AUSTIN, Texas — ERCOT’s Board of Directors on Tuesday approved the Far West Texas transmission project, which will result in the construction of two 345-kV lines southwest of Odessa, Texas.
The project would have received unanimous approval but for the abstention of American Electric Power, which will build the project, along with Oncor and Lower Colorado River Authority Transmission. The ISO’s Technical Advisory Committee unanimously approved the project in May. (See “Far West Texas Project Gets TAC’s OK,” ERCOT Technical Advisory Committee Briefs.)
| ERCOT
The $336 million project is designed to address the region’s continued load growth, which has averaged 8% since 2010. Increased oil and natural gas exploration in the Permian Basin and a jump in generation projects — mostly solar — are behind the numbers. ERCOT said peak electricity demand in the area has jumped from 22 MW in 2010 to more than 200 MW in 2016 and is projected to exceed 500 MW by 2021.
“We continue to see a tremendous amount of load growth in West Texas,” said Jeff Billo, ERCOT’s senior manager of transmission planning.
One 85-mile line would run between the Riverton and Moss switching stations, with a second circuit added to the existing 16-mile 345-kV line between Moss and the Odessa line. A second 68-mile 345-kV line will connect the Solstice and Bakersfield substations.
The project is expected to be completed within five years, pending approval from the Public Utility Commission of Texas.
Oncor and AEP initially proposed the project to ERCOT’s Regional Planning Group in April 2016. Staff reviewed 40 different alternatives and lowered the cost to $336 million after settling on the most cost-effective of four options: two separate double-circuit 345-kV lines — each with one circuit in place, substation expansions and other transmission elements. ERCOT concluded the upgrades “meet the reliability criteria in the most cost-effective manner and have multiple expansion paths to accommodate future load growth.”
In a departure from previous years, the 2017 Organization of MISO States-MISO resource adequacy survey suggests the RTO will have sufficient capacity to meet near-term planning requirements.
The annual results show the RTO will have 2.7 to 4.8 GW of excess resources from 2018 to 2022, translating into a 16 to 22% reserve margin — “sufficiently” above the 15.8% planning reserve margin requirement, according to MISO.
“The MISO region will have ample electricity-generating resources to meet expected demand while also maintaining an adequate supply of reserves for the next five years,” the RTO said in a statement. “The results show an improved resource adequacy outlook compared to last year.”
MISO Executive Director of Strategy Shawn McFarlane said this year’s range represents a 2 GW increase over the range predicted by last year’s survey.
“For the first time in the survey, we show adequate capacity resources,” he said during a special June 16 conference call to discuss results.
More than 96% of MISO’s load responded to the survey, according to the RTO. “We’re glad to see another high participation rate,” said OMS president and Indiana Utility Regulatory Commissioner Angela Weber.
The rosier results can be attributed to lower demand forecasts and a lukewarm growth rate of 0.5%, down from 0.8% in 2016, the RTO said. Its forecasted 2018 summer peak of 125.1 GW is down 2.5 GW from predictions made earlier in the year, it said. (See MISO Slims Summer Reserve Prediction.)
Changes to the way the RTO counts megawatts available as capacity might have also boosted the results. Weighted averages in this year’s survey included a 35% share of projects in the definitive planning phase of the interconnection queue, a change made to address stakeholder concerns that the survey was producing overly conservative capacity forecasts. (See OMS-MISO Survey Moves Ahead with New Calculation.)
Weber said the process of the survey and results continue to improve.
“Capturing resource adequacy for a moment in time remains an important tool,” she added.
Last year’s survey forecasted that the RTO would exceed its then-projected 15.2% reserve requirement by 0.9 GW — or 0.7% above the 2017 requirement — and that it could face a capacity shortfall by 2018 under a worst-case scenario. (See OMS-MISO Survey: Generation Shortfall Possible.) The 2015 survey concluded that a shortfall could occur by 2020.
| 2017 OMS MISO Survey Results
This year’s results show that two zones still face capacity shortfalls in 2018, but MISO said that “load-serving entities in these areas should be able to reliably acquire capacity from outside their zones to meet these needs.” Zone 5 in Missouri is expected to have a 0.3-GW shortfall, while Zone 7 in Lower Michigan could come up short by 0.7 to 1 GW. Shortfalls in both areas are predicted to persist into 2022. All other local resource zones are expected to have surpluses ranging anywhere from 0.4 to 1.6 GW in 2018 and 0.2 to 1.5 GW by 2022, except Indiana and Kentucky’s Zone 6, which has the potential for either a 0.7 surplus or a 0.4 shortfall by 2022.
Zone 4 in Southern Illinois showed the greatest improvement: Its 1.6-GW forecasted deficit became a 0.7-GW surplus in this year’s survey after MISO reduced load, added 0.4 GW of new resources and factored in the increased availability of existing resources in the zone.
“Several units at 1.8 GW that were previously expected to retire were determined to serve MISO load at the committed level,” McFarlane said of Zone 4.
Minnesota, Wisconsin and the Dakotas’ Zone 1 was limited to 600 MW in exports in 2018 due to a capacity export limit. Exports from MISO South’s Zones 8, 9 and 10 were limited to 1.2 GW because of the continued MISO South-to-Midwest constraint from the use of SPP’s transmission.
Some stakeholders asked how MISO predicted capacity import and export limits, given that the RTO does not calculate limits more than a year in advance. Laura Rauch, MISO manager of resource adequacy coordination, responded that MISO does estimate out-year import and export limits, but added that export limits only have a “minimal” impact on survey results.
MISO predicts when new transmission will relieve constraints, and the Zone 1 transmission constraint that limits exports to 600 MW is expected to disappear by 2022, Rauch said.
Xcel Energy’s Randy Oye asked MISO to provide more detail about how it determines future export limits and transmission constraints, a subject McFarlane said would be discussed at a July 12 Resource Adequacy Subcommittee meeting addressing the zonal breakdown of survey results.
An unforeseen demand increase could affect survey results “unless balanced by policy or market forces.” He warned that results are “highly sensitive” to the same load forecasts largely responsible for the excesses shown in the survey.
“We appreciate continued collaboration with the Organization of MISO States to provide this outlook on supply and demand in the MISO region,” CEO John Bear said. “This forward-looking view informs and enables collective actions by states and MISO members to ensure continued resource adequacy.”
PJM’s Independent Market Monitor said last week that it has rejected fuel-cost policies for 11% of generating units for the review period ending May 15.
