind power.

LADWP received approval in 2016 from Los Angeles Mayor Eric Garcetti, the City Council and the Board of Water and Power Commissioners to begin work to join the Western EIM.

LADWP said that the process has involved modifying LADWP’s transmission and generation systems with new grid-level information technology, new systems for billing and tracking energy transactions, improving bulk power metering, and other work to integrate the LADWP system with the ISO’s other Western EIM participants.

Arizona public power utility Salt River Project and Seattle City Light are also active participants of the Western EIM.

By 2023, 22 active Western EIM participants will represent over 83 percent of the load within the Western Electricity Coordinating Council.

President Biden proposal includes $100 billion for power infrastructure

April 6, 2021

by Paul Ciampoli
APPA News Director
April 6, 2021

The Biden Administration on March 31 outlined infrastructure legislation that includes $100 billion for power infrastructure.

According to a summary of the plan released by the White House, the president is proposing a “targeted investment tax credit that incentivizes the buildout of at least 20 gigawatts of high-voltage capacity power lines.”

In addition, President Biden plans to establish a new Grid Deployment Authority at the Department of Energy that “allows for better leverage of existing rights-of-way – along roads and railways – and supports creative financing tools to spur additional high priority, high-voltage transmission lines.”

He also proposed a ten-year extension and phase down of an expanded “direct-pay” investment tax credit and production tax credit for clean energy generation and storage. These credits will be paired with strong labor standards.

It is unclear whether these direct-payment credits would be available to state and local entities, in part because the summary goes on to explain that the President’s plan will “support state, local, and tribal governments choosing to accelerate this modernization through complementary policies – like clean energy block grants that can be used to support clean energy, worker empowerment, and environmental justice.”

To accelerate responsible carbon capture deployment and ensure permanent storage, President Biden’s plan reforms and expands the Tax Code’s Section 45Q tax credit, making it direct pay and easier to use for hard-to-decarbonize industrial applications, direct air capture, and retrofits of existing power plants.

President Biden is also proposing to spend $174 billion on the electric vehicle market. The plan would enable automakers to spur domestic supply chains from raw materials to parts, retool factories to compete globally, and support American workers to make batteries and EVs. It will give consumers point-of-sale rebates and tax incentives to buy American-made EVs.

It will also establish grant and incentive programs for state and local governments and the private sector to build a national network of 500,000 EV chargers by 2030, while promoting strong labor, training, and installation standards.

President Biden is also proposing electrify the entire federal fleet, including the United States Postal Service.

Other proposals include requiring federal buildings to be powered “24/7” with clean power, establishing an Energy Efficiency and Clean Electricity Standard aimed at cutting electricity bills and electricity pollution, increasing competition in the market, incentivizing more efficient use of existing infrastructure, and continuing to leverage the carbon pollution-free energy provided by existing sources like nuclear and hydropower.