Page 970 – RTO Insider

May 23, 2021

FERC Reduces Entergy’s Return on Equity

FERC on Thursday reduced Entergy’s base return on equity to 10.37% from 11%, applying the methodology it adopted for MISO transmission owners in Opinion 569-A a year ago (ER13-1508-001).

The order reversed an initial decision issued in 2015 by the presiding administrative law judge governing sales of energy and capacity among the Entergy operating companies (NYSE:ETR). It also addressed briefs submitted in response to a 2019 order seeking input on the commission’s methodology.

The commission said it was not persuaded by the briefs to change its methodology, choosing to continue using the procedure it laid out in Opinion 569-A, which incorporated the risk premium model (RPM) into ROE calculations along with the discounted cash flow (DCF) and capital asset pricing models (CAPM) (EL14-12, et al.).

That ruling reversed the stance the commission had taken in Opinion 569 in 2019, which rejected use of the RPM. (See FERC Ups MISO TO ROE, Reverses Stance on Models.)

In 569-A, FERC said that in future proceedings, “parties will have an opportunity to argue that the base ROE methodology … should be modified or applied differently because of the specific facts and circumstances of the proceeding involving that party.”

But, the commission said, “no party has demonstrated that the methodology applied in those proceedings should not be applied to the facts and circumstances of this proceeding.”

It ordered Entergy to revise its unit power sales tariff and submit a report quantifying refunds with interest within 30 days. The new rate was made effective Dec. 19, 2013, when the tariff took effect, prompted by Entergy Arkansas’ withdrawal from the Entergy System Agreement.

Commissioner Mark Christie (R) concurred in Thursday’s order, saying that the commission’s policy is flawed because “it replaces judgment with rote application of preset formulae.” He called for a general proceeding to consider changes to the methodology.

He also said the commission should set procedural deadlines requiring FERC to act much more quickly in future ROE proceedings.

“We are today putting into place an ROE with an effective date of Dec. 19, 2013 — roughly seven and a half years ago — ostensibly on the theory that these rates are required to incentivize investment in a future that began, at this point, several years in the past,” he said. “Although a certain amount of ‘lag’ is perhaps inherent in any regulatory system, I do not accept that this degree of delay is inevitable. Going forward, I believe we can and should do better.”

He added, “As indicia of why this commission’s ROE policy needs to be revisited, I would note that as of May 14, 2021, the 30-year U.S. Treasury bond — one of the most commonly used benchmark ‘safe’ investments — was yielding 2.36%. Thus the ROE approved in this order represents a risk premium of approximately 800 basis points. As compared to the 10-year Treasury bond, which was yielding 1.64% May 14, 2021, the ROE approved herein represents a risk premium of nearly 900 basis points.”

He acknowledged that rates on Treasury bonds were somewhat higher in December 2013 — with 30-year bonds slightly below 4% and 10-year bonds slightly below 3%. “On a going-forward basis, however, as well as for most of the past eight years, the risk premium represented by a 10.37% ROE is extraordinarily generous for a regulated utility.”

Commissioner Allison Clements (D) dissented, saying the 569-A methodology including the RPM does not protect consumers.

“The order of magnitude of transmission investment required to achieve [decarbonization, resilience and replacement of aged infrastructure] is unprecedented, which translates into a massive opportunity for utilities and transmission developers. But the value proposition for consumers is in no small part dependent on this commission’s rigorous scrutiny of the rates charged for transmission service, of which ROE is a central component,” she said.

“Given this context, I believe the commission must revisit its existing ROE policy. I appreciate that this policy has been unsettled for years, a state that increases investment uncertainty and extends litigation,” she added. “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.”

But FERC Chair Richard Glick, who had dissented on inclusion of the RPM in the May 2020 order, indicated at the commission’s open meeting Thursday that he wasn’t eager to reopen the issue.

“When we issued opinions 569-A and 569-B, I expressed concerns about the commission’s decision to add the risk premium model, because the first ROE order had thoroughly explained why the risk premium model is not an appropriate tool for assessing a just and reasonable ROE,” he said. “I continue to have my concerns, but I also believe we cannot keep on changing our ROE methodology. Companies need to have some level of regulatory certainty if they are going to continue to make multimillion- — in some cases, multibillion- — dollar investment decisions.”

May 23, 2021

More Unexecuted FSAs in MISO Self-funding Squabble

FERC last week ushered through three more unexecuted facilities service agreements (FSAs) between MISO, wind developers and transmission owners.

The unexecuted FSAs are a continuing protest against a 2018 commission order reinstating MISO transmission owners’ unilateral rights to self-fund network upgrades. Wind developers are leaving FSAs unsigned of late, hoping that interconnection customers will again be able to self-fund the upgrades necessary to connect to the RTO’s system. (See MISO TOs’ Self-funding Option Tested Again.)

The unexecuted FSAs stem from Next Era Energy’s 200-MW Heartland Divide II wind project in Iowa with transmission owner MidAmerican Energy (ER21-834, ER21-836 and ER21-837).

MISO Self funding — Heartland Divide II | *NextEra Energy*

Once again, the wind developer asked FERC to direct MISO to amend the FSAs by including a provision for the self-funding option’s possible reversal.

Once again, FERC declined.

In accepting the FSAs, the commission said it disagreed with NextEra’s argument for an amendment. FERC also said it wouldn’t take action on allowing interconnection customers to “retroactively annul and reverse … initial funding elections” should it later alter or eliminate the TO self-funding option.

