On August 21st, a total solar eclipse will sweep across the United States. This will be the first total eclipse that is visible across the contiguous U.S. since 1918, and the first total eclipse visible from the mainland U.S. since 1979.
Needless to say, this is a rare event.
Nevertheless, it is one of those intermittent events that will impact solar power output. The California Independent System Operator (California ISO), which manages most of the high-voltage power lines in the state (and in parts of Nevada), has been preparing for this eclipse for more than a year.
Why Planning Is Required
You may ask why there is a need for extensive pre-planning, given that solar photovoltaic (PV) output drops to zero every night, and therefore grid operators and power plant managers already know how to deal with solar intermittency.
There are a couple of things to consider. Although California is south of the path of the total eclipse, the state will experience a partial eclipse ranging from ~90% in the northern part of the state to ~60% in the south of the state. The entire state will experience a partial loss of solar power at approximately the same time — an extremely rare daytime event.
Of course, that’s no different than what happens every evening when the sun goes down. The difference, in this case, is that the eclipse will occur late in the morning when solar PV systems are typically near peak output. It also takes place at a time of year when air conditioning demand is high. Sometimes, during periods of high demand, cloud cover can diminish solar PV output in a particular area, but never across the entire state at once.
What that means is that solar power is going to ramp down rapidly across the entire state during a period of relatively high demand — and at a time when peaking power plants are usually not required to operate.
Posted in Forbes
Given all the media hype about peak oil demand — which is supposed to come about largely as a result of the explosive growth of electric vehicles (EVs) — you might be forgiven for missing the news that U.S. gasoline demand just hit a new all-time high. This new demand record comes despite EV sales that tripled in the U.S. from 2012 to 2016.
My news feed tends to be dominated by headlines like Goldman Sachs warns of peak oil demand by 2020 (even though that headline doesn’t accurately reflect what the article said). But do the facts contradict the narrative? Sensationalism dominates the news, and the idea that oil demand will begin to decline shortly is definitely sensationalistic. I believe that this is one reason oil prices remain depressed because it perpetuates expectations that oil’s days will soon be at an end.
Every Wednesday the Energy Information Administration (EIA) releases its Weekly Petroleum Status Report. Last week’s report noted that Finished Motor Gasoline supplied in the U.S. for the week ending 7/28/17 was 9.842 million barrels per day (BPD). That is a record, and not just seasonally. Last week’s gasoline demand was the highest weekly U.S. gasoline consumption on record. The top four weekly gasoline consumption numbers on record have all occurred in 2017 — not exactly what one might expect given all of the “peak demand” articles that are all the rage.
Not only are we using record amounts of gasoline in the U.S., but refiners are also exporting record amounts of crude oil and finished products — more than 3 million BPD (even though the U.S. is still a net importer of crude oil). And just to be clear, the gasoline consumption numbers reported above do not include gasoline that is exported. The EIA specifically notes:
Product supplied: In general, product supplied of each product in any given period is computed as follows: field production, plus refinery production, plus imports, plus unaccounted-for crude oil (plus net receipts when calculated on a PAD District basis) minus stock change, minus crude oil losses, minus refinery inputs, and minus exports.
California is responsible for nearly half of all EV sales, with explosive growth in recent years. You might expect to at least see a decline in gasoline demand there. But gasoline demand in California has climbed each year since 2013 and is on track to rise again this year. Since 2013, gasoline demand in California has grown by 850 million gallons (~6%).
The reason gasoline consumption continues to increase despite the rapid growth of EVs is that the population continues to grow. I believe that this variable is generally missed by those calling for a short-term peak in oil demand. The problem is more complex than “More EVs = less oil consumption”, but that’s how it’s being treated by some analysts. Thus, as a result of this glaring blind spot, it should come as no surprise that gasoline demand trends don’t match the narrative that is being constructed.
Posted in Forbes
Underneath the surface of North Dakota is the Bakken Formation, which is part of the Williston Basin that also lies underneath parts of South Dakota, Montana, southwestern Manitoba and southern Saskatchewan. Last week I was in Bismarck, North Dakota at the 2017 Bakken Conference and Expo. I spoke about my company’s efforts to eliminate natural gas flaring in oil fields and then drove around the state to observe the most recent drilling activity there.
