Transmission owners told PJM last week that its rules for supplemental projects satisfy the RTO’s obligation as a regional planner, despite protests from dissatisfied load interests.
Executives from a dozen TOs sent a letter to the Board of Managers on Thursday applauding the way staff addressed stakeholder concerns while implementing revisions to Manual 14B: PJM Region Transmission Planning.
The TOs said the current manual language reflects months of compromise by stakeholders and demonstrates PJM’s willingness to increase transparency at every stage of the Attachment M-3 process approved by FERC.
“This has resulted in a process that harmonizes the presentment of baseline and supplemental projects such that there is minimal difference between the two presentments beyond the PJM board’s approval of baseline projects,” the letter reads.
Transmission owners sent a letter to PJM’s Board of Managers supporting how staff implemented revisions to supplemental project planning rules. | Entergy
At January’s Markets and Reliability Committee meeting, PJM rejected two paragraphs in a set of revisions that stakeholders approved for inclusion in Manual 14B. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
The paragraphs came from an American Municipal Power proposal — designed to address load interests’ concerns — that said supplemental projects “should be based on written articulable criteria, models and guidelines that are measurable and, to the extent available, quantifiable (e.g., asset replacement prioritization) so stakeholders can replicate TO planning decisions and validate their proposed solutions.” AMP cited the transparency principles in FERC Order 890, saying TOs should disclose asset-specific condition assessments and the criteria and models supporting supplemental projects.
PJM staff opted against incorporating the revisions, saying the disputed text is an “overreach” of the RTO’s Regional Transmission Expansion Plan, which is limited to studies of load flows, short circuits and stability.
The TOs backed the RTO’s stance, saying “PJM correctly determined that certain suggested changes went beyond and/or were not consistent with the FERC orders, and that stakeholders were advancing positions through manual changes that FERC had already rejected.
“What must be considered is that PJM and the PJM TOs have the ultimate responsibility for ‘keeping the lights on,’” the letter concludes. “This consideration must be weighed when planning processes are modified.”
In a separate letter to the board Feb. 11, the American Public Power Association and the Transmission Access Policy Study Group said the RTO’s refusal to incorporate AMP’s language lacks “compelling justification.”
NEW ORLEANS — Entergy Louisiana CEO Phillip May says his company’s electric rates are among the lowest in the nation. Attorney Randy Young, who represents a group of industrial customers in the state, says his clients can do better.
Entergy and the Louisiana Energy Users Group (LEUG) will eventually make their competing cases to the Louisiana Public Service Commission. On Thursday, May, Young and others previewed the debate at the Gulf Coast Power Association MISO South Regional Conference.
At issue is Entergy’s proposal to spend $10 billion to $12 billion to address a 7,000-MW capacity deficit Entergy Louisiana forecasts through 2038.
Of the total shortfall, 5,800 MW is from generation deactivations while only 750 MW is from projected load growth. As a result, Young said, costs will increase much faster than sales, which LEUG consultant Brubaker and Associates says would increase base rates by at least 50%.
Young said industrial customers should be given the option of purchasing from the wholesale market or using combined heat and power (CHP) generation to serve their needs, which he said would decrease the shortfall, potentially saving money for Entergy’s remaining captive ratepayers. He’d also like a new tariff that gives industrials the option of choosing interruptible service, real-time pricing and a market-based standby service, under which customers pay for capacity and energy based on MISO clearing prices.
Young’s position was echoed by Devin Hartman, CEO of the Electricity Consumers Resource Council (ELCON), a D.C.-based group that represents large industrial electric consumers nationwide.
Hartman, who joined May in the final panel of the conference, said his members want to take advantage of falling energy prices and flat load growth. “When you have supply-side shifts or demand-side shifts in the electric industry, you’re going to see markets respond very differently than a regulated, cost-of-service process will,” he said. “Overwhelmingly we’ve seen upward pressure [on rates] in most regulated states for end-use consumers across classes, whereas we’ve seen downward pressure for the most part in the market states.”
Failing that, he said, regulators should ensure state procurements for new generation are truly competitive and not gamed by incumbent utilities.
Hartman said industrials’ interest in direct market access is most pronounced in regulated states in an RTO. “MISO is going to be one of the next ground zeroes, I think, for this going forward,” he said.
While some advocates for residential consumers have reservations about retail choice, Hartman said, “You’ve seen [commercial and industrial customers] just say, ‘Give us the markets. We don’t need to have our hands held anymore. We don’t need a paternalistic approach.’”
With generation trending toward low-marginal-cost renewables, “it becomes more and more important to make sure that we’re injecting more accountability mechanisms and competitive forces to drive more efficient procurement and entry [and] exit of resources in the overall electricity sphere,” Hartman said.
Entergy Responds
May responded that “unregulated states are paying substantially more than the regulated states” and that Louisiana has “some of the lowest rates in the country.” According to the Energy Information Administration, Louisiana had the cheapest residential electric rates and sixth-lowest industrial rates in November 2018, the most recent data available. A recent survey by LEUG found Entergy Louisiana’s industrial rates were the eighth-lowest among 30 Southeastern utilities.
May said LEUG’s projection of a 50%-plus increase in rates must be put in context. “If rates go up 50% [though 2038], that’s 2.5 to 3% annually. Base rates for industrial customers are about half [of residential rates], so maybe 1.5% [annually] … which is about the rate of inflation.