The FSAs “appropriately reflect the state of the law as of the date the agreement becomes effective,” the commission said.

FERC Chair Richard Glick and Commissioner Allison Clements have said that MISO TOs’ absolute right to self-fund could be unfair. They said TOs could engage in preferential treatment among interconnection customers and that customers unable to finance upgrades at more favorable rates could be forced to reimburse TOs at a predetermined rate of return.

The two commissioners did not weigh in on the overall fairness of MISO’s self-funding options in the latest orders.

May 23, 2021

NAESB Standards Gain Final FERC Approval

FERC on Thursday approved a final rule ordering utilities to implement the latest version of the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communication Protocols for Public Utilities (RM05-5).

Under the commission’s rulemaking, the timeline for implementation of version 003.3 of the standards — approved by NAESB’s Wholesale Electric Quadrant (WEQ) last year — is tied to that of version 003.2, which FERC adopted in February 2020. (See FERC Adopts NAESB Business, Communication Rules.) A compliance filing for the earlier version is due July 27, with implementation no earlier than Oct. 27; the compliance filing for version 003.3 will be due 12 months after implementation of version 003.2, with implementation at least three months after that.

NAESB Standards — FERC headquarters in D.C. | © *RTO Insider LLC*

Public utilities will therefore be required to implement version 003.3 no earlier than Jan. 27, 2023, a 15-month timeline, with the final implementation date to be set by the commission. FERC said this schedule should “account for any external dependencies and system changes” that could affect entities’ ability to implement the standards. Utilities that need more time can file extension requests, which the commission said it will consider on a case-by-case basis.

An exception to this timeline is the standards relating for cybersecurity and parallel flow visualization (PFV), compliance filings for which are due nine months after the final rule is published in the Federal Register. The standards are to be implemented no earlier than three months after that.

Version 003.3 includes modifications, reservations and additions to several existing standards:

WEQ-000: Abbreviations, acronyms and definition of terms;
WEQ-001: Open Access Same-Time Information System (OASIS);
WEQ-002: OASIS standards and communication protocols (S&CP);
WEQ-003: OASIS S&CP data dictionaries;
WEQ-004: Coordinate interchange;
WEQ-008: Transmission loading relief — Eastern Interconnection Business Practice Standards;
WEQ-013: OASIS implementation guide; and
WEQ-023: Modeling.

Among the changes from the previous version are improvements to cybersecurity protections suggested by Sandia National Laboratories and new rules on redispatch services and transmission curtailments. In addition, the new standards replace 56 requirements in NERC’s Modeling, Data and Analysis (MOD A) reliability standards addressing the calculation of available transfer capability (ATC).

The expedited schedule for the cybersecurity and PFV standards was in part because of feedback FERC received from the ISO/RTC Council (IRC) last year. (See RTOs, BPA Fear NAESB Rules Will Cut Tx.) The IRC said accelerating the adoption of PFV would help utilities “more accurately account for internal flows [i.e., network native load] by incorporating the use of real-time data into relief obligations” and thereby improve congestion management in the Eastern Interconnection.

FERC’s final rule also acknowledged a request by the IRC to “continue to acknowledge [that] each public utility may seek as part of its compliance filing waiver of new or revised standards in the WEQ version 003.3 standards and renewal of existing waivers.” The commission emphasized that its “policy on when these waivers will be granted or denied is not being changed” and said that it may grant such requests that are in the public interest. Unless the waiver is approved, however, “compliance … is still required by all public utilities,” FERC said.

May 21, 2021

FERC Approves Pipeline Orders After Impromptu Amendment Vote

FERC approved two natural gas pipeline projects at a bitter open meeting Thursday after accepting a last-minute, one-sentence amendment from Commissioner James Danly to gain his support.

Chairman Richard Glick and Commissioner Allison Clements, both Democrats, dissented in part.

Since shortly after Glick joined FERC in 2017, the commission’s members have disagreed on partisan lines over whether they should assess a gas infrastructure project’s emissions and their effects on climate change. These latest two orders were no different, with the three Republican members rejecting the need for such an assessment and the two Democrats dissenting over its lack thereof.

But they were also highly unusual, not just in the heated debate that took place prior to their approvals, but in the manner in which they were approved.

FERC pipeline orders — One of the projects that FERC approved is Northern Natural Gas’ Northern Lights project, which would expand the company’s system capacity along the Minnesota-Wisconsin border. | *Berkshire Hathaway Energy*

At issue were two projects to expand capacity on existing pipeline systems: Northern Natural Gas’ Northern Lights project in Minnesota (CP20-503) and TC Pipelines’ Tuscarora Xpress project in northern Nevada (CP20-486).

Glick brought orders granting the projects’ certificates of public convenience and necessity to a vote at the meeting despite his and Clements’ partial dissents over their lack of environmental impact statements regarding climate change. All five commissioners agreed that the developers had shown that the projects were needed.

Glick and Clements had reached a compromise in March with Republican Commissioner Neil Chatterjee to assess the climate impacts of a different Northern Natural pipeline project, the South Sioux City-to-Sioux Falls A-line Replacement Project. (See FERC Assesses Climate Impact of Gas Project for 1st Time.) But Glick and Clements said these latest two projects’ emissions were much more substantial, warranting a full EIS.

Nevertheless, Glick said, he thought it was best to allow the orders to move forward, as he expected the majority to approve them. Glick also told reporters in a teleconference after the meeting that, although he is able to as chairman, he does not want to withhold orders that the majority supports just because he does not, as both Chatterjee and Danly did during their tenures as chair.

