Weeks after stakeholders introduced six proposals for redesigning PJM’s capacity construct, another three have materialized. Many of the nine are variations on a two-stage auction repricing structure, while others envision vastly different procedures.
All nine were presented and explained at a two-day meeting last week of the Capacity Construct/Public Policy Senior Task Force, which was created earlier this year to address concerns about state subsidies of generators undermining PJM markets. It has been moving to have an agreement endorsed and filed at FERC by the end of the year. PJM has held several two-day task force meetings to accommodate the depth of discussion stakeholders have demanded for the process. (See PJM Stakeholders See Capacity Auction Flaws, Offer Solutions.)
The proposals can be broadly categorized among those revamping the entire construct, developing repricing processes that accommodate subsidized units and extending a rule intended to eliminate the impact of subsidies.
The revamp proposals include full-scale redesigns from American Municipal Power and the Natural Resources Defense Council, and a limited revision to existing fixed resource requirement (FRR) rules called “Capacity Choice” proposed by John Horstmann of Dayton Power & Light.
The repricing proposals originated from a two-stage auction design by PJM. Many felt it unfairly discriminated against units on the margin in the capacity auction and proposed tweaks that would either reduce capacity awards (NRG Energy) or reduce the clearing price (LS Power). Another proposal would trigger repricing only if the clearing price rises to a level that incentivizes new generator construction (Exelon), while a fourth would calculate the clearing price by removing subsidized offers and scaling the remaining competitive offers to replace the shortfall (Old Dominion Electric Cooperative).
ODEC’s Mike Cocco said other repricing proposals utilize reference pricing schemes to replace the market offers from subsidized resources but failed to account for what would be corresponding change in the supply stack. ODEC’s proposal was designed to fully synthesize an auction as if subsidized units never existed and competitive units covered the entire demand.
“Once you open that door and decide you’re going to reprice with reconstituted offer prices, you have to open that door all the way,” Cocco said.
Monitoring Analytics, the Independent Market Monitor, proposed an extension of the existing minimum offer price rule that would require units to undergo analysis every year they receive subsidies without an exemption — requiring them tosubmit the variables and equation they used to calculate their offer. The Monitor would then review the submissions for competitiveness, much like it now does with fuel-cost policies and cost-based offers. (See PJM Monitor Rejects Fuel-Cost Policies for 11% of Units.)
“If states want control over their assets, they should reregulate — and that’s fine,” Monitor Joe Bowring said. “If we’re going to have markets, we should have markets.”
James Wilson of Wilson Energy Economics also provided comments on the redesign proposals, arguing that “markets are not as fragile as some suggest.” With enough lead time, markets have a “substantial ability to absorb incremental/decremental resources with minimal impact on prices,” said Wilson, who consults for the consumer advocates in New Jersey, Pennsylvania, Maryland, Delaware and D.C.
He predicted that the process would settle on “some sort of two-tiered pricing,” for which he has concerns. He also expressed reservations about expanding the MOPR.
The comments found some favor with AMP’s Ed Tatum, who has argued the best solution is to replace reliance on the annual capacity auction with long-term bilateral contracts between generators and load-serving entities.
“With enough notice, the true market would be able to absorb these things,” he said.
He also liked Horstmann’s “Capacity Choice” proposal, which would allow LSEs to determine how they want to fulfill their capacity obligations, either through long-term contracts under the existing fixed resource requirement (FRR) rules, annually through the existing Reliability Pricing Model or some combination of the two extremes.
All current and future subsidized units would be required to choose the FRR option, which would eliminate their potential influence on the RPM auctions. The entity enacting the subsidy would have to elect how it would be funded through its rate base.
“This is kind of a different approach than some of the ones you’ve seen before,” Horstmann said. “As opposed to being told how to manage your capacity obligation, basically what I’m putting on the table here is you get to choose how to manage your capacity obligation.”
He outlined several as-yet unanswered questions but noted that because the structure is largely already approved by FERC, it would require minimal Tariff changes. He said he analyzed the stakeholder proposals to address as many interests as possible but couldn’t include all of them — such as proposals to trigger repricing.
“Clearly it doesn’t accommodate the one that doesn’t think there’s a problem,” he said.
Going forward, PJM plans to distribute a poll to judge stakeholder interest in each of the proposals, including the status quo. The poll results, if emphatic, could determine the CCPPSTF’s ongoing direction and which proposals receive the most attention.
PJM is looking to schedule another meeting on Aug. 17, followed by meetings on Aug. 23, Sept. 11, Sept. 12 (if possible), Sept. 26, Oct. 16, Nov. 1, Nov. 21 and Dec. 11.
NEW YORK — New York’s grid is transitioning from a one-way transmission system to a multidirectional one, and utilities still need time to develop the analytical tools to understand how to deal with distributed energy resources.
“We are at a very early stage of bringing DERs into what has historically been a passive distribution system,” NYISO Senior Manager for Market Design Michael DeSocio said during a panel on the ISO’s DER Roadmap, which outlines the grid operator’s plans for integrating DER into its ancillary services, capacity and energy markets over the next five years.
“We want to get to a 21st-century grid, but we’re still running 20th-century computer systems. We’re still running 20th-century metering,” DeSocio said.
Natara G. Feller of Feller Law Group posed some of the main questions on the topic: “In NYISO’s bulk transmission system versus Con Ed’s distribution system, how do DER resources impact reliability? How can we shave the peak off the grid? How does this impact the state’s requirement for meeting certain capacity standards? What kind of obligations are consumers going to assume, or are they passive obligations where they’re not assuming responsibility?”
“Are we going to have deployment first, or the markets first?” asked Chris Rauscher, director of public policy at Sunrun, the country’s largest rooftop solar company. “As my company and others deploy more storage paired with PVs, are we going to do that in states that already have open access to markets, or are we going to other states that have incentives, for example? And how do we sync all this up together?”
Ben Pickard, a distributed energy analyst at National Grid Ventures, which has a strategic partnership with Sunrun, said the development of a DER roadmap comes with the risk that ISO will “overbuild and structure for every contingency at the expense of just trying to get markets going.”
DeSocio responded that distribution systems must evolve because they haven’t necessarily been designed to deal with all the traffic they will handle with increased DER adoption. The ISO will need enough information to determine whether its own actions create a reliability issue for utilities, which — in turn — are trying to learn how to spot ISO-driven reliability needs on their systems.