The Bakken was known to contain oil for many years, but it just wasn’t economical to produce. Hydraulic fracturing and horizontal drilling changed that. Up until about 2008, North Dakota hadn’t produced much more than 100,000 barrels per day (BPD). But in 2008 the shale oil boom started to pay dividends. In late 2008, North Dakota’s oil production reached 200,000 BPD and then climbed steadily to a peak of 1.2 million BPD in late 2014.
As production in the Bakken Formation boomed, infrastructure raced to catch up. This often meant that there was insufficient takeaway capacity for natural gas that is co-produced with oil (“associated gas”). The result was a significant amount of natural gas flaring in the state, which the North Dakota government sought to address through legislation.
In early 2014, North Dakota was flaring 36% of its natural gas production. An article from the Energy Information Administration last year stated that the amount flared had fallen to 10% of the state’s natural gas production by March 2016, but that also corresponded to a period of time that oil prices collapsed (which subsequently caused drilling activity in the state to plummet).
In 2014 there were around 200 rigs drilling for oil in the Williston Basin. By March 2016, the rig count had fallen to 31. That ultimately fell to a low of 22 rigs in May 2016, but the number has since rebounded back to more than 50 rigs. That, in turn, has resulted in a small rebound in North Dakota’s oil production.
Following my talk in Bismarck, I spent a couple of days driving around the North Dakota Bakken region to get a sense of the drilling activity in the state. According to Baker Hughes, there are currently 53 rigs drilling for oil in North Dakota, and I managed to find most of them as I drove around the state. Below are a few of my observations about the early stages of the Bakken Shale Boom 2.0, along with some photos I took.
Let me be clear that just because a company is flaring, they aren’t necessarily doing anything in violation of the law. There are plenty of reasons companies are allowed to flare, but the gas that is flared is a wasted resource that could potentially be utilized. But I don’t want to give the impression that I am suggesting these companies are doing anything wrong.
The “peak demand” hypothesis is the idea that demand for oil will peak as alternatives to oil become widespread. The notion that peak demand will happen within the next few years – and that EVs will be the primary driving force behind this shift – has gained in popularity over the past couple of years, particularly among cleantech enthusiasts. Bloomberg has especially pushed this narrative in several articles (See here, here or here). One Bloomberg article last year argued that EVs could cause a permanent oil crash as soon as 2023.
Norway’s experience is perhaps instructive.
In response to generous incentives and some of the highest gasoline prices in the world, Norway’s electric vehicle (EV) sales have grown at the fastest rate of any country in the world. Over the past seven years, Norway’s EV sales have averaged more than a 90% annual growth rate.
At the end of 2016, EVs had achieved a 5% share of all passenger cars on the country’s roads. This is greater than five times the market share in the U.S. Last week it was announced that 42% of all Norway’s new car sales in June were EVs.
Given Norway’s leading position in this space, we can gain some insights by examining the impact of EV sales on the country’s oil demand.
In 2005, there were 167 electric vehicles on Norway’s roads. By 2015, that number had exploded to just under 40,000. Yet according to the 2017 BP Statistical Review of World Energy, Norway’s oil consumption in 2015 was 6% higher than it was in 2005. Further, in 2016 when Norway’s EV sales eclipsed 50,000 vehicles and reached a 5% market share, oil demand rose again to within 0.7% of its all-time high mark set in 2013.
There are some legitimate reasons why Norway’s oil consumption grew even as EV sales were skyrocketing. A growing population can help explain this seeming discrepancy. But it becomes harder to rationalize when Norway’s oil consumption growth is compared to that of its peers. Norway isn’t a member of the European Union, but it is surrounded by EU members. It is also bordered by other Scandinavian countries with similar demographics. Yet the EU as a whole and all of Norway’s neighbors saw oil demand decline over the past decade:
The exception to the rule of declining oil consumption was the world’s leading EV market.
