NCAC May 2019 Newsletter Now Available
NCAC USAEE Newsletter – May 2019
June 21 NCAC Luncheon - The Energy Workforce in Transition
The June 21 NCAC luncheon, “The Energy Workforce in Transition” will feature Joel Yudken, economist and technology policy analyst. Yudken is principal and founder of High Road Strategies LLC. His research is focused on manufacturing, energy and workforce issues. His clients have included not-for-profit policy and environmental organizations, business associations, labor organizations, universities, and think tanks. His most recent publication is A Federal Policy Agenda for Revitalizing America’s Manufacturing Communities.
NCAC President Travels to Greece for Energy Economics Conference
By Michael Ratner
In early May, I got to travel to Athens, Greece to participate in the Hellenic Association for Energy Economics’ (HAEE) conference, Energy Transition: SE Europe and Beyond. I was invited to participate by Kostas Andriosopoulos, Chairman of HAEE, and Vice President for Publications for IAEE. During my time there I learned a lot and met many smart people, including Christophe Bonnery, President of the IAEE.
The three-day conference covered many topics: geopolitics of the energy transition, LNG bunkering, challenges and innovations of a green energy transition, and energy privatization, among other issues. I participated in a panel discussion on the Geopolitics of Energy and Energy Security for Europe. This is a topic I have written on in my capacity at Congressional Research Service and discussed in meetings and conferences here in Washington. The opportunity to exchange ideas and views with Europeans on this topic was fantastic. I encourage everyone in our membership to attend an IAEE or USAEE event if possible. Going to these events really shows the breadth and depth of the greater international association.
Michael Ratner is an energy policy specialist in the Congressional Research Service. He is the president of NCAC.
Two Guest Speakers Available for Travel to USAEE Chapters
By Natalie Kempkey
If you belong to a chapter of the US Association of Energy Economists (USAEE) you should know about the opportunity to have one of the USAEE Distinguished Lecturers come speak at an event for your chapter.
This year, the two Distinguished Lecturers are Guy F. Caruso and Russell Gold. If your chapter is interested in hosting a presentation by either of these speakers, please contact USAEE VP of Membership and Chapter Liaison Natalie Kempkey.
Guy F. Caruso is a senior adviser in the Energy and National Security Program at CSIS and was the 2018 USAEE President. Prior to joining CSIS, he served as administrator of the U.S. Energy Information Administration (EIA) from July 2002 to September 2008. EIA is the statistical agency within the U.S. Department of Energy (DOE) that provides independent data, forecasts, and analyses regarding energy. Before leading EIA, Caruso had acquired over 40 years of energy experience, with particular emphasis on topics relating to energy markets, policy, and security. He first joined DOE as a senior energy economist in the Office of International Affairs and soon became director of the Office of Market Analysis. He has also held a variety of other senior leadership positions at DOE.
Russell Gold is the senior energy reporter for The Wall Street Journal and is based in Texas. He is responsible for covering all facets of global energy with a particular focus on the U.S. energy boom, power generation and the global energy transition. His writings appear regularly in the print and online editions of The Wall Street Journal.
Natalie Kempkey is an economist at the U.S. Energy Information Administration (EIA).
German LNG Prospects
By Henrik Vorloeper
In 2018, the German government supported the construction of at least one liquefied natural gas (LNG) regasification terminal. The construction of Germany’s first LNG terminal represents a significant shift in Berlin’s gas import strategy; so far, the country receives all its gas imports via pipeline. This article will address why Germany’s policy of moving towards LNG is so important for the global gas market and what Germany’s plans are for future LNG projects.
A major consumer enters the market
German LNG projects could create between 8 and 22+ billion cubic meters (bcm) LNG regasification capacity per year. This is not much, compared to Germany’s pipeline import capacity and the EU’s total LNG import capacity of 227 bcm/year. Germany, however, is the EU’s largest consumer and importer of natural gas and has become an important continental gas hub. The country’s commitment to LNG creates a huge opportunity for international LNG suppliers.
Most of the LNG will come from the US
The current investor relationship and off-take contracts for the German terminals confirm that US LNG producers are keen to supply Germany with LNG. The terminal operator will still participate in the global LNG market and will still be supplied by non-U.S. suppliers. Qatar, the world’s largest LNG exporter, has shown interest in ordering LNG off-take capacities at German terminals. That is especially important.
Understanding the four German LNG terminals
Four LNG terminals are planned in Germany. All terminals are different in their location, investor constellation, capacity, cost, timeframe and potential off-take contracts. Here is what we know about them and how viable their prospects are.
LNG Wilhelmshaven. The LNG terminal is a Floating Storage Regasification Unit (FSRU) located at the Jade-Weser-Port, near Wilhelmshaven. Uniper, a German energy company, Mitsui, a Japanese shipping company, and Titan LNG, a Dutch gas company, are the major shareholders. The FSRU has a capacity of 10 bcm/year and will cost $200-400 million. The terminal is planned to be operating by the end of 2022. The US company ExxonMobil and a Qatari LNG producer have already ordered substantial off-take capacities.
German LNG GmbH. This on-shore LNG terminal is located at Brunsbüttel, near Hamburg. German LNG GmbH is owned by a joint venture consisting of two Dutch companies, Gasunie and Vopak LNG, as well as the German company Marquard & Bahl. The terminal will have a capacity of 8 bcm/year and will cost $530 million. The terminal will be operational by 2022. The German energy company RWE has ordered a substantial off-take capacity and will supply LNG from the US export terminal at Corpus Christi, Texas operated by Cheniere Energy. The Swiss company Axpo is the second company that has ordered off-take capacity and will likely supply LNG from the Canadian terminal, “Goldboro”.
LNG Stade GmbH. This on-shore LNG terminal is located at Stade, near Hamburg. The main investors are the Australian investment group, Macquarie Group Ltd. and the Chinese construction company, China Harbor Engineering. The terminal will have a capacity of 4 bcm/year with upgrade potential to 8 bcm and will cost $567 million. Plans are to have it operating by 2023. There is no evidence of pre-booked capacity, but the head of the project seeks LNG supplies from the US.
Rostock LNG GmbH. The on-shore LNG terminal is located at the harbor of Rostock, on the Baltic Sea. The joint venture consists of the Russian LNG supplier Novatek and the Belgian gas infrastructure company Fluxys. The capacity of the terminal will be 300,000 cu/year, will cost $100 million and be operable by 2022. As the terminal will not have regasification capacities, LNG will be provided as shipping fuel or for truck and train transportation. Novatek will most likely be the only LNG supplier.
All four terminals are excellent prospects, but LNG Wilhelmshaven and German LNG at Brunsbüttel appear to be the most likely to be completed. Both projects also have a convenient geographical location and a stable ownership. While the German government supports construction of an LNG terminal with financial incentives, it has not ruled out financial support for another terminal.
Henrik Vorloeper is a co-founder and analyst at Eurasianventures.com
Petroleum Engineering Enrollment in Decline: Should Industry Worry?
By Paul Ruiz
Thousands of students will graduate from American colleges and universities this month. Amid the usual pomp and circumstance accompanying the festivities, this year’s graduates have reason to be especially enthusiastic. Earlier this month, the Labor Department’s March jobs report said monthly unemployment was just 3.8 percent of the labor force.