Pickard pointed to one outcome of an ISO roadmap that contemplates its system at the sub-nodal level. In such small and specialized cases, he said, “market power becomes a real issue, and you’ve created all these tiny markets that are quite hard for regulators — it’s like a Hydra problem.”
Speaking on a different panel on defining value stacks for DERs, Kelli Joseph, director of New York market and regulatory affairs for NRG Energy, said, “It’s really difficult to forecast some of the values within that value stack. Some of it is intended to be fixed, but then some of those fixed values aren’t fixed for the entire length of what the tariff is supposed to be. These are 20- and 25-year projects where some aspects are fixed for only a couple of years and others for even less than that.”
Capacity Factor
Divorcing the market from physics is a recipe for trouble, DeSocio said. If the market creates incentives that don’t recognize the limited capacity on wires — and price signals are faulty — the system is going to get response that it can’t handle, he said.
“We have to rethink what is capacity,” DeSocio said. “In the wholesale and the retail space, capacity is measured against one hour of one day of one year, and we do that every year. But there’s going to be more days to become important and we need to start to think about how we change both the viewpoint and the value of the ICAP [installed capacity] tag. The ICAP tag is how we currently couple the retail rate with the wholesale rate, and so that will be important for the capacity portion of value DER or other retail rate usage of the capacity portion.”
| NYISO
NYISO prices energy and reserve use on a five-minute basis, but it doesn’t apply that same time-based standard to resources that are asking to sell at the retail rate. Including the time factor would better couple the value of DER with the wholesale market price, according to the ISO.
Paul A. DeCotis, a former state planning official now with West Monroe Partners, said the DER pricing challenge could be likened to the early years of co-generation or energy efficiency when “we had difficulty assigning value to the reductions in load or in the kilowatt-hours saved.”
“A monthly average LMP does not help me drive or motivate behavior of any sort,” DeSocio said. “I smooth it all away, it’s gone. The three days a month that I as a grid operator am worried about how I’m going to meet the next megawatt of load, those price signals are gone in a monthly average LMP. As we do that, there’s less need for some of these other ‘rough justice’ or ‘fudge factors’ in those reads, because now you’ve exposed the exact time and locality information into the rate itself and the resources that can best fit that need are going to profit the most.”
In the longer term — such as over the next 10 years — DER will look a lot like today’s demand response space, where those resources become more capable of providing near-term action for real-time reliability, DeSocio said.
NEW YORK — New York state wasn’t the first out of the gate on offshore wind, but it will be the biggest player if it meets Gov. Andrew Cuomo’s 2,400-MW target. State policymakers are embracing offshore wind for its utility-scale generation, its ability to be developed close to the major load centers of New York City and Long Island — and its potential jobs.
“Right now, there are over 300,000 jobs in the offshore wind industry in Europe,” Sierra Club Senior New York Representative Lisa Dix said last week when she moderated a panel at the Infocast New York Energy REVolution Summit at Times Square.
The federal government has identified more than 100 GW of offshore wind potential off the Atlantic coast, and the Bureau of Ocean Energy Management has moved forward with the offshore wind lease process in New York and seven other states. The first offshore wind lease for New York, a nearly 80,000-acre site off the Rockaways in Queens, went to Norway-based Statoil last December.
“Offshore wind provides power when it’s needed the most, at peak times,” Dix said. “And it’s at a scale that the state needs not only to fulfill its renewable energy policy goals, but also to help combat climate change, where New York City and Long Island are really on the front lines.”
State and Stakeholder Support
Chris Wissemann represents the U.S. activities of Germany-based offshore wind developer Innogy, which he characterized as being four times the size of Consolidated Edison and generating enough electricity to serve the entire load of New York state.
“Long-term, stable policy is what makes this become cost-effective,” Wissemann said. “Along those lines is the corollary, which is the four P’s: politics-proof purchase program. Look at Cape Wind, several years ago: The minute their benefactor was out of office, they lost their [power purchase agreement]. New Jersey’s OSW economic development program was never implemented because of politics.”
Cuomo in January called for 2,400 MW of offshore wind projects by 2030, starting with the 90-MW South Fork Project off Montauk, Long Island.
The growing breadth and depth of support for offshore wind is spectacular, but not surprising, said New York Offshore Wind Alliance director Liz Gordon. All the different interest groups don’t necessarily have the same reasons to support OSW, she said.
“Environmental groups clearly see clean, reliable offshore wind power as a climate change solution, or at least a mitigation,” Gordon said. “Labor in New York state is all-in; they’re vocally supporting offshore wind because they see massive job potential — good jobs, quality jobs. That will depend on there being a reliable pipeline of projects and ideally a port or two here in New York.”
Greg Matzat, senior adviser on large-scale renewables at the New York State Energy Research and Development Authority, said: “New York has the largest goal for offshore wind in the country of 2,400 MW. Massachusetts is behind us at 1,600. But we’re the only state that doesn’t have enough areas currently leased to support our goal. Massachusetts has more than 1,600 MW [in leased sites] available, so it’s really important for us to identify sites that make sense for New York and hopefully work for BOEM too … so we can move forward with more leases.”
The Statoil site has room for about 800 MW, only one-third of New York’s target.
James F. Bennett, chief of renewable energy programs at BOEM, described the 13 commercial OSW leases contracted so far, extending from Cape Cod to Cape Hatteras.
“There’s at least one off of every state, from Massachusetts to North Carolina, and obviously where the greatest demand would be,” Bennett said. “New York is one of these areas, obviously, where that demand is indeed great. In particular for New York, we have the one area that was leased in December of last year to Statoil for $42 million, which was an incredible milestone for the program. And we also had a sale in North Carolina in March of this year that went for $9 million to Avangrid. Both of those are indicators that the industry, if it hasn’t arrived, it’s arriving. We’re very optimistic about activities in the future.”
According to Bennett, New York has great OSW potential because it has all the factors that make a wind project succeed: wind resources are prime; shallow water off the continental shelf supports seafloor foundations; strong demand that constitutes a good market; and state support.
“I don’t know if there is a stronger demand than immediately from New York,” Bennett said. “All of these leases have occurred with state involvement and state input, and in particular New Jersey and Massachusetts are great examples of states that have put the time and effort into putting the environmental and stakeholder interests together, and that’s the lead that New York is following.”