“I can tell you we want to provide the lowest-cost electricity we can to those industrial customers because they are competing on a global stage, and we intend to continue to be competitive so we can attract that load and have them continue to be successful.”
With the planned opening of the St. Charles Power Station in June and the Lake Charles Power Station in June 2020, Entergy Louisiana will have replaced about half of its older capacity with more efficient natural gas units since 2004.
LEUG made its proposal in a docket opened by the Louisiana PSC to consider alternatives to integrated resource plans filed by Entergy Louisiana, Entergy Gulf States, Cleco Power and Southwestern Electric Power Co. (S-34426).
The commission held two technical conferences in 2017 and received written comments earlier this month in response to a Dec. 14 staff report on the issue. LPSC spokesman Colby Cook said no timeline has been set for commission action.
A View from Arkansas
Arkansas Public Service Commission Chair Ted Thomas, who appeared on an earlier panel with Young, said he would consider an equivalent to the LEUG proposal in Arkansas, but he would “match it with a … program that gave residential [customers] as much of an opportunity to change their behavior as the commercial people do.”
“We need low rates for our industrial customers to compete and provide jobs. But the area between [New Orleans] and the boot heel of Missouri — if you draw a circle around that [Mississippi] river — is the most protracted area of poverty in this entire country. And we can’t shift costs over to them,” he said.
Thomas said his “end goal” in Arkansas is “a grid that is plug-and-play with respect to all existing and new technologies, that serves as a platform for an apples-to-apples price comparison and provides price visibility for all technologies with respect to capacity, energy and ancillary services. … It’s a challenging goal because then you’d want some way to compare the price of, say, a rooftop solar installation with an interruptible tariff. You want competition across the whole thing.”
To get there, Thomas said, third parties need to have the same access as incumbent utilities to automated meter data “under the right privacy restrictions.”
“If you don’t have data access, you don’t have a level playing field, and if there’s not a level playing field, your entrepreneurs and innovators won’t come and play and there will be no innovation,” he said. “A second key issue is aggregation. If you’re going to have data access and you want to represent customers, you have to put them in a group. If you don’t have data access and aggregation, you’re not going to get the consumer involvement that you need to have a consumer-driven innovation the way that we’ve seen in telecom and other areas.
“There’s only so many utility nerds out there … most of them are probably sitting in this room,” Thomas continued. “We need a killer app to automate demand response, to automate the consumer to have a consumer-driven system.”
Three years ago I wrote skeptical analyses of Big Transmission, microgrids and grid batteries.
I thought it might be interesting to see how those analyses are holding up and add a New York note.
Big Transmission
“The Rise and Fall of Big Transmission”1 gave the reasons why Big Transmission has never made sense. Much of it is pretty basic, such as the fact that energy is transmitted, not electrons. As Scotty said, you can’t change the laws of physics.
Since that article, Clean Line Energy (remember them?) has sold off a couple pieces and seems to be otherwise winding down. Hopefully someone will write that history.
Getting a lot of hype last year was the release of a “study” led by the National Renewable Energy Laboratory claiming that huge interregional transmission projects make economic sense.2 I put “study” in quotes because even though it was reported as a “study,” it actually was a slide deck describing some future real study. A slide deck is essentially a black box because you can’t tell what’s going on with somewhat important stuff like input assumptions, algorithms, etc.
This study is like its predecessors that I debunked in the original article.
One screaming flaw is the study’s claim of an estimated $14 billion cost for an HVDC transmission buildout to transmit 36 GW from west to east.3
Such an HVDC transmission buildout, if ever politically possible, actually would cost at least $50 billion under the least expensive Energy Information Administration estimate of HVDC cost per megawatt-mile of $700.4 This minimum $50 billion cost is more than the study’s claimed benefits.5
For Big Transmission, the song remains the same.
In its 2018 Interconnection Seams Study, the National Renewable Energy Laboratory’s “Design 2b” envisions three HVDC transmission segments built between the Eastern and Western Interconnections, with existing facilities co-optimized with other investments in AC transmission and generation. | NREL
Microgrids
“Microgrids: Where’s the Beef?”6 explained why microgrids are an inherently uneconomic throwback to the utility islands of the 19th century (yes, that century). Amusingly, some microgrid proponents are now talking about the importance of integrating microgrids into the grid,7 which of course is what the grid itself is all about: integration.
Microgrid proposals continue to proliferate but only where subsidized by Other People’s Money, which in utility parlance means utilities get enormous returns on microgrid projects that are paid for by other — non-microgrid — customers.
The acid test should be whether microgrid beneficiaries are willing to pay for the cost of the microgrid themselves. The answer is never — because people aren’t dumb.
One shocking attempted raid of federal taxpayers, and the undermining of our national defense, was a study by a consultancy Noblis for the Pew Charitable Trusts urging that our nation’s military bases replace individual backup generators at critical buildings with base-wide microgrids. I pointed out in a later article8 that because 87% of base outages were cause by on-base distribution system failures that centralizing backup base generation in a microgrid would dramatically increase outage risk for critical buildings. Not to mention that microgrids are inherently vulnerable to cyberattack while individual building backup, typically diesel, is not internet-connected and therefore not vulnerable to such attack.