Instead, Glick said, the orders contained data on the projects’ emissions without any analysis, as the commission has been doing since 2019 under a compromise between Chatterjee and former Commissioners Bernard McNamee (R) and Cheryl LaFleur (D). (See LaFleur Sides with Republicans on LNG Terminal as Glick Dissents.)

But Danly refused to support the orders as drafted because they “represent yet another change in the commission’s analysis of greenhouse gas emissions, and they fail under the [Administrative Procedure Act] because they do not properly acknowledge the serial departure, as happened” in a ruling on the South Sioux City-to-Sioux Falls A-line Replacement project in March. (See FERC Assesses Climate Impact of Gas Project for 1st Time.)

Danly had also dissented from that order for similar reasons, saying it marked a “drastic departure” from the commission’s previous positions and was unfair to the developer because it was unexpected. Both he and Commissioner Mark Christie (R) said the commission should not be changing its certificate policies until it completes its Notice of Inquiry on the subject, which Glick restarted in February. (See Glick Hits ‘Refresh’ at 1st FERC Open Meeting.)

Danly’s Motion

But Danly surprised all of his colleagues during the meeting by moving to amend both of the orders by adding a single sentence: “The forgoing analysis on greenhouse gas emissions is offered for informational purposes only, does not inform any part of this order’s holding and shall not serve as precedent for any future certificate order.”

He said the amendment, which he called “a simple and elegant solution,” would alleviate his concerns about the orders’ legality and allow him to vote for them. “What I want to avoid during a pending NOI is breaking new ground,” he said.

Before Danly’s motion — and without alluding to what exactly the dispute was about — both Glick and Chatterjee already sounded exasperated with the matter. Chatterjee said that “there is nothing productive about sitting in separate corners, insisting on getting 100% of what we’d like to see. … Today we could have moved two critical infrastructure projects forward, and the fact that we’re not is extremely frustrating to me. This is not a game.”

In his prepared remarks, Christie also expressed frustration with the debate and, in a way, chastised all of his colleagues. “There are five members that agree that these projects are needed, and let’s remind ourselves why: so people can heat their homes and not freeze in the winter; so people with gas stoves can cook; so people with gas water heaters can have hot water. These are needed projects; it’s not a bureaucratic exercise.”

He said he respected the Democrats’ position on the GHG issue but that he was frustrated by what he viewed as policy changes in both the A-line Replacement order and the two latest orders, citing “some members’ refusal to honor the NOI process.”

Danly’s motion only increased his colleagues’ exasperation.

“I think your motion is out of order,” Glick said. “You did not provide a copy of the amendment. I didn’t know you were going to make the motion. I talked to you many times yesterday; I talked to you again this morning. You didn’t even mention it once. You didn’t share it with anyone. … We all say this isn’t a game; let’s not play games. OK?”

“This is a deliberative body,” Danly responded. “Back before the prepared speeches and wooden performances of the commission’s meetings that we have today, it was very common practice for orders to be edited in real time, for amendments to be made in real time, during a meeting … and there is nothing of which I am aware — and I’ve looked into it — that is a new rule of procedure or a new order that the commission issued between the time that this was in common practice and today.”

Christie immediately voiced support for Danly’s amendment.

Glick, formerly a staffer for the Senate Energy and Natural Resources Committee, noted that it was standard procedure for senators to offer amendments on bills in advance of committee meetings, but that apparently the commission did not have any such rules. He also said that, though he was “deeply disappointed” that Danly did not present the amendment ahead of time, he would be fine with approving it, as it would not change his vote on the orders themselves.

Chatterjee, former adviser to Senate Minority Leader Mitch McConnell, was also supportive, but he scolded Danly for the maneuver. “People are watching this. The markets are watching this. We are toying with these companies. If this sentence is what would have taken to have gotten us to the three votes, it should have been offered before the meeting. … These kinds of methods and tactics — look, I used to do them all the time in the United States Senate — this is different. This is a regulatory body. … I’m very frustrated with how all this went down.”

“I wish I believed that this amendment was made in good faith,” Clements said. She said the GHG issue is “too serious a matter to get caught up in this surprise amendment proposal.”

Clements ultimately abstained from the vote on Danly’s motion, while the other four commissioners voted to approve it. The commissioners then voted 3-2 on the certificates themselves.

The text of the two final orders had not been published as of press time Thursday night.

“I do have optimism that our Notice of Inquiry on our long-outdated 1999 policy statement will give us the information we need to create a better approach,” Clements said. “With the NOI public comment period closing on May 26, we are drawing closer to that time and what I hope will be — although today is dampening my optimism a little bit — an improved, modernized and fair policy statement.”

May 21, 2021

Texas RE Knee-deep in Response to Feb. Winter Storm

The Texas Reliability Entity’s primary focus for the rest of the year will be on helping prevent another occurrence similar to ERCOT’s near collapse during the February winter storm, staff told their Board of Directors on Wednesday.

Mark Henry, the organization’s director of reliability services, said three staffers are working closely with NERC and FERC as those agencies investigate ERCOT’s response to the storm. The Texas grid operator, forced to make do without half of its generation because of the storm’s freezing temperatures, called for load shed that lasted for almost a week and resulted in billions of dollars in economic destruction to the state and the market.