The Monitor said 22 of the 479 power supplier fuel-cost policies it evaluated — less than 5% of the policies, but representing 11% of units — failed to meet its standards for being algorithmic, verifiable and systematic.
Sellers must go through the process again starting June 15, when PJM’s annual review period begins. The annual review runs through Nov. 1.
The policies are important because sellers will be penalized if they choose to offer into PJM’s markets without them.
“Before you put an offer into Market Gateway, you need to have an approved fuel-cost policy,” PJM’s Jeff Schmitt said.
‘Ask Bob’
The initial review was the culmination of a long and often contentious coordination between the RTO and Monitor to get every market seller who must source fuel to submit a policy explaining how it developed the fuel costs included in its cost-based offers. PJM approved all offers submitted.
“We don’t actually agree with PJM that all of the policies that PJM agreed to were consistent with the Tariff,” Bowring said. There were several of the issues that caused his team to fail policies, including submission of unsupported cost adders and reliance on internal estimates.
“That’s what we refer to as ‘Ask Bob.’ So you go down the hall and ask your trader,” Bowring said, noting that the “probably 80%” of gas-fired units that used that method two years ago was “reduced dramatically.”
Some of the explanations shocked stakeholders.
“Someone for real submitted a gas hub that was not in any way, shape or form physically related to the unit that they were submitting it for and didn’t give an explanation as to why?” EnerNOC’s Katie Guerry asked. “You’re saying that someone submitted it without any sort of attempt at explaining it to you, knowing who you are?”
“Precisely,” Bowring responded. “Believe me, we understand all the nuance and subtleties about how it could be.”
The ongoing fuel-cost policy requirements have created fatigue among some stakeholders. During last week’s Market Implementation Committee meeting, Gabel Associates’ Mike Borgatti reconstructed the timeline.
“By May 15, we had to get our fuel-cost policies approved to resubmit them by June 15 to maybe get them approved again by Nov. 1, right?” he asked.
Sellers are required by June 15 to submit updated policies to PJM or confirm that their current policies remain compliant. The Monitor will make its determination on policy reviews by Aug. 1, which is also the deadline for sellers to provide policies and sample emissions, variable operations and maintenance calculations to PJM. The Monitor plans to have a fuel-cost policy template incorporating hourly offers available this week, and PJM expects to have its templates ready June 30.
PJM will make its determination on polices by Nov. 1. Schmitt said that review will capture any changes to ensure the policies allow for intraday offers.
“It’s not that we’re trying to recreate work. We just want to make sure that we’re good to go going forward for the winter,” he explained.
With the implementation of FERC Order 825, sellers will be able to update offers hourly to adjust for changing market and supply conditions.
“We know this process is not easy,” said Joel Romero Luna, who is part of Bowring’s team at Monitoring Analytics. “I’ll be surprised if anyone submits by June 15 a policy that captures hourly offers, so it’s my expectation that we’ll work through it, and hopefully we’ll get something acceptable by Nov. 1.”
Online Systems
Going forward, PJM and the Monitor will be using online systems for the process. The Monitor will require all market participants to use a new section on its Member Information Reporting Application (MIRA) for reporting cost-based offer data as of June 30.
The new “Cost Offer Assumptions” module was brought online June 12 with the expectation of having all market sellers transitioned by the end of June. The Monitor uses the inputs to verify sellers’ cost-based offers. Participants will need to verify that the data is correct because “incorrect or incomplete data in MIRA may trigger an evaluation of cost-based offers for potential penalties under Schedule 2 of the Operating Agreement,” the Monitor said.
PJM will also be using “a tool” to track policies, which Schmitt said could be MIRA — although that isn’t assured.
Bowring said one of his frustrations is securing PJM’s commitment on the topic.
“My read of what PJM has been telling us is that they don’t intend to rely on MIRA, but I’m not quite sure why. It’s going to cost them at least millions of dollars in order to replace it on their side,” he said. “Until PJM tells us they’re going to rely on it, we’re not making changes to make it work more smoothly for PJM.”
CAISO finalized a set of updates to its proposed policies on demand response and distributed generation, saying there is strong stakeholder support for the new rules to be presented to the Board of Governors in July.
An incremental approach would be best as CAISO learns from the changes stemming from the policies and their influence on generation resources and grid operations, the ISO said in a draft final proposal on “Energy Storage and Distributed Energy Resources (ESDER) Phase 2.”
“The ISO will continue collaborating with stakeholders on the remaining ESDER 2 topics in a phased policy approach that is appropriate in a rapidly evolving market environment that currently does not have a clear end state,” CAISO said.
The board next month will review finalized proposals for alternative baselines, distinguishing between charging power and station power for energy storage resources, and changes to the threshold price for DR, among others.
For DR, a baseline analysis working group developed enhancements to the method whereby proxy DR resources are evaluated. The ISO has finalized the alternative baselines, which are designed to improve the accuracy of DR performance calculations. CAISO said there has been “overwhelming” support for the alternative baseline proposal.
| CAISO
The ISO currently relies on a “10-in-10” baseline methodology that works well for many large commercial and industrial customers but not for all customer types, leading to the development of a new approach.
Using the 10-in-10 methodology, the ISO calculates a baseline by examining the 45 days prior to a trade date and finding 10 “like” days in which no DR was required. It then uses hourly average meter data to create a baseline representing a typical load profile, and the resource is paid for reducing usage below the baseline.
Under the new proposal, baselines for residential resources would be based on a four-day weather match that estimates what electricity use would have been in the absence of DR dispatch under similar weather and on similar days, using a control group of similar users.
Commercial baselines would be based on the 10-in-10 method with a 20% adjustment cap, an average of the previous five days and a control group. Baselines are adjusted using actual load data in the hours preceding a DR event to better reflect variables that might not appear in the historical data.
The stakeholder process showed that station power is a retail issue, CAISO said, and listing specific functions for wholesale and retail functions is not the best approach.
“The CAISO believes that it is prudent to simplify the definition of station power to energy for operating the electrical equipment of an energy resource subject to a retail tariff, as defined by the local regulatory authority,” CAISO said. This definition would be consistent across regulatory authorities and avoid conflicts if the California Public Utilities Commission changed its definition of station power.
The ISO is also proposing to expand the list of gas price indices available for use in the calculation of DR benefits. This allows the DR “net benefits test” to recognize Energy Imbalance Market (EIM) entities outside of the state that want to participate as DR in the CAISO market.