NYSERDA is drafting a master plan that will include a plan for transmission to get wind-generated power to shore. “Some of this you’ll see in our Public Service Commission filings,” said Matzat, “but the master plan will include recommendations on how to move pre-permit forward for OSW and a timeline on how we see this going.”
| NYSERDA
BOEM manages the lease process and step one is planning and analysis to identify a wind-energy area, “which is where we are now in the process for New York,” Bennett said. “It’s obvious that the biggest one [lease area] is the one to the north, from New York to Nantucket, and right now that probably will include a couple leases off Martha’s Vineyard, which went unleased just two years ago, and we expect very high demand for those areas and are looking to 2018 for an auction for that. Beyond that, and we’re always hesitant to get nailed down to a date, but after that we think we’re in a position to go forward with another sale in New York.”
Docks and Dolphins
NYSERDA applies a similar evaluation process to ocean areas and to the shoreline for the ports needed to fabricate the huge turbine blades and host the purpose-built vessels used in building OSW installations. The authority is looking at 75 sites. The turbines off Block Island, which are 6 MW each, stand 600 feet above the water. The turbines NYSERDA is looking at will average 10 MW and approach 700 feet tall, plus their 200-foot foundations.
“We’re looking at the whole supply chain, so we’re not just looking at New York Harbor and the Port of New York and New Jersey, but we’re looking around Long Island and we’re looking up the Hudson too,” Matzat said.
Certain activities should be done as close to the wind farm as possible, such as staging for assembly, but other parts of the supply chain, such as manufacturing cables or blades, can be done farther away, he said. Most parts cannot be put on a truck and must be put on a ship, so a large part of the supply chain has to be on the water.
“But that doesn’t mean you couldn’t build up on the Hudson, where there are areas of labor that might fit a particular part of the supply chain, and bring that down on a barge to an assembly area,” Matzat said.
NYSERDA is now conducting public comment sessions, with four for the fishing industry alone this month.
“Another big group that isn’t 100% on board with us is the fishing industry, so we’ve really made a point of reaching out to the fishermen, and we’ve had a dedicated fishing liaison who just goes around to docks, not just in New York but in other states too, to talk to fishermen and understand their concerns,” Matzat said.
The master plan also includes intensive surveys of the shoreline and coast.
The authority has a survey vessel about 15 miles south of New York City doing sediment profiles and sediment samples of the sea bottom over a couple million acres so planners can understand the habitat on the seafloor and what the seafloor is made of, which has environmental as well as construction-planning value.
“I don’t believe any state has ever done that in advance of identifying areas for offshore wind,” Matzat said. “Usually that’s done later by developers.”
NYSERDA also is conducting a digital aerial wildlife survey, using a plane with high-resolution cameras to photograph more than 12,000 square miles of ocean four times a year over three years. It has already completed the first year.
NEW YORK — Energy storage developers and utilities in New York are working with NYISO to establish dual participation of storage in retail and wholesale markets.
The goal is to boost storage growth “to get to the gigawatt level, where just five years ago we were talking about one megawatt,” Martha Symko-Davies said in New York on Thursday.
Symko-Davies, program manager for energy systems integration at the National Renewable Energy Laboratory, headed a panel on storage integration at the Infocast New York Energy REVolution Summit held last week in Times Square.
The panel discussed the industry’s progress since FERC last November issued a Notice of Proposed Rulemaking aimed at knocking down market barriers to storage and distributed energy resources (RM16-23, AD16-20). (See FERC Rule Would Boost Energy Storage, DER.)
Tim Banach, vice president of development for microgrid developer GI Energy, said that in the past, “there was little to no coordination with the utility around where these projects would be sited and what impacts the projects might have on the utility grid, both beneficial or potentially doing some harm.”
Now GI Energy is working with U.K.-based software developer Smarter Grid Solutions on storage demonstration projects for Consolidated Edison.
Graham Ault, executive vice president of Smarter Grid, said his company has mainly developed technology to manage DER for utilities. “The same technology as developed for and used by utilities is highly relevant to the owners and operators of fleets of DER, and that is what we as a company are addressing,” Ault said. “The GI Energy-Con Edison project is an excellent example of that.”
Adrienne Lalle, project manager for Reforming the Energy Vision (REV) demonstration projects at Con Ed, said: “We, through our value-stacking goal, are big supporters of dual participation and using the assets for utility grid support and wholesale markets. It enables developers like GI Energy to offer lower-cost storage solutions to us.”
Brian Asparro, chief commercial officer of Demand Energy Networks, said technology must be straightforward to win customers. The company, which in January was acquired by Italian energy giant Enel, provides turnkey services for storage and DER.
On a recent project in Brooklyn, the company used its software to reduce demand charges for Con Ed customers and help the utility manage load reduction on its local network. (See NYPSC Extends Con Ed Demand Program.)
And customers also want resiliency so that in the case of an outage, critical elements of a housing or office complex can keep running, Asparro said.
Banach said that it was sometimes a challenge to educate owners of multi-family housing complexes or commercial enterprises — people whose expertise is not energy — on how storage projects were going to affect their energy bills. His company needed to explain “stand-by rates, contract demands and effects to ICAP [installed capacity] tags, so it was a constant requirement to educate.”
Now it’s a simpler real estate transaction between the developer and the host site, which can rely on predictable lease payments, Banach said. “We are now able to participate in wholesale markets and generate additional revenues. Ultimately our hope is to demonstrate that by stacking all these revenues, we can lower the cost of service to the utility for the energy services provided and provide ratepayer benefits through an effective and targeted non-wires alternative,” he said.
Lalle said Con Ed is looking to simplify the value proposition for the customer by disconnecting the project economics from the customer load profile, bringing the battery in front of the meter but providing a customer with a lease payment for the space.
“So, you get all the benefits of distributed storage,” Lalle said, “but you can add a utility value by directing the location strategically to a network constraint, sizing it a little bit bigger so that we can possibly offset some [transmission and distribution] investment and make the dispatch coincident with the network need as opposed to the customer load profile.”
John Bellacicco, director of Northeast operations at Stem, which focuses on behind-the-meter storage systems, said: “One of the biggest monetizable value streams today for energy storage is demand management, and the best way to get customer participation, especially when we think of REV and how REV wants to bring the customer into it as a prosumer, is to put the energy storage behind the meter and to have the customer participate.”
In front of the meter or behind doesn’t matter to Ryan Wartena, president and cofounder of Geli (Growing Energy Labs Inc.), an Australian company that develops software and services for storage and microgrid systems.