My favorite factoid remains this: The nation’s “flagship” microgrid at the University of California, San Diego flunked its acid test in the Southwest Blackout of 2011. The campus shut down with the rest of San Diego.9
You can’t make this stuff up.
Grid Batteries
“Grid Batteries: Drinking the Electric Kool-Aid”10 debunked this continuing infatuation of our haute couture crowd. The newest shell game is the notion of “value stacking,” which is the equivalent of saying that you can jog around the neighborhood while watching your kids at home. No, not possible.
By the way, batteries increase carbon emissions.11 Two reasons: The generation used to charge batteries tends to be dirtier than the generation displaced when batteries are discharging. And there are losses from converting AC to DC, storing energy and converting back. Batteries ≠ green.
Battery boosters, realizing they can’t make it on the merits,12 have been lobbying regulators and legislators to subsidize them through procurement mandates, direct subsidies, utility rate base and other special treatment.
My favorite is New York arbitrarily deciding that 1,500 MW (oops, now 3,000 MW) of grid batteries sounded like a good, round number and putting up $265 million of Other Peoples’ Money for that.13
Escape from New York
This is the same New York that is forcing the shutdown of the economic Indian Point Nuclear Plant; subsidizing uneconomic upstate nuclear plants; subsidizing 2,400 MW (oops, now 9,000 MW) of uneconomic offshore wind;14 risking electric reliability in New York and New England and curtailing new natural gas home connections by blocking federally certificated natural gas pipelines;15 paying $1,973 per public housing apartment to install LED lighting;16 and stiffing Cheryl LaFleur,17 a dedicated public servant, for another FERC term because Chuck Schumer didn’t like a highly technical, totally correct NYISO decision.18
New York, you are a Green New Deal Mini-Me. Condolences.
Amazon, you got out while the gettin’s good. Congratulations.
4- The cheapest HVDC cost per megawatt-mile is $700 per this EIA study, https://www.eia.gov/analysis/studies/electricity/hvdctransmission/pdf/transmission.pdf (pdf pages 33-34). $700 MW-mile x 12,000 MW each HVDC line x three HVDC lines x 2,000 miles each line = $50 billion. This does not include the enormous AC transmission facilities that would be required to accommodate the HVDC lines (i.e., inject/withdraw 12,000 MW each line from their converter stations in the middle of nowhere).
5- The negative “Total Non-transmission Cost” of $45.16 billion on slide 15 of deck in footnote 3.
9- http://www.eenews.net/stories/1059996047. (“The university’s two 13.5-MW Trident turbines were running full-bore when power from the utility abruptly went dead. With no time to shed their load, the turbines also shut down, and the campus lost electricity.”)
14- https://rtoinsider.com/new-york-renewable-energy-109515/. Gov. Andrew Cuomo claims that the offshore wind would be located in “this state.” No, it would not. It would be located far outside New York’s nautical boundary that is 3 miles from shore.
Both the PJM Markets and Reliability and Members committees held their meetings Thursday via conference call because of a snowstorm that hit the East Coast the day before. The meetings had originally been scheduled to be held in Wilmington, Del.
Markets and Reliability Committee
Transmission Replacement Vote Deferred Until April MRC
The MRC on Thursday agreed to delay a vote on revised transmission planning rules until April by a sector-weighted vote of 3.73 to 1.27, with the Transmission Owners sector opposed.
Sharon Segner of LS Power asked for a deferral to accommodate further discussion on the language her company crafted for Manual 14B: PJM Region Transmission Planning regarding how supplemental projects are added or removed from the Regional Transmission Expansion Plan. The proposal specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” if it is rejected by a regulatory agency.
The RTO has suggested a review of the entire process at the Planning Committee in response to LS Power’s proposal. Segner told the MRC that the delay would allow extra time for the PC — through regular or special meetings — to discuss the process in detail, including its relation to FERC Orders 890 and 1000. (See “Holistic Review of RTEP Removal Suggested,” PJM PC/TEAC Briefs: Feb. 7, 2019.)
Segner first presented the proposal during the Jan. 24 MRC meeting as a friendly amendment to a proposal from American Municipal Power to increase transparency of supplemental project planning. PJM accepted most of AMP’s proposal, but it rejected one section that it called an overreach of the RTEP. This seemingly rendered LS Power’s amendment moot, but Segner successfully moved to delay any action on it until Thursday’s meeting. (See PJM Rebuffs Stakeholders on Supplemental Projects.)
NextEra Energy offered a friendly amendment to the LS Power proposal that would require PJM to remove supplemental projects with incomplete siting permit applications from the RTEP. If PJM discovers an RTEP project that would eliminate the need for the proposed supplemental, the RTO would inform all applicable committees and regulatory agencies. Segner said the amendment will become part of the PC discussions in March and April.
Stakeholders Urge Slower Timeline on Fuel Security
Stakeholders told PJM their 12-month timeline for addressing potential fuel security threats and accompanying market rule changes is too aggressive.
PJM’s Mike Bryson solicited feedback from the MRC on a first reading of a problem statement and issue charge centered on ensuring grid reliability during times of extreme stress.
In November, PJM released an eight-page summary of a study that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements. The study, which evaluated more than 300 winter scenarios, was a “stress test … intended to discover the tipping point when the PJM system begins to be impacted,” the RTO said. (See PJM Begins Campaign for Fuel Security Payments.)