The policy issues discovered in the process will affect the EIM if DR or distributed energy resources are used. The EIM Governing Body will review the proposal on July 13 in its advisory role.
CARROLL, N.H. — New England regulators and market participants expressed optimism last week that they will find a way for wholesale markets to coexist with state energy policies, warning of dire consequences if they fail.
In a discussion Monday at the 70th Annual Symposium of the New England Conference of Public Utilities Commissioners (NECPUC), panelists discussed the proposals that have arisen from the New England Power Pool’s Integrating Markets and Public Policy Process (IMAPP).
Angela O’Connor, chair of the Massachusetts Department of Public Utilities, said IMAPP has been successful, although it has not yet resulted in a solution. At the FERC technical conference in May, she said, “New England appeared well ahead of other parts of the country in looking at solutions and trying to understand each other’s priorities.”
New England states are set to procure more than 3,600 MW of nameplate renewable generation, including Massachusetts’ requirement that its electric distribution companies solicit long-term contracts for approximately 1,200 MW of clean energy generation and 1,600 MW of offshore wind.
“The bottom line is, if New England does not find a way to harmonize markets and the requirements of state laws, it creates the risk that consumers will have to pay twice for resources — once through the regional markets, and again as the result of the requirements of the state laws,” O’Connor said. “For those who go to work every day thinking about consumers, that outcome is absolutely unacceptable and would most likely lead to the end of the competitive markets as we know them today.”
Tom Kaslow, chair of NEPOOL’s Participants Committee, said “collaboration is the cornerstone” of the power pool, adding that he hoped New England would develop a solution rather than leaving it “to be solved by the courts.”
“We are all in this together,” he said during lunch remarks Tuesday. “We either make this market work together or we don’t succeed.”
Although it is the Participants Committee that will ultimately determine whether to support proposals brought before it, Kaslow stressed his personal commitment to the regional efforts. “I will not accept failure, at least during my tenure as chair.”
ISO-NE CEO Gordon van Welie said the RTO is working overtime on the issue in order to reach agreement on a proposal that could be submitted to FERC in time for the February 2019 capacity auction.
“We definitely put ourselves in the ‘urgent’ camp,” he said. “These contracts that the states are intending to sign are probably going to happen during the next 12 months or so. In 2018, we expect resources that are winning these [requests for proposals] are going to want to enter the capacity market in the following cycle. And the qualification process for that 2019 auction will commence in 2018. And so we ideally would like to have a rule set that can deal with that prior to the start of qualification in 2018.”
Because of the RTO’s minimum offer price rule (MOPR), resources receiving a power purchase agreement may have their prices reset to a higher level in the capacity auction, with the result that they likely would not clear. “And so that has an unfortunate consequence if the states are going to go ahead and contract for these resources anyway, which is you ultimately end up overbuilding the system,” van Welie said.
But allowing subsidized resources to participate in the auction without mitigation would drive capacity prices down, he said.
“I often get a lot of eye-rolling back at the ISO when I go back to the market design people and say we need a design that will make six states happy [along with] 460 market participants and it needs to be approved by the FERC,” van Welie said. “If we did nothing and we just rely on the status quo to exist, I think we’d end up creating investor uncertainty in the market because of the litigation that will result,” he continued. “It’s a very fragile premise, an investment incentive, and it can unwind extremely quickly. So we believe it is important for us to have a solution in place that will give the marketplace confidence that we can deal with this.”
The Competitive Auctions with Subsidized Policy Resources (CASPR) proposal, developed by the RTO and Market Monitor David Patton, would provide financial incentives for existing, high-cost capacity resources to transfer their capacity obligations to subsidized new resources and permanently exit the capacity market. It would involve a two-stage, two-settlement process with a substitution auction occurring immediately after the primary auction.
The plan would “accommodate the subsidized resources into the capacity market over time and also preserve competitive capacity pricing for unsubsidized resources,” van Welie said. “The key idea here is to coordinate the entry of subsidized capacity resources with the exit of unsubsidized resources … over time.”
A second proposal, a “Dynamic Clean Energy Market” backed by the Conservation Law Foundation, NextEra Energy Resources and Brookfield Renewable, would use forward capacity auctions to procure clean energy attributes unbundled from energy. Charles River Associates consultant Robert Stoddard briefed NECPUC on the proposal, which he helped design.
ISO-NE says CASPR falls into the “accommodation” category as a project that can be implemented relatively quickly. The Clean Energy Market is an “achieve” proposal that attempts to incorporate state policy into wholesale markets; it will take more time to evaluate to determine how it would work with the Forward Capacity Market and the MOPR, the RTO says.
‘Intriguing’ Proposals
“Both proposals are intriguing,” O’Connor said. “You’ll not be surprised that I have more questions than answers at this point.”
O’Connor said she was concerned that the RTO’s proposal would eliminate the annual 200-MW MOPR exemption for renewable resources. She noted the exemption has been supported by the six New England states and the RTO and approved by FERC despite opposition by some conventional generators. “I do question the notion of eliminating the one mechanism that gives me the certainty I need,” she said. “That said … CASPR has some tremendous advantages. We all know there are tradeoffs in these sorts of discussions.”
She suggested combining CASPR and the exemption might “increase the likelihood that CASPR will actually meet its objectives and really give the states the certainty … that we’re going to need.”
O’Connor also said she liked that the Clean Energy Market proposal “seeks to be mindful of the fact that states are responsible for executing their state laws.”
“The CLF, NextEra and Brookfield proposal, like many of the longer-term ‘achieve-style’ proposals are complex and raise questions for states about authority and other matters. They also require a significant investment of time and money to develop and implement.”
She said the New England States Committee on Electricity (NESCOE) is conducting analyses of the proposals, which will be released this fall.
IMAPP Chair William Fowler, president of Sigma Consultants, told NECPUC that 100 to 150 people attended each of the nine IMAPP meetings thus far. He said the next meeting of the group will be in September.
Stoddard and Mark Vannoy, chair of the Maine Public Utilities Commission, said integrated resource planning has moved from public utility commissions to legislatures.
“When legislators say now we want some biomass, or now we want some Massachusetts solar, they’re really getting back into integrated resource planning, so there’s tension about economic efficiency and other priorities,” Stoddard said.
Maine’s Concerns
“That’s the reality of the political economy in which we live,” agreed Vannoy. “There’s this insatiable appetite and I don’t expect that to change at the legislatures. The technology will change, but the desire to direct outcomes is not going to change. When we come to a multistate RTO, that’s where it becomes difficult because we have multiple states looking at a whole new set of complexities.”