Wartena said he spent years developing batteries “until I realized that you can give the world an everlasting, almost free, solid-state battery, but no one’s really going to know how to use it. We have to think about batteries as a hard drive, where you can co-optimize, run multiple applications. So that’s where our initial intellectual property is.”
A developer can do demand charge reduction behind the meter and be available for wholesale participation, which Geli is doing now in Australia.
“Australia has a different market than the United States does, for they expose wholesale prices to residents,” Wartena said.
Wartena emphasized the need for alignment between developers and utilities. “Not just nodal to nodal, but if it’s a huge market price, I’m going to punch out a megawatt right now,” he said. “But my local distribution system does not want me to do that. The problem is you’re trying to feed the wholesale market from inside the mothership and you’ve got to use the mothership’s pipes, so there has to be that alignment, and that software, and that’s a lot of work to get that type of alignment.”
Everyone is entitled to their own opinions. But no one is entitled to their own facts.
IMHO, the facts are that climate change is happening, is man-made, and is a threat to mankind. How much of a threat, and how imminent the threat, are things we can talk about.
The big question is what to do about it. There are some who peddle the false hope that we can fix climate change on the cheap.
No. Climate change is not going to be fixed on the cheap. Sugarcoating the requisite effort isn’t doing us any favors.
Which brings us to the widely publicized 2015 claim by four academics from Stanford University’s Department of Civil and Environmental Engineering and the Institute of Transportation Studies at the University of California, Berkeley that we can power the entire economy at “low cost” with just wind, water and solar (WWS) resources, using electricity and hydrogen as the delivery systems. The study was led by Stanford’s Mark Jacobson, so let’s call them the Jacobson Group.[1]
Their vision is not just electric generation powered with WWS resources, mind you: everything to be powered with WWS resources as the sole primary sources. Planes, trains and automobiles. Ships. Trucks. Industrial processes. All natural gas facilities — yes, your gas furnace, dryer, water heater and stove[2] — are torn out. All nuclear, gas and coal plants are shut down. Got the idea?
To put this staggering “low-cost” scenario in perspective, past analyses of deep decarbonization (80% reduction) of only the electric sector (and keeping nuclear plants) estimate increases of $23 to $53/MWh in average retail electric rates by the year 2050.[3] Whether one views a retail price increase of this magnitude as worthwhile can be debated, but it certainly can’t be called “low cost.”
Two years have gone by since the Jacobson Group paper was published, and thankfully the National Oceanic and Atmospheric Administration’s Christopher Clack and 20 others (the Clack Group) have come forward to refute it.[4] The Jacobson Group replied, claiming their analysis was impeccable.[5] And the Clack Group has responded.[6]
Up to this point you may be thinking: “OK I read about this controversy in TheNew York Times, Washington Post and/or The Economist,[7] and there’s probably some truth to each side.”
You would be wrong. The Jacobson Group is in the realm of alternative facts. It is simply wrong.
Don’t take my word on this. If you have the time and inclination, please read the Clack Group’s detailed (and fascinating) “Supplemental Information,” available here.[8] And then read the Jacobson Group response, available here.[9] You’ll see that the Clack Group demolishes dozens of Jacobson Group claims; the Jacobson Group ignores most of the demolition and offers tweet-like replies for the rest.[10]
Why care? Right and wrong matter because wrong has tragic policy implications.
For example, the Jacobson Group claims that WWS resources can suffice for a low-cost carbon-free future, so it rules out other carbon-free sources like nuclear power. In the case of nuclear power, the Jacobson Group asserts a life-cycle mortality analysis that assumes nuclear wars occur on a 30-year cycle, which they haven’t, and that civilian nuclear power somehow sustains military nuclear power, which it doesn’t.[11]
The Jacobson Group also claims that all nuclear generation is uneconomic, relying on studies of new nuclear generation costs. As noted earlier, past analyses of electric sector deep decarbonization keep existing nuclear generation, the bulk of which is economic on a going-forward basis even with current low natural gas prices.[12]
Here’s another tragic policy implication: Energy efficiency doesn’t matter. If WWS resources can supply existing energy demand at low cost, why be more efficient? I’ve written before about how LED lighting has reduced demand by more megawatt-hours than rooftop solar has generated.[13]
That’s how significant energy efficiency can be. Let’s not abandon energy efficiency on the false hope that WWS resources can supplant all existing energy resources at low cost.
And how about reversing deforestation, which may be the cheapest way to fight climate change?[14] Or incenting India to take the most inefficient air-conditioning units off the market?[15]
Again, the Jacobson Group implicitly says “don’t worry, be happy,” we can stop climate change on the cheap with WWS resources.
I’m not going to take up a lot of your valuable time regurgitating the entire Clack Group demolition, but I do want to highlight some of the more outrageous Jacobson Group claims so you have a taste. And I’ll do a little demo of my own.
Aviation. The Jacobson Group claims that all aviation fuel can be replaced with hydrogen created by electricity from WWS resources. Their support for this is an experimental four-seat airplane that runs on hydrogen.[16]
So … with a pilot, co-pilot and steward, the plane has room for one passenger. Luggage and toilet not included.
The cruising speed of this plane is 102 mph. I guess commercial airlines — and the U.S. Air Force — will just have to make do with a plane barely faster than a car.[17]
Hydrogen Production. Here’s a sleight of hand that us electric geeks will understand. Citing themselves, the Jacobson Group claims hydrogen production and storage will cost 4 cents/kwh-to-H2. But the Clack Group points out that this cost is based on a 95% capacity factor, while the capacity factor for hydrogen production in the Jacobson Group model is about 9%.
That means the capital cost for hydrogen production will be 1,000% more than the Jacobson Group claims. The Jacobson Group offers no defense.
Solar Thermal with Storage. Wow, another piece of work. The Jacobson Group says we can build massive networks of solar thermal panels that heat up glycol and then pump it underground to storage pools and then make withdrawals as needed. The Jacobson Group cites a residential housing project in Canada that involved 52 homes costing $134,000 each.[18]
Mind you, that just gets space heating. Air conditioning, hot water, clothes drying, cooking — all extra. Not “low cost”!
The Jacobson Group claims underground thermal energy storage has a capital cost of $1,320/kW, but, as the Clack Group points out, its cited references don’t provide any support. In another paper, the Jacobson Group said it relied on “Lazard’s (2014) estimates with 18-hour storage”; that Lazard document says that solar thermal costs more than $9,000/kW.[19]
And where does the Jacobson Group account for the cost of facilities to convert excess electricity into heated glycol for injecting underground in the storage facilities? There is an assumed conversion capacity that is enormous, but I can’t find any associated cost for such capacity in the modeling.