For the nation’s newly minted petroleum engineers, the opportunities seem boundless. Yet, strikingly, there are fewer of them entering the workforce than at any time in the last four years. According to data from Texas Tech University, this year the nation’s 22 petroleum engineering programs enrolled nearly 2,000 seniors—roughly 1,800 fewer than in 2016. In total, more than 4,500 U.S. undergraduates were pursuing petroleum engineering degrees in 2019, down 60 percent from three years ago.
Petroleum engineering enrollments track the volatility of crude oil prices by about two years, the Texas Tech data shows (freshmen who start their course of study when prices are high may not complete that course when prices fall). July 2014 prices peaked at approximately $98 per barrel; one year later, as prices started to decline, nationwide enrollment reached a 12,000-student high and remained at that level through the 2016 academic year.
“Students are even more aware of what oil prices are and how they might impact their jobs,” Dr. Lloyd Heinze, a professor of petroleum engineering at Texas Tech University, told me. “We talk about it with our students when they start their sophomore and junior years. Oil prices have rolled up and down every seven years or so; it’s part of our industry.”
This means that U.S. oil companies are only now feeling the recruiting pinch of OPEC’s price war with American shale producers. From 2014 to 2016, OPEC and its de facto leader Saudi Arabia refused to cut global production, causing oil prices to crash. Thirty years ago, petroleum engineering enrollment encountered a similarly steep decline when an oil glut caused a rapid price decline. The last time there were so few undergraduates pursuing Bachelor of Science degrees in petroleum engineering was 1986, when prices were approximately $31 per barrel ($2015).
“The one thing that’s different about petroleum engineering over other standard engineering programs is that we are dealing with a raw material. Other engineering programs build something from raw materials. The economics of our business is very different,” Dr. Heinze explains. “Any industry that uses raw materials is significantly influenced in price by governments.”
In a way, oil is no different than other commodities: prices are largely a function of supply and demand. However, unlike other commodities or primary produced products, petroleum powers more than 40 percent of all energy consumed, and 92 percent of the energy used in transportation. Supply shocks caused by events like civil conflict or natural disasters can create distortions that ripple throughout the economy.
In the short term, a shrinking pool of graduates could make it tougher for the industry to attract new talent. Petroleum engineering is already a small field in total enrollment terms—so small, in fact, that statistical analyses sometimes lump it in with the broader discipline of mechanical engineering. Still, the medium- and longer-term outlook is positive; BLS notes the total number of petroleum engineering jobs are expected to rise by more than 15 percent nationwide between 2016 and 2026.
As petroleum engineers age, the industry will need to replace a retiring cohort of Baby Boomers. To manage this employment “crew-shift,” oil majors are engaged in a wide-ranging public relations effort to improve the attractiveness of the discipline. Specifically, they want to appeal to Millennials and Generation Z through marketing and advertising that emphasizes environmental stewardship.
The effectiveness of oil’s marketing and advertising effort is not yet known, but the industry will have a better sense next September when an incoming class of freshmen join Dr. Heinze’s classroom. Whether enrollment figures jump or decline will signal either an expected uptick in registrations due to the oil price recovery, or, potentially, a worrisome shortage of talent.
Paul Ruiz is a policy analyst at SAFE (Securing America's Future Energy). A longer version of this article appeared in The Fuse.
Renewables Generated At Least 10% of Power in Over Half the States in 2018
By Ben Doggett
More than half of the United States generated more than 10% of their electricity from renewable energy sources during 2018, with 2 out of 5 states generating 20% or more of their electricity from renewables, according to the U.S. Energy Information Administration (EIA).
The United States generated a record 17% of its electricity from renewables—hydro, wind, solar, biomass, and geothermal—in 2018, but many states had a larger share than 17% coming from renewables.
EIA’s Electric Power Monthly shows the top ten states for renewable electricity are located west of the Mississippi River and in New England. Those states and their percentage of renewable power are Vermont (99.7%), Idaho (81.5%), Washington (77.7%), Maine (74.7%), Oregon (70.5%), South Dakota (70.1%), Montana (47.3%), California (42.7%), Kansas (36.6%), and Iowa (35.7%).
Southern states had some of the biggest growth in renewable electricity generation during 2018, with North Carolina and Alabama’s share of total generation from renewables exceeding 10% for the first time.
EIA data shows that every state generated some of its electricity from renewables at utility-scale sites of 1 megawatt or larger in 2018.
The bottom 5 states for renewable power are Delaware (2.2%), Ohio (2.5%), Mississippi (2.8%), New Jersey (3.1%), and Connecticut (3.2%).
Ben Doggett is a student member of NCAC-USAEE and a junior at Frostburg State University, majoring in Earth Science and Geography.
The Trouble with Carbon Pricing
By Meredith Fowlie
From the Energy Institute at Haas blog, UC Berkeley
We economists have long been enamored with carbon pricing. The concept is simple and sensible. If the economic damages from greenhouse gas emissions can be reflected in market prices, powerful market forces will work for, versus against, the planet. Continue reading
Thanks to everyone who participated in the annual NCAC conference at George Washington University on Wednesday, April 24. The members made it a great success. More than one hundred people attended. Special thanks go to conference chair and NCAC VP David Givens, and to NCAC President Michael Ratner. David managed the entire event and Michael secured our keynote speaker, General David Petraeus. Photos of the event can be found here.
The speaker is Keith Martin, Chief Commercial Officer, Uniper
Uniper is an international energy company active in more than 40 countries that owns and manages power plants throughout Europe and Russia. The company also engages in commodity trading in natural gas, liquefied natural gas, coal, emission certificates, and freight. Uniper employs roughly 12,000 people, and boasted €78 billion in sales in 2018. It is active in the export of US coal and LNG and is planning an LNG floating storage and regasification unit (FSRU) at its site in Wilhelmshaven, Germany.
By Elaine Levin
NCAC members have shown a lively interest in Futures markets. After all, Futures markets are really different from the traditional physical markets that most of us learned about in introductory economics classes. Futures markets offer a unique way to control costs and budgets for energy producers, governments and private companies for whom energy is an important input.
Powerhouse’s principals have frequently offered training to NCAC members in Futures as they relate to energy markets. Attendees have been overwhelmingly satisfied with the experience.
Powerhouse will be offering a new course on Practical Fuel Hedging on May 2nd and 3rd at the Georgetown Inn here in Washington. You’ll learn how to use Futures and Options on Futures in two days of intense and immensely satisfying training focused on practical applications of the Futures contract suite.
The course will cover:
This is a course you won’t want to miss. To register or get more information:
Email firstname.lastname@example.org or call (202) 333-5380
By Rita Beale
In April, Saudi Arabian Oil Company (“Saudi Aramco”) débuted in the international capital markets pricing $12 billion of corporate debt through five tranches of 3- to 30-year dollar-denominated senior unsecured notes carrying coupons of 2.75% to 4.375% to be traded on the London Stock Exchange’s Regulated Market.
The offering was notable in several ways – strong investor confidence of a new emerging market security (investor orders of $85-100 billion), revelation of the world’s most profitable company ($111 billion of net income in 2018 with the sum of Apple plus Google plus Exxon Mobil), normalization of Saudi Aramco’s financial reporting and business practices toward international standards (underway since 2017), and standing as a milestone in Crown Prince Mohammed bin Salman’s plan to diversify the Saudi economy.
Bond issuance appears to be a shrewd way to test acceptance by international investors, following the delay of an Initial Public Offering, now planned for 2021. Debt carries advantages versus equities, given their even tighter transparency requirements, potential investor demands for greater control of the company, and potentially higher cost, particularly if dividends were competitive with other international oil companies.