The use of tailored mitigation strategies has been only partially successful in preventing the socialization of other states’ public policy decisions, Vannoy said. “It’s not an effective long-term approach … because it doesn’t provide regulatory certainty for market participants.”
Vannoy also expressed concern about the CLF proposal, saying incorporating incentives for clean energy into the RTO Tariff “might be a jurisdictional bridge too far.”
Environmental legislation in New England is often the result of compromises between policy goals of reducing greenhouse gasses and economic goals of creating and retaining jobs, he noted.
For example, Maine legislators last year approved spending $13.4 million in taxpayer funds to supplement the price that in-state biomass generators get from selling their power in the wholesale market, a subsidy projected to save almost 300 jobs. The legislation was coupled with the idea of “keeping people cutting wood, and is being judged on the basis of an economic result, while Vermont Tier II [distributed renewable generation] talks about connecting generation facilities of 5 MW or less to sub-transmission or distribution systems.”
Noting that Maine is the only New England state whose manufacturing load is greater than its residential demand, Vannoy said a carbon adder would make the state less competitive than other regions. Owners of large manufacturing operations such as Bath Iron Works and Texas Instruments have complained about the state’s high rates. Any rate increase would raise the risk of manufacturers of moving their operations to a Southern or Western state with cheaper power and higher carbon intensity, he said. “You’re not going to solve the carbon issue by shifting [manufacturing] to other parts of the country.”
Fuel Security
Van Welie also addressed concerns over fuel security, acknowledging that the CASPR proposal could accelerate the retirement of 6,000 MW of older, at-risk steam generators. The RTO needs about 22,000 MW to meet its winter peak, but its dependence on gas-fired generation is limited by pipeline constraints.
“When you look at what’s actually running those winter days, it’s a lot of oil, and historically we’ve had a lot of coal we used to use for winter reliability,” he said. “And so that begs the question: Where’s the energy going to come from in the future to maintain reliability in the winter?”
Van Welie said the RTO is seeking to quantify the risk through analyses that model what the system will look like in 2025 under sensitivities that consider higher and lower levels of retirements, LNG imports and renewables. (See Study: New Resources Could ‘Crowd Out’ Old in ISO-NE.)
Van Welie noted that the RTO’s out-of-market winter reliability program will end in winter 2017/18, with the region relying on its Pay-for-Performance initiative in the future.
“The question is, will the Pay-for-Performance mechanism, together with the stop-loss provisions inherent in that mechanism, be sufficient to drive the level of forward fuel arrangements that we require to get through winter with the pipeline constraints?”
CARROLL, N.H. — Energy storage technology is still moving faster than state regulators and the markets can accommodate, speakers told the 70th Annual Symposium of the New England Conference of Public Utilities Commissioners (NECPUC) on Tuesday.
“Markets are moving at the pace of entrepreneurs, while states are moving at the pace of bureaucracy,” said Richard Fioravanti of energy consultancy Exponent.
The technology is changing so fast that CAISO recently had trouble qualifying a new lithium-ion battery storage project for California’s ancillary services market.
“You may think of some complicated reason why, but it was actually very simple,” said Jason Allen, vice president of operations and power for AltaGas Services U.S. The company’s 20-MW, 80-MWh facility in Pomona, Calif., holds 12,240 lithium-ion batteries. “We were ramping so fast they couldn’t” get an accurate data reading.
CAISO needs three data points to qualify a project during an ancillary services test: a starting point, one point on the ramp portion of the curve and an end-point.
“I can go from 20-MW charge and 20-MW discharge every 100 milliseconds, or 10 times a second,” said Allen. “It took [almost] two months working with them to get that simple issue worked out. And instead of the 10,000-MW/minute ramp rate, we actually detuned the system to 100 MW/minute and qualified for 36 MW [per minute], which is physically where we’re sitting right now in the market.”
Allen emphasized that his dealings with CAISO were not adversarial. “They have worked very closely with us to resolve the issues,” he said.
“If you can ramp to your full load in much quicker than five minutes, it’s interesting but not necessarily valued,” said the director of market design and policy at FirstLight Power Resources, Tom Kaslow, who also serves as chair of the New England Power Pool’s Participants Committee. “As a practical matter, participation in the energy market, it really matters what you can do in five minutes — and if you can do it consistently, when the system operator needs it.”
There is a disconnect between the performance capability of new technologies and the market need for that level of performance, Kaslow said. “As a practical matter, while some of these new technologies bring a really interesting résumé to the table, their capabilities may actually exceed their ability to be valued, at least in the wholesale ISO market.”
Kaslow said battery storage can also present a challenge to RTOs’ operation of regulation markets. “I was on a panel last week where [PJM officials] were indicating that they [were] having problems, because achieving the neutral state of charge while on regulation is actually yielding periods where the charging is working in the opposite direction of their actual regulation needs in that particular interval. So there are things that need to be dealt with in respect to that much smaller market.”
He explained afterward that PJM had implemented a solution in January: PJM is placing a limit on the charging function when the regulating capability is needed to manage the area control error in a direction opposite to charging. Kaslow said it is unclear whether New England will face a similar problem.
Moderator Ned Bartlett, Massachusetts undersecretary of energy and environmental affairs, said storage is a small portion of the Massachusetts electric supply compared to other commodity supply chains. Storage of “food, water, gasoline, even oil [and] natural gas distillates [is] often close to 10%” of the daily consumption of each of these commodities, he said. “In Massachusetts right now … approximately 1% of our electricity used on a daily basis [is] in a storage capacity.”
Jesse Jenkins, a Ph.D. candidate at the Massachusetts Institute of Technology, said his research indicates energy storage costs must fall 60 to 85% to be competitive with gas peaking plants and that the value of storage drops with its volume.
“The first gigawatt of storage that you might stick in the New England system has a very high value. It displaces our most costly resources that are used most infrequently,” Jenkins said. “And as we deploy more and more storage, the challenge of displacing additional capacity increases and the marginal value steadily falls.”
But assessing the total value of storage means looking at the long-term value of the assets, according to Allen, who explained the economics of the Pomona storage facility.