I don’t raise this issue to denigrate Norway’s experience, nor to suggest that EVs won’t eventually make a notable impact on oil demand. Indeed, I think if the growth trajectory continues, that will indeed happen.
My point is that it won’t necessarily happen as quickly as proponents think because the equation is more complicated than “More EVs = Less oil demand.” That’s the narrative being pushed by some, but Norway’s example shows that it isn’t as simple as that. The U.S. is also well behind Norway in both EV market share and growth rate, so that would argue for a longer timeframe for peak demand in the U.S. (as far as EVs are concerned).
Posted in Forbes
The first half of 2017 marked the worst first-half performance for crude oil since 1998. The price of West Texas Intermediate (WTI) and Brent crude both fell 14% in the first half of the year. Coal and natural gas also declined by more than 10% in the first half.
Nearly every segment of the energy sector was hard hit. The Energy Select Sector SPDR ETF, which represents the largest energy companies in the S&P 500, declined by 14.8% in the first half. The S&P Oil & Gas Exploration & Production SPDR ETF, which is more representative of the smaller oil and gas drillers, had a total shareholder return (TSR) of -22.9%.
Among the 20 largest North American and Western European energy companies, only four registered positive returns. The top performer of this group was Williams Partners LP, with a TSR of 9.3%. The worst performer of this group was Schlumberger with a TSR of -20.5%.
Among the five supermajor oil and gas companies, the top performance was turned in by Royal Dutch Shell with a TSR of 0.7%. Chevron was last among this group with a TSR of -9.6%, followed closely by ExxonMobil at -8.9%.
The carnage was so extensive that only two of the Top 50 oil and gas producers had a positive return in the 1st half. The top performer in this group was Rice Energy, which returned 24.7% in the first half. Rice surged recently on news that it is being acquired by EQT Corporation.
The midstream sector performed better than upstream. The Alerian MLP Index, which captures about 75% of the midstream sector’s market, registered a TSR for the first half of -6.3%. The top-performing MLP for the first half was Southcross Energy Partners LP, which notched an impressive TSR of 135%. But this followed a disastrous 2016 which, among other things saw its parent enter and exit Chapter 11. Since the beginning of 2016, SXE is still down by 11%.
SXE was the only MLP with a triple-digit first-half performance. Noble Midstream Partners LP, the 2nd best performer, registered a TSR of 26.2%. Also topping 20% for the first half were VTTI Energy Partners LP, Western Refining Logistics LP, and EQT GP Holdings LP.
Downstream companies fared better than upstream or midstream, as one might expect in an environment of declining oil prices. Most of the major refiners turned in positive first half performances. The best performer among the refiners was Alon USA Energy with a first half TSR of 19.9%. Delek US Holdings notched a return of 11.2%, while Tesoro followed at 8.4%. Valero, the world’s largest independent petroleum refiner, barely broke even with a TSR of 0.8%, while Phillips 66, a major holding in Warren Buffett’s portfolio, declined by 2.7%.
Back in January, I warned investors in Why The Ethanol Industry Should Fear President Trump that the new administration posed unique risks for the ethanol industry. At the time, I wrote, “The downside [for ethanol companies] seems relatively high given the risks ahead, and it’s hard to see much upside past this year.”
In fact, three of the four worst downstream performers were biofuel companies, and two of them are pure ethanol companies. Advanced biofuel maker Amyris Inc turned in the worst performance with a first half TSR of -71.0%, followed by ethanol producers Pacific Ethanol Inc at -34.2%, and Green Plains Inc at -25.4%.
But the brightest spot in the sector in the first half was the solar sector. The Guggenheim Solar ETF is a global index that tracks companies within several business segments of the solar power industry. The ETF had a first-half TSR of 20.0%, handily outperforming even the broader market benchmarks. SolarEdge, a maker of inverters for solar photovoltaic (PV) systems, soared by 61.3% in the first half. (Full disclosure: I own shares of SolarEdge). First Solar, a provider of PV systems, rose by 24.3%. Chinese solar PV provider JinkoSolar rose by 36.6%.