Back to the electric industry we know and love.
Water/hydropower. Let’s start here with the Clack Group calling out the Jacobson Group’s claim that U.S. hydropower capacity can be easily expanded from the current 87 GW to 1,300 GW (not a typo). This issue is the one that got the bulk of media attention.
The Jacobson Group asserted in reply to the Clack Group that it was assuming a feasible increase in capacity at existing hydro facilities.
The reality is that there is very limited hydropower expansion capability. A best-case scenario is an additional 13 GW by 2050, according to the U.S. Department of Energy’s recent 407-page study of this subject — which is hiding in plain sight on the DOE website.[20]
Installed capacity values for 2015 (left column in each pair) and those used in the Jacobson studies (right column in each pair). The 100% wind, solar, and hydroelectric studies propose installing technologies at a scale equivalent to or greater than the entire capacity of the existing electricity generation infrastructure. The other category includes coal, natural gas, and nuclear, all of which are removed by 2050. | Clack, et al.
Yes, the best case is 1% of what the Jacobson Group claims. One percent.
And of course we couldn’t release the water associated with 1,300 GW of hydropower without causing massive flooding across the U.S. A minor detail to be sure.
The Jacobson Group claim is a fantasy.
Flexible Electric Demand. In order for the intermittent WWS resources to “work,” the Jacobson Group assumes 63% of industrial demand is flexible (totally controllable by system operators within eight-hour windows). We in the electric industry know that despite large economic incentives, only a small percentage of industrial load opts to participate in demand response programs (which involve only demand reduction, not demand increases on command).
In other words the Jacobson Group envisions a paradigm shift in which most industrial load conforms to intermittent resource output rather than the other way around. Not going to happen at low cost, if at all.
Offshore Wind. All of us in the industry know what a brutal slog it is. After many years there is all of 30 MW off Rhode Island at a cost of $244/MWh. The Jacobson Group makes the incredible claim that 750 GW can be economically constructed, when the aggregate of all pending offshore proposals is 9.1 GW.[21]
Electric Transmission. Despite changing virtually all sources of electric generation, and increasing the maximum electric generation the transmission system must handle by more than 500% from 977 GW to 5,271 GW,[22] the Jacobson Group assumes negligible incremental transmission system costs.
The Clack Group pointed out that the National Renewable Energy Laboratory estimated that a 90% renewable electric supply (just electricity not all other energy sources) would require doubling existing long-distance transmission capacity. That was being polite.
The Jacobson Group simply ignored the staggering cost and staggering siting issues involved with a 500%+ increase in transmission system capability.[23]
Electric Distribution. In its critique, the Clack Group left out a huge problem in the Jacobson Group modeling: the electric distribution system. The Jacobson Group’s assumptions of net injections from 652 GW of rooftop solar (more than 100 times what currently exists) — and increased electric demand from eliminating retail natural gas, propane and oil use, and from making all cars electric — would require a massive expansion of the distribution system at a staggering cost.[24] How much did the Jacobson Group allow for that? Zero.
System Modeling. Frequency regulation and operating reserves are ignored by the Jacobson Group. Congestion is avoided by assuming unlimited transmission capability. The Clack Group laid out the problems with all this, and the Jacobson Group simply ignored it.
Cost of Capital/Discount Rate. Saving the best for last because so much money is involved. The Jacobson Group forecasts a cost per kilowatt-hour of its WWS scenario in 2050 based on a “discount rate” of 3%. The Clack Group rightly points out that the true cost of capital is more than twice that.
The Jacobson Group replies that the 3% “is a well-referenced social discount rate for a social cost analysis of an intergenerational project.” Whatever that may mean, it is irrelevant.[25]
Electric utility customers — which we’ll all be for almost all the energy we use — will pay the weighted average cost of capital of those utilities, which right now is about 7.4% plus an income-tax allowance.[26]
Because virtually all WWS resource costs are capital costs, this element by itself means that the overall cost of the Jacobson Group vision will be 200 to 300% more than it claims (and before correcting for everything else discussed earlier).
Bottom line, the Jacobson Group’s analysis is deeply flawed. It would be a terrible mistake to base public policy on any of its claims.
Steve Huntoon is a former president of the Energy Bar Association, with 30 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
On the subject of stoves, I know a lot of cooks who will give up gas cooking when their frying pan is pried from their cold dead fingers. Don’t get them started. ↑
Oh, and in the media making ad hominem attacks on Clack Group contributors such as having “conflicts of interests” to favor other energy resources. These attacks on distinguished academics and scientists are utterly without merit. ↑
But to play out this assumption of periodic nuclear wars ad absurdum, they would cause global cooling offsetting to a greater or lesser extent than global warming. So the Jacobson Group’s own assumption about nuclear wars is inconsistent with the need to battle global warming. What an intellectual mess. ↑
The existing transmission system interconnects 977 GW of resources per NERC’s State of Reliability Report 2016, Table 4.1 (removing Canadian resources). The Energy Information Administration reports a slightly larger 1,064 GW of “Net Summer Capacity” in its Electric Power Outlook, Table 4.3. The Jacobson Group hypothesizes 5,271 GW of off-site resources in its “Supporting Information,” Table S2 (starting with total of 6,390 GW and removing on-site PV and solar thermal resources). All these resources have to be deliverable under its model because “zero electricity shedding occurs.” ↑
A note about the ultimate cost to customers: Regulated cost-of-service rates provide a utility a regulated return based on depreciated original cost of the specific facilities, and a depreciation expense based on that original cost. An essentially new and vastly larger transmission system would entail a utility return on the undepreciated full cost of the new system, and a depreciation expense based on the full cost. Modeling this transmission system cost, along with the distribution system cost discussed below, is beyond the capability of this writer. But the cost would be staggering. ↑
California utilities already claim to need billions of dollars for new distribution facilities in order to handle a relatively small amount of rooftop solar. ↑
Irrelevant, as in “The Treasure of the Sierra Madre” when Tim Holt says, “Not so far as the crow flies,” and Humphrey Bogart replies, “But we ain’t crows.” ↑
AUSTIN, Texas — ERCOT’s energy-only market may not be broken, but stakeholders will discuss some fine-tuning at a Public Utility Commission workshop this week.