“Yes, the up-front cost is more, but you look at the operating costs,” Allen said. “Right now it’s about $5/kWh on an ongoing [operations and maintenance] basis. There’s no fuel, very little maintenance. Our technicians who used to [work] 24/7, for now they’re on day shift to do minor maintenance. … You also need to consider what it’s doing to your other assets. I’ve got a couple [cogeneration] units that I use right now that are dispatched for about 300 starts a year. We are just destroying those units; maintenance has gone through the roof. Getting the storage in place can really help dampen those curves and control our costs.”
Christopher Parent, ISO-NE director of market development, said the RTO is seeing increasing interest by storage developers. “The market is maybe starting to support [storage], and people are starting to look out at what the future is and the revenue opportunities and that in certain cases, now it is economic,” he said.
The message for policymakers? “For most storage stakeholders, what they really want to see is just the markets opening up, access opening up,” Fioravanti said. “Don’t try to predict where the business cases are going, where the technologies are going. Let the markets drive that.”
Why is storage complicated? he asked. Why all the questions when there is increasing deployment, with about 2.6 GW predicted to come online by 2022?
“The reason is because … it can go everywhere and do many things,” Fioravanti said. “This becomes problematic when people look to make policy off it because … we have it on the transmission side, it works on the distribution side, we’re putting it on the customer side. All of these create issues.”
Electric Utilities and More
The Pomona storage site, formerly a paper mill, illustrates the fast changes taking place in the storage business, according to Allen. Gas-fired boilers served the paper mill, he said. “In the early ‘80s they put in a cogen unit; they innovated lower cost electric. Paper mill went away, that got torn down; the cogen unit went into the deregulated California market. We now built this battery storage facility inside the warehouse that was there. The cogen unit is still there, still in the market [but] hasn’t run for a year.”
The storage facility won a contract in the request for proposals issued in mid-2016 to counter the potential loss of the Aliso Canyon storage facility.
“The big concern there was the potential loss of gas, loss of [natural gas supply for] peaking units,” Allen said. “The mandate of that arm of the [power purchase agreement] was that we could provide four hours of [reliability assurance] service with the battery, hence the 80-MWh structure. We were awarded this in June, actually started construction in early August and it went online on Dec. 31, 2016. [Southern California Edison] said it was the fastest generating asset they’ve ever had go from groundbreaking to in-service.”
Fioravanti reminded the audience of the ubiquity of batteries, saying the industry now manufactures about 5 billion a year of the type that most people have in their laptops.
“That’s going to go up, probably double, when the [Tesla] Gigafactory fully comes online,” Fioravanti said. “Of all the batteries out there — how [storage] has penetrated into our vehicle, transportation world, our aircraft world, our shipping world and all of our everyday devices — to think that we’re going to draw the line at the utility world and say it’s going to stop here, I think can be almost a little silly.”
PJM’s David Schweizer said the process is the second iteration of a five-year cycle that began in 2013. (See “New Black Start Units Will Have New Annual Revenue Requirements,” PJM Markets and Reliability Committee Briefs.)
“The purpose of the RTO-wide black start RFP is to look at the system every five years and essentially reoptimize the effectiveness of the cranking paths,” Schweizer said. “What really does drive the amount of black start megawatts and units needed is the critical load amount and the need to serve critical load across cranking paths.”
Existing black start units are expected to remain in service and are not required to respond to the RFP, Schweizer said. However, an approved black start unit could be issued a one-year termination notice if system changes mean that it is no longer serving critical load. The critical-load analysis is being done this year, he said, so “we should have a good idea by the time that RFP is issued what the critical load will be.”
“Even if we don’t have a shortage, the RFP gives us an opportunity to reoptimize the process,” he said.
Ken Seiler, PJM’s executive director of system operations, has assumed the chairmanship of the Operating Committee as of June. He succeeds Mike Bryson, who remains vice president of operations.
Seiler brings 17 years of PJM experience to the position. Prior to PJM, he worked at General Public Utilities for 14 years as a field engineer building substations and transmission lines before moving into other positions, such as managing transmission engineering, construction management and distribution system operations.
Seiler expects the committee to focus on “the evolving resource mix and its subsequent impact on how we operate the system today and in the future, along with the resilience of the power grid.”
Stakeholders Challenge PJM Decisions on Reserve-Shortage Identification
PJM’s Joe Ciabattoni said PJM’s new shortage pricing algorithm hasn’t identified any shortages, despite complaints from stakeholders that data available online appear to show shortages. (See “Shortage Rule Takes Effect amid FERC Silence,” PJM Market Implementation Committee Briefs.)
Citigroup Energy’s Barry Trayers asked what it takes to create a shortage case.
“You’d look at all your resources, all your ramp rates, and if you’re short of your reserve requires, you’d trigger shortage,” Ciabattoni said.
Tom Hyzinski of GT Power Group asked if there have been shortage cases that system operators haven’t approved, or if there just have not been any shortages yet.
Dispatchers have to “sanity-check” cases and approve them, Ciabattoni said, but situations haven’t warranted a shortage case.
“The cases are the cases,” he said. Dispatchers “won’t go in and play with the numbers in cases.”
However, Calpine’s David “Scarp” Scarpignato argued that PJM’s publicly available data show that several situations have shortage pricing under its new rules related to FERC Order 825. PJM staff argued that they don’t have to implement shortage pricing if the units already dispatched are ramping up to meet the increased reserve requirement, but Scarp said the wording of the order clearly states that the RTO must implement shortage pricing as the units ramp up.
Staff said part of the issue is that units aren’t following their dispatch signals, but Scarp said that’s no justification for not declaring a shortage.
Order 825 “says quite the opposite,” he said. “It says: ‘regardless of cause.’ … It’s black and white.”
Staff suggested that an operator might purposefully disobey the signals to induce shortage pricing. Scarp also dismissed that, saying such action is so egregious that the actor would “probably end up in FERC jail.”
Seiler attempted to quell the argument by saying that it’s a new procedure that will likely require ongoing adjustments.
“We’re not going to settle it here,” he said.
“There’s nothing to settle,” Scarp shot back. He asked to convene a discussion between attorneys for each side.
Staff agreed to develop a report of security constrained economic dispatch cases that were not approved by dispatchers but would have resulted in shortage pricing.
PJM plans to produce a monthly report on its progress developing distributed energy resource rules, PJM staff said.
FirstEnergy’s Jim Benchek urged all stakeholders involved with DER to contribute to the process so they can “know what’s coming and be able to impact what’s coming.”
“When you’re talking about DER, it’s really who the DER is connected to,” he said. “If you have the potential to have DERs connected to your system, get engaged.”
