- New York Isn’t California: But Same Path, Same Results?
- Blind Men, Elephants And Oil Demand Forecasts
- California Dreaming, Or How I Banned Gasoline Car Sales
- Supreme Court And Climate Change Could Help Oil Industry
Musings From the Oil Patch
October 6, 2020
Allen Brooks
Managing Director
Note: Musings from the Oil Patch reflects an eclectic collection of stories and analyses dealing with issues and developments within the energy industry that I feel have potentially significant implications for executives operating oilfield service companies. The newsletter currently anticipates a semi-monthly publishing schedule, but periodically the event and news flow may dictate a more frequent schedule. As always, I welcome your comments and observations. Allen Brooks
New York Isn’t California: But Same Path, Same Results? (Top)
Wildfires have ravaged the California landscape, which are blamed on climate change by the state’s governor, Gavin Newsom. While a popular rallying cry for environmentalists, the lack of wildfires elsewhere in North America, or anywhere in the world, in fact, raises an interesting question. Does climate change have the power to target individual states like California and Washington, yet skip all the other forests in the nation and North America? Or is there another reason? We were fascinated that more than a dozen people have been arrested and charged with setting wildfires on the West Coast. One arsonist was arrested for using a Molotov cocktail to set a wildfire in Oregon. He was arrested, charged and released on bail. He was later arrested for setting an additional six fires. One arsonist even livestreamed his setting a fire, then claimed he was in the process of notifying authorities when he was arrested. Absent such arsonists, there might not be as much forest land burning, but there are certainly instances when lightning and power lines have sparked fires.
Exhibit 1. Forests Dominate the Eastern U.S.
Source: Wikipedia
A map of the United States shows in green those areas where forests are dense. While dense forests extend along much of the West Coast, there are other areas of the West with meaningful clusters of forests, as seen on the map. However, almost the entire East Coast, nearly a third of the nation landmass, is heavily populated with forests. California is only the 41st ranked state (among all U.S. states and territories) with forest coverage of 32.7% of its land mass, compared with #1 Maine with an 89.5% coverage ratio.
If we consider the entire West Coast (California, Oregon and Washington), forests cover 84.8 million of the 203.7 million acres of land mass, or a 41.7% coverage ratio. If we compare all of the New England states, – Maine, New Hampshire, Vermont, Massachusetts, Rhode Island and Connecticut – collectively, they have an 80% coverage ratio, with 32.2 million acres of forests out of the region’s 40.1 million acres of land mass. If we listen to those living in and governing the New England states, climate change is ravaging the region and needs to be addressed just as people on the West Coast are demanding. Yet, none of the New England states has experienced a significant wildfire, even though drought conditions exist. The explanation is that it is due to greater moisture in the East and different vegetation.
An examination of forest fire data produces an interesting perspective. In 2019, according to the National Interagency Fire Center, California experienced over 8,000 fires, while Texas had nearly 6,900. However, California was only fourth in the number of acres burned, while Texas was fifth. Alaska led all states that year with nearly 2.5 million acres burned, but it failed to make the top ten states for the number of fires. California’s fires burned only one-tenth of the acres as Alaska, while Texas burned about 8.5%.
Exhibit 2. U.S. State Wildfire Record Of 2019
Source: Insurance Information Institute
When we examine the record of acres burned in wildfires nationally from 1980 to 2019, we see a marked increase in annual totals starting around 2000. According to the Forest History Society, up until around 1970, federal land managers remained obsessed with controlling large fires. During the 1960s, scientific research increasingly demonstrated the positive role fire played in forest ecology. In the early 1970s, Forest Service policy began allowing natural-caused fires to burn in designated wilderness areas. This “let it burn” policy suffered a setback due to the 1988 Yellowstone fires. Since 1990, fire suppression efforts required taking into account suburban sprawl and development of communities within high-risk forest areas. These efforts were challenged by the fire-fighting budget growing until it consumed roughly half the Forest Service’s entire budget, reducing the agency’s funds available for land management activities, such as land restoration and forest thinning. These issues are much more important contributors to the outbreak of wildfires, and certainly to the escalation of the cost of wildfires, than climate change. Fire management philosophy has contributed to fires by leveraging the build-ups of burning material due to the historical fire suppression policy that characterized the Forest Service mandate since its creation in 1905.
Exhibit 3. Annual Wildfire Acreage Burned Record
Source: Insurance Information Institute
Data on the number of wildfires and acres burned from a much longer time horizon show a quite different picture than the 1980-2019 span. For most of 1926-1956, the number of fires nationally were twice the rate they are averaging now. The number jumped back up to that high rate in the latter years of the 1970s.
Exhibit 4. Past Fire Counts Twice Current Rate
Source: Paul Homewood
When one looks at the number of acres burned, it is an interesting picture. Since about 2000, there has been a noticeable increase in the acres burned compared to the 1960-2000 period (Exhibit 5, next page). This reflected the cooling and wetter climate experienced during those earlier years. In the late 1920s and 1930s, the dry climate that created the infamous Dust Bowl in the middle of the country and led to substantial destruction of our agricultural industry also allowed increased forest fires. That period was also when a large amount of fertile topsoil blew away with the wind and dry conditions, forcing many farm families to migrate, as told in John Steinbeck’s Pulitzer Prize-winning novel, The Grapes of Wrath.
Exhibit 5. Pre-1960 Acreage Burned Much Higher
Source: Paul Homewood
Some people would argue that the preservation of forests in California was of such importance that it warranted the change in forest management policies. However, the history of California, as well as other regions of the country, shows that Native Americans used fire to drive animals out of the woods enabling them to be hunted for food. In addition, Native Americans understood that opening up the forests by burning the build-up in underbrush contributed to the forests remaining healthy.