The solar sector clearly has momentum headed into the second half of the year. Even though it had a terrible first half, so does oil as the half closed out with seven straight winning sessions for crude prices. The midstream sector also finished strong, but rising oil prices could spell trouble for downstream companies in the second half.
Posted in Forbes
Last month the BP Statistical Review of World Energy 2017 was released. This report gives us the opportunity to review the big picture when it comes to global energy supply and demand. I consider the BP Statistical Review to be the bible of energy statistics. The report provides a comprehensive picture of supply and demand for all the key energy sources on a country-level basis.
Since its release, I have been busy analyzing the data and creating graphics. Today I want to review some highlights from the report, which covers global energy production and consumption through 2016.
I briefly addressed oil consumption in Peak Oil Demand Is Millions Of Barrels Away. Global oil consumption rose 1.6% in 2016 to a new record high of 96.6 million barrels per day (BPD). This growth rate was well above the 10-year average growth rate of 1.2%. U.S. demand rose by 0.5% to 19.6 million BPD, the highest demand level since 2007. After falling steadily for several years, demand in the European Union has now risen two years in a row. EU demand in 2016 was up 1.8% over 2015 to reach 12.9 million BPD, the EU’s highest demand since 2012.
The highest growth rate in the world took place in Pakistan, which saw a 12.0% increase in demand over 2015. Other countries with fast-growing demand included the Philippines (+9.0%), Poland (+8.8%), Slovakia (+8.5%) and India (+7.8%). China’s demand increased by 3.3%, well below its 10-year average growth rate of 5.7%.
On the supply side, global oil production advanced by 0.5% to reach 92.2 million BPD.* The U.S. remained in a dead heat with Saudi Arabia for the crown of the top oil producer. The top three producers were the U.S. (12.4 million BPD), Saudi Arabia (12.3 million BPD), and Russia (11.2 million BPD). It is worth noting that BP’s definitions include natural gas liquids (NGLs) in the oil production numbers, which is the only reason U.S. production numbers are as high as they are.
The greatest percentage increase in oil production took place in two OPEC countries. Production in Iran rose by 18.0% (700,000 BPD) and production in Iraq was up by 10.8% (400,000 BPD). This marked the highest production level for Iran since the 1970s and was the highest-ever production level for Iraq.
However, some of the largest percentage declines were seen in two other OPEC countries, with Venezuelan production declining by 8.9% (234,000 BPD) and Nigerian production falling 11.9% (277,000 BPD). Overall OPEC production rose by 1.2 million BPD, while non-OPEC production declined by 780,000 BPD.
(*According to BP: Differences between these world consumption figures and world production statistics are accounted for by stock changes, consumption of non-petroleum additives and substitute fuels, and unavoidable disparities in the definition, measurement or conversion of oil supply and demand data).
There is currently no energy source with such a long and consistent track record of demand growth as natural gas. For more than 50 years, natural gas demand has steadily grown, with only one significant down year during that time (during the financial crisis of 2008-2009):
The U.S. is the world leader in both consumption and production of natural gas. The 75.1 billion cubic feet (BCF) the U.S. consumed in 2016 was more than the entire Asia Pacific region consumed, and was nearly double the 37.7 BCF consumed by Russia, the world’s second largest consumer.
The 5.1 BCF year-over-year (YOY) increase in U.S. consumption was also the world’s largest, but the largest percentage increases in consumption were seen in Israel (+14.5%), the Philippines (+14.3%), Ireland (+14.0%), the United Kingdom (+12.2%) and Chile (+11.1%).
Natural gas production exploded in the U.S. as a result of the shale gas boom, growing by nearly 50% from 2006 to 2015. Last year low natural gas prices brought an end to an 11-year streak of increasing production in the U.S., but the 72.3 BCF produced by the U.S. was still far ahead of 2nd place Russia’s 55.9 BCF. To put U.S. natural gas production into perspective, it was greater than all Middle East production of 61.5 BCF in 2016.