PJM to Expand Data Capabilities, Discontinue Flat-File Support
The capabilities of Data Miner 2 are being expanded, PJM’s Thomas Zadlo explained, which means companies have a year to upgrade their internal systems before the flat files many member systems rely upon disappear.
“Data Miner 2 will become the central source for PJM public data,” Zadlo said.
The expanded database will go live in August and flat file postings will be retired in August 2018. Zadlo urged all stakeholders to send representatives to PJM’s Tech Change Forum to stay informed and be prepared.
PJM’s Bryson laid out a roadmap through 2018 to increase grid resiliency, focusing on short-term risks — such as assuring black start service — and gradually extending the perspective to discuss long-term goals such as enhanced dispatching and strategic islanding for critical infrastructure.
The paper found no point at which the percentage of gas-fired units caused reliability threats, but that a capacity mix of more than 20% of solar would threaten reliability. It was narrowly focused and purposely didn’t address other topics, such as environmental issues or whether natural gas infrastructure could keep pace with the high percentage of gas-fired generators PJM’s analysis said the fleet could handle.
CARROLL, N.H. — Residential customers installing behind-the-meter generation are just the latest factor stretching electric power utilities far beyond their original role as vertically integrated monopolies, speakers said Tuesday at the 70th Annual Symposium of the New England Conference of Public Utilities Commissioners (NECPUC).
“The most intermittent resource could be the customer,” said Barbara Tyran of the Electric Power Research Institute, part of a panel that explored the future of regulation and utilities by looking at parallels between the telecom and electric sectors.
Tyran said the electric industry’s data analytics are not sufficient for the changes coming. “It’s almost like we’re on a freeway driving 55 mph, but we’re only allowed to open our eyes once every 15 seconds,” she said. “That’s how much situational awareness is occurring. We need sensors throughout that system; we need to understand what that data is generating and what the value of it is and how to use it to improve the system performance, enhance the customer experience and also create new efficiencies.”
“Over the past 30 years, we as a region have shifted away from vertically integrated, economically regulated utilities, the ones that were envisioned by the foundational regulatory standards of just and reasonable rates for monopolistic utilities,” said New Hampshire Public Utilities Commissioner Kathryn Bailey, who moderated the panel. “However, I think in New England, we haven’t gone as far with the transformation of the electric industry as we have with the telecom industry.”
Janet Gail Besser, executive vice president of the Northeast Clean Energy Council and former chair of the Massachusetts Department of Public Utilities, said customer adoption of solar and other distributed technologies is the latest step in a process that began with competition in the generation sector following the 1978 Public Utility Regulatory Policies Act and grew with restructuring in the 1990s and the adoption of energy efficiency. She also pointed out that further changes are coming with the electrification of transportation and buildings.
Restructuring and Social Policy
One cause of the restructuring of the electric industry was the disparity between retail and the wholesale prices, according to consultant Louise McCarren, former chair of the Vermont Public Service Board and former commissioner of the state Department of Public Service.
“State regulators thought they could load anything onto” retail prices, McCarren said. “Social programs, conservation programs, you name it. And that price went up, way above the wholesale price.”
Nonetheless, McCarren said that her experience in Vermont has shown that regulatory frameworks can provide valuable public benefits, such as increased rural access to broadband service.
Hawaii Public Utilities Commissioner Lorraine Akiba said that “in the distributed energy resources paradigm shift of the future, we’ll actually be able to [support rural populations] more cost effectively because microgrids, and putting generation closer to the load saves all that transmission expense. In our jurisdiction, we require you to at least look at non-transmission alternatives.”
Regulators need not only to look at what markets can do, but also at what they can’t do, such as addressing social policy needs, said ISO-NE Director Kathleen Abernathy, a former Federal Communications Commissioner. “But don’t decide not to do something because it’s too expensive for low-income customers … you can fix that later or provide the necessary supports,” she said.
Competition forces companies to do things that might not be in their own economic interest but that benefit the public, said Abernathy, who cited unlimited cellphone minutes as an example. “Way back when in the wireless world, we used to pay per call,” she said. “It was only when the FCC allocated additional wireless licenses that all of a sudden you got unlimited minutes. That never would have been mandated by regulators; that happened in the market place. So embrace this kind of disruption and go with the flow on it.”
As with the telecom industry, technology preceded regulation, Besser said, giving customers an alternative to using incumbents’ landline phones. One question is whether some entity other than electric distribution companies will find ways to provide customer and system data to customers, third parties and the EDCs themselves, she said.
Electric Utilities Need to Add Value
“If you shift the risk away from the customer and to the utility, in theory you should shift the reward structure,” McCarren said. “And that is really hard to do, because when the wheels come off you still have to provide adequate and reliable services to all your citizens.”
In 1970s Vermont, hot water heaters were radio controlled in an effort to smooth the load curve. “The only problem was when you had an outage and you had to go reset them. But that was load control,” McCarren said. “Now the customer can do that, so if the utility wants to stay relevant, they have to add value.
“It’s Darwinian. If [companies] can’t change, they’re going to be roadkill,” she continued. “Is it your job as a regulator to create incentives or disincentives that encourage them to participate, or is [it] their job to figure it out?”
Akiba and others highlighted the importance of utilities’ ability to use big data analytics to operate the energy networks of the future.
“I feel sometimes we’re like the Oracle, that very sage character” in the 1999 movie “The Matrix,” Akiba said. “She has to make correct decisions, and she gives cryptic advice to Neo as he navigates the Matrix. … But we do have to keep our eye on the future trends and actions transforming the energy industry.”
Abernathy said that “sometimes a corporation’s addiction to a framework that guarantees certain revenue flows actually prohibits the kind of risk-taking that is essential for survival. … There’s no question that traditional regulatory frameworks actually prevent creativity and innovation, and people who are creative and innovative, they leave those companies for other ones who are doing more interesting work.”
McCarren said the regulatory solution “isn’t just one-size-fits-all, but going back to consumerization, localized solutions and keeping very flexible. … A very simple but effective rate design, that may or not require smart meters, can get you really far. The issue now is will we have to increase the charge to cover this fixed cost. … As long as it’s adequate, efficient and fair, it’ll work.”
CARROLL, N.H. — More than 300 regulators, market participants, consultants and RTO officials traveled to rainy Mount Washington last week for the 70th Annual Symposium of the New England Conference of Public Utilities Commissioners (NECPUC). Here’s some of what we heard.