A reality about wildfires that cannot be ignored, but which highlights why better forest management policies and restricted development in forests is required, is the moisture issue in America. The existence of the Rocky Mountains restricts moisture flowing from the Gulf Coast ever reaching the West Coast. The jet stream and prevailing wind patterns take Gulf moisture up through the central portion of the nation and over the Eastern one-third of the nation.
Exhibit 6. How Moisture Flows Throughout The U.S.
Source: Earth Science
Nothing is going to change this reality, which is why people like climate economist Bjorn Lomborg argue that adaptation is our best defense against climate change.
Exhibit 7. East Vs. West Difference In Forest Makeup
Source: U.S. Forest Service
Nature further helps the East Coast forests as they are populated with hard wood trees versus the West Coast’s soft woods. The latter are more susceptible to drying out from a lack of moisture and hotter temperatures. Data from a 2000 U.S. Forest Service report showing the trends in hard and soft woods by region of the country highlights the forest composition difference between the East and West Coasts. The South shows a much more mixed forest composition.
While New York and California differ in the amount of forest coverage and the composition of their forests, the two states are driving down a similar path to carbon-free economies. In 2018, California’s then governor, Jerry Brown, signed legislation mandating the state achieve 100% clean energy by 2045. In light of the current wildfires, California Governor Gavin Newsom said, “I think 2045 is too late.” He said that his Administration is “currently in the process of putting together new ideas, new strategies to accelerate our efforts, accelerate the application and implementation of commitments we’ve previously made, and to look at these stretch goals 2045 and see if we can pull them closer into the future.” Banning the sale of gasoline-powered cars by 2035, which Gov. Newsom has just done by executive order, is another step on the road to a carbon-free economy. This follows a mandate beginning this year that all new homes install solar panels. In addition, a number of California cities are banning new natural gas hookups, further boosting the clean energy agenda.
New York State is more ambitious, as its Clean Energy Standard was revised in 2019 requiring the state to reach 100% clean energy by 2040. A new 22-member New York State Climate Action Council was established and given three years to develop a “scoping plan” that would include mandates, regulations, incentives and other measures. Expectations are that building codes would be revised to improve housing energy efficiency, while also laying out a path for utilities to get 70% of their electricity from renewable sources by 2030 with the balance over the remaining decade. Mass transit expansions and increased energy efficiency guidelines are anticipated. A New York Times article commenting on the revised goal stated that 26.4% of the state’s 2018 electricity came from renewables, based on data from the New York Independent System Operator (ISO), the nonprofit that runs the state’s power grid.
Exhibit 8. New York State Electricity By Fuel
Source: New York ISO
What the data actually shows is that New York got 21% of its 2018 renewable electricity from hydropower, with only 5% coming from wind and solar. By only citing the total renewables’ percentage without giving more detail, the newspaper article leaves readers with the perception that traditional renewables – wind and solar – are responsible for a sizeable amount of New York’s electricity.
The most notable point about New York’s electricity supply, which few people are likely to have known, is that the share of electricity from hydropower was the third largest component behind nuclear and natural gas, each of which provided a 32% share. In fact, in 2018, New York produced the most hydropower of any state east of the Rocky Mountains, and is the third largest hydropower producing state nationally.
We were not surprised that natural gas plays a large role in New York’s electricity. New York, along with New Jersey, is the gateway to New England, through which virtually all the natural gas supply flows. That is a critical juncture as electricity in New England depends heavily on natural gas, a dependency that impacts the region’s carbon emissions battle when winter arrives. New pipelines, and expansions of existing ones, have been fought successfully by the governors of New York and New Jersey. This has led New England residents paying higher power prices than otherwise would have been the case.
The inability to expand gas supply capacity means that winter electricity demands must be met from other fuels. During the winter months, electricity demand peaks at night when the coldest temperatures are recorded. Renewables are not a viable electricity supplier at those times as the sun isn’t shining and wind is usually absent. While electricity demand normally falls at night, in New England, electric heat is important. According to U.S. Census Bureau data for 2018, 13% of New England homes heat with electricity. A Massachusetts analysis suggests that homeowners heating with electricity pay four times the cost of heating with natural gas. This highlights why consumers are highly sensitive to electricity prices. To offset the loss of renewables electricity during the winter and especially at night, utilities must fire up standby coal- and oil-fired power plants to supplement the rest of the suite of dispatchable power sources.
When one examines the 2019 ISO New England (the region’s non-profit manager of the region’s grid) electricity generation by fuel source data, it becomes clear just how dependent the region is on natural gas, as well as nuclear power. The latter is in the process of being shuttered, which will reduce the amount of dispatchable clean energy available during winter months, importantly at a time when people are concerned about carbon emissions.
Exhibit 9. How New England Gets Its Electricity
Source: ISO New England, PPHB
New England also depends heavily on imported power from Canada, which is primarily from hydropower. As mentioned earlier, New England consumes coal and oil, especially during winter months when natural gas is diverted from power generation to home heating use, but sometimes even in peak demand periods during the summer.
Exhibit 10. California’s Electricity By Fuel History
Source: California Energy Commission, PPHB
California, like both New York and New England, is significantly dependent on natural gas for its electricity generation. In fact, based on 2018 power data from the California Energy Commission, natural gas generated power provided 46.5% of the electricity generated in the state, and 32% of the total power used, an amount equal to what is imported by the state. While California is planning to shut down its nuclear power plants, they only accounted for 9.4% of in-state generated power. While both California and New York are shutting down their nuclear power plants, the major difference in the fate of the states is that New York depends on nuclear for 32% of its power, while California’s dependence is slightly under 10%. In other words, New York faces a greater challenge than California in replacing the loss of its nuclear power.