Bryson said PJM would schedule a vote on the problem statement for the March 21 MRC, with a task force recommendation by September and a FERC filing in December.
“I think it’s prudent for PJM to put a timeline out there,” Bryson said. “I don’t want to go to the opposite extreme and say it’s open ended.”
PJM drafted the problem statement as part of a three-phased approach for ensuring the resilience of its generation portfolio. Staff completed the Phase 1 analysis in December, saying that while no imminent risk currently exists, the RTO should explore proactive, market-based mechanisms for retaining or procuring fuel-secure resources.
A multitude of stakeholders said that while they appreciated PJM’s work on the issue, the timeline Bryson presented was far too short, saying there needed to be more discussions before any recommendation came before the committee.
Paul Sotkiewicz, president of E-Cubed Policy Associates, went further with his criticism.
“What you have done is shown there isn’t an issue here,” said Sotkiewicz, representing Elwood Energy, a 1,350-MW gas-fired generator in Illinois. “I think that’s very important for policymakers to see there is no problem. … We are talking about making market design changes when there is absolutely no evidence that there is a problem with market design.”
He encouraged other stakeholders “not to go down the road” but instead pursue a market-based analysis.
PJM staff gave stakeholders a March 7 deadline for submitting feedback on the problem statement, with an updated draft to be released March 14.
Manual Changes Endorsed
Stakeholders approved the following manual changes:
Manual 14B: Transmission Planning Process: Cover-to-cover periodic review. Includes changes to section 1A on critical energy/electric infrastructure information (CEII).
Manual 14D: Generator Operational Requirements: Added requirements to section 7.1.1 regarding generator real power control associated with FERC Order 842, which requires new generators seeking interconnections to be equipped to provide primary frequency response. The new rules apply to generators that entered the PJM transmission queue on or after Oct. 1, 2018. (See FERC Finalizes Frequency Response Requirement.)
Manual 12: Balancing Operations: Cover-to-cover periodic review with updates to section 3 regarding primary frequency response per FERC Order 842. The changes were endorsed by the Operating Committee on Feb. 5 over the opposition of FirstEnergy and Duke Energy. FirstEnergy challenged the manual’s formula for judging primary frequency response performance. (See “Utilities Question Primary Frequency Response Calculation,” PJM Operating Committee Briefs: Feb. 5, 2019.)
Members Committee
Calculator Vote Placed in ‘Parking Lot’
The MC agreed to postpone a vote on whether to force PJM to accept opportunity costs calculated by the Independent Market Monitor until a member requests it.
Bob O’Connell of Panda Power Funds had proposed Operating Agreement changes last August if PJM refused to accept the Monitor’s calculator in determining generators’ cost-based energy offers.
The proposal passed the MRC in August, which incentivized the RTO and the Monitor to work toward a deal, announced the following month. The MC had postponed a vote at its September meeting to give PJM and the Monitor time to put the new process in effect. (See “PJM, Monitor Come to Agreement on Opportunity Cost Calculator,” PJM MRC/MC Briefs: Sept. 27, 2018.) Under the agreement, the Monitor will explain its inputs and logic to PJM to demonstrate that the unit-specific opportunity costs are compliant with the OA.
O’Connell said the unusual motion puts the issue in a “procedural parking lot,” giving members flexibility to bring up the issue on short notice in case PJM suddenly decided the Monitor’s calculator was no longer valid. Stu Bresler, PJM senior vice president of operations and markets, said staff supported the motion.
Stakeholders to Consider Retiring Wilmington as Meeting Site
Members will vote next month on a proposal by Katie Guerry of Enel X to move all MRC and MC meetings to PJM’s Conference and Training Center in Valley Forge, Pa., instead of splitting them between there and The Chase Center on the Riverfront in Wilmington, Del.
PJM had held all its meetings in Wilmington until it opened the center in 2012, where it began holding lower committee meetings and some MRC/MC meetings. The RTO had historically been centered around the I-95 corridor, and the city was deemed a good midpoint, Dave Anders, director of stakeholder relations, explained to the committee.
Guerry said that the Valley Forge location provides stakeholders cost efficiencies, as they have access to PJM staff and resources while they are there.
Virtually all stakeholders who spoke expressed reluctant support for the proposal, saying that while Valley Forge is harder to get to because of a lack of public transit options, the facility provides a far better meeting experience. Several noted that there are often technical difficulties at the Chase Center — the RTO’s meeting site in Wilmington — with unreliable wireless connections causing delays in voting.
Several others noted that ride-sharing services such as Uber have made up for the lack of public transportation in the area.
Stakeholders were prepared to approve the proposal immediately Thursday, but Guerry said she wanted to give PJM meeting planners time to review the RTO’s contract with the Chase Center, as well as give any on-the-fence members time to think about the issue.
Entergy last week reported a fourth-quarter loss of $66 million ($0.36/share), beating analysts’ expectations by 12 cents. That compared favorably with a $479 million loss for the fourth quarter in 2017 ($2.66/share).
Five analysts surveyed by Zacks Investment Research had projected a loss of 48 cents/share.
For the year, Entergy reported earnings of $849 million ($4.63/share), compared to $412 million ($2.28/share) in 2017.