Texas RE is waiting to see what the state legislature passes as far as weatherization of power plants and the natural gas system’s infrastructure, both of which have been fingered for most of the generation losses. Staff said they expect to take on more enforcement responsibilities with the final legislation.

Separately, the regional entity has conducted virtual outreach to generation owners on NERC’s pending cold-weather standard, a result of the January 2018 cold snap that primarily affected MISO South. (See FERC, NERC to Probe January Outages in MISO South.)

Texas RE storm response — NERC is nearing completion of its timeline for cold-weather standards as a result of a 2018 event. | *Texas RE*

The NERC project requires generation owners to develop and implement cold-weather preparedness plans for its units and includes notification provisions through “documented data specifications of generating unit status” during forecasted cold weather.

Joseph Younger, director of enforcement, reliability standards and registration, said Texas RE’s focus has been on “measurable standards” for freeze-protection measures and technologies. Staff also provided comments on clarifying implementation timelines and training requirements, he said.

The comment period ends May 28, with the final standards to be presented to NERC’s Board of Trustees in June. The standards will become effective 18 months from the first calendar quarter’s date following adoption. That would be as early as year-end 2022.

“We’re still trying to figure out how things work in the winter, but we do a better job of navigating the summer,” Texas RE CEO Jim Albright said. NERC’s draft 2021 summer reliability assessment warns that Texas faces a risk of energy shortfalls, echoing similar warnings in recent years. (See related story, FERC Summer Assessment Spotlights Western Drought Risks.)

Albright also addressed the recent hack that shut down the Colonial Pipeline, saying it serves as a warning to all. (See Experts Call for Cyber Shift in Response to Colonial Hack.)

“It does give us a perfect example of why we’ve got to work together as an industry and partner with regulators to ensure we have a secure and reliable grid,” he said. “This shows exactly what could happen to us.”

Texas RE has also completed its certification of Lubbock Power & Light as a transmission operator in advance of the utility’s load migrating from SPP to ERCOT over Memorial Day weekend. Staff issued more than 250 requests for information in completing the work.

Board OKs 20% Budget Increase

The board unanimously approved a 20% increase in Texas RE’s budget and business plan for 2022. The increase, from $14.2 million to $17.2 million, covers additional staff and relocation costs for new office space next April. (See Texas RE Asks for 20% Budget Increase.)

Texas RE’s annual expenditures are still below the average of other NERC REs.

The board also approved a nominating committee comprising independent Directors Suzanne Spaulding and Crystal Ashby and CPS Energy’s Curt Brockmann, and an audit with no reported findings of 2020’s financial statements.

NERC Trustees Rob Manning and Susan Kelly and new Texas Public Utility Commission Chair Peter Lake attended the virtual meeting.

May 21, 2021

FERC Summer Assessment Spotlights Western Drought Risks

Extreme heat and drought conditions are once again a major cause for concern in the Western Interconnection, while the ongoing COVID-19 pandemic is likely to drive uncertainty across the North American electric grid, according to FERC’s 2021 Summer Energy Market and Reliability Assessment.

In the report issued Thursday during the commission’s monthly open meeting, FERC staff noted that “resource availability has improved for this summer” compared to last year, when the organization warned that Emergency Measures Possible for ERCOT, FERC Warns.) But while reserve margins are “expected to be adequate in all regions under normal conditions,” six out of 13 NERC subregions may experience energy emergencies during “extreme environmental conditions.”

Temperatures up Continent-wide

FERC’s assessment partially draws on NERC’s not yet released Summer Reliability Assessment, which NERC staff previewed at last week’s Board of Trustees meeting. (See “Reliability Assessment Preview,” NERC Board of Trustees/MRC Briefs: May 13, 2021.) In that presentation Mark Olson, NERC’s manager of reliability assessments, explained that the above-normal temperatures expected across much of North America this summer are likely to drive up electricity demand, leading to elevated risk of energy shortfalls across the Western Interconnection, Texas, MISO and New England.

FERC’s report expands on these projections, noting that the elevated temperatures could also limit supply “by affecting power plant heat rates and transmission line carrying capacity.” In addition, the hot and dry weather is likely to contribute to the Western Interconnection’s ongoing drought, raising the threat of wildfires as warned in a Western Drought Increases Wildfire Risks.)

FERC summer assessment — Drought conditions in the West as of May 4, 2021 | *National Drought Monitor Center, University of Nebraska-Lincoln*

“Wildfires pose major operational risks as they can threaten major transmission lines, strand generation and compromise the delivery of electricity to customers,” the report said. “Transmission lines also pose a liability risk as high winds or lightning, along with dry conditions, could damage equipment and potentially trigger wildfires.”

Last year saw five of the six largest fires in California history, according to the state’s Department of Forestry and Fire Protection, while Colorado experienced multiple fires in 2020 that exceeded the previous acreage record set in 2002. The year was also one of the most destructive fire seasons ever recorded in Oregon. With the threat continuing to mount, FERC warned that California utilities are likely to use public safety power shutoffs to mitigate the risk of wildfires, potentially impacting thousands of customers.

Grave Conditions for California Hydro

Another potential victim of the drought in California is hydropower because of ongoing shortfalls in the snowpack in the Sierra Nevada and other mountains that provide water to the state during its dry season from May to October. The melting snow also feeds into reservoirs for hydroelectric dams and supplies cooling water for thermal generation, but the lack of snowfall in recent years is contributing to major issues for these facilities.