U.S. trade in natural gas also surged in 2016. Pipeline exports of natural gas grew 23% over 2015, primarily driven by growing trade with Mexico. Liquefied natural gas (LNG) exports from the U.S. increased from 24 billion cubic feet in 2015 to 155 billion cubic feet in 2016. The U.S. exported LNG to about a dozen countries in 2016, with 34% going to South and Central American countries, and 23% destined for countries in the Asia-Pacific region.
Global coal consumption declined by 1.7% to its lowest level since 2010. Coal consumption has been falling for a couple of reasons. Countries around the world are passing legislation to limit carbon dioxide emissions, and cheap natural gas and renewables are providing economic alternatives to coal.
Last year’s decline marks the second consecutive annual decline in coal consumption. China remains by far the world’s top consumer and producer of coal, with 50.6% of the world’s consumption. But China’s consumption declined last year as well, which accounted for about 50% of the global drop in coal consumption.
Almost every region of the world saw a decline in coal consumption. In the Organization for Economic Co-operation and Development (OECD) countries — primarily the world’s developed countries — coal consumption fell by 6.4%. In the European Union, it declined by 8.9%.
U.S. coal consumption continued to fall sharply. The 8.8% decline in consumption took U.S. coal demand to its lowest level since 1978. U.S. coal production followed, with a 19.0% decline to levels also not seen since the 1970’s.
India was a notable exception with a 3.6% increase in coal consumption. Indonesia, Malaysia, and Pakistan all saw coal consumption grow at double digits, but from relatively low consumption levels.
In an upcoming article, I will cover the data on renewables and nuclear power.
Posted in Forbes
Last month BP released its Statistical Review of World Energy 2017. Overall world primary energy consumption hit a new record, increasing by 171 million metric tons of oil equivalent (MTOE) from 2015 to 2016. The largest share of that increase came from new oil consumption, which accounted for 77 MTOE of the increase. Natural gas took the second biggest share with 57 MTOE of new consumption.
Interestingly, coal consumption declined by 53 MTOE, but modern renewables like wind and solar power increased by 53 MTOE. So one could accurately argue that the increase in the consumption of modern renewables like wind and solar power exactly offset the decline in coal consumption. That seems to be the first time that has ever happened.
The balance of the energy consumption increase was made up of increases in nuclear power (+9 MTOE) and hydropower (+27 MTOE).
Over the past decade, global primary energy consumption has increased by 17%, but the energy mix is slowly shifting. For overall energy consumption in 2016, fossil fuels continued to maintain a dominant share. Oil led all sources with a third of global energy consumption.
Coal still had the second largest share with 28% of global consumption, but natural gas at 24% is closing the gap on coal. In 2016, fossil fuels made up 85% of global energy consumption. Nuclear contributed 5%, while renewables like wind, solar, geothermal, and biomass contributed 3%. Along with hydropower, renewables made up 10% of primary energy consumption.
For reference, in 2010 the renewable share was 1.3%, and fossil fuels were at 86.9%. So global energy systems are shifting, albeit it slowly because of the large share held by fossil fuels. Renewables will likely keep growing at exponential rates for the foreseeable future, and even then it is going to take some time to capture significant market share from fossil fuels.
Posted in Forbes
As a long-time investor in the energy sector, the current quarter has been one of the worst I can recall. It seemed like the market had turned the corner in 2016 when energy was the top-performing sector following two difficult years, but the price of West Texas Intermediate (WTI) is now down 20% from this year’s highs. Many are wondering why the bear market has returned.
There is one fundamental reason for the weakness in oil prices and that is record global crude oil inventories. These record inventory levels resulted from two primary causes. The first is that since 2008, the U.S. shale oil boom has put about five million barrels per day (BPD) of additional oil on the markets.
The market largely discounted this unexpected surge of U.S. production, and crude oil prices held steady at around $100/bbl for far longer than they should have. Lingering high prices worsened the oversupply situation by keeping too much marginal production on the market.
But in mid-2014, the market could no longer ignore growing crude oil inventories, and oil prices finally broke decisively below $100/bbl. In November 2014, following a $25/bbl decline in crude oil prices, OPEC decided that instead of attempting to balance the market, it would defend market share. Over the next two years, the group added two million more BPD of crude into an already oversupplied market.