The notes have investment grade credit ratings of A1/A+, slightly below the levels of Exxon, Shell and Chevron and at similar levels as the sovereign debt of the Kingdom of Saudi Arabia. The risks in the Prospectus underscored the Kingdom’s ownership of the resources, its authority over the 40-year operating leases and fiscal regimes, as well as the Kingdom’s reliance on Shari’ah principles. Fund flow from operations at $26 per barrel in 2018 was noted to be $5 to $12 per barrel lower than Total SA and Shell respectively, largely due to the heavy income taxes, royalties, and dividends paid to the Kingdom.
Financial information in the Prospectus also generated various analyst viewpoints about potential equity price levels should a Saudi Aramco equity issuance ever come to fruition. The size of the debt offering suggests ability to return to global investors for future issuances, given the perception of low overall debt levels.
Rita Beale is Managing Partner of Energy Unlimited LLC. Ms. Beale’s first career was in financial services at marquee New York broker-dealers as a research commodity analyst, advising institutional clients on global markets and futures/options hedging and trading strategies. The author relied on information from reputable news agencies and does not have ownership of any Aramco securities.
by Henry P. Aszklar, Jr.
In his 2003 State of the Union address, President George W. Bush announced the arrival of the hydrogen economy that would unshackle the U.S. economy from fossil fuels and provide a clean, carbon-free energy environment. And then we waited, and waited, and waited. Today hydrogen is starting to fuel an energy transformation in California, with over 6,000 fuel cell electric vehicles on the road and 39 retail hydrogen refueling stations. California is leading the charge toward the goals set out by the 2005 U.S. Energy Policy Act to enable production, delivery, and acceptance by consumers of model year 2020 hydrogen fuel cell electric vehicles. Unfortunately, the rest of the U.S. lags far behind, but as the fifth largest economy in the world, California has the engine to pull the rest of the U.S. into the hydrogen economy.
So why should we be cheering on California? A 2017 report by the Hydrogen Council, co-authored by global consulting firm McKinsey and Company, emphatically states that the technology is proven, and what remains to be done is the scaling up of existing technologies, combined with starting the virtuous cycle of deploying hydrogen technologies across the energy sector with the economic benefits of manufacturing fuel cell electric vehicles - 400 million cars, 15 to 20 million trucks and 5 million buses by 2050. And where will these cars, trucks and buses be manufactured? Hopefully here in the U.S. But China and other countries are giving the U.S. a run for the money. It would be tragic if the manufacturing base for the hydrogen economy ends up going the same way as the solar industry – to China.
Toyota and Hyundai recently broke ground on manufacturing facilities to support the production of 30,000 to 40,000 fuel cell electric vehicles by 2020. Toyota currently sells fuel cell electric vehicles in eleven countries and expects to sell 10,000 per year in Japan by 2020. Today there are 50 hydrogen refueling stations in Germany, and more than 100 in Japan. Toyota has begun selling its fuel cell electric buses and expects to have 100 in operation in Tokyo in time for the 2020 Olympics. A 2018 Global Executive Survey of leading automotive companies by KMPG indicated that most believe fuel cell electric vehicles will serve as the key breakthrough to fully enable electric mobility.
A 2017 report by the U.S. Department of Energy’s National Renewable Energy Laboratory on the current status of fuel cell electric powered buses assessed the technology readiness level range from 7 to 8, with 9 reflecting a mature technology, such as diesel. The report noted that fuel cell stacks are reliable and robust, with most of the problems instead associated with the balance of plant. The report further notes that durability of the fuel cell stack in older buses has surpassed the ultimate target of 25,000 hours without repair or replacement of the fuel cell.
The hydrogen economy has landed on the shores of California. Let’s hope that the U.S. has the foresight and ability to develop the associated manufacturing base within our borders and not let hydrogen technology go the way of solar photovoltaics.
Henry Aszklar is a senior energy advisor working with renewable energy companies, private equity funds, and multinational technology and service providers. He is a member of the U.S. Department of Energy Hydrogen and Fuel Cell Technical Advisory Committee, as well as a board advisor to a community solar company.
By Ben Schlesinger
Now nine months into our carbon net-neutral experiment, the house is still amazing. It’s already generated about as much electricity as it’s consumed, and the remaining three months (mid-April through mid-July) typically have easy weather and sunshine. The info from Choptank Electric Cooperative’s website tells the story so far
– Starting from July 12, 2018, when our 50 solar PV panels went live, our electricity generation in the summer and early fall far outstripped power demand in the house, which was mostly for cooling and construction equipment. Having a highly-insulated shell helped too.
– Then, this pattern reversed during peak winter months, when the low sun angle and even some snow cover made solar less effective. Our 8-well geothermal energy system was seasonally less productive as well, but the house’s 45 SEER ground-source heat pumps still used much less energy than conventional heat pumps while also providing hot water.
– So far in late winter and spring 2019, our solar PV ‘power plant’ is once again out- producing household demand, on average.
But even though the house is indeed net-negative in terms of energy use (produces more than it uses), we wonder if this means we’re also meeting our goal of carbon net-neutrality? I suspect it does mean that, but we’ll need to use quarter-hour PJM fuel use data to prove the point, i.e., see exactly what fuels we’re displacing. On the positive side, we can widen the circle and include carbon avoided by charging electric cars with solar power versus using gasoline cars. We’ll also try managing our 3 Tesla batteries this spring to minimize carbon production, as discussed in last month’s blog – up to now, we’ve held these for emergency power supply in the winter. On the negative side, there’s our prodigious lawn that needs to get cut weekly with conventional smelly equipment – we’re considering an electric mower. We’ve also got propane distributed through the house to gas fireplaces and the cooktop, but these are basically cosmetic uses, a few gallons per month.
Bottom line is we’ve got a zero-energy house, producing more than it consumes over an annual cycle. We’re still gathering info to prove the same point for carbon, and we’ll also be able to assess the basic economics of this experiment, including years to pay-back and internal rate of return of our incremental investment. As always, the devil is in the details! More to follow.
Ben Schlesinger, founding president of Benjamin Schlesinger and Associates (BSA), is a leading independent energy consultant. As the principal independent gas advisor to NYMEX, Dr. Schlesinger helped write the highly successful NYMEX gas futures contract, prepared the analytic justification for Henry Hub before the Commodity Futures Trading Commission (CFTC), and helped design gas swap futures contracts throughout the US and Canada.
By Josh Cohen
While much of the electric vehicle (EV) policy conversation focuses on state legislatures and public utility commissions, local governments have an important role to play too. Cities and counties are where the rubber meets the road, so to speak, and local policies can go a long way towards increasing EV adoption.
In last November’s midterm elections, thousands of new mayors, county executives, councilmembers and commissioners were elected to local office. As these local leaders begin serving their terms, here are eight actionable, concrete steps they can take to accelerate EV adoption in their jurisdiction.
Fleets: Establish targets to replace government fleet vehicles with EVs, starting with widely available light-duty passenger EVs and electric transit buses. Set future targets for medium- and heavy-duty EVs as they become more widely commercially available.
Existing facilities: Install charging stations at government-owned facilities such as public parking garages, office buildings, libraries, schools, parks and other destinations.
Capital projects: Require new government capital projects to include “EV ready” spaces with pre-installed conduit, 208/240-volt 30-amp wiring and two pole 40-amp breakers. Why? It’s measurably less expensive to wire parking spaces during construction than to retrofit them afterwards. Then, once funding becomes available to purchase the charging stations, little or no additional expense will be needed.