“California’s snowpack is critically low, at 6% of normal levels as of May 11,” FERC’s Gilberto Gil told commissioners. “According to the California Department of Water Resources, this has resulted in two consecutive years of below-average levels; last year during the same period, snowpack level was 16% of normal levels.”

The supply of water is likely to run out even earlier than one might first assume, as small snowpack melts faster than usual. This means California’s hydropower generation could peak early in the year, with less generation available for mid- to late-summer.

There are bright spots in Western hydropower, however. Washington’s Columbia river basin is near normal levels with 86% of normal snowpack, while the snowpack of the state as a whole is at 125% of normal. As a result, hydropower generation in this area may be higher than normal, helping to “mitigate upward pressure on electricity prices” in California and other Western states.

Capacity Additions Help Regions Meet Margins

Aside from the issues in the West, FERC’s report notes that more than 10 GW of electric capacity is scheduled to enter operation during summer 2021. Solar, wind and battery resources make up the majority of these additions, with CAISO projected to add about 1 GW of battery storage capacity and 500 MW of solar and ERCOT adding 4.5 GW in wind, solar and batteries.

PJM is the only region predicting a net loss of capacity, with 3 GW to be retired against 2.5 GW coming online. The biggest retirement is the 2.3-GW Byron nuclear plant in northern Illinois, but 700 MW of coal-fired generation is expected to retire as well. The additions comprise natural gas, solar and wind resources.

But all regions are positioned to meet reserve margins, according to NERC’s preliminary figures. PJM even looks to have the biggest cushion, with its nearly 35% anticipated reserve margin more than double its reference margin level of 15%. ERCOT, with a 15.3% reserve margin and 13.8% reference margin, has the lowest.

While these levels mean all regions should have adequate resources for normal conditions, extreme weather events, such as last year’s Western heat wave or hurricanes in the SERC Reliability footprint, could create difficulties for utilities on either the demand or supply side. The COVID-19 pandemic also represents a major unknown in entities’ planning: With many employers planning to end their remote work postures, the changes in commercial and residential loads will be hard to predict.

Natural Gas Findings

FERC staff also presented forecasts of summer natural gas markets during Thursday’s presentation:

Natural gas demand is expected to increase over last year, with demand — including net exports — up 2.6% to 82.9 Bcfd. This increase is attributed to a rebound in natural gas exports, up 4.6 Bcfd, or 85%, over 2020 levels. Total domestic demand is expected to decrease by 2.5 Bcfd, with the biggest decline — 4.6 Bcfd — in electricity generation because of higher gas prices relative to last year.
Production is projected to increase 2.2% above summer 2020 levels to 91.4 Bcfd, resuming a pattern of growth every year since 2017 that was broken last year because of the pandemic. The 2021 rise is largely attributed to an increase in crude oil costs, with WTI crude spot prices up nearly $20 on average over last summer.
Inventories are projected to be 3,700 Bcf at the end of the injection season in October, down 200 Bcf from last year. The injection season began at 1,750 Bcf, 240 Bcf lower than at the start of the 2020 season. However, the weakened demand because of the pandemic means natural gas volumes added to storage during this year’s injection season should be higher than both last year’s total and the five-year average.

May 21, 2021

Nonprofit Plans River-source Geothermal in Eastern Mass.

The Home Energy Efficiency Team (HEET) is developing a way to transport heat from the Merrimack River in eastern Massachusetts to houses using geothermal technology.

Eventually, the nonprofit plans to use heat from Massachusetts Bay to keep homes warm during the cold New England winters, Co-executive Director Zeyneb Magavi told NetZero Insider.

Drawing heat from a river or the ocean uses technology that is similar to ground source heat pumps.

Massachusetts is one of the most developed states in the country, and its densely packed houses leave little room for new infrastructure. More than half of the state’s housing stock relies on natural gas, but Magavi said geothermal heat pump systems can run in the same rights of way that gas pipelines occupy, creating a decarbonization pathway for the industry.

“Instead of delivering gas, we are delivering water at specific temperatures,” Magavi said.

Gas utilities could manage a system-wide geothermal network while retaining their workers for the maintenance and construction of geothermal lines and pumps, Magavi said.

Massachusetts geothermal — The Home Energy Efficiency Team wants to use river-source geothermal technology as an alternative to natural gas in Lawrence, Mass., which had 93 unrepaired pipeline leaks (seen here in yellow) last year. | *Home Energy Efficiency Team*

And while gas prices fluctuate, heat from the river or the bay is always free, she added.

Mark Sandeen, president of MassSolar, and Magavi estimate that lowering the temperature of the Merrimack River one degree with geothermal technology would produce 500 MW of thermal energy while benefiting the warming river ecosystem.

Applying the same thermodynamic principals to remove heat from ocean water would be restorative for the Massachusetts Bay, which is part of one of the fastest warming ocean waters in the world.

Pulling thermal energy from water is “cheaper, safer and more reliable” than natural gas, HEET Co-director Audrey Schulman said. Heat pumps can be placed under docks in the harbor or contained within concrete boxes on the side of the Merrimack River.

“A loop of pipe curled at the bottom of a river doesn’t interfere with the water, it just absorbs the temperature,” Schulman said.

The water in the tube at the bottom of the river would run colder than the water in the river, but slowly become warmer by soaking the heat out of the river into its water in the tube, bringing that temperature through a pipe system to houses and buildings.

Heat pumps allow utilities to control the speed of the energy transfer. If the system is run through the ground in the street directly to homes, there is “almost no thermal loss,” Schulman said.