Market participants have complained about ERCOT’s use of reliability unit commitments, reliability-must-run contracts and other out-of-market actions. The Independent Market Monitor’s most recent State of the Market report made several recommendations on improving price formation. Texas regulators frequently discuss the need for real-time market co-optimization.
And now comes an ERCOT market review by a pair of industry experts on competitive market design, William Hogan and Susan Pope. Hogan, professor of global energy policy at Harvard University’s John F. Kennedy School of Government, is credited with pioneering the design of modern energy-only markets. Pope, the managing director of FTI Consulting, is an expert on economics and price formation in electricity markets.
Their report, “Priorities for the Evolution of an Energy-Only Market in ERCOT,” was commissioned by Calpine and NRG Energy “to inform important policy decisions … to ensure the sustainability of the ERCOT competitive market” and filed with the commission in May.
On Thursday, Hogan and Pope will present their recommendations during a workshop hosted by PUC staff. They will be joined by Potomac Economics President David Patton, whose firm provides market monitoring services for ERCOT, ISO-NE, MISO and NYISO. All three will participate in a Q&A session with staff, commissioners and other interested parties, while ERCOT staff and the Monitor will discuss progress on the commission’s market co-optimization and price-formation dockets (41837 and 47199).
“Our energy-only market is doing pretty well,” PUCT Commissioner Ken Anderson said during the commission’s most recent open meeting in July. “There are issues that need to be improved or corrected. There are always tweaks.
“I’d like ERCOT and the IMM to be able to comment on the cost estimate and time implementation,” Anderson said. “[The IMM has] been pushing real-time co-optimization in the time I’ve been here. I’ve been concerned about the price estimate and the time it would take to implement.”
ERCOT’s preliminary estimate is that it will take at least $40 million and up to five years to implement co-optimization. Staff has also reported to the PUC the numerous actions it has already taken or will to address price formation.
Anderson has called Hogan and Pope’s report a “very interesting read” and “largely complimentary” to the ERCOT market.
“It does point out the challenges resulting from natural gas [generation] and the dramatic expansion of intermittent renewable resources,” Anderson said. “At the heart of the report is a recognition that our market is premised foundationally on proper scarcity pricing.”
The report calls ERCOT’s commitment to price formation as the “single most important principle to get right in the energy-only market structure.”
“However,” Hogan and Pope write, “the existence and emergence of numerous factors that distort price formation” threaten the ERCOT competitive market “if left unaddressed.”
Hogan and Pope’s review was primarily meant to assess ERCOT’s operating reserve demand curve (ORDC), a PUC-ordered price adder designed to reflect the value of reserves. They concluded that while the ORDC has operated “within the context of its basic design,” it has not been “severely tested,” and scarcity price formation is being “adversely influenced by factors not contemplated by the ORDC.”
Anderson has pointed to an August 2015 event, when “the ORDC adder did not seem to reflect appropriately” a reduction in physical responsive capacity (PRC) — online generation able to quickly respond to system disturbance. He questioned whether the inputs used to calculate the loss-of-load probability should be re-evaluated. (See ERCOT: No Consensus on Operating Reserve Changes.)
During that event, ERCOT operators deployed non-spinning reserves as PRC dropped to 2,371 MW. However, real-time online reserve capacity was 3,629 MW, and wholesale prices reflected that availability.
Hogan and Pope also say other improvements can be made to ERCOT’s market “to better maintain private market response to energy prices as the driver of resource investment, maintenance expenditure and retirement decisions.”
The energy-only market was supposed to drive investment in generation, but the availability of cheap natural gas and renewable resources has made new coal and nuclear plants uneconomic.
“The stress of these forces has exposed areas where there is a need for adjustments to pricing rules and policies within ERCOT,” Hogan and Pope write.
Their report focuses on three recommendations:
Improving the ORDC calculation to address “the reliability impacts of changes in the generation supply mix and the price impacts of reliability deployments,” and considering the use of the marginal cost of transmission losses in dispatch and pricing.
Changes to mitigated offer prices and pricing of transmission constraints to properly set prices when using RUCs or other reliability actions to relieve transmission constraints. Regionwide and local ORDCs should be included in co‐optimized energy and reserves dispatch.
Considering alternatives to socialized transmission planning, “which, by building new transmission in advance of scarcity developing, fails to provide the opportunity for markets to respond.”
Luminant, the largest generator in the state, opposes the use of marginal losses, saying pricing and dispatch based on marginal losses is inconsistent with transmission-cost policies established by Senate Bill 7, Texas’ 1999 deregulation legislation. Amanda Frazier, the company’s representative to ERCOT’s Technical Advisory Committee, said using the marginal cost of transmission losses could result “in a significant disruption to the market by redistributing revenues from generators in the West and North to generators in Houston.”
Luminant’s opposition is just emblematic of the shareholder discussions taking place within ERCOT.
“Stakeholders have been addressing this, I think, a little too slowly,” Anderson said. “I think we’re probably going to need to pick this up to get the ball moving a little faster.”
FOLSOM, Calif. — CAISO is refining market rule changes to more accurately reflect suppliers’ costs of producing and dispatching electricity while also increasing their bidding flexibility.
Stakeholders attending an Aug. 3 workshop learned more about recent proposed changes to bidding rules in the ISO’s Commitment Cost and Default Energy Bid Enhancements (CCDEBE) initiative. Energy suppliers say that even with improvements over the past decade, they don’t have the bidding flexibility they need to reflect all costs under all conditions.
Based on feedback from market participants, CAISO has acknowledged that its current bidding rules need more flexibility and do not always reflect certain costs, price volatility and “business needs.” The rule changes are also designed to incentivize flexible resources that help manage renewable generation when fuel supplies are tight and reduce the risk of not recovering costs for gas and non-gas resource operators.
CAISO is the only organized wholesale electricity market in the U.S. that does not currently support market-based commitment cost bids subject to mitigation, said Cathleen Colbert, senior market design and policy developer at the ISO.
“We wanted to put this out, to get the conversation started and to get feedback,” she said at the workshop, where she presented details of the proposal.
Market rules must allow suppliers to submit economic prices based on costs and risk while protecting themselves from structural issues in the market, the ISO said. Mitigated prices must reasonably reflect suppliers’ expectations of their costs.