Grants: Pursue grant opportunities that offer significant subsidies or rebates for EVs and EV charging stations. Local governments are tax-exempt and don’t benefit from tax credits, but free money always helps. For instance, states and tribal nations can allocate much of their $2.9-billion share of the Volkswagen “dieselgate” settlement towards grants for EV charging stations, electric school and transit buses and freight trucks. These grants are low-hanging fruit for local governments to pursue.
New construction: Enact ordinances and building codes that require EV-ready spaces in new construction. Different jurisdictions take different approaches, but generally they require single-family homes and some portion of parking spaces at multi-family and commercial properties to be EV-ready. Examples are found across the country and include Atlanta, Denver, New York City, San Francisco, and Maryland’s Howard County.
Tax credits: Enact a property tax credit so property owners can receive a one-time credit for the costs of charging station purchase and installation. Tax credits can be capped at different dollar amounts depending on the station type (e.g. Level 2 or DC Fast Charge) and should be broad enough to apply to both purchase and installation costs.
Driver incentives:Offer incentives for EV drivers, for instance by waiving the entry fee at county parks or by allowing EVs to receive an hour of free parking in municipal lots. Driver incentives don’t have to cost the government a lot of money. Small but noticeable incentives can have an outsized impact in making a community more EV-friendly.
Regional planning:Establish a plan for priority charging routes and destinations that is informed by local input and implemented in coordination with neighboring jurisdictions. Local government plans should align where possible with federal and regional routes such as Alternative Fuel Vehicle Corridors and should complement other investments by state agencies, Electrify America and other entities.
By putting these recommendations into action, local leaders will do more than make their communities more EV-friendly; they will also be more competitive when it comes to attracting jobs and businesses for which EV charging is no longer an amenity but an expectation.
Josh Cohen is Director of Policy and Utility Programs at SemaConnect, a leading national provider of smart, networked EV charging solutions. Josh served 12 years in local elected positions, including a term as mayor of Annapolis, Maryland. He can be reached at email@example.com. This article originally appeared in the March/April 2019 issue of Charged EVs magazine.
EV drivers don’t pay the gasoline tax, so pay less for roads.
By Lucas Davis and James Sallee
From the energyathass blog at the Haas School of Business, University of California Berkeley-Blog: Should Electric Vehicle Drivers Pay a Mileage Tax?
Every time we buy a gallon of gasoline, we help pay for roads. 18 cents go to the U.S. Highway Trust Fund. Here in California, 30 cents go to the state’s Road Maintenance and Rehabilitation Program.
EV drivers don’t pay the gasoline tax, so they pay less for roads. Several states are considering imposing a mileage tax on electric vehicle drivers to make up for the lost revenue.
How much lost revenue are we talking about? And does this policy response make sense? In a new Energy Institute working paper, we ask, “Should Electric Vehicle Drivers Pay a Mileage Tax?”
According to our calculations, EVs have reduced U.S. gasoline tax revenues by $250 million annually. Of this, 30% ($75 million) is foregone federal tax, while the other 70% ($175 million) is foregone state and local tax.
For this we assumed that EV drivers would have otherwise been driving 15,000 miles per year in a 28.9 mpg gasoline-powered vehicle. These assumptions follow recent economic research (here and here), though we also report calculations based on, for example, fewer miles driven.
We also take into account the highly uneven pattern of EVs across states. As these maps illustrate, there tend to be more EVs in states with higher-than-average gasoline taxes (correlation 0.46). This correlation increases the gasoline tax revenue impacts by about 20%.
Gasoline taxes include all federal and state taxes including components not explicitly targeted at roads.
This $250 million annually in missing revenue represents less than 1% of total gasoline tax revenue. After all, EVs are less than 1% of the U.S. vehicle stock, so it makes sense the aggregate impact is so far pretty modest. Still, the impact per EV is substantial — $318 annually according to our estimates.
In addition, the missing revenue is highly concentrated in a handful of states. We calculate that for California alone the missing revenue is $90 million annually. California aims to have 1.5 million EVs on the road by 2025, and 5 million EVs on the roads by 2030, 10 times the number today. So, this trickle could soon turn into a flood.
The missing revenue is also highly regressive. We find that two-thirds of the missing revenue comes from households with $100,000+ in annual income. This reflects, as you might have guessed, that EV drivers continue to be disproportionately very high income.
Right about now all the EV drivers are breathing heavily. “Yeah sure, we use the roads, but we create environmental benefits too!”
Yes, according to the latest analysis from Holland, Mansur, Muller, and Yates, EVs do tend to be less damaging than gasoline vehicles. It depends on where you drive, but the U.S. electric sector continues to get cleaner, which reduces the environmental damages from plugging in an EV.
That said, the environmental damages from EVs are not zero. Also, don’t forget, EVs cause traffic congestion and accidents, just like any vehicle. Ian Parry and other economists have argued that these “mileage externalities” are actually larger than the environmental externalities from driving.
With this as a backdrop, several states are now considering implementing a mileage tax. California, Washington, and Illinois have all conducted mileage tax pilots, and Oregon passed legislation allowing 5,000 voluntary motorists to pay a mileage tax of 1.7 cents per mile, in lieu of gasoline taxes.
A mileage tax would likely be more efficient than a gasoline tax for targeting traffic congestion and other mileage externalities. After all, vehicles create traffic congestion regardless of whether they get 10mpg, 50mpg, or 100mpg. Moreover, a mileage tax would help plug the hole in road budgets.
Mileage taxes are not a panacea, however. For example, traffic congestion depends on where and when you drive. Some people drive on crowded freeways at rush hour, while others drive on uncongested roads at 2am. As Severin Borenstein points out, what you would really like to do is tax all externalities using time-varying, location-varying dynamic prices.
So suppose we transition to a mileage tax. Let’s assume, moreover, that at least for the moment, the “tax all externalities” dynamically is off the table. In the paper we develop a model of driving under these circumstances and ask what level of mileage tax makes sense for EVs. This exercise highlights a key tradeoff.
On the one hand, driving an EV does generate externalities, which leads you to want to impose a mileage tax on EVs. On the other hand, gasoline-powered vehicles generate externalities too, and there has been a tendency to underprice these externalities. For example, many economists believe that gasoline in the United States is significantly underpriced.
If the externalities from gasoline-powered vehicles are sufficiently underpriced, then you don’t want to impose a mileage tax on EVs. To the contrary, you may actually want to subsidize drivers to use EVs, just so they won’t drive in gasoline-powered vehicles. One possibility would be to subsidize EV purchases, as is currently done, for example, with state and federal EV credits, while simultaneously imposing a mileage tax on EVs.
But again, none of this is as good as the “tax all externalities” approach. Perhaps the biggest benefit of moving to a mileage tax would be that, in the longer-run, it becomes easier to implement more dynamic pricing. With the gasoline tax this is impossible, but it would be relatively easy, for example, to move from a simple mileage tax to one that varies by location and hour-of-day.
Lucas Davis is the Jeffrey A. Jacobs Distinguished Professor in Business and Technology at the Haas School of Business at the University of California, Berkeley. James M. Sallee is an Assistant Professor in the Department of Agricultural and Resource Economics at UC Berkeley.
The topic for the all-day conference is The Global Quest for Energy Security. The keynote speaker is David Petraeus, Chairman of KKR Global Institute.
General Petraeus is former director of the Central Intelligence Agency and was commanding general of the International Security Assistance Force in Afghanistan, as well as Commander of United States Central Command.