We know that the last time New England shut down nuclear power plants, it resulted in a sharp increase in natural gas use, as well as an increase in carbon emissions. As shown in the accompanying chart, wind and solar added very little in new power to offset the loss of the nuclear plants. The lost power was totally offset by increased natural gas-generated power. Analysts expect the same phenomenon to occur when California shuts its nuclear plants in 2025.
Exhibit 11. When Nuclear Shuts, Gas Rescues
Source: energywatch-inc.com
New York, however, anticipates offsetting the shutdown of its Indian Point Units 2 & 3, in April 2020 and April 2021, with a huge new offshore wind farm. Empire Wind, owned by Norwegian energy company Equinor, and now joined by partner BP plc, is building an 816-megawatt (MW), 60-80 wind turbine farm located 15-30 miles southeast of Long Island. The lease spans 80,000 acres with water depths ranging between 65 and 131 feet. It will require both fixed-bottom and floating wind turbines. Equinor believes the site can provide as much as 2,000 MW of electricity. The 816 MW wind farm with its 60-80 turbines will require $3 billion of investment according to Equinor, and it is targeted to start up in December 2024.
Exhibit 12. Empire Wind Lease Location For N.Y.
Source: Equinor
For New York, the Indian Point units accounted for 36% of the nuclear power produced in the state in 2019. Multiple reports examining the decision of New York Governor Andrew Cuomo to shutter Indian Point ahead of its projected retirement date and replace it with renewable power have pointed to logistical challenges. The bill Governor Cuomo signed into law mandating the 2045 clean energy target envisions 9,000 MW of offshore wind capacity by 2035, 6,000 MW of solar capacity by 2025, and 3,000 MW of energy storage capacity by 2030. Given that neither wind nor solar power produces substantial output, the total amount of power these sources will supply will be a fraction of the generating capacity that needs to be built. The impact of the intermittency on power supplied, along with the land-use issue of renewables, is addressed in the accompanying chart.
Exhibit 13. Renewables Need Much More Land
Source: energywatch-inc.com
Energy writer Robert Bryce estimates that replacing the power from Indian Point with wind will require 1,300 times the amount of land the nuclear plant sits on. The standard rebuttal is that wind turbines are getting larger and improving their efficiency, thus fewer turbines will be needed in future wind farms to generate the desired output, therefore, less land area will be covered in turbines. Once again, we are told about future trends, but history often shows those forecasts are not realized, or on the timetable predicted.
Ken Girardin, a policy analyst at the Empire Center for Public Policy, calculates the offshore wind buildout will cost more than $48 billion upfront and $1 billion in annual operating cost. He also sees at least 56 square miles of solar panels needed to reach the solar generation goal.
On the other hand, Professor Mark Jacobson of Stanford University, famous for predicting how the entire U.S. energy needs could be met with renewables, led a 2013 study outlining how New York could transition to 100% renewable energy by 2030. The study envisioned 4,020 onshore wind turbines spread across 1.5% of the state’s land area — 818 square miles. And solar farms would cover 463 square miles, substantially more than Mr. Girardin estimates. However, today, Professor Jacobson estimates that about a third less land would be needed due to improved technology. He did acknowledge that the cost and challenges of overcoming local opposition to renewable power projects will be significant. This is all before we even begin to consider the opposition to the miles of new transmission lines that would be needed to tie in to the grid these new wind and solar power projects.
“It’s definitely going to cost ratepayers a lot more for reliable electricity,” said Gavin Donohue, president of the Independent Power Producers of New York, whose members produce three-quarters of the state’s electricity. In his view, the state will continue to need the new efficient and low-emission natural gas plants that have been built in the last 10 years. “To say we’re not going to have any fossil fuel by 2050 is preposterous,” he said. “Are we not going to have airplanes or gas-fueled cars? Is everyone going to have to retrofit their houses?” These are important questions to which those making energy policy today often forget to answer.
Exhibit 14. NY Faces Huge Clean Energy Gap
Source: Financial Times
To understand the challenge New York faces in reaching its clean energy goal without nuclear power is highlighted in a chart of 2019 electricity production by month from renewable power and renewables with nuclear power. Superimposed on the chart are lines showing how these amounts compare with the 2030 renewable energy use goal and the 2040 zero-carbon energy production. Renewables alone fall way short of these targets, with barely a decade to the first target.
Shuttering nuclear power may be a dumb move, but one that has been a long-standing goal of Governor Cuomo since his election in 2010. He believes that the Indian Point plants are a risk to the populous Westchester County (his home) and New York City. He has accomplished his goal, but must now manage replacing that power with intermittent renewables at a significant cost. Maybe the cost and availability issues are beginning to be recognized by the public. An article early this year in the Financial Times contained a map showing, by county, how New York adults’ views in 2019 compared against national averages with regards to the actions of the governor on climate change.
Westchester County has the highest rating, calling for more action, followed by the Albany and Ithaca regions, centers of highly progressive clean energy philosophies. Much of the state is calling for less action, with the highest opposition ratio in the western part of the state where oil and gas activity predominate. We would also point to the northern counties of Pennsylvania, where the shale revolution is very important, in opposing increased climate action.