Following a natural gas disaster in Merrimack Valley in 2018, students from Harvard University’s Climate Solutions Living Lab researched the viability of a Merrimack River source heat pump to heat homes. The system would serve low-income and minority communities in Lawrence, Mass.

Excessive pressure in natural gas lines owned by Columbia Gas caused a series of explosions and fires in 40 homes in the valley. Advocates in Massachusetts are pushing for alternative forms of energy to avoid similar tragedies in the future.

With only water in the pipes, geothermal energy does not pose an environmental hazard, Schulman said.

After screening various project sites, the Harvard lab project called for a three-phase approach to adoption of river-source geothermal in Lawrence, including a pilot project run by the Massachusetts Department of Environmental Protection (DEP). The lab also suggests an initial expansion of the pilot by two blocks before scaling up the energy system to more than 430 residences in Lawrence.

The report gives a wide cost range — between $123,000 to $481,000 — for the DEP pilot because the technology is new and there is uncertainty around the scale of the geothermal industry in the future. As proposed, however, the system would generate an estimated 1,600 alternative energy certificates, worth between $25,600 to $32,000 per year.

The pilot phase of the project would also reduce GHG emissions by 63 metric tons annually, and a larger district energy system would eliminate 510 metric tons of emissions from the air annually. Emissions from thermal energy systems would drop even more as the grid shifts to renewables.

Massachusetts is set to release a request for proposals for a competitive grant to build a networked geothermal project in the Merrimack Valley, run by the attorney general’s office.

“We are hopeful something really innovative can happen here,” Magavi said.

May 21, 2021

BP CEO Explains Oil Co.’s ‘Net Zero’ Target

This time, Bernard Looney insists, BP really does intend to move “Beyond Petroleum.”

Shortly after becoming the international oil company’s CEO in February 2020, Looney announced a strategy to transition it to an integrated energy company and to become net zero in emissions by 2050 or sooner.

“The world does have a carbon budget, it’s finite, and I think we’d all agree that it is running out… [and] society, including our employees, they want us to change, and they need us to change,” Looney said at Columbia University’s Center on Global Energy Policy (CGEP) Energy Summit Wednesday.

The company’s 2020 announcement included a pledge to reach net zero on carbon across its operations and its oil and gas production by 2050, while also reducing the carbon intensity of the products it sells by 50%.

Less Than Meets the Eye?

But the Transition Pathway Initiative, an investor-led group that tracks corporate climate plans, reported in May 2020 that none of the promises by BP and other oil giants were consistent with the Paris Agreement’s goal of limiting warming to below 2 degrees Celsius from pre-industrial times.

BP net zero target — Left to right: Jason Bordoff, CGEP; and BP Chief Executive Bernard Looney. | *Center on Global Energy Policy*

It also said BP’s pledge was less ambitious than its peers, covering only 51% of its externally sold energy. BP’s pledge to reduce the carbon intensity of the products it sells by 50% is its most significant commitment, TPI said. “However, with trading/supply and crude oil sales not covered by this commitment, BP’s overall emissions intensity only falls 20.5% by 2050.”

Other critics recall the fanfare with which the company adopted the slogan “Beyond Petroleum” in 2000. Greenpeace gave the company its first “Emerald Paintbrush” award for greenwashing in 2009 after the company shut down its wind and solar generation division. Greenpeace said 93% of the company’s investments were in oil and gas at the time.

Reuters reported this week that BP has lobbied for the European Union to continue supporting new natural gas plants, arguing that it was necessary for the shift away from coal.

IEA Report

Jason Bordoff, dean of the Climate School at Columbia University and founding director of the CGEP, didn’t ask Looney about that criticism in an interview with the CEO Wednesday. But he did cite the report issued by the International Energy Agency (IEA) this week that said achieving net zero emissions by mid-century would mean no new investments in fossil fuel supply. (See IEA Paints Daunting Path to Net Zero by 2050.)

“In 2050 oil and gas use are not zero, but obviously much lower than today, about a quarter of today’s oil use and less than half its gas use,” said Bordoff.

“Is that the world BP is planning for, and are you on board with it?” he asked Looney.

A few things stood out in the report, Looney said, including “an unprecedented jump in low-carbon spending, from $2 trillion a year to $5 trillion a year. That plays right into our strategy.”

One reason the company decided to pivot toward clean energy and climate goals is that “it’s an enormous business opportunity,” Looney said. “Trillions of dollars are going to get spent rewiring and replumbing the earth’s energy system. It’s a hard, complex problem to solve, and quite frankly we love that complexity because in many ways it’s what we’re built for.”

Indeed, the company announced last week it was partnering with Mexico’s Cemex to decarbonize the cement production process.

‘Responsibility to Lead’

Looney said that the world will continue investing significant amounts in oil and gas, “about $170 billion per annum in the 2040-plus period,” which he said is consistent with BP’s plans “to reduce oil and gas production by 40% within the next decade.”

The IEA report “is a scenario on a piece of paper, and what the world needs more than anything is maybe less scenarios and less debate, and more action, and that’s what we’re intent on doing,” Looney said.

Bordoff asked if BP’s reduced production targets meant that the company would no longer be investing in new oil fields.

“The carbon that’s liberated from the hydrocarbons that we introduce … we want to bring that down, we want to bring the absolute emissions of that down by between 35% and 40% by 2030,” Looney said. “And part of that means that we will produce 40% less oil and gas by 2030. It’s quite a unique part of our strategy, not something other companies have come out with. We think it’s the right thing to do, and right for our shareholders and investors because we want to be the best-run hydrocarbons business, not the biggest.”