In a Feb. 20 conference call with financial analysts, Entergy CEO Leo Denault said 2018 was “another successful year” and said the company is “on track” to achieve its long-term goals.
The company said its results reflected asset impairments and other expenses related to its decision to exit its Entergy Wholesale Commodities business and its four aging nuclear plants. The New Orleans-based company completed the sale of Vermont Yankee and announced agreements to sell Pilgrim and Palisades. (See Entergy Sees Quicker Exit from Pilgrim, Palisades Nukes.)
Denault said Entergy is making progress on Pilgrim’s sale to Holtec and is “actively working” toward a post shutdown sale of New York’s Indian Point plant. Pilgrim will be shut down no later than May 31.
“We executed on our strategy and met major milestones in our transition to a pure-play utility. We expect 2019 will be no different,” Denault said.
The company’s stock price gained $3.67 after opening at $89.10 on Feb. 20, closing the week at $92.77. Entergy’s stock price is up 7.8% this year through Feb. 22, slightly above the 7.3% gain by the S&P 500 Utilities index.
OGE Earnings Slip, but Beat Expectations
OGE’s quarterly performance nevertheless beat Zacks’ consensus estimate of 24 cents/share. The Oklahoma City-based company reported a fourth-quarter net income of $54.7 million, down from $295 million the year prior when it enjoyed a $198 million windfall, thanks to the 2017 Tax Cuts and Jobs Act.
OGE CEO Sean Trauschke told financial analysts during a Feb. 21 conference call that 2018 “may well be regarded as the best [operational] year in our company’s history.”
Trauschke pointed to strong safety numbers, the addition to its fleet of the 462-MW Mustang Energy Center and its seven gas-fired generators, the commissioning of a 10-MW solar farm, the addition of scrubbers at its two coal-fired Sooner Power Plant units, and the conversion to natural gas of two coal units at its Muskogee Power Plant.
Wall Street reacted favorably to OGE’s report. The company’s share price was up 2.2% following its open Feb. 21, gaining 94 cents to close the week at $42.78.
AUSTIN, Texas — Parks Associates’ annual Smart Energy Summit attracted more than 100 industry representatives to the state capital, home to Silicon Hills and a vibrant technology environment.
Attendees participated in workshops and panel discussions on new roles for utilities as U.S. households adopt smart technologies, creating new layers of competition and complexity for home services, grid operations and energy management.
It’s not just about “customer engagement” but making everything easier for the customer, agreed a panel discussing new ways utilities can expand their footprint beyond traditional energy services.
“If you send someone a switch that requires a screwdriver … well, the vast portion of our population doesn’t use a screwdriver. They hire someone who uses a screwdriver,” said Joel Miller, a principle supervisor with DTE Energy. “Can the utility now become the homeowner’s handyman? We don’t know that yet.”
“We have to think like Netflix; we have to think like Amazon and make the customer experience easier and easier,” Tendril CEO Adrian Tuck said.
“Everybody is selling something smart … consumers have all these options,” said Todd Rath, marketing services director for Alabama Power. The consumer “doesn’t want 12 different apps. The opportunity for utilities is to combine all these things.”
Case in point: Alabama Power’s Smart Neighborhood initiative, in which the utility partners with Alabama homebuilders to build energy-efficient, smart neighborhoods. Its first neighborhood in the Birmingham suburbs integrated “high-performance homes, energy-efficient systems and appliances, connected devices and a microgrid on a community-wide scale.”
“It was not an energy efficiency or microgrid project, but a living lab to understand how those things work together,” Rath said.
To do so, the 62 homeowners had to all agree to a 24-month research project in which all the data would be collected. Rath said Alabama Power learned “some things are good, some things are bad.”
“We think the future is going to be [distributed generation] and connecting to that DG to maximize the grid and customer experience … seamless integration,” he said. “That all sounds good when you talk about it, but when you try to implement it, things come up that you’re not aware of.
“I don’t think we’re going to out-Amazon Amazon. We’re looking to advance electrification, to find a way to help customers understand the next generation of the grid,” Rath said.
“We believe the utilities are in a great position to do so much for the customers. They just need the tools to reframe the relationship,” Simple Energy’s Judd Moritz said. “If you do it right, you make the utility central to every decision the customer makes. You will become one of the largest retailers of smartphone-enabled technologies in America.
“We have that trusted adviser role,” Miller said. “We want to ensure we’re continuing to do that.”
Gen Z a Growing Consumer Group
Aaron Berndt, the head of Central Region Energy Partnerships for Google and its Nest company, said utilities should be learning how to connect with Generation Z, so-called “digital natives” who were born in 1997 or later.
“They live and breathe technology. They’re really focused on customization and personalization,” Berndt said during his keynote address, noting Gen Z members represent $44 billion in buying power and are just now entering the job market.
By 2020, he said, Gen Z will be the largest consumer group in the U.S.
“There’s room to grow in this area. Utilities lag other industries in digital experience,” Berndt said.
He said the next great change is in artificial intelligence, “which shows up to consumers through voice and voice assistance.” Google has “made available” 1 billion voice-enabled devices — cars, phones, watches, TVs — over the last 18 months, Brendt said.
“It’s simplifying and reshaping the way consumers engage with technology,” he said.
Energy-efficiency expert Ken Wacks suggested utilities embrace a new role as distribution service operators (DSOs).