Exhibit 15. How New Yorkers View Climate Action
Source: Financial Times
To place the New York and California moves to upend their power generation profiles in pursuit of 100% clean energy futures into perspective, two charts (next page) from the Energy Information Administration (EIA) help. The first shows the history of U.S. electricity generation by major fuel source from 1950-2019, while the other shows the history of the renewable power segment.
Exhibit 16. How U.S. Electricity Is Generated By Fuel
Source: EIA
Exhibit 17. U.S. Renewable Electricity By Fuel Source
Source: EIA
In 2019, coal represented 23.5% of the nation’s electricity generation, while natural gas was 38.4%, nuclear at 19.7% and renewables at 17.5%. Coal’s share has been, and remains, in decline, just as the shares from natural gas and renewables have increased. Nuclear power’s share has remained flat for the past decade, but with the wave of plant retirements underway that share will shrink. That will be unfortunate as the data (next page) from 2019 shows nine of the ten most productive power plants in the nation were nuclear.
Exhibit 18. Nuclear Plants Are Most Productive
Source: EIA
When we examine the composition of the renewable energy segment, we see interesting trends. With the rapid build out of wind and solar power, the shares represented by hydropower, biomass and geothermal are shrinking. Again, not a surprise, but a harbinger of the future. The growth of wind and solar output will put increasing pressure on utilities, and power regulators, to improve their management of the grid. The recent California rolling power blackouts due to the heat wave highlighted how huge that challenge is, and that it will likely continue growing. I’m sure New York is hoping that all it needs to do is lay a power cable underwater from Empire Wind to the coast and plug it into the grid. That would eliminate the eyesore debate, but doesn’t mean the grid management issues would be resolved.
California has always been a leader, whether it was social trends, music, dress or blondes. The green movement points to the state as the model of a clean energy future – at least from the policy perspective. The blackouts have even forced clean energy proponents to acknowledge that California doesn’t have a 21st century power grid – a “smart” grid – that can effectively manage itself. Energy experts are already pointing out that the state will have a problem by mandating the elimination of gasoline-powered vehicles. They will have to figure out how to power all those electric vehicles (EV) when they plug in at the same time and want a fast charge.
Several small experiments have been conducted seeking to understand people’ use of EVs and their charging patterns. Not surprisingly, it seems everyone plugs in at dinner time. The experiments highlighted the need for substantial upgrades to neighborhood electricity distribution networks to handle multiple homes possessing EVs. Failure to do this will lead to local blackouts and the potential for fires from overloaded transformers. Correcting these risks will inflate the cost of electrifying the nation.
While California is the leader in the clean energy race, New York is chasing it with hopes of passing it. Politicians are directing the races, but the public will be footing the bills that will come due long after the politicians are out of office. Fortunately, New York doesn’t have the wildfire risk of California, but it seems to be making the same energy policy mistakes. As a result, both states may show the rest of the nation that getting out over the tips of one’s skis when aggressively revamping electricity systems to meet clean energy agendas may lead to serious consequences – not all of which are easily foreseen.
Blind Men, Elephants And Oil Demand Forecasts (Top)
Many may be familiar with the parable, first attributed to the Buddhist text Udana, of the five blind men encountering an elephant and trying to determine what is was. Each blind man feels a different part of the elephant’s body, but only one part, such as the side or the tusk. They then describe the elephant based on their limited experience and their descriptions of the elephant are wildly different from each other. In some parable versions, each blind man suspects the others are dishonest and they come to blows. The moral of the parable is that humans have a tendency to claim absolute truth based on their limited, subjective experience as they ignore other people’s limited, subjective experiences, which may be equally true.
The parable suggests a scenario about how energy forecasters are being forced to project future oil demand scenarios. Everyone acknowledges that due to Covid-19, history provides much less of a guide to the future than normally would be the case. Behavioral patterns have been altered by both the populous response to protecting themselves from the spread of the virus, but also due to heavy-handed mandates by governments. Now forecasters have to
Exhibit 19. Examining And Describing The Unknown
Source: nsjour.wordpress.com
wrestle with determining which of the emerging economic and social trends will be sustained. While many of these trends suggest radically different outlooks for the future of economic activity and energy consumption, no one can be sure which trends will be sustained versus those that fade with the setting sun. Oil market forecasters have suddenly had to become historians, amateur epidemiologists, social philosophers and futurists.
As part of their work, forecasters must offer views about megatrends such as the future of urban life and cities, social migration patterns, working from home, mobility, business and leisure travel, food consumption, and retail purchasing trends, just to name a few. Just where forecasters land on each topic can impact their future energy consumption projections, as well as which fuel will benefit or suffer the most. Understand, we are not being critical of these forecasters because we practice in the same field. Rather, to appreciate how the forecasting business has changed, we cite how much our span of reading topics has widened, as well as the webinar topics we might not have paid much attention to in another era. We have listened to many speakers from across the world offering insights to topics that we figure might have a bearing on energy consumption. Some offer insights based on very different life experiences, but others offer the same perspectives we have heard elsewhere.
In our search for additional insights, we have paid less attention to the supply side of the oil market equation, as we have plenty of it today. Maybe in a couple of years we will find the world energy-constrained, but, in our view, there is plenty of time to begin sorting that out, and any tightness will be a function of future demand.