Upstream spending has fallen from up to $19 billion annually to between $7 and $8 billion in 2021, he said.

Bordoff asked whether BP was concerned about losing money by being “ahead of the curve” with society’s environmental goals.

“Let’s take the example of hydrogen trucking in Germany,” Looney said. “I was talking to Ola Källenius, the CEO of Daimler, just a few weeks ago, and he was saying if you want to drive a 40-ton truck up a hill, that’s a lot of batteries. His view, and we would support it, is that hydrogen is going to be a solution in heavy duty transport.”

Daimler’s not going to build a hydrogen truck until there’s a customer for one, and no one will want a hydrogen truck until they know they can refuel it, and BP isn’t going to build a hydrogen network in Germany until it knows there are customers that will use it, he said.

“If we just said we’re going to do this in step with society, we’re stuck, because nobody moves,” Looney said. “We have a responsibility to lead, to pull people together, pull customers and OEMs and ourselves together and take what is otherwise an intractable problem and actually move it forward in a way that progresses the transition and equally doesn’t destroy value for our shareholders.”

May 21, 2021

Walgreens Looks Beyond Buildings Milestone at DOE Summit

After achieving its Better Buildings goal in 2020 to its reduce energy use by 20% across its 9,000-store portfolio, Walgreens (NASDAQ:WBA) is looking ahead at new opportunities to make its operations more efficient.

Walgreens became a Better Buildings Challenge partner in 2011 and reached its goal last year by focusing on HVAC and LED retrofits and more recently launching a refrigeration replacement program, according to David Hughes, senior director of facilities and energy management.

Reducing energy “over 100 million square feet of Walgreens footprint is not an easy needle to move,” Hughes said Thursday during the closing plenary session for the U.S. Department of Energy’s Better Buildings, Better Plants Summit.

Now, the company is focusing on an internal smart buildings program that taps data for efficiency measures beyond retrofits.

“Managing thousands of stores across a huge footprint gives us a small city to make sure that we’re operating as efficiently as possible,” Hughes said. “Putting as much technology and automation in these stores over hundreds of thousands of assets and leveraging that data to help guide our decisions … is the best way to keep bending the curve on our consumption.”

Walgreens has rolled out about one-third of its smart buildings program and has a few more years to go before it is completed.

“Having an intelligent building platform is critical to setting the stage to identifying the right next strategies that are going to help us build upon our strong foundation of energy efficiency,” he said.

Walgreens buildings — Walgreens, which debuted the net-zero store seen here in Illinois eight years ago, met its Better Buildings goal this year to reduce energy 20% across its 100 million-square-foot portfolio. | *Walgreens*

Walgreens hopes to look at the power it uses to understand its stores’ baseload requirements better. With that data, Hughes said, the company could deploy distributed generation technologies in the near term to ensure stores remain open during emergencies as critical infrastructure.

Based on its stores’ current power needs, Hughes said the right DG solution for smaller loads is not available yet.

“Many of the scale technologies that are out there operate in the 100-kW to 250-kW block, and that’s way above our load,” he said. “We’re at about 60 kW to 70 kW on average in a store.”

Procter & Gamble (NYSE:PG) is also looking at new energy challenges after 11 years as a Better Buildings partner. The company, which owns iconic brands like Downy, Head & Shoulders and Tide, is building on the success of collaborative efforts like the Renewable Energy Buyers Alliance.

P&G set a goal in 2010 of using 30% renewable energy by 2020, which it reached, according to Steve Skarda, GHG and energy director. But tackling natural gas emissions associated with manufacturing is a much bigger challenge than the transition to renewables was, he said.

“We’ve covered all the emissions that we can eliminate with renewable electricity and efficiency and [carbon] offsets this decade, so we are net zero today, but that’s not the long-term vision,” Skarda said.

P&G is participating in the Renewable Thermal Collaborative and trying to identify the role electrification will play in the organization and how best to tap new technologies, such as hydrogen and carbon capture.

May 21, 2021December 5, 2023

HECO, Hawaii PUC Go More Rounds over Clean Energy Plans

Two recent orders illustrate how the Hawaii Public Utilities Commission’s growing frustration with Hawaiian Electric Company’s halting progress on clean energy development is matched with an increasingly weak hand in dealing with the utility’s delays.

A new round of back-and-forth between the PUC and HECO began with an April 29 order in which the regulator approved the proposed Kapolei Battery Energy Storage System (BESS), a 185-MW, 565-MWh system to be built on Oahu.

In approving the project, the PUC cited concerns about HECO’s two-year delay in developing other renewable energy projects, which could stall the decommissioning of AES’s coal-fired Hawaii Power Plant (37754). (See Discontent Mounts over HECO Coal Plant Closure Plans.)

“The Commission is approving this Project to provide further assurance that the ‘lights will stay on’ during the retirement of the AES coal plant in 2022 and future retirements of aging fossil-fueled plants in the next several years,” the PUC wrote.

The other order directed HECO to quantify the customer costs stemming from its delays in building renewable energy projects (37752). The PUC said that “due to the ongoing loss of customer bill savings resulting from these delays, the Commission finds it necessary to direct Hawaiian Electric to quantify the magnitude of those lost savings.”