“The distribution system has been static, but that is changing because distributed energy resources are proliferating at the edge of the grid,” Wacks said. “We think a [DSO] is an opportunity for utilities to make money from DERs by using the equipment that is already in place and letting the customer generate and sell energy via the distribution grid to the utility or to other customers.”
Wacks should know, having been appointed by the Department of Energy to four terms on the GridWise Architecture Council and contributing to its work to ensure reliable and efficient distribution of electricity while accommodating DERs.
“Utilities have to figure out how to let customers use the grid, how to price the grid and how to use equipment on the grid. Some of these equipment items today can’t handle the backflow or excess energy, so that requires active management of the distribution grid and possible equipment upgrades. Intelligence in homes and buildings will help customers manage DERs and power flows to the utility or to other customers via the distribution grid,” Wacks said.
The technologies to affect this change are emerging now, said Dane Christensen, National Renewable Energy Laboratory team lead for residential systems performance, ticking off thermostats, water heaters and batteries as examples.
“In five years, we’ll see the same transformation as we did from the flip phone to the smart phone. We’re trying to understand this potential of enabling other value streams,” he said. “When you look at a smart home, price is not the goal of a new product. The No. 1 goal isn’t to save money. It’s convenience and access to data.”
New York’s Consolidated Edison is on its way to becoming a DSO “the same way an RTO operates,” said Shira Horowitz, the utility’s demand response manager. She said the move is necessary to accommodate a high number of renewable DERs.
“We’re able to balance these renewables with demand response and batteries and other dispatchable distribution resources,” Horowitz said. “Demand response and some other dispatchable resources can prevent cascading failures. … Our demand response programs are used to manage the distribution system, as opposed to others using them for peak shaving or something else. We’re able to respond to distribution-level contingencies and events with distribution resources.”
Panels Discuss Value of Green Homes, Data
Several panels discussed energy-efficient, net-zero homes and their potential for storage, and what that means to grid operations.
“Don’t underestimate the power of the consumer,” warned Austin Energy’s Debbie Kimberly, the utility’s vice president of customer energy solutions and corporate communications. She said an average of 4,400 homes are built every year in Austin, “fully 30%” being Green Building homes that increase by $35,000 in value over non-green homes.
“That was really driven by consumer preferences,” Kimberly said. “It’s like, ‘I’d love to be able to remodel my home, if I could only get all those devices to talk to each other. I want an app to control my apps.’”
“There’s a true value proposition to having a home with a true energy experience,” Inspire CEO Patrick Maloney said. “You will find a set of consumers that highly value purchasing a home that feels like owning a Tesla, because no one [understands] kilowatts. If you want to have an impact on the greenhouse gas issue, zero-net homes are really a massive tool. We have to figure out how to create integrated service offerings. … I’ve never met a person who wanted to change their behavior willingly.”
Abhay Gupta, CEO of data consultant Bidgely, said AI may provide the key to the utilities’ challenge of optimizing their costs, adding revenue and “personalizing customer engagement.”
“Change will happen. It’s inevitable,” he said. “The question is, are we going to be ready for the future? Netflix and Amazon understood what they do, but do utilities? Something has to be done about massive aggregation. If you can unravel what’s happening in the home, you can get the same amount of information that Netflix gets.”
“For meter data to be valuable, we need it to become more granular,” said Matt Johnson, vice president of business development for EnergyHub. “One of the things that excites us about meter data is the potential — when marketing programs to customers — of being able to take advantage of that and get that data to impact the load-management side of the equation.”
Democrat Cheryl LaFleur joined with FERC’s two Republicans on Thursday to approve the Calcasieu Pass LNG export terminal, signaling a compromise on how to compute greenhouse gas emissions from it and other pending LNG projects (CP15-550).
Democrat Richard Glick, who has joined LaFleur to oppose some gas pipeline projects, dissented.
In a press release, FERC hailed the approval of Venture Global LNG’s terminal, related pipelines and a 720-MW generation facility in Cameron Parish, La., as a “breakthrough … agreement that may provide a path forward” for the commission’s review of 12 other proposed LNG export facilities.
Artist’s rendering of the Calcasieu Pass LNG export terminal, which will include two trains of natural gas liquefaction | Venture Global LNG
Chairman Neil Chatterjee, who joined with Commissioner Bernard McNamee in the 3-1 vote last week, said expediting the commission’s review process has been one of his priorities.
“I really appreciate the efforts of my colleagues to work together to come to an agreement on this facility. This is significant, as I anticipate we’ll be able to use the framework developed in this order to evaluate the other LNG certificates that the commission is considering.
“Commissioner McNamee showed just how he got his reputation as being a ‘lawyer’s lawyer’ through his attention to the law and work to find common ground,” Chatterjee continued. “And Commissioner LaFleur was supportive of this project and constructive in working to reach our agreement.”
By refusing to address pipelines’ impact on GHG emissions, Glick contends, the Republicans are ignoring a 2017 D.C. Circuit Court of Appeals order that remanded FERC’s approval of an environmental impact statement (EIS) for the Southeast Market Pipelines Project. (See Glick Shines Light on FERC Dispute over GHG.)
Until someone is appointed to replace late Commissioner Kevin McIntyre, LaFleur and Glick can block gas projects with 2-2 deadlocks. That has led Chatterjee to pull gas items from the consent agenda at open meetings.