Our shift in thinking about future oil demand began to be reshaped after listening to a presentation by economist Marie Fagen of London Economics. Her presentation was based on a paper she published in 2019 titled “Up the down staircase: What history teaches us about oil demand after a crisis.” She and her co-author examined the history of income elasticities for crude oil, gasoline, and diesel fuel, and between OECD and non-OECD countries, as well as the world overall. While we knew much of this intuitively from decades of petroleum industry involvement, there were some interesting insights. The concluding paragraph of the paper stated:
“The profile of oil demand is set to change, with demand for petrochemicals for plastics and fertilizers expected to be an increasingly important driver of oil demand. At the same time, other fundamental changes are potentially on the horizon (for example, the widespread adoption of electric vehicles) and they could result in a further decline in long-term income elasticities of oil demand. This could lead to the next downward step in global oil-intensity: though demand could continue to increase, it will struggle ‘up the down staircase.’”
Based on Dr. Fagen’s presentation, we built our first oil demand forecasting model, which left us not reaching 2019’s oil demand level until 2022. That struck us as overly pessimistic, as many forecasters were anticipating a V-shaped demand recovery from the March/April lows, and a return to 2019 oil demand levels by the end of 2020, or certainly by mid-year 2021. At the time, we, too, expected a V-shaped oil demand rebound, but then a slow recovery afterwards. We had nagging doubts that everything would return to working normally. For example, air transportation consumes roughly eight million barrels per day (mmb/d) of jet fuel, while shipping used four mmb/d of marine bunker oil. These sectors were certainly going to experience tougher times ahead in the pace of their recoveries.
With respect to marine transportation, we had already wrestled with getting our arms around the impact on the segment’s fuel consumption from the implementation of IMO 2020, which mandated ships worldwide switch from high-sulfur to low-sulfur fuel at the start of this year. Forecasters debated how much high-sulfur bunker oil would be stranded – one mmb/d, or more? There was also a fear that ship operators would be hurt by the anticipated explosion in the price of low-sulfur diesel, a preferred compliant fuel, which might also create a shortage and price spike for the global trucking industry. As it turned out, there was less of an impact on price and demand in the early months of 2020 than anticipated. When Covid-19 began shutting down global trade and the cruising industry, shipping’s fuel needs eased, along with overall global oil demand. What is the future for these businesses?
Recently, we watched the BP plc introduction of its 2020 Energy Outlook that sets out the firm’s thinking about the most important trends driving energy markets, assuming current government policies, but also in an environment with more aggressive behavioral shifts and tighter government policies. BP also put together a much more aggressive clean energy strategy and what that might mean for energy fuels.
We also recently listened as energy consultant Rystad Energy’s analysts laid out their outlook for oil demand and supply, both for the near and intermediate terms. Rystad was originally slightly more conservative about the oil demand recovery compared to many investment analysts, but their recovery outlook has pushed further into the future. We have plotted (next page) their total demand declines by month for all of 2020 and 2021 compared to 2019’s oil demand. As our chart shows, Rystad sees oil demand in December 2021 still trailing 2019’s level by 1.5 mmb/d.
Exhibit 20. How Rystad Sees The Oil Recovery
Source: Rystad, PPHB
Another view of the future from S&P Global Platts Analytics shows a V-shaped recovery this year and into 2021. While we only have their chart, visually it looks like by the end of 2021 oil demand would be about equal with 2019. If it is short of 2019, the gap is quite small, much like Rystad’s projection.
Exhibit 21. Platts Has Different Recovery Outlook
Source: S&P Global Platts
It appears from the S&P Global Platts’ chart that their analysts do not expect much of a slowdown in oil demand growth once the recovery has been completed. When we look out to the intermediate term – 2025 – it looks like the firm is forecasting a roughly 5 mmb/d increase in oil demand. That contrasts sharply with the view of Rystad that looks at oil supply in 2025 lagging due to the impact of lower oil prices and deferred exploration and development work as a result. It sees overall supply falling 3.3 mmb/d below its pre-Covid-19 projections. Assuming stable inventories, then the supply shortfall would approximate the decline in oil demand.
When we consider BP’s view of the future oil market, as shown in its 2020 Energy Outlook, we find essentially no demand change between 2019 and 2025 for its Business-as-usual scenario. They are projecting demand at 98 mmb/d in 2025, but only 94 mmb/d for both the Rapid scenario and the Net Zero scenario, or a shortfall of 4 mmb/d from the Business as usual outlook. Rapid and Net Zero are BP’s scenarios for more aggressive climate change responses that impact energy consumption patterns.
We have produced two charts based on the data from the BP report. The first shows the three oil demand scenarios out to 2050. These are the charts that have received the most press coverage, as they show a contracting oil market, a scenario about which environmentalists are cheering and investors are worrying. The second chart shows the oil demand history through 2019 (using the latest BP statistics data for oil consumption) along with the 2025 demand estimates for the three scenarios. These demand estimates are consistent with the Rystad scenario.
Exhibit 22. BP’s Oil Outlook Appears Bleak
Source: BP, PPHB
Exhibit 23. Near-Term Oil Outlook Isn’t That Bad
Source: BP, PPHB
After examining all the scenarios, we are left with a 5 mmb/d oil demand increase (S&P Global Platts), a flat outlook reflecting BP’s Business-as-usual view that global oil demand likely peaked in 2019, a potential 3.3 mmb/d decline (Rystad), or a 4 mmb/d reduction if BP’s various clean energy scenarios are adopted. To understand the ramifications of each forecast, one really must understand key demand assumptions each forecaster has made.
S&P Global Platts provided a chart showing the sectors and the issues, about which one must make a judgment in order to prepare a forecast. The calls are about how the future will compare with or differ from past trends. As the chart shows, virtually every segment of the economy and its energy demand will be impacted. The firm didn’t comment on several key trends such as migration, both from cities to suburbia and rural areas, as well as between countries. They also didn’t comment on the future of offices, especially in expensive cities.