The order requires HECO to “establish regulatory liabilities” to record costs arising from the delays of Stage 1, Stage 2 and Community Based Renewable Energy (CBRE) Phase 1 projects.

The PUC made its frustrations clear in the BESS order: “Despite the Commission’s multiple admonitions to utilize standalone storage fueled by fossil fuels as a last resort, Hawaiian Electric appears to continue ignoring the high costs of this Project and attendant risks of further dependence on fossil fuel by their representations throughout this docket.”

It added that “the urgency of this situation is largely a byproduct of Hawaiian Electric’s willful disregard of the Commission’s guidance and presents a number of concerning impacts to ratepayers.”

The PUC approval of the BESS came with nine conditions, including:

- - a prohibition on HECO seeking cost recovery through performance incentive mechanism (PIM) awards for Stage 1 projects;
  - removal of requirements for energy storage on Phase 2 CBRE projects on Oahu, expanded CBRE capacity, and removal of daytime export restrictions for existing and new distributed energy resources programs;
  - commitment to closure dates for fossil fuel units at HECO’s Waiau and Kahe facilities;
  - submission of monthly reports on the amount of fossil-fuel energy stored in BESS and how much the facility is being used;
  - adherence to a PUC-mandated minimum threshold for renewable energy charging for BESS, or face penalties for failing to do so;
  - prohibition of HECO affiliates from having a relationship with BESS;
  - creation of an annual utilization report that includes an explanation for any missed milestones;
  - creation of an “end-of-life management plan” for BESS;
  - crediting of all daily delay damages to HECO customers.

‘Highly Problematic’

HECO and BESS developer Kapolei Energy Storage I (KES) filed separate motions for reconsideration of Order 37754.

In its motion, HECO said while it understood the need for some of the conditions, “at least four are highly problematic for reasons that go well beyond the Project.” It argued that the PUC’s approval “is in title only” because the conditions would be tantamount to forcing HECO or KES to cancel the energy storage power purchase agreement (ESPPA).

HECO complained that the rejection of PIM awards for BESS amounts to a $1.7 million loss, what the utility calls a violation of its due process rights. It also contended that removing grid constraints for CBRE would require physical upgrades to the grid, while the “forced financial or operational retirement” of fossil fuel burning units raises financial and grid reliability concerns.

HECO expressed particular concern about the minimum renewable energy charge requirement, saying it would prevent BESS from charging at times when renewable energy is unavailable, and that the requirement for a minimum unlawfully exceeds targets in Hawaii’s renewable portfolio standard (RPS) rules. The condition renders BESS “largely unusable,” and if not removed, “it will mean that the KES Project will have been effectively terminated,” HECO said.

The utility expressed its frustration with the PUC, saying that it is “particularly troubled by the accusatory and derogatory statements from the Commission that have seemed to escalate as of late.” It says that the development of renewable infrastructure is complex and that missteps and differences of opinion can result.

In addition, HECO said that “the Company respectfully submits that the Commission’s unsupported and unnecessarily disparaging characterization of the Company’s planning efforts is erroneous, not supported by fact.” It said many factors contributing to delays were out of HECO’s control, including the PUC’s reviewing time.

“Simply put, this is a good project and one that is needed now,” HECO said.

KES Motion

KES’s motion noted that the ESPPA gives HECO sole discretion to determine whether a PUC approval order is satisfactory and that the PUC’s added conditions could pressure the utility to cancel the deal altogether. The company also expressed worry that the project could suffer additional delays if HECO requested a stay of the approval order. A delay or cancellation of BESS would further jeopardize the planned retirement of the AES coal plant, KES said.

KES also argued that the first five conditions in the order could constitute an abuse of discretion on the part of the PUC, citing a Hawaii Supreme Court ruling as saying such an abuse exists if “an agency’s sudden change of direction leads to undue hardship for those who had relied on past policy.”

The company additionally contended that the PUC took more than eight months to consider BESS, a timeline that forced the company to “redesign and renegotiate its construction and supplier plans and deadlines,” along with dealing with a “global supply crunch” for batteries.

KES also expressed frustration at the PUC’s characterization of the proceedings, saying the company “was deeply disappointed” to see PUC Chair James Griffin equate the charging of BESS with oil-fired generation with the use of crack.

HECO and KES both said that BESS is important for the decommissioning of the AES coal plant, and that the PUC’s conditions are better served in separate dockets rather than being tied to the approval of BESS.

PUC Yields

The PUC on Friday gave ground on most of the conditions, partially granting HECO’s motion for reconsideration while denying KES’s motion as moot.

The regulator’s response eliminated the first (PIM) condition entirely, while removing the second to be reused in corresponding DER and CBRE dockets. In modifying the third condition, the PUC still required HECO to shut down Waiau Units 3 and 4 while removing the requirements for the other units.

The PUC also agreed to modify the fifth condition to remove the minimum thresholds and will instead conduct an annual “prudence” review. The seventh condition will remain but with fewer requirements for HECO’s Annual Utilization Report.

The PUC also denied HECO’s request to strike the “offending” language used in Order 37754, saying it “used pointed language in describing its disappointment with being placed in the position of having few options to respond to the extremely serious situation that is developing as a result of the retirement of the AES coal plant next year” and that “the record in this proceeding clearly supports the Commission’s findings and conclusions.”

After reviewing the PUC’s changes to the modifications, HECO agreed to proceed with the project. However, the utility maintained that it “still disagrees with that certain language and those certain characterizations used” in order 37754.