New Hampshire’s electric rates, among the highest in the country, are a big concern for Gov. Chris Sununu, he told a lunchtime audience on June 5.
The high cost of electricity “affects business, it affects families, it affects those on fixed income,” said Sununu, a former environmental engineer who took office in January. “New Hampshire has an aging population, with the median age older [than] Florida, believe it or not. … It tells me more folks are going to be on fixed incomes. We already have a pretty high property tax here. … That means when you talk about flexibility in discretionary income, it’s pretty minimal for some folks. So when we talk about utility costs and energy costs and where we’re going … it’s our job to provide them with as much flexibility as possible.”
At an average of more than 16 cents/kWh, New Hampshire ranked sixth in retail electric rates in 2015, according to the Energy Information Administration’s most recent available data. Only remote Hawaii and Alaska — and New England neighbors Connecticut, Rhode Island and Massachusetts — were more expensive.
Sununu blasted the state’s energy plan, calling it “terrible” and “very poorly written.” He also defended his decision not to join California, New York and other states in pledging to abide by the Paris Agreement on climate change.
“I found it humorous that the governors of California and New York — two of the worst environmental polluters in the country — thought that everyone should sign a piece of paper to reaffirm their environmental commitments,” he said, recalling his time living in smoggy California and cleaning up hazardous waste sites in New York. “We are one of the best in the country in terms of our environmental stewardship.”
Officials Hope for Progress on Nuclear Waste
Spent fuel rods and other radioactive waste from four decommissioned nuclear plants in New England sit on-site today, in some cases more than two decades after the plants were shuttered.
That provided the context for a panel on the status of commercial nuclear waste disposal titled “The Slow and the Furious,” the former referring to the federal government, the latter to unhappy utilities and state officials.
American electricity users paid more than $20 billion into the Nuclear Waste Fund between 1982 and 2014, a figure that has more than doubled as interest has accrued. About $11 billion of the $46 billion in the fund has been spent on the program so far, said Katrina McMurrian, executive director of the Nuclear Waste Strategy Coalition, an organization of state and utility officials formed in 1993 to push for a final resting place for radioactive waste.
McMurrian and other speakers saw reasons for optimism.
Plans for a permanent waste repository at Yucca Mountain in Nevada were squelched in 2009 when President Barack Obama ordered the Nuclear Regulatory Commission to stop work on a licensing permit, a move taken at the behest of then-Sen. Harry Reid (D-Nev.). The license application for the site, 140 miles northwest of Las Vegas, was the product of 30 years of work and billions in spending. Obama’s decision outraged nuclear operators and state regulators.
With Reid retired and a new president in office, two major political obstacles to Yucca are gone. President Trump’s proposed 2018 budget seeks funds for both the permanent repository at Yucca and “consolidated interim storage,” McMurrian said.
She outlined several bills have been introduced or are under discussion in Congress.
A comprehensive Senate bill, which was introduced in two prior Congresses, hasn’t been introduced again yet this session, but a comprehensive House “discussion draft” is expected to be filed soon, she said.
Neither specifically identify permanent disposal facilities. The House draft, the Nuclear Waste Policy Amendments Act of 2017, builds on existing NWPA direction to move ahead with Yucca. The Senate bill proposed seeking locations to volunteer for both permanent disposal and interim storage.
Rep. Darrell Issa (R-Calif.) has introduced a narrower bill on private interim storage, the Interim Consolidated Storage Act (H.R. 474).
NRC Chairwoman Kristine Svinicki has asked Congress for $30 million to review a revived license application for Yucca Mountain. At a congressional hearing Wednesday, she said it could take three to five years to resolve more than 300 legal challenges to Yucca Mountain, many of which were filed by the state over alleged risks to groundwater.
Svinicki also said it would take three years to complete licensing on sites in Texas and New Mexico, where private contractors are seeking to temporarily store waste.
One of those companies is Holtec International, whose program director, Ed Mayer, briefed NECPUC on the company’s New Mexico project, a 1,000-acre site he said was capable of storing all the waste from all the commercial reactors in the U.S.
Spent fuel rods must be cooled in 40-foot-deep water tanks for at least five years before being put into dry casks, where they need to be air-cooled by natural ventilation for at least another five years before being buried deep underground.
Robert Capstick, director of regulatory affairs for Yankee Atomic Electric Co., Maine Yankee and Connecticut Yankee, presented slides showing the challenge of moving nuclear waste. Dry transportation casks weigh about 100 tons, but Capstick noted that the decommissioning of the Yankee plants has already resulted in the transportation of radioactive reactor pressure vessels weighing between 300 and 1,000 tons.
“While the removal of the reactor pressure vessels from the Yankee sites was certainly a challenge, the slides showed that the transportation of large radioactive components during plant decommissioning was safely completed – and those packages far exceeded the size and weight of the future spent fuel transportation casks,” Capstick explained afterward.
VALLEY FORGE, Pa. — It took another hour of debate, but stakeholders at last week’s Market Implementation Committee meeting found just enough consensus to approve a problem statement and issue charge developed by PJM to analyze potential changes in how energy efficiency resources can participate in wholesale markets.
The vote was precipitated by a Kentucky Public Service Commission order saying state retail electric customers have no authority “to participate directly or indirectly in any wholesale electric market.”
The Advanced Energy Economy has also petitioned FERC to issue a declaratory order on the topic.
“There was a state commission that was being asked to clarify its requirements” for letting in-state energy efficiency aggregators bid into the RTO’s energy efficiency market, PJM’s Denise Foster said. “We looked at the rules in PJM and realized there was no way for us to respect any determination that came out of that process. … There was a lot of discussion about jurisdiction … but there was also a lot of discussion about how proscriptive the problem statement and issue charge was — so we cleaned up the problem statement.”
Foster was careful to clarify that PJM doesn’t want to get involved in the regulatory process but seeks to move the analysis forward to be ready to take action as soon as FERC has made a decision. (See “Energy Efficiency Proposal Sparks Debate over State Jurisdiction, Stakeholder Identification,” PJM Market Implementation Committee Briefs.)
Representatives of utilities involved in the issue — including Dana Horton of American Electric Power, Chuck Dugan of the East Kentucky Power Cooperative, Jim Benchek of FirstEnergy and Brian Garnett of Duke Energy — all voiced support for the problem statement. Benchek pointed out that rule changes should be careful to avoid unintended effects on electric distribution companies.