Exhibit 24. Issues Impacting Future Oil Demand
Source: S&P Global Platts
The tightness of the range of oil demand estimates for the 2025 forecasts concerns us. Either all forecasters do not see any meaningful changes to demand dynamics or they just assume it will take much longer for them to impact the market. We must acknowledge that this might happen. However, as we think about the oil industry’s future, we are reminded of an observation made by Gary Burnison, Korn Ferry CEO, who recently wrote:
“Too much optimism could anchor us in the old—and threaten us with irrelevancy (and maybe extinction). We need healthy pessimism so we can wipe the board, erasing what’s no longer relevant, and give ourselves a clean slate on which to imagine tomorrow.”
No one knows the future. The exercise in making projections is that it forces us to think about what could happen and assess the probabilities. If we view things through the optimistic lens that things will return to a more normal relationship, we cannot imagine a truly alternative future. Who in the industry, even Bob Dudley, then CEO of BP, would have imagined that we would be where we are essentially six years after the great oil price boom began to unwind? Had we known then, what we know now, what would we have done differently? Would we, or the industry, be better off today? I’d like to think yes. But the more important question to ask is: What unimaginable scenarios should we be considering now, as we consider what the industry may look like in another six years?
We were intrigued reading a recent Barron’s Special Supplement to The Wall Street Journal. It asked the question: What will be the biggest financial surprise over the coming year? Three investment professional forecasters, covering various financial markets offered their views. While each surprise was addressed to the next year, the changes suggested could become permanent, with meaningful changes for the energy business.
Liz Ann Sonders, chief economist for broker Charles Schwab, offered up the prospect that “The Almighty Consumer Will Stumble.” In her view, the economy would shift away from its consumer orientation (70%) with a substantial loss of jobs. It would move toward an investment-driven model, which could be good for long-term growth. The concern is that the lost jobs would largely be lower-income ones, putting pressure on the wage scale, while also increasing structural unemployment, boost welfare rolls, and force governments to provide more money, necessitating raising taxes. Increased social discord could be an outcome, also.
Nela Richardson, investment strategist at broker Edward Jones, offered up the idea that “The Federal Reserve Will Launch a Digital Currency.” She sees that development revolutionizing the U.S. payment system and altering customer and business habits. This would be an extension of an increase in the digitization of the economy, which could lead to more layoffs and firm’s cost-cutting. While potentially good for corporate profits, it would not be good for workers with all the attendant negative fallouts.
Nicholas Colas, co-founder of DataTrek Research, described “An Unwelcome Surprise: The Debt Bomb Could Explode.” He sees the possibility that interest rates rise to 2%, or 2.5%, forcing the Federal Reserve to raise rates. This could force the cost of debt service consuming a quarter of the $4 trillion government budget, forcing out expenditures on many other things, especially on the social welfare agenda. In his view, this scenario, which would likely push up inflation rates, might also lead to another geopolitical oil shock, something being ignored by markets. It would certainly lift global commodity prices, upsetting the balance among nations of the world.
Each of these surprises would upset the current outlook for 2021, with implications for energy demand, but the more significant issue is whether they might create new economic and social trends with long-term energy demand implications. Imagining a different world than the one we have been living in requires imagination. That is often a skill we lack.
California Dreaming, Or How I Banned Gasoline Car Sales (Top)
California Governor Gavin Newsom recently signed an executive order banning the sale of gasoline-powered automobiles in the state beginning in 2035. This was part of his push to further embed a ‘really green’ agenda within the state’s economy. The car-sale ban ignores the challenge that will face the state’s electric utilities in meeting the power needs for all the new electric vehicles (EV) that will be sold. But, that’s a detail, and we have 15 years before the ban goes into effect. Not to worry. However, 15 years isn’t the longest runway when one is talking about developing, permitting and building substantial new power supply sources, especially when existing natural gas-powered and nuclear plants are scheduled to be retired in the foreseeable future.
The first point of the executive order stated:
“It shall be a goal of the State that 100 percent of in-state sales of new passenger cars and trucks will be zero-emission by 2035. It shall be a further goal of the State that 100 percent of medium- and heavy-duty vehicles in the State be zero-emission by 2045 for all operations where feasible and by 2035 for drayage trucks. It shall be further a goal of the State to transition to 100 percent zero-emission off-road vehicles and equipment by 2035 where feasible.”
According to the California New Car Dealers Association’s most recent report, California Auto Outlook Second Quarter 2020, new vehicle sales are projected to reach 1.63 million in 2020, a 22% decline from 2019’s sales, but exceed 1.8 million units next year. During the recent boom years, new vehicle sales reached, or slightly exceeded, 2 million units annually. The state is the largest automobile market in the nation, and the largest EV market, too.
Counting vehicle sales by state and type is challenging, as reflected by the difference between the EV sales data from two respective monitors of that market – EVAdoption.com and InsideEVs.com. According to EVAdoption.com, California sold nearly 95,000 EVs in 2017, which jumped to 153,400 units in 2018. Those sales compare against US sales of 188,000 and 328,000, respectively, for those same years. California’s EVs represented just over 5% of total vehicle sales in 2017 and 7.8% in 2018. National EV market shares, however, were only 1.2% and 1.96% in 2017 and 2018, respectively. InsideEVs.com estimates about 2,000 more EVs being sold in 2017 and 33,000 additional units in 2018 than EVAdoption.com. InsideEVs.com posted 2019 sales data suggesting 329,500 units were sold, a decline of nearly 9%. We estimate, by reading off its charts, that the national EV market share was approximately 1.2% in 2017, 2.2% in 2018, but down to 1.9% last year.