Even though global crude oil demand continued to grow at a healthy rate, it couldn’t keep pace with the surge of production from U.S. shale producers and from OPEC. The world built a massive oversupply of crude oil, and that oversupply just continued to grow. OPEC finally reversed course in November 2016 and instituted production cuts, but at the same time, U.S. shale oil production — which had dipped in response to low prices — began to bounce back.
Several fears will likely drive the market for the foreseeable future. One is that crude oil inventories will remain high for a long time. Thus, the upside potential for an investor is limited. Second is that U.S. production gains will nullify the impact of OPEC’s production cuts. Should that happen (and it may), then OPEC is going to have to decide whether to make deeper cuts or return to the strategy of defending market share (which could send oil back into the $20s).
Further weighing on investors’ minds is the constant drumbeat of stories suggesting that the world is on the cusp of peak oil demand. In that scenario, oil prices may never recover. (That’s certainly not something I believe; see my previous Forbes article Peak Oil Demand Is Millions Of Barrels Away).
The peak demand belief is that in essence alternatives to oil will soon result in falling demand (as has been the case in the coal industry), which will render oil far less valuable. That this belief is helping suppress oil prices is somewhat ironic, considering that a decade ago peak supply fears helped drive up the price of oil.
Global inventories will be impacted by OPEC’s cuts, gains in U.S. shale production, and increases in demand. I can rationalize why I think the impact of growing demand and OPEC’s cuts will trump the growth in U.S. shale production, but the theory ultimately has to manifest itself in lower inventories.
So the bottom line comes down to crude oil in storage. What the market needs to see are major reductions in crude oil inventories, but that’s going to take time. Inventories are coming down, but in a bear market like this bad news has a far larger impact that positive news. The bullish news of five straight inventory declines can be undone by one surprise inventory build, sending prices reeling.
That’s likely to be the status quo for a while. It’s hard to say where the bottom is on oil prices. The current price is unsustainable long-term for producers (long-term investors take note), but the only thing that’s going to turn this market around is lower crude oil inventories.
Posted in Forbes
The notion that demand for crude oil will soon peak has largely replaced the idea from a decade ago that crude oil production was about to peak for geological reasons. This new idea is that we will no longer need oil (or at least a lot less of it) because consumers will choose alternatives to oil.
But actual oil consumption numbers suggest that peak demand for oil won’t happen soon, and when it does happen it will do so at a demand millions of barrels per day (BPD) higher than current demand.
Proponents of peak demand expect that exponential growth in electric vehicles (EVs), and to a lesser extent an increase in biofuel production will send oil demand into permanent decline. In fact, nearly a year and a half ago Bloomberg suggested that at a continued annual growth rate of 60%, electric vehicles could displace two million BPD of oil by 2023. At a 30% growth rate, two million BPD would be displaced by 2025.
I addressed the key problem with the Bloomberg scenario here. In a nutshell, the article treated oil demand as stagnant, which resulted in the assumption that in 2023 the displacement would take place from current demand levels. In other words, if 2016 demand was 95 million BPD, the Bloomberg scenario presumed 2023 demand at 93 million BPD (and falling every year).
The flaw in the scenario is that for over 30 years average oil demand has grown each year by more than a million BPD. Over the past decade, oil demand has grown each year by 1.1 million BPD. Over the past five years, 1.4 million BPD. Last week the bible of energy statistics was released — the BP Statistical Review of World Energy 2017 — and it showed that oil consumption grew by 1.6 million BPD last year:
Oil consumption in 2016 represents a new all-time high in global oil demand and occurred despite the fact that global EV sales grew at a 41% rate in 2016 to reach nearly 800,000 vehicles (Source: InsideEVs). The growth over the past decade also took place during a time that global biofuel production increased by over a million BPD. (I can recall many who suggested ten years ago that growth in biofuels would lead to peak oil demand).
Underlying oil demand is growing for several reasons. The population is growing, the middle class is growing, automobile sales in developing countries are growing at a blistering pace, and the number of miles driven is reaching all-time highs.