CAISO mitigates market-based commitment costs using the “three pivotal supplier” test, which checks for market power by measuring the degree to which a given market relies on just three suppliers — rather than drawing on excess generation from other suppliers — to meet demand. Commitment costs refer to the portion of the supply offer that involves start-up, transition and maintaining minimum load requirements. Suppliers can submit either market-based energy offers or cost-based commitment cost offers. Cost-based offers are subject to a cap that provides only limited flexibility, CAISO said, while market-based energy offers have a $1,000/MWh cap and are mitigated when uncompetitive conditions are found.
The CCDEBE program is one of a series of ongoing market updates CAISO is working on to deal with changing conditions on the grid and public policy goals. The ISO plans to end certain temporary measures in a separate proceeding on Aliso Canyon gas-electric coordination when the CCDEBE procedures are implemented. (See CAISO Board Approves Aliso Canyon Rules Package.)
The ISO is additionally working to comply with FERC Order 831, which requires that supplier costs are reflected when energy bids rise above $1,000/MWh. (See New FERC Rule Will Double RTO Offer Caps.) The federal rule was put in place last November after wholesale power prices spiked during the winter storms of 2013-2014 and generators said they could not recover their costs.
The system operator posted its revised CCDEBE proposal on Aug. 2, with comments due Aug. 7. The package is due to go the Western Energy Imbalance Market (EIM) Governing Body for an advisory vote on Oct. 10 and to the CAISO Board of Governors for approval on Nov. 1.
“People are very eager for us to get this in place a quick as we can in 2018,” CAISO Market Design Manager Brad Cooper said. “Our timeline is very tight.”
Duke Energy executives used Thursday’s quarterly earnings call to outline a vision for expanding its solar generation assets through recently enacted legislation in North Carolina.
The nation’s second-largest utility reported earnings of $686 million ($0.98/share) in the second quarter on revenue of almost $5.6 billion, a jump from $509 million ($0.74/share) on revenue of $5.2 billion a year earlier.
Adjusted diluted earnings for the quarter were $1.01/share, compared with $1.07/share a year ago.
Duke spent nearly a year fighting for the “Competitive Energy Solutions for North Carolina” plan, which was signed into law by Gov. Roy Cooper (D) on July 27 (House Bill 589). The law establishes competitive bidding for most utility-scale solar projects in the state and allows for utilities to use the state’s fuel cost rates to recover cost for facilities contracted under the Public Utility Regulatory Policies Act. It also reduces mandatory PURPA contracts from 15 years to 10 and places an 18-month moratorium on wind development in the state.
Pathway for Solar
Good | Duke Energy
Duke Chairman and CEO Lynn Good praised the legislation for providing the company a pathway to developing almost 900 MW of solar generation and acquiring more. The law includes a commitment from Duke to seek 2,660 MW of new renewable energy by mid-2021. The company is permitted to compete for 30% of that goal and may buy other approved projects to expand its ownership beyond the 30% cap. Without the legislation, Duke would have little control over the projects’ development but would be required by PURPA to purchase the power.
“The law also allows for the recovery of costs associated with these projects through a new rider to be established by the [North Carolina Utilities] Commission. The competitive bidding process will ensure that new renewables are brought on to the system at market-based rates, delivering nearly $1 billion in savings for our customers over the next decade,” Good said. “In our five-year plan, we have something like $400 million of capital directed towards that type of investment in the Carolinas. So, we do have more investment opportunities than we imagined.”
Additionally, company officials argued that proposed rate increases for coal ash disposal will ultimately benefit customers. The company has been dealing for years with issues regarding leakage from ponds used to store residual ash at its coal-fired generators. It has set aside $500 million for resolving the disposal and contamination issues and has asked for another $195 million from ratepayers in cases filed with the NCUC in June and July.
If approved, the requests would include recovery for a wastewater treatment facility at the Mayo plant in Roxboro, N.C., and an estimate of ongoing costs for closing the ponds.
Pipe at Dan River Ash Basin | Duke Energy
“This approach would allow us to recover our estimated costs as incurred, reducing our financing costs and ultimately benefiting our retail customers,” Duke CFO Steve Young said. “If approved, this will build upon the recent third quarter, allowing both [the Duke Energy Carolinas and Duke Energy Progress subsidiaries] to recover costs for coal ash remediation from wholesale customers. We believe this was a prudent approach to managing these expenses and maintaining competitive rates for our customers.”
Good also called the transition to electric vehicles “positive” but wasn’t overly enthusiastic.
“I think it will grow over time. I don’t see it as a step change though in load growth because of all the other factors impacting load, including energy efficiency and other items,” she said.
Misgivings on Wind Ban
Duke Energy Center in Charlotte, NC | Duke Energy
In signing HB 589, Cooper criticized the last-minute addition of an 18-month bar on wind development, issuing an executive order to mitigate the effects of the moratorium.
Cooper said he signed the bill because of its importance to the state’s “already booming” solar industry. “I strongly oppose the ugly, last-minute, politically motivated wind moratorium,” he said. “However, this fragile and hard-fought solar deal will be lost if I veto this legislation and that veto is sustained.”
Supporters of the moratorium, which bars approval of new wind farms before the end of 2018, said it was necessary to allow the legislature time to study the impact of wind turbines on the state’s military bases.
Cooper’s executive order directs the state Department of Environmental Quality “to continue recruiting wind energy investments and to move forward with all of the behind-the-scenes work involved with bringing wind energy projects online, including reviewing permits and conducting pre-application review for prospective sites.”
“I want wind energy facilities to come online quickly when this moratorium expires so our economy and our environment can continue to benefit,” Cooper said.
Recommendations made by NERC and FERC in a June report on restoring power after the loss of normal communications are guidelines and not likely to become binding, a NERC official said last week.
ReliabilityFirst Corp. Chair John Idzior, one of several experts who prepared the joint FERC-NERC study and report, told the MISO Reliability Subcommittee that utilities are too reliant on supervisory control and data acquisition (SCADA) and energy management systems (EMS) when restoring the bulk power system from a total blackout. (See NERC: Despite Solid 2016, Grid Threats Remain.)
The joint report recommends that entities take five measures to restore power absent SCADA and EMS, which include:
Improving backup communication measures;
Planning for extra control room personnel on hand during a restoration without SCADA or EMS;
Reviewing backup power resource provisions beyond normal battery backups;
Using other power system analysis tools; and
Training personnel for situations where SCADA and EMS are unavailable.
Idzior said that the recommendations will not be enforced and will likely not become future NERC reliability requirements.