Environmental Impact
Calcasieu Pass will be able to process up to 12 million metric tons of natural gas a year. Under its 1999 Certificate Policy Statement, the commission balances the public benefits of such projects against the potential harms.
FERC said its final EIS concluded the project “will result in some adverse environmental impacts, but impacts will be reduced to less-than-significant levels with the implementation of applicants’ proposed, and commission staff’s recommended, mitigation measures.”
The EIS found that operation of the terminal and its generating facility may result in emissions of up to 3.9 million metric tons per year of CO2 equivalent, potentially increasing U.S. emissions by 0.07%. “Currently, there are no national targets to use as benchmarks for comparison,” FERC said.
Block flow diagram of the Calcasieu Pass LNG export terminal | Venture Global LNG
‘Kafkaesque Approach’
In his dissent, Glick said the commission’s analysis did not meet the requirements of the National Environmental Policy Act or Natural Gas Act and “effectively writes climate change out of the public interest determination entirely.”
“The commission is finding that its choice not to evaluate the significance of the environmental harm caused by the project’s GHG emissions supports the conclusion that the project will not cause significant environmental harm. That Kafkaesque approach is not the ‘hard look’ that NEPA requires,” he said. “The commission’s rigid refusal to monetize the harms of climate change using the social cost of carbon while simultaneously monetizing the project’s long-term socioeconomic benefits — including direct, indirect and induced benefits from employment, investments and local taxes — is arbitrary and capricious.”
In a concurring statement, LaFleur said, “I appreciate the work done in the final EIS to address a range of resources impacted within the identified geographic scope of the Calcasieu Pass project. However, I disagree with the commission’s failure to disclose and discuss cumulative potential direct GHG emissions associated with Calcasieu Pass project, as well as the other projects identified in the final EIS within the 50-km air region.”
LaFleur said she also disagreed with the exclusion of the emissions from the cumulative impacts analysis.
“I believe it would take minimal effort to disclose the direct GHG emissions for the other projects identified in … the final EIS, and include an estimate of the total annual potential GHG emissions associated with the Calcasieu Pass project and those other projects as part of our environmental review.”
LaFleur’s statement included a table estimating that Calcasieu Pass and 10 other LNG or gas projects within 50 km would increase national GHG emissions by almost 0.8%.
“It is clear that the liquefaction of natural gas for export has meaningful GHG consequences,” she said. “I believe, at a minimum, direct GHG emissions must be disclosed and considered, both cumulatively and with respect to individual facilities.”
New Mexico’s Public Regulation Commission vacated an order earlier this month that had paved the way for Public Service Company of New Mexico (PNM) to join CAISO’s Western Energy Imbalance Market by the spring of 2021.
The move surprised many. The effort for PNM to join the EIM was largely uncontroversial and received unanimous support from the PRC’s five elected commissioners on Dec. 20. But the commission decided to revisit its decision after Albuquerque’s water agency protested the December ruling and after two new commissioners were sworn in this year.
PNM doesn’t need the commission’s approval to join the EIM because it does not involve the transfer of any of the company’s assets and market participation is strictly voluntary.
Proponents say New Mexico’s ample wind and solar power would be a valuable addition to the Western Energy Imbalance Market. | U.S. Department of Energy
The case (18-00261-UT) instead dealt with PNM’s request for an order governing the accounting treatment of costs related to joining the EIM. The commission’s December order authorized PNM to recover its expenses in a future rate case.
Now, however, PNM and some environmental groups worry the PRC’s latest move could delay PNM’s membership in the EIM for another year and cost ratepayers $10 million in projected annual benefits.
“Until a new order is issued, PNM will not undertake efforts to join the Energy Imbalance Market,” Western Resource Advocates argued in an emergency motion to the PRC. “Likewise, because it takes two years of preparation to join the EIM, there is a queue to join and a deadline of April 1 in each year, unless the commission issues an order quickly. … New Mexico will lose one year of substantial economic and environmental benefits.”
The Coalition for Clean Affordable Energy joined WRA in its motion, and the Natural Resources Defense Council said in a news release that the commission’s action was a “step backwards” in state efforts to use more renewable energy.
PNM said in it was disappointed by the commission’s move.
“PNM’s decision to join the EIM was dependent on the commission’s December 2018 approval,” Thomas Fallgren, vice president of generation, said in a statement emailed to RTO Insider. “PNM has suspended all work on the Energy Imbalance Market due to today’s actions. Any further delays or changes of the December order may jeopardize our ability to reap the customer benefits.”
In a brief order Feb. 6 vacating its December ruling, the PRC did not explain the reasons for its action. It merely said it had the legal authority to rehear the case at the request of the Albuquerque Bernalillo County Water Utility Authority.
The water utility had argued that the cost-recovery decision was made too hastily by a commission that included members near the end of their terms.
“The procedural record in this case establishes that the commission only had hours to review the hearing transcript, evidence introduced into the record during the hearing, briefs filed by the [water authority], PNM and staff, and the proposed order on accounting treatment,” the water utility’s lawyers wrote in their brief.
“Given the time for this review and the voluminous record to review, a thorough review by commissioners of this material was impossible as a practical matter,” it said. “Such a rush to judgment by departing commissioners is problematic and should not bind the present commission to an ill-advised course of action.”