Based on the California data from EVAoption.com, assuming the new vehicle market remains roughly a two-million unit per year market, then between 2018 and 2035, annual EV sales will need to increase 13-fold to reach 100% of vehicle sales. That is a very significant growth rate over the 17-year period. Can it happen? Will it happen? The answer to the first question is “Maybe.” There remain lots of questions about the cost of EVs, especially for their batteries, versus internal combustion engine (ICE) vehicles. There are also questions about the ability of the minerals markets to develop and deliver the required volumes to manufacture the necessary EV batteries. What about the environmental issues with battery disposal?
The answer to the second question is “Only if there is an enforcement aspect to Gov. Newsom’s executive order,” assuming it remains in place. California may also experience the greatest auto sales boom in 2034 as citizens seek to avoid the mandate. Not considered is what happens if there isn’t enough gasoline, especially for lower-income families who can’t afford EVs and are priced out of the gasoline market?
Potentially the greatest hurdle for California reaching the target for all new vehicle sales to be zero-emissions is having sufficient power available to charge its rapidly expanding EV fleet. A recent article suggested energy consultants and academics are predicting the switch to an all-electric vehicle fleet could boost California’s electricity demand by up to 25%. Of course, those same forecasters want all that power to come from renewable sources, which means, given the intermittency of wind and solar power, that the state’s electricity utilities will need to build two to three times that amount of power in new generating capacity.
Some clean energy proponents see the EV growth as an opportunity to revolutionize the delivery of electricity. Renewables, however, create a serious challenge for managing the power grid when the sun is setting and solar power drops off quickly, especially if the wind is not blowing. They see the future being a “smart” grid that will enable EV batteries and battery backup units at homes to release their stored electricity to supplement the grid. With respect to EVs, it is known as “vehicle-to-grid,” also expressed as “V2G,” and it is being explored in the U.K. and Denmark. According to Matt Petersen, chairman of the Transportation Electrification Partnership, a public-private effort in Los Angeles working to accelerate the deployment of EVs, “We end up with rolling batteries that can discharge power when needed. The more electric vehicles we add to the grid, the more renewable energy we can add to the grid.”
To gain a better understanding of what is involved in V2G, we turned to the web site of Virta, a Finland-based EV charging company. Virta was founded in 2013 following discussions among Finnish energy utilities about the future of transportation. Based on their belief that the future will be electric, these 18 utilities founded Virta to build up a national charging network. Even before it could set up a network in Finland, the company secured work in foreign markets. Today, Virta operates in 28 countries.
The concept of V2G is relatively simple. It is similar to regular “smart” charging, also known as “V1G,” in which the charging of EVs can be done in a way that allows the charging power to be increased and decreased as needed, i.e., to take advantage of lower-cost power when demand is otherwise low. V2G goes one step further by enabling the charged power to be momentarily pushed back into the grid from the EV’s battery to balance variations in energy production and consumption.
Electricity flowing in the grid always takes the shortest possible path to the nearest location where it is needed. A V2G charging device absorbs electricity from the EV battery and simply pushes it back to the grid where it continues its journey to the nearest location where it’s needed. Virta provided an example of how such a system works.
“At Virta Headquarters, we currently have two V2G charging stations in use. These stations are located in the office building garage, next to regular, publicly available smart charging points. When the V2G station is discharging, the electricity here at Virta HQ transfers directly to the nearby car batteries charging at the regular stations — they are the nearest locations where the demand for electricity is continuous. If no cars are being charged, the discharged electricity will be used on garage lighting or air conditioning. This reduces the total energy consumption of the building, which balances the energy system around our office.”
Virta suggests that V2G can become a core grid management tool, enabling EVs to be used to balance electricity supply and demand in the short-term, and to store energy for longer periods. The key is having the capability to control individual charging devices from the cloud via the internet. Bidirectional charging features enable the electricity to be taken back from the EV battery. Just as the charging device can be controlled by an algorithm to ensure optimal charging times by using local total charging loads, using the price of electricity, solar energy production or the grid frequency as signals, the EV battery can shift from storage to electricity supplier. Importantly, the programming of the bidirectional charging device will ensure that the EV battery is charged to 70%-90% of capacity at the time the user wishes to drive the EV.
This technology all seems straight-forward, but it depends on a number of changes to the existing grid, EV hardware and charging installations. Virta has two tests underway – one involves the 9,000 buses in London and the second is with a utility vehicle fleet in Denmark. The algorithm employs both machine learning and artificial intelligence to adjust the timing and pace of charging and discharging of EV batteries. A key point is that EVs need to be built to allow for bidirectional charging. Not everyone is so equipped. Nissan’s Leaf models appear to be the only vehicles currently equipped with this bidirectional capability, although the company is now adding such a capability to a second EV model. Mitsubishi has also announced plans to commercialize V2G with its Outlander plug-in hybrid EV (PHEV). We don’t know if adding this technology will increase the vehicle’s cost, which could become another issue.
One aspect of V2G that Virta addressed is the issue of battery life. As a result of how V2G works, EV batteries will be discharged more frequently than they would during normal driving. The company does not believe shortening of battery lives is an issue, but we suspect the more frequent discharging will have a cumulative impact on battery life, but maybe it will not materially diminish the battery’s performance at a rate in excess of its normal deterioration. We also do not know what adjustments and/or upgrade investments grid operators will need to make to deploy V2G technology outside of concentrated recharging stations, which are the subject of the current tests. In other words, is this truly feasible technology for home installation, or only for commercial fleets?