Rick Drom, an attorney representing AEE along with an unnamed energy efficiency aggregator in Kentucky, reiterated his position that the activity is premature.
“I was glad to hear [the utilities] say that once the FERC jurisdictional issues are resolved, then we can move forward with the problem statement, because I think it’s very clear that until FERC jurisdictional issues are resolved, it would be difficult to modify the Tariff,” he said. “To me, this is a simple educational issue.”
Energy efficiency resource providers contract with manufacturers and wholesale retailers, not with retail customers, Drom said, suggesting that the Kentucky PSC might not be aware of that nuance. He warned that by moving forward with the problem statement, “PJM stakeholders will be spending resources on a problem that simply does not exist.”
Dugan said retail customers’ rates will be adversely impacted by energy efficiency providers.
“I don’t think any education is going to change their mind,” he said of the Kentucky PSC. “I truly believe they knew what they were talking about.”
Other stakeholders raised points on both sides of the issue, including EnerNOC’s Katie Guerry, who said PJM’s demand response processes still have “kinks” to be worked out. “I do see value in working out the kinks in advance,” she said.
CPower’s Bruce Campbell motioned to defer a vote on the problem statement until after FERC has ruled, a measure seconded by Tom Rutigliano, who represents energy efficiency providers. That measure failed.
Stakeholders discussed whether the problem statement’s language should be further neutralized. Foster said PJM was very deliberate in its word choices because it didn’t want to be in a position of determining whether participants need to be in compliance.
The measure eventually passed with 85 votes in favor, 81 opposed and 14 abstentions.
All DR Registration Changes Fail
After months of discussion in the Demand Response Subcommittee, all three proposals for increasing flexibility to add and subtract resources from aggregators’ portfolios failed to garner necessary stakeholder support. The three options differed on registration deadlines and testing requirements. (See “DR Open Registration Under Consideration,” PJM Market Implementation Committee Briefs.)
Guerry and NRG Energy’s Brian Kauffman were quick to register their opposition.
“At the outset of this discussion, we had reservations because we knew it was going to be very complicated” and create administrative problems along with additional costs that must be passed on to customers, Guerry said. “From our perspective, it just sort of spiraled out of control.”
Independent Market Monitor Joe Bowring challenged Guerry’s opposition, asking whether she opposed the idea of requiring removal of resources that can no longer reduce load.
“Do I have a specific opposition to that? No, I do not … but these are the additional layers of complexity that we believe are unnecessary just to allow the registration window to be open beyond the window that it’s open to right now,” she said.
“One person’s complexity is another’s solution to a problem, but I understand what you’re saying,” Bowring said.
Campbell, who proposed the problem statement, acknowledged that he hadn’t foreseen some of the issue’s complexity but was simply attempting to make DR comparable to generators, which can enter PJM’s markets at any time.
Three new proposals for revising financial transmission rights rules moved forward, although one didn’t advance as easily as the rest.
The wave of FTR actions began when stakeholders endorsed by acclamation revisions to Manual 28 regarding allocation of balancing congestion.
A problem statement and issue charge presented by Direct Energy’s Jeff Whitehead to review the allocation of surplus funds for day-ahead congestion and FTR auction revenues received a little more discussion. GT Power Group’s Dave Pratzon asked if the adjective “alternative” could be substituted for “appropriate” in describing the disposition of the surpluses. The issue, which had received substantial debate previously, was subsequently approved. (See New FTR Task Force on the Way for PJM?)
The final measure, resolving delayed results for periods of the year when there are several overlapping FTR products available, didn’t fare as easily. Bruce Bleiweis of DC Energy suggested the issue might be technological.
“We think that PJM may not be using the most efficient clearing engine,” he said.
Other stakeholders offered differing perspectives. Eventually, Calpine’s David “Scarp” Scarpignato threw up his hands to register his confusion.
“I can’t vote to approve this problem statement because too many people are interpreting it in too many ways,” he said. “I hate telling people to come back with another rock, but this doesn’t do it for me.”
As the meeting broke for lunch, stakeholders debated the issue and eventually agreed upon a two-phased problem statement and issue charge. The first phase would explore reducing the overlapping periods while maintaining liquidity through other market enhancements, and the second would explore other ways to solve the issues, such as through algorithm or technological changes. The revised document subsequently received endorsement.
PJM’s Asanga Perera noted that a special session of the MIC will be held on June 23 to begin exploring the issues.
Started from the Bottom, Now We’re at the MTSL
PJM and the Monitor remain at odds over how much compensation black start units should be allowed to receive for storing fuel.
The RTO is willing to cover storage costs for the oil units require to meet its black start requirement — usually 16 hours of operation — plus the minimum tank suction level (MTSL), which is the lowest amount of fuel needed to provide adequate supply to the generation unit, PJM’s Tom Hauske said.
Bowring argued that the incremental cost of keeping the level of fuel needed for black start capabilities is zero. The tanks are often used for multiple units and are so large that the black start needs are but a small fraction of the tank’s overall MTSL.
Bowring later added that his office agrees with PJM that black start units should be paid carrying charges on the fuel required to meet the 16-hour obligation and for the MTSL when there are tanks dedicated to them.
“But the PJM approach can require customers to pay for more than 10 times the MTSL required for the black start unit, depending on the size of the tank,” he said. “The PJM approach assigns to the black start unit the MTSL for a very large tank that was designed to serve another unit and continues to serve that other unit. The actual MTSL does not change by even a gallon when a black start unit is added for such a unit. The result is unfair to all the customers who pay for black start service.”
Balancing Differences
A PJM analysis of FTR data became a battleground when Roy Shanker, an industry consultant, took exception to the numbers suggesting that auction revenue rights holders benefited from a recent FERC order that allocated the costs for balancing congestion to load.
Perera presented the analysis, which suggested that the value of FTRs for the 2017/18 delivery year would have increased by $91 million compared to the previous year, during which balancing congestion was allocated to the ARR holders.
While other stakeholders defended the analysis as an important backward-looking review, Shanker complained that it seemed to be sending a message.
“I do mind when [the numbers are] represented as a metric of the benefit to the ARR holders,” he said.
“I agree it’s a material difference in perspective: I’m paying for balancing congestion and you’re not,” Direct Energy’s Whitehead countered.
“And you always should have been!” Shanker immediately shot back.
Bowring said the numbers should be neutral, but analysis should still be done. “I would be shocked if there’s a net benefit, but if there is, there is,” he said.