The conference will be held at George Washington University in the Marvin Center Continental Ballroom. A full agenda is posted on the NCAC website. Please register now to reserve your space; we expect the event will sell out.
More than seventy people attended the NCAC Annual Dinner on February 5 to hear Ed Morse, global head of commodities research at Citi, speak about Oil and the Heisenberg Principle: How OPEC+ efforts to assure market stability become a source of market volatility.
Morse served as the Deputy Assistant Secretary of State for Energy Policy in both the Carter and Reagan Administrations; in management at Phillips Petroleum Co.; as co-founder of PFC Energy; and as publisher of Petroleum Intelligence Weekly. He has helped design Yemen's oil pricing policy and assisted in the negotiations of its initial export contracts. He also helped the UN Security Council design the Oil-for-Food Program for Iraq and assisted in negotiations with Baghdad to achieve its agreement. He is a Senior Fellow of both the USAEE and the IEEJ and in 2018 was named by Petroleum Economist in its inaugural “Global Energy Elite” issue as among the ten most prominent individuals in energy banking and finance. Morse’s presentation is available on the NCAC website.
NCAC Is grateful to NCAC Council member Aaron Annable, Counsellor for Energy and the Environment at the Embassy of Canada, for facilitating Canada’s role as co-host.
Click here for the 2019 Photo Library to view more photos from the dinner
By Elaine Levin, Immediate Past President of NCAC and President of Powerhouse, an energy price risk management company
At the NCAC Annual dinner at the Canadian Embassy on February 5, NCAC Immediate Past President Elaine Levin presented the 2019 Mark Lively award for dedicated support and service to Alan Levine. Elaine remarked:
Al is one of NCAC’s founding members. He became the second NCAC president in 1980. His area of expertise is energy futures markets and hedging price risk. He was a consultant to the New York Mercantile Exchange when they formed the first successful energy futures contract, the home heating oil contract that is still traded today.
Al shares his knowledge generously. He has made presentations to NCAC many times over the years, demystifying a part of energy economics and finance that is very important to energy pricing domestically and increasingly internationally. He presented a four-hour workshop on hedging, futures and options at the September 2018 USAEE conference in DC.
When NCAC was founded in 1978, it was designed as a forum where energy professionals could share ideas and discuss important energy issues. One of the express missions of the association was to promote interest in energy economics among college students and young professionals. That support continues today through the NCAC mentor program.
Al embraced this idea throughout his career. In 1982, he became an energy futures broker, helping companies hedge price risk. In 1988, he started a search for an intern. NCAC was offering a scholarship to students interested energy economics. Al volunteered to contact all the local colleges and universities, letting them know about the offer.
Luckily for me, only my university, Marymount, responded to that outreach. So, of course, that is where he went to find his intern. Al and I have worked together ever since. Everyone should be so fortunate to have had such supportive and caring mentor. I’d like to think we are NCAC’s longest running mentoring match!
In 2012, Al, David Thompson and I left Morgan Stanley to start our own risk management company, Powerhouse. Even now, when we interview a candidate for a position or internship, Al’s introduction is always the same, ‘We are in the best industry in the world. I have been in energy most of my career, and what a ride!’ I am happy to present this award to a terrific mentor, my business partner and good friend, Alan Levine.
By Joel S. Yudken, Ph.D., Principal, High Road Strategies, and NCAC Treasurer
Every year, NCAC hosts at least one interesting field trip to sites of important regional energy-related activities. This year, on Thursday, February 21, fourteen of us took a half-day tour of the Washington Gas operations center in Springfield, Virginia.
About eight of us met in downtown DC to take a bus, and the rest drove directly to the center. Washington Gas serves over 1 million customers in the Metro area, supplying natural gas and other energy services to much of Northern Virginia, all of Washington, DC and parts of surrounding Maryland counties.
After a brief orientation, our hosts showed us around the Pipetown facility. It’s a state-of the-art training center, opened in 2009, built to simulate an urban community, with the purpose of providing a realistic training environment for field operators, line supervisors and emergency responders. The trainers can create a wide array of realistic scenarios, including a damaged facility, leak or fire emergency scenarios.
Aside from Washington Gas employees, the facility trains approximately 400 firefighters from local jurisdictions each year. Our group was also briefed on the center’s dispatch operations, which can be called on to respond to as many as 400 incidents each day, such as broken pipes and residential leak reports. We visited the gas control office, where large computer screens track pipeline flows and alerts, including connections to citygates of local distributors across 14,000 miles of pipeline.
Finally, we learned about the company’s Accelerator Replacement Program (ARP) created to replace aging cast iron, steel, and pre-1975 plastic pipelines throughout the system. After the tour, those of us on the bus stopped at a restaurant in Alexandria for lunch to get to know each other better and network, always one of the most enjoyable benefits of these trips.
By Peter E. Paraschos, Director, Energy and Geopolitical Risk, International Technology and Trade Associates, Inc.
Venezuela is a petrostate in abject decline, its society mired in sustained politico-economic crisis, and its once robust oil industry dogged by declining output and U.S. sanctions.
U.S. policy toward Venezuela now openly aims to replace the Maduro regime. On January 23, the Trump Administration recognized Juan Guaido, head of Venezuela’s National Assembly, as the country’s new interim president. On January 28, the administration blocked U.S. companies from conducting financial transactions with state-owned PdVSA, effectively curbing U.S. imports of Venezuelan heavy crude oil.
Incomplete Energy Information Administration data indicates that Venezuela exported about 500,000 barrels of heavy crude oil per day (b/d) to U.S. Gulf Coast refineries in 2018. According to recent reports, U.S. imports of Venezuelan crude declined to a 28-year low of 385,000 b/d in November 2018.
While the recent surge of U.S. and international pressure has yet to produce the desired political result in Caracas, the absence of Venezuelan heavy crude has created a shortage in the U.S. market. Reduced supply is pushing up heavy crude prices, cutting refiner margins on diesel and other middle distillate fuels, and jeopardizing the price competitiveness of U.S. middle distillate exports.
U.S. refinery companies, which process about half the world’s supply of heavy crude, are now seeking alternative supplies. However, this is proving difficult. Canada is cutting production of heavy crude in Alberta due to export pipeline constraints, and Saudi Arabia is cutting exports of heavy crude to support the OPEC+ production restraint agreement of December 2018. This leaves U.S. and Asian refiners competing for scarce heavy crude supplies from relatively smaller suppliers.
Record increases in U.S. oil output are predominantly light in quality and cannot replace heavy crude required by the highly complex U.S. refineries along the Gulf Coast and in the midcontinent region. And the U.S. shale revolution is of no help. Even as the United States races toward net petroleum exporter status, its world class refinery sector will remain dependent on imported heavy crude over the long-term.
By Ben Schlesinger | Benjamin Schlesinger and Associates, LLC (BSA)
Tesla Batteries, late winter solar energy, and more…
Our attempted-carbon-neutral home in St. Michaels, Maryland, is now finished, and we’ve moved into this most beautiful house! Energy bills are incredibly low – just paid our January bill to Choptank Electric Cooperative, totaling $22. And that’s the highest monthly electric bill since July, when the solar PV panels went live. Awesomely low compared to other houses this size in the mid-Atlantic region; we just paid $660 for gas and electricity in a comparably-sized, and well-insulated Bethesda house. As we’ve pointed out before, this amazing savings is owed to highly-insulated walls, 8 geothermal wells, and 50 SunPower PV panels.