The implications are clear with respect to the peak demand argument. While many proponents are pushing the notion that peak demand is imminent, growth in EVs thus far hasn’t even been able to slow down oil demand growth.
What peak demand will actually look like — assuming EV sales continue at exponential growth rates — is for oil demand growth to first slow down. What we may see is that in contrast to Bloomberg’s scenario of 2023 demand being two million BPD less than current demand, it might only be five million BPD higher than today’s demand (instead of seven, which assumes the growth rate of oil remains consistent). In fact, oil demand today is close to two million BPD higher than it was when Bloomberg made its forecast in February 2016.
The bottom line is that even in a best case scenario for EV growth rates, demand for oil rose by 1.6 million BPD last year, and it’s projected to increase by 1.4 million BPD this year. It will take a few years of rapid EV growth to halt the growth rate for oil, and what that means — and what many peak demand proponents don’t get — is that peak demand for oil is going to be millions of BPD higher than current demand, and it’s almost certainly going to take place beyond 2023.
Posted in Forbes
It was clear from his statements while campaigning that if Donald Trump won the presidential election, it wasn’t going to be good news for renewable energy. President Trump has spent his time in office so far undoing environmental regulations and trying to fulfill his campaign promise to revive the coal industry. The latest move in that direction was President Trump’s announcement that the U.S. will pull out of the Paris Accord on climate change.
The intricacies around the Paris Accord could cover several posts. But the optics of this are terrible for the U.S. on the world stage. Opponents of the agreement cite the costs to the U.S. economy. Trump himself stated that the agreement is unfair to the U.S. and that he hoped to negotiate a better agreement.
If you disagree that the world needs to take action to prevent the unabated rise of carbon dioxide emissions, then you need read no further. I am not going to argue that case in this article. But if you at least agree that there is a risk associated with failing to curtail emissions, let’s first consider historical and current emissions.
According to the 2016 BP Statistical Review of World Energy, since 1965 the U.S. has emitted 264 billion metric tons (BMT) of carbon dioxide. This was nearly 24% of the world’s total carbon dioxide emissions during that time and represents the most of any country in the world. In comparison, over that same time span, the European Union emitted 209 BMT, China emitted 169 BMT, and India was way down the list with only 39 BMT.
So the U.S. ranks first among countries responsible for the current inventory of atmospheric carbon dioxide. But the direction of trends in recent years suggests that this won’t remain the case. China’s annual emissions exceeded those of the U.S. in 2006, and by 2015 had increased to 67% higher than annual emissions in the U.S. India’s emissions have doubled in the past dozen years, and on the current trajectory will reach U.S. emission levels toward the end of the next decade.
In fact, carbon dioxide emissions in the Asia-Pacific region are nearly double the combined emissions of the U.S. and the European Union, and they are rising rapidly:
It seems pretty clear that the Asia-Pacific region will be the most important driver of carbon dioxide emissions in the near future, and that it is imperative to rein them in. But the Paris Accord was not going to accomplish this. The treaty was non-binding, and analysis by the International Energy Agency concluded that the agreed upon measures fell far short of what was needed to achieve the treaty’s goals.
But it is also clear that the atmospheric concentration of carbon dioxide reached its current level above 400 parts per million (PPM) with significant contributions from the U.S. and the EU. So this is a problem in which there are multiple responsible parties, and it will require cooperation among all of them if there is any hope of coming up with a solution.
Thus, the U.S. must not abdicate leadership on this issue. We must take responsibility for our historical emissions while helping developing countries avoid taking the same high-emissions path to development. Not only do we need to maintain a seat at the negotiating table, but we need to let the rest of the world know we are serious about addressing the problem. We can’t give other countries the excuse of not meeting their commitments that the U.S. decided not to participate.
Further, there may be other real costs to the U.S. for abandoning the agreement. Some countries may opt not to trade with a country that isn’t a participant. We could also lose our advantage in the cleantech industry to other nations. It wouldn’t be the first such industry the U.S. has lost.
Our long-term future is in clean energy. It will be a shame if we have to depend on other countries for that energy. By abandoning commitments to clean energy, that’s exactly what we risk.
Posted in Forbes