The water utility contended PNM should be required to file quarterly reports on its EIM benefits and shouldn’t be guaranteed a return on investment, with ratepayers bearing the risk.
“It is axiomatic that the commission is the surrogate for the marketplace, and if PNM were operating in the marketplace, rather than as a regulated monopoly, it would not be guaranteed recovery of its investments,” the water utility’s lawyers wrote in a Jan. 17 application to reopen the case.
Further action by the PRC is pending. It remained unclear if the commission will hold another hearing or, as Western Resource Advocates urged, decide the case on the record before it to expedite a decision.
CAISO, which did not comment on the PRC’s action, says the EIM has generated $565 million in benefits for its members since its founding in November 2014.
The EIM’s membership consists of CAISO, PacifiCorp, Arizona Public Service, Idaho Power, NV Energy, Portland General Electric, Puget Sound Energy and Powerex. The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District and four other entities, including PNM, are scheduled to join between 2019 and 2021.
FERC on Thursday again denied Vermont Transco permission to embed transmission acquisition costs in its rate recovery through the ISO-NE Tariff.
In rejecting a rehearing request on the issue, the commission affirmed its decision last year rejecting the company’s attempt to recover $639,780 from Vermont ratepayers to cover property transfer taxes, closing fees and advisory fees related to its acquisition of shares in the Highgate Transmission Facility near Quebec (ER18-1259-001).
Vermont Transco first filed the request for recovery in March 2018, and FERC rejected it in May.
| Vermont Transco
In a 2017 filing seeking FERC approval to acquire Green Mountain Power’s stake in Highgate — which was eventually granted — Vermont Transco acknowledged that “there is no mechanism in [ISO-NE’s] cost-based transmission formula rate that allows the automatic pass-through” of transaction-related costs. The company promised to make a separate filing if it intended to seek any transaction-related costs that would also demonstrate “specific, measurable and substantial benefits to ratepayers.”
But the company’s 2018 cost-recovery request contended that the requirement to show ratepayer benefits didn’t apply because the company was not seeking to recover an acquisition premium. The company also contended it could recover the expenses from customers because service over Highgate is provided under ISO-NE’s Regional Network Service rate, which relies on cost causation and beneficiary pays principles. It also noted that it never made a hold-harmless commitment on such recovery.
In denying the request, FERC pointed to Vermont Transco’s previous commitment — set out in the transfer application — to demonstrate ratepayer benefits. The commission also said the company couldn’t simply bypass ISO-NE’s restriction on an automatic pass-through of the transaction-related costs and reminded it of its earlier promise that the transaction would not have an adverse effect on rates.
The commission added that Vermont Transco was free to file again for cost recovery provided it detailed how the recovery would benefit ratepayers.
FERC said last week that PJM’s proposal for reimbursing generators for fuel-switching costs and for penalties incurred when gas pipelines fail lacked specificity and clarity.
In a ruling issued Feb. 19, FERC rejected the stakeholder-approved mechanism submitted for inclusion in PJM’s Operating Agreement and Tariff that would have implemented a process for market sellers seeking cost recovery for certain gas contingencies associated with fuel-switching instructions from the RTO (ER19-664.)
FERC rejected PJM’s proposal for compensating generators for costs associated with fuel-switching orders. | Entergy
PJM’s filing would have become effective Dec. 21 and allowed generators to request cost recovery from FERC across nine different categories: park-and-loan service charges; overrun charges; exceeding maximum daily quantity; exceeding minimum/maximum storage balance; imbalance cash-out charges; disposal of gas and related products costs; other gas balancing costs; start-up costs; and alternate fuel costs.
FERC described PJM’s definition of “penalty” — costs that are designated as such in the pipeline or local distribution gas company tariff and imposed by the applicable pipeline or company — as “unreasonably narrow and unsupported.” The commission said pipeline tariffs delineate between penalties and the RTO’s proposed categories in different ways, meaning what appears to be relevant fuel-switching costs for one pipeline could be considered a penalty for another. The commission also faulted PJM for not including events that might trigger fuel-switching directives in its Tariff and for lacking established procedures for dealing with such contingencies through existing market design.
“Continuous communication and coordination between the RTO, the gas pipeline operator and the relevant generation owners can be critical to ensure the reliable operation of both systems,” FERC concluded in its ruling. “Given this lack of clarity, PJM’s proposal does not reasonably ensure that coordination occurs prior to a generator’s switching to an alternate pipeline.”
The D.C. Office of the People’s Counsel crafted the rules and compensation plan detailed in the filing after earning a majority of stakeholder support at the December meeting of the Markets and Reliability Committee. (See “Gas Pipeline Contingencies,” PJM MRC/MC Briefs: Dec. 6, 2018.)
The supermajority vote signaled a major victory for load interests who were opposed to the Calpine-authored plan endorsed at the Market Implementation Committee in November. That proposal would have developed a formula for cost recovery to be filed with FERC that did not include pipeline penalties. (See “Gas Pipeline Contingencies,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)
Jeff Shields, a PJM spokesperson, said Friday that staff are still considering next steps.
“We continue to believe that this is an important issue to resolve and is another step in improving gas-electric coordination,” he said. “We are evaluating the order and our options for working with stakeholders to rectify the issues FERC found with our filing.”