On January 9, Tesla delivered our 3 PowerWall batteries, Manny, Moe and Jack, and installed them on the garage wall. See the photo of Manny, Moe and Jack….and Joyce’s Model 3 Tesla. Given the severe winter weather that’s ensued, we’ve kept the batteries topped off, relying on them mainly for emergency back-up. Sure enough, they powered the house seamlessly during one brief outage in February.
Our batteries charge preferentially on solar power, so it’s green storage, but it’s also a green challenge. The question is how best to use them to maximize carbon avoidance. We’ll start next month by experimenting with different modes to time-shift loads. Initially, we’ll use them to abate the steep evening ramp-ups in energy demand that follow sunny days, much as major Li-Ion battery installations are used in Southern California.
The idea is that PJM uses its most polluting generators to meet this need, so we target the batteries to avoid that. Another pattern will be to use them to meet our mid-evening demand using stored solar power. Yet another will be to preferentially charge the EVs with solar power. Only with a more complete understanding of PJM’s marginal fuel at each 15-minute interval will we be able to maximize the effectiveness of our batteries in avoiding carbon emissions.
Meanwhile, the “power plant on the roof,” combined with a low-energy-demand house, is amazing. As the days grew longer, we’ve found that by late February we’re now steadily putting more energy into the grid than withdrawing on sunny days. Snow cover has been less of a problem than we thought – despite the panels’ nearly zero-degree angle (flat) mounting, it’s been taking only a day for the snow to melt away and for solar energy production to be restored.
By Jim McDonnell and Evelyn Teel, Avalon Energy Services, LLC
Compared to the rest of the United States, electricity prices in New England are high. Nothing surprising there. So, just how expensive are they? Well, it depends. And, the surprising part is which utility, in one comparison, has the lowest rates.
First, some background.
Eversource Energy is an investor-owned utility headquartered in Hartford, CT and Boston, MA. Eversource is the rebranded name of Northeast Utilities, after its merger with NSTAR in 2012. Through its three electric distribution companies, Eversource operates New England’s largest energy delivery system and has 3.2 million electricity customers.
United Illuminating Company, a subsidiary of Avangrid, Inc., is an electric distribution company serving 325,000 customers in Connecticut. Avangrid, through its four electric utility subsidiaries, serves about 2.2 million customers in New England and New York State.
Wallingford, Connecticut is a town of 45,000 people located between Hartford and New Haven. Despite its size, the town operates its own municipal electric utility, known as the Wallingford Electric Division (WED).
Despite operating in the same geographic area, the three utilities vary dramatically in terms of their rates and the costs to their consumers.
A recent bill insert sent out by WED provided the following rate comparison. These are residential rates for an account that averages 750 kWh per month.
Utilities have different energy procurement strategies and different infrastructure issues, which contribute to their varied pricing. Furthermore, municipal electric utilities are exempt from certain mandates that affect the pricing of larger utilities. However, the 6.2 and 11.5 cents per kWh differences between a small municipal utility and the two large investor-owned utilities are dramatic.
Note: The WED bill insert was provided by Dan McDonnell of Wallingford, CT.
The Avalon Advantage – Visit our website at www.avalonenergy.us, call us at 888-484-8096, or email us at firstname.lastname@example.org.
The NCAC Annual Dinner on February 5, 2019 will be co-hosted by the Embassy of Canada. The dinner will feature Ed Morse, Global Head of Commodities Research at Citi, as the keynote speaker. Dr. Morse will present his perspective on the important energy events affecting the world and what they mean for energy markets this year.
Please join us for what promises to be a thought-provoking evening. The dinner is February 5, from 6 PM - 9 PM at the Embassy of Canada, 501 Pennsylvania Avenue NW, Washington, D.C.
The National Capital Area Chapter of the U.S. Association for Energy Economics is offering a tour of the Washington Gas Light training facility in Springfield, Virginia, on Thursday, February 21, 2019.
Bus transportation will be provided from a location near a Metro stop, most likely Smithsonian. The schedule for the event is tentatively an 8 a.m. pickup and 2 p.m. drop-off. Lunch details are forthcoming, but it is probabe that we will go to a local restaurant after the tour.
Cost for NCAC members is $60. A registration link will be provided shortly.
The facility at the company's operations center, known as Pipetown, was built to simulate an urban community. Pipetown was designed to provide the most realistic training environment possible for field operators, line supervisors and emergency responders. The intention of Pipetown is to do training in a live, controlled environment that will result in high performance, safety and efficiency.
WGL officials will also discuss gas dispatching and supervisory control and data acquisition (SCADA) software with NCAC members. If you want to know how natural gas moves to the burner tip from the city gate of a local distribution company, this is an excellent learning opportunity.
In December, I participated in an energy trip to Poland, which has undertaken multiple projects to eliminate its dependence on Russia for natural gas. Companies have signed deals to import U.S. LNG, and Polski LNG plans to double the capacity of its facility to 10 BCM.
PGNiG is constructing the Baltic Pipeline to bring 10 BCM of Norwegian natural gas via Denmark to Poland. The country also produces about 4 BCM of natural gas and consumes 19 BCM. When all the projects are completed, Poland is planning to export its excess capacity to its neighbors.
Frederick J. Lawrence, Vice President, Economics & International Affairs | Independent Petroleum Association of America
The American oil and natural gas renaissance continued to unfold with impressive growth in 2018. The U.S. has become more of a global energy player, thanks to the rising levels of production and exports, but this growth comes with new challenges as well as unprecedented opportunities.
The industry has been dealing with a rather disrupted market over the past five years, as we have seen both OPEC and non-OPEC members compete for global market share as global inventories became over-supplied leading up to and following 2014. The U.S. has been a star player in the non-OPEC group.
Unquestionably, the U.S. has solidified its role as a top tier global oil producer and will play an instrumental future role in supplying domestic energy to the world’s largest consumer as well as exporting to the growing global market which recently hit total consumption levels of 100 mmb/d.
A tug of war has emerged between the bulls (touting Iran sanctions, Venezuela production deterioration and limited spare capacity) and bears (noting slowing global demand, growing trade war frictions, weakening emerging market economies and a strong dollar) recently. But American tight oil production and export levels will be closely watched for any signs of slowdown in terms of growth, whether due to high first year decline rates, peaking sweet spots/maturity or other challenges in the field, and the ability to keep up over the long term with more long-cycle conventional production.
Long-cycle production sustainability will also have to contend with years of under-investment in the mega-projects that are necessary to sustain production growth. However, no matter how the tug of war breaks over the next year, exports of oil, natural gas liquids and natural gas (and all their associated products), look to rise in proportion to anticipated production growth and added export infrastructure.
The U.S. energy export engine has strengthened considerably over the past few years with added diversification of products and new geographical destinations. The U.S. has been exporting a long menu of petroleum products and pipeline natural gas for some time, but lifting the crude oil ban in December 2015 and the gradual growth of LNG have added notably to the trend. In the monthly Commerce Department reports, it is challenging to find any other American export that has experienced as much growth on percentage terms as energy (derived from oil and natural gas) over the past five years.
Between 2003 and 2007, the value of energy imports to the U.S. was about ten times greater than the value of exports. According to the Energy Information Administration (EIA) and the U.S. Census Bureau, imports were only about 1.5 times greater than exports. Following five percent (~464kb/d) growth in 2017, the U.S. is expecting annual oil production growth of 1.5 mmb/d this year. Natural gas and natural gas liquids volumes are also continuing to grow, whether in the massive Appalachian area or due to associated volumes in key oil-producing regions such as the Permian and Delaware Basins. Why are exports growing so quickly and why can’t we use all this energy domestically?