“It’s currently guidance for entities to use as they see fit. There is no follow-up or tracking as a result of these recommendations,” Idzior told MISO stakeholders at an Aug. 3 Reliability Subcommittee meeting. “This is more an above-and-beyond. I don’t see a push for this being included in reliability standards.”
Hwikwon Ham of the Minnesota Public Utilities Commission asked if any entity could enforce the recommendations. RTOs could incorporate the recommendations into their own restoration planning protocols, Idzior responded.
Idzior said the report’s findings will be presented to NERC’s Operating Committee at future meetings, but the entities that participated in the study will remain confidential.
MISO: Not Enough Solar to Add More Reserves
MISO staff expect the RTO will remain largely unaffected by a possible NERC industry recommendation to procure more operating reserves to cover the widespread loss of solar resources during faults on the power system.
The possible NERC recommendation stems from an August 2016 event, when 1,200 MW of Southern California solar generation was lost after the Blue Cut wildfire erroneously tripped inverters. (See CAISO Boosts Reserves After August Event Report.) RTOs have until Aug. 31 to respond to NERC’s request for solar inverter data and reserve information.
Steve Swan, MISO senior real-time operations engineer, said MISO will solicit data from the three solar farms representing about 170 MW capacity in the RTO’s footprint.
“MISO will be answering for the MISO balancing authority. We’re drafting the answer, and it’s basically going to say yes and no,” Swan said, referring to the fact that the RTO does cover the loss of solar through reserves, but only incidentally because of the relatively small amount of solar participating in the market.
“Eventually, we’ll get over 1,700 MW of solar, but that’s a ways down the road,” Swan said.
MISO is more interested in reviewing the responses from markets in the Western U.S., where solar participation is more prevalent, he said. “There will be some good information coming out of this, but right now, it’s not an issue to MISO.”
Dispatch Instruction Pilot Almost Ready
MISO is “very close” to implementing a pilot program that seeks to encourage generating units to more closely follow dispatch instructions, Swan said.
Under the program — which was conceived by MISO’s Independent Market Monitor, the RTO will send real-time alerts to generators that do not follow dispatch, followed by direct contact from MISO operators notifying unit operators of their non-responsiveness. Before rolling out the pilot, MISO staff will work with the Monitor to eliminate the chance for false positives, which could occur when the RTO binds a transmission constraint, Swan said.
Information collected from each notice will be conveyed to the Monitor to either confirm the lagging response or report system conditions that prevented efficient dispatch.
“The idea is we’ll be sending information back to the IMM in every instance,” Swan said.
Reliability Subcommittee Chair Tony Jankowski asked for MISO to provide a presentation on its current dispatch requirements at the next Steering Committee meeting in October. He also asked for an update on the RTO’s effort to tighten its tolerance bands on generators’ uninstructed deviations from dispatch orders. MISO in May said the project was in the software development phase after several months of delay. The Monitor has been recommending the project for more than five years. (See Monitor Again Criticizes MISO’s Uninstructed Deviation Rules.)
Northern Indiana Public Service Co.’s Bill SeDoris said his company is concerned about the move to tighten dispatch tolerance bands. The new standard is set to go live next spring, and generation owners need to know if the move will affect headroom, he added.
Swan said he would return to the RSC with updates.
MISO and PJM on Aug. 1 filed changes to their joint operating agreement (JOA) to better manage the RTOs’ pseudo-tied resources, MISO’s Kim Sperry said.
The filing (ER17-2220) aims to improve the “administration and coordination of pseudo-ties between MISO and PJM by incorporating into the JOA standard definitions, rules and responsibilities between the two RTOs,” MISO said. PJM submitted a simultaneous filing to adopt identical changes in its version of the JOA.
The standard rule set makes clear that pseudo-ties must obtain station service according to native balancing authority rules and follow the modeling rules of both the native and attaining balancing authority areas. The rules dictate that only pseudo-tied units — and not the RTOs — are responsible for compensating an attaining balancing authority for failure to deliver energy. Pseudo-tied resources also cannot be directed to serve load in the native balancing authority when the attaining balancing authority requires the unit’s output — unless they are needed to avoid exceeding NERC operating limits in the native balancing authority. (See MISO, PJM Float Pseudo-Tie Coordination Plan.)
Jankowski asked if the filing marked a first in a series of filings to improve MISO and PJM pseudo-tie coordination.
Sperry said that while the RTOs will continue working together into the fall on a separate filing to address the double-counting of pseudo-tie congestion, MISO does not envision another joint filing to amend the RTOs’ administration of pseudo-ties.
PPL is maintaining a flat demand outlook for its U.S. service territories through 2020, company executives said during Thursday’s quarterly earnings call.
The utility, which operates in Pennsylvania, Kentucky and the U.K., said it is not forecasting load growth in the U.S. through the end of the decade. Its previous business plan assumed 0.5 to 1% annual load growth.
Chairman and CEO Bill Spence said the company’s Pennsylvania utility may ask regulators for a rate true-up based on volume. He said there was no “near-term concern” for its Kentucky operations.
Spence | PPL
“I think the best tool for us to deal with demand, which is flat, is our forward rate years,” added Victor Staffieri, CEO of PPL’s LG&E and KU. “So, we take that into account every time we file [a rate case]. You all know we’ve been filing every two years and so I would expect that would be the best way for us to capture any changes in the … demand.”
The company posted a profit of $292 million ($0.43/share) in the second quarter, compared with $483 million ($0.71/share) a year ago. The decline was primarily driven by lower foreign currency exchange rates, company executives said.
Earnings from ongoing operations were $356 million ($0.52/share), compared with $380 million ($0.56/share) a year ago.
PPL Pole Truck | PPL
The company reduced its expected annual earnings from its regulated Kentucky utilities by 2 cents/share, attributing the drop to lower electricity sales because of mild weather. For the year, which included Kentucky’s warmest February on record, the company said weather in the U.S. has negatively impacted its results by about 3 cents/share.
However, the company remains confident in its 2017 earnings forecast of $2.05 to $2.25/share, a 5 to 6% compound annual growth in earnings per share and a 4% growth in dividends through 2020.
The British pound, which fell from about $1.48 to as low as $1.20 following the U.K.’s vote in June 2016 to leave the European Union, has since rebounded to about $1.30. The company said it can reach the low end of its projected EPS even if the pound hits parity with the dollar.
British pound to U.S. dollar exchange rate | XE
“We’re executing very well on our low-risk business plans,” Spence said.
[Editor’s note: Quotes from conference call courtesy of Seeking Alpha.]