The significance of utilizing EV batteries for backup power is the plan of clean energy proponents to offset the huge increases in electric power necessitated by a shift to an all-electric transportation system. Bloomberg New Energy Finance forecasts global electricity demand to rise 300-fold due to the growth of EV’s. That means an increase from 6 terawatt-hours (TWh) in 2016 to 1,800 TWh in 2040. In 2040, electric transportation would represent 5% of global electricity demand. In Europe, the share of electric vehicles is assumed to reach 80% by 2050. This would require an additional 150 gigawatts (GW) of electrical capacity. The share of total electricity demand just for charging EVs varies between 3% and 25%, depending on the number of EV’s assumed in each country.
In another assessment, the International Energy Agency (IEA) suggests EVs will add over 30 TWh of installed battery storage capacity by the 2040’s. This means EVs would become a cheap way to deploy energy storage, with no extra capital cost and relatively low operating costs.
Will California actually end up banning ICE vehicles in 2035? It is one thing to sign an executive order dictating a radically different vision of the future than currently assumed, but it is quite another thing to see such a vision become reality. That is especially true when one realizes how quickly 15 years passes. Not everyone thinks Gov. Newsom’s plan is that radical. The Union of Concerned Scientists calculated that under the plan, ICE vehicles could still make up almost half the cars on California’s roads in 2035, something it still considers unacceptable.
To appreciate the work needed to transform California’s power grid, as well as increase it to meet EV charging demand, here are some numbers from the California Energy Commission. Last year, California’s in-state and imported electricity generation totaled 277,704 gigawatt-hours (GWh). Nearly 28% of that total was imported. While total electricity generation has declined in the past few years, it showed a steadily increasing trend from 1983 until the financial crisis in 2008. In our accompanying chart, we show the history of in-state generation, as well as imported generation. The most interesting point of the chart is imported generation’s share of total generation. When we fit a linear trend line, it was absolutely flat at about 30%.
Using 2019 data, and assuming no change due to different population and/or economic conditions, the estimated 25% increase in power needs to satisfy EV charging requirements would add 69,400 GWh to the total. With the state moving toward a grid powered completely by clean energy, its ability to import power from neighboring regions will be challenged since those states increasingly will need all their currently surplus power, as they pursue similar clean energy agendas. If we assume California must replace all its imported generation, in addition to meeting the EV power growth, the state will have to expand its in-state generation by 73%. We would also point out that 9% of current power comes from nuclear power plants destined to be shut down, besides natural gas plants. We would describe the future California power market as walking on a treadmill set to its highest slope.
Exhibit 25. California Electricity Depends On Imports
Source: California Energy Commission, PPHB
With the backdrop of wildfires, banning ICE vehicles would seem to be a logical move. The reality is that this governor will not be around when the fallout from the execution of his executive order comes into play. It also assumes people shift into gear immediately to implement it. Our belief is that few utilities, regulators or governments are ready to move. Does anyone remember what another California governor ordered 15 years ago?
In 2004, via executive order, former Gov. Arnold Schwarzenegger ordered preparation for the arrival of zero-emission, hydrogen-powered cars, buses and trucks. This was an early blow against climate change, but the revolution never followed, despite the state having spent more than $300 million in the past 10 years funding rebates for those who buy or lease hydrogen cars, construction of refueling stations, and the purchase of transit buses, as well as subsidizing development of hydrogen-fueled heavy-duty trucks.
Today, California represents the hydrogen car market. All but a handful of the 7,800 hydrogen-powered cars in the United States are there. The state is also home to most of the nation’s 43 hydrogen refueling stations. All of a sudden, people are beginning to wonder if the hydrogen age will finally blossom in California. EVs have more momentum, and their economics, although still disadvantaged even with subsidies, are better than hydrogen. However, the environmental fallout from battery materials may become a greater concern down the road, restricting the growth of EVs. Without sufficient power, EV buyers will not buy them, even if alternatives are banned. They will travel outside of the state to buy new ICE vehicles elsewhere and register them in California, as their use is not banned by the executive order. This will also provide a huge lift to the used car market. Those of a certain age remember California dreaming, but they also remember Hotel California. The former is happy. The latter a horror. Which will characterize the California of 2035?
Supreme Court And Climate Change Could Help Oil Industry (Top)
Last Friday, the U.S. Supreme Court agreed to hear an appeal by major international oil companies contesting Baltimore’s lawsuit seeking damages for the impact of global climate change filed in Maryland’s state courts. The justices will consider if the lawsuit must be heard in state court – as the city would prefer – or in federal court, which the corporate defendants argue is the appropriate venue given that carbon emissions are a national rather than a local issue.
The announcement is significant as multiple states including Rhode Island, New York, Massachusetts and various cities have sued the energy companies, first in federal courts, but then in state courts. The state attorneys general have moved to state courts because the initial suits filed in federal courts in California were tossed for being the wrong venue and the issue really being a legislative matter rather than a legal matter. State courts provide a more sympathetic playing field for state attorneys generals filing their suits.
This move was a surprise, but likely reflects the seriousness of the debate over climate change and whether it is a national rather than a local issue, which influences the appropriate venue for adjudicating it. In 2011, the Supreme Court held unanimously in AEP v. Connecticut that regulating CO2 emissions is the Environmental Protection Agency’s (EPA) job. The opinion for the court was authored by Justice Ruth Bader Ginsburg. A favorable Supreme Court ruling on the Baltimore case would mean less litigation for the oil industry.
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Parks Paton Hoepfl & Brown is an independent investment banking firm providing financial advisory services, including merger and acquisition and capital raising assistance, exclusively to clients in the energy service industry.