Because U.S. refineries prefer to process heavier and more sour crudes, continued domestic tight oil production growth (of oil which is predominantly light and sweet in quality) will correspondingly push continued export growth. According to the EIA, crude oil was the largest U.S. petroleum export in the first half of 2018, averaging 1.8 mmb/d. These exports increased almost 80 percent compared to the first half of 2017. Much of the crude went to destinations in Asia (China, S. Korea, India, etc.) and Europe (Italy, U.K., Netherlands, etc.).
The U.S. exported a record amount of 2.2 mmb/d in June but the exported crude oil is still less than half the level of petroleum product exports which constituted 70 percent of the total value of U.S. energy exports in 2017. Through September 2018, the U.S. averaged 1.8 mmb/d of crude oil exports and 5.4 mmb/d of petroleum product exports to our allies and trading partners around the world.
Similarly, the global drive for increased power generation helped natural gas grow at rates near three percent per annum last year, which will help sustain demand for U.S. liquefied natural gas in Europe, Asia and other regions. According to the EIA, the U.S. net natural gas exports in the first half of 2018 were more than double the 2017 average at 0.87 billion cubic feet per day. The U.S. became a net natural gas exporter in 2017 and this trend looks to continue in 2018 and beyond.
The top export challenges in the U.S. exist in the infrastructure and take-away arena as new pipelines and processing/storage capacity are needed in critical areas such as the Permian, to get the various production volumes to terminals on the Gulf Coast. Expanded port capacity with access to larger ships (such as VLCCs) is also needed to help U.S. production growth reach international destinations. New pricing benchmarks for U.S. West Texas crude in Houston have arrived on the scene for oil delivered to Houston/Gulf Coast refining and port hubs, because so much more crude product is being exported overseas.
Increased U.S. production has provided producers and our country with more energy and trade power optionality nationally, regionally and globally. Given our notable large petroleum imports from Canada (our largest trading partner for energy products) and the rising natural gas and petroleum product exports to Mexico, the NAFTA energy synergies remain important and the new USMCA Agreement will continue to showcase the strong and interdependent North American energy market. But this is not just a story for the Western Hemisphere, as companies are now more international in their perspective.
Energy interconnectedness is a theme that will continue to play a larger and more important role with global oil and natural gas demand continuing to grow. The U.S. will continue to have an expanded role to play in the global energy marketplace, thanks in large part to the shale revolution and the continued efforts of America’s independent oil and natural gas producers.
Wil Goldenberg, Associate, Public Institutions, JLL, and Brian Oakley, Executive Vice President, Public Institutions, JLL
The commercial power grid is increasingly exposed to natural hazards as well as to man made threats, including weather-related outages, other natural disasters, and physical or cyber-attacks. The cost of an outage may be immeasurably large at facilities providing critical services such as health care or national security.
Energy resilience is defined as the ability of facilities to survive grid outages without material disruption to operations.* This can require investment in generation and storage assets which are continually maintained in a standby state. While many government entities recognize the importance of resilience, they also find funding it to be challenging. Private sector participation under a public-private partnership offers a potential solution for government entities seeking to achieve a more resilient state while funding such improvements over time.
Resilience Funding Challenge
Government entities seeking to invest in resiliency projects face several challenges in funding new projects, including:
Size of Load: Back-up power systems need to be sized to meet essential peak loads during a multiday outage (for example, water treatment at a military installation). This can require large capital expenditure to meet requirements, including isolation of critical loads with a microgrid.
Cost Justification: Standby assets provide some assurance against unexpected disruption of operations, and by design may not be used for several years in between outages. However, common approaches to power purchase and investment decision-making do not consider the value of energy security, which could justify spending more than the cost of conventional services. Some revenue-generating government entities (such as a port authority) could estimate the value of lost revenue or increased costs from outages.
Performance Assurance: Resilience projects need to be fully functional during disasters, and capital investment alone does not ensure performance. Government installations need to maintain resilience assets in a state of readiness and ensure that adequate fuel is available at all times.
While the threat of grid disruptions is perceived to be increasing, resilience has not emerged as a funding priority, often resulting in facilities employing a patchwork of solutions that does not fully cover all critical loads.
Private Sector Solutions
Through public-private partnerships (P3)—also referred to as third-party financing—the private sector can help government entities improve resilience through expertise, risk sharing and financing. This can be achieved through a long-term agreement whereby a private developer designs and invests in a resilience project at a government facility in exchange for a stream of payments. Two models include:
Leveraging Assets: Many systems which provide backup power during an outage can also provide valuable services when the grid is functioning properly. For example, several US military installations have allowed power companies to build power plants on their property to serve the electric grid. In return, the plants are capable of being turned inward during a grid outage to serve the needs of the base.
Service Contracts: The government entity will commit to a series of payments that provides developers with steady revenue on which financing can be raised. This approach may be particularly attractive for standby energy resilience projects which only provide service in the event of an outage and is analogous to capacity payments in conventional power plant project finance.
Depending on accounting conventions, third-party financing may be off-balance sheet for a government entity. For federal entities, such arrangements may avoid capital budgeting rules and allow assets to be financed over time with operating dollars while accessing focused technical expertise from the private sector.
Service quality presents a greater challenge for resilience projects than for conventional ones because failure during a disaster may be catastrophic. Conventional remedies for subpar performance, such as liquidated damages to compensate a customer for insufficient energy delivery, will not suffice if a resilience project fails during a disaster. On the other hand, achieving a state of reliability that absolutely assures no down time is prohibitively expensive.
The risk profile of a grid outage is asymmetric: the likelihood of occurrence is low, but the cost of an outage may be catastrophic. Resilience projects will require the development of new contractual and risk allocation approaches to minimize the chance of failure while remaining bankable. Performance measures will need to focus on maintaining an ongoing and measurable state of readiness rather than on performance during an outage. The risk of a catastrophic event can be shared between a private developer and the government if they agree on the required level of service and performance indicators for monitoring compliance.
Under a well-designed P3 arrangement, private capital can be raised to fund resilience infrastructure while assuring performance up to specified standards. Private developers can raise revenue by providing additional services from resilience assets, or by receiving contractual benefits from the facility benefitting from the infrastructure. Similar models could apply to resilience infrastructure in other sectors and could enable financing of infrastructure to improve resilience in the face of climate change.
By Paul Ruiz, Senior Analyst, Securing America’s Future Energy and the Electrification Coalition
Electric vehicle (EV) sales in the United States grew impressively in 2018. National data for the full 12 months ending in December show automakers sold more than 362,000 units, an 83 percent increase over 2017. This exceptional rate of growth was largely driven by one automaker, Tesla, which significantly ramped up its production capabilities in the third quarter and completed deliveries on its mass-market Model 3 sedan. More than half of all EV sales in 2018 were Teslas (52 percent) with the Model 3 capturing more than 38 percent of sales alone.
More than any other currently available battery electric vehicle (BEV), the Model 3’s success shows there is tremendous pent-up demand for more affordable all-electric cars. Consumers also demand choice, as evidenced by the growing number of models currently available in the national market and automaker announcements of new MY 2019 and 2020 rollouts.
This year and next, automakers will release at least a dozen new BEVs and plug-in hybrid electric vehicles (PHEVs) and a growing share of those additions will fulfill popular consumer interests, such as sports cars and sports-utility vehicles (SUVs). There are now more than 16 BEV models available and 29 PHEV models available to consumers nationwide. As battery costs continue to decline, analysts project a growing number of these cars will go further on a single charge and at a lower cost.
These are encouraging signs, but let’s temper our expectations for the EV market this year. EVs currently represent just one out of every 50 new vehicles sold in the United States: undoubtedly better than the nascent market of only a few years ago but still a niche within a car market that sold more than 17.4 million units last year.
According to the latest data from the Bureau of Economic Analysis and InsideEVs, the combined category for BEVs and PHEVs accounted for just above two percent of new vehicle sales in the United States. Much of that growth has been concentrated in states with robust zero emissions vehicle programs and driven by a federal $7,500 tax credit available to OEMs’ first 200,000 vehicle sales.
While automakers are introducing new models this year, some are being offered in limited quantities in a select few U.S. states. Mercedes, Porsche, and BMW have all announced new model year vehicles that fit this description. The high-end Mercedes EQC, for example, will be produced in large quantities in Europe but offered at significantly lower volumes in the United States. Mercedes—like many popular brands—is still developing plans to mass-market EVs in the U.S.
Complicating that strategy is U.S. consumers’ decisive shift away from smaller sedans and toward larger pick-up trucks and SUVs. On an annualized basis, light trucks represent an astonishing seven out of every 10 new vehicles sold in the United States, an unparalleled figure that does not show signs of slowing. “It’s Plug-ins Versus Pickups in the Newest Culture Crash,” read the headline in a recent Bloomberg Opinion piece. Accommodating this trend, several automakers have announced plans to introduce electric SUVs and crossovers in the next several years, joining the Tesla Model X, Jaguar i-Pace, and the Hyundai Kona EV that are on the market in 2019.
So, will the U.S. reach an inflection point in EV sales this year? The short answer is no (despite many positive market signals that suggest it could be in the medium-term future).
Last May, the International Energy Agency (IEA) said global EV sales will triple to 13 million by 2030, provided the world builds at least 10 gigafactories to produce batteries at scale. Given the improved efficiency and durability of U.S. light-duty vehicles and the slow turnover in the U.S. vehicle fleet, internal combustion engine vehicles (ICEVs) will be around for quite some time. To reach lift-off in EV sales figures—to the point of becoming a majority versus ICEVs—dedicated government policy alongside private sector R&D will be necessary to continue encouraging EV adoption, the IEA says. In the U.S., this could mean lifting the cap on the federal EV tax credit, advancing more state and municipal policies that increase EV awareness locally, encouraging consumers to test drive EVs, and continuing to build out the infrastructure to support this vibrant ecosystem.
Some of these policy levers are more politically practical than others. But if there is one key fact to which the auto industry is keenly attuned, it is the potential pace of change. Experience in personal computing, cell phones and smartphones all show us that past inflection points have a way of creeping up on us – just so long as the right ingredients are in the mix. As the EV market heats up in 2019, 1.1 million cumulative sales since 2011, 60,000 public and private EV charging stations, and automaker commitments to introduce a diverse line of EV models are just the recipe this slow cooker needs.
PJM’s Dysfunctional Capacity Markets
Robert L. Borlick, Senior Energy Advisor
PJM’s capacity market is inefficient and produces excessively high capacity prices and encourages chronic overcapacity. In effect, it is a welfare program for suppliers of capacity.
The fundamental problem is PJM’s Variable Resource Requirement (VRR) curve, which reflects how much PJM is willing to pay for an additional MW of capacity over a range of system reserve margins. Figure 1 illustrates the current VRR curve.
Figure 1 – The PJM Variable Resource Requirement (VRR) Curve
The fatal flaw is that the VRR curve does not reflect the economic value of capacity to wholesale electricity buyers. It is not a true demand curve, as defined by classic economic theory, but rather is an administrative construct based on a hypothetical notion of what the “cost of new entry” would be (Net CONE).
So how would one develop an economically sound VRR curve? A remarkable study funded by the FERC answered that question in 2013.* It estimated the economic value of various levels of reserve margin based on the costs avoided by a hypothetical ISO that is interconnected with three neighboring power systems and resembles PJM. Figure 2 illustrates the demand curves the study produced and compares them with PJM’s VRR curve.
Figure 2 – Economic Demand for Capacity Curve vs. the PJM VRR Curve
The study derived demand curves for different amounts of interconnection capacity. The 50% Transmission Case reflects a 50 percent reduction in interconnection capacity, relative to the Base Case, and reveals that the value of local installed capacity substantially increases when an ISO has less ability to rely on emergency imports from its neighbors.
It is notable that PJM’s VRR curve systematically produces substantially higher capacity prices for reserve margins in the neighborhood of those required to satisfy the industry’s LOLE standard of one event in ten years. This implies that PJM systematically pays too much for capacity, which encourages capacity surpluses and imposes excessive costs on electricity consumers within the PJM footprint.
Figure 2 also suggests that the LOLE standard is too conservative. It is noteworthy that Southern Company, one of the industry’s largest and most successful utilities, rejected LOLE more than 25 years ago and replaced it with an avoided cost-based standard like the one used in the FERC study. Yet PJM and most of the electric utility industry still slavishly rely on this 1960s standard - much like Linus in the “Peanuts” comic strip, clinging to his security blanket.
While I submit that the ideal market design is an energy-only market (e.g., ERCOT) I recognize the need for capacity markets to serve as transitional vehicles. Unfortunately, the current ISO energy and capacity market designs encourage excess capacity and also discourage the formation of price-responsive demand, thereby producing a vicious circle of market dysfunction. Both energy and capacity markets need to be redesigned to allow capacity markets to gradually fade away as increasing amounts of price responsive demand enter the markets.
* Federal Energy Regulatory Commission, “Resource Adequacy Requirements: Reliability and Economic Implications,” Sept 2013.
Naughty Children – Not Electric Utilities – May Drive U.S. Coal Demand This Winter
Carl Greenfield,Manager, Energy and Environment | International Technology and Trade Associates, Inc. (ITTA)
Remember when parents told us that Santa would leave a lump of coal in our stockings if we misbehaved? As Christmas 2018 quickly approached, it seemed that those naughty boys and girls could be the primary drivers for coal demand this winter. Analysts expect this trend to continue as U.S. utilities move away from coal-fired generation.
According to a recent EIA analysis, domestic coal consumption this year is expected to be the lowest in nearly 40 years, due to declining demand from the electric power sector. As capacity factors decrease and plant retirements increase, coal generators are facing increasingly stiff competition from low-cost natural gas and subsidized renewable sources.
Despite the Trump Administration’s recent efforts to roll back CO2 regulations, reform electricity market rules, and suggest declaring a “national emergency” to help the struggling coal sector, U.S. utilities continue to opt for cheaper, cleaner options.
Nothing highlights this trend more than PacifiCorp’s announcement in early December that shutting down nearly 60 percent of its current coal fleet by 2022 may be cheaper than keeping those plants in operation. In presentations to stakeholders involved in its 2019 long-term resource planning, the coal-heavy utility noted that 13 of its 22 coal plants are uneconomic and more expensive to operate than alternative options.
Although PacifiCorp’s announcement is far from an official shutdown notice, it is part of a larger trend regarding the economics of operating coal plants in today’s changing electricity sector.
Unless this trend reverses and coal generators can compete across the board in this new environment, naughty children may be the U.S. coal industry’s best bet to remain in business.