Fossil Fuels

News outlets are reporting that a congressional budget deal could end the oil export ban in exchange for extension of the Investment and Production Tax Credits (ITC and PTC) that support solar and wind energy. Here I want to lay out what ending the oil export ban could mean for markets, climate, and geopolitics. (I suspect Varun may weigh in later on the ITC/PTC extensions if and when details emerge.) Short version: Little immediate impact on anything; a possible boost on the order of a few hundred thousand barrels a day to U.S. oil production over the longer run; a factor of perhaps fifty smaller impact on carbon dioxide emissions than the Clean Power Plan and CAFE (fuel economy standards); and a mixed bag for geopolitics and trade talks. Markets There is currently little if any incentive for U.S. oil producers to export crude oil even if the ban is lifted. Light sweet crude oil for January delivery in Northwest Europe (Brent) – the destination most commonly envisioned for U.S. crude oil exports – is currently selling for less than similar oil delivered on the Louisiana coast (LLS). It costs in the neighborhood of three dollars a barrel to ship oil from the U.S. Gulf coast to Europe. Spending three dollars in order to lose money is not something sane people do. (The spread could, of course, change, particularly during refinery turnarounds.) The result is that large sustained oil export volumes are unlikely to materialize soon. This should remain unchanged until U.S. oil production recovers to substantially above previous highs. U.S. refineries were previously able to accommodate U.S. production despite the export ban; they will presumably continue to be able to unless and until production rises above historic highs. And then what? To get a sense of the possible longer term impact of lifting the ban, take a look at the Energy Information Administration (EIA) modeling of what would happen to markets if the ban were lifted. In its reference case, which is its best guess of reality, lifting the ban has no impact on U.S. production or prices because U.S. refineries can absorb all the oil that the United States produces. In its high resources case, where U.S. oil resources turn out to be considerably more plentiful than the EIA currently estimates, it estimates that U.S. production would be 220 thousand barrels a day higher, on average, between 2016 and 2025, without the oil export ban than with it. The EIA modeling also projects that world oil prices (Brent) would drop by roughly a dollar on average over the next decade, while domestic oil prices (WTI) would rise by about four dollars on average over the same period, if resources were abundant and the ban were lifted. The EIA is of course fallible. But these numbers comport well with basic intuition. Were the ban to remain in place, U.S. oil could still make it to world markets if demand were there; it would just need to be refined and exported as product (gasoline, diesel, etc.), which is already legal. Refining light sweet crude oil costs a few dollars a barrel. Domestic prices would therefore need to be a few dollars lower with the ban than without it in order to make the economics of exports work. It’s tough to see how a few dollar difference in oil prices would alter domestic oil production by more than a few hundred thousand barrels a day. (The studies that claim much larger consequence for oil production assume that domestic prices can detach from international ones by twenty dollars a barrel or more without prompting any investment in refining capacity; I find that sort of departure from rational profit-seeking incredibly unlikely.) And an additional few hundred thousand barrels a day on the global market shouldn’t lower world prices by more than something on the order of a dollar a barrel. That’s basically the same as what the EIA model says. Climate All of this has consequences for climate change too. Let’s use the EIA modeling again. In the reference case, lifting the ban has essentially no impact on production, prices, or actual exports. That means it has no impact on carbon dioxide emissions either. What about in the high resource case? The EIA estimates that U.S. production rises by an average of 220 thousand barrels a day over the next decade. This will be offset in part by lower production (as a result of lower prices) elsewhere. It’s reasonable to assume that the offset is on the order of 50 percent of the increase in U.S. production, which leaves us with a net increase of about 110 thousand barrels a day, or about 40 million barrels a year. If you figure a barrel of oil, when produced, refined, transported, and consumed, generates about half a ton of carbon dioxide emissions, this works out to about 20 million tons of additional carbon dioxide emissions annually. The number could be lower if the international production response was stronger than I’ve assumed. To put this all together, assume that there are 50/50 odds of being in the reference case world or the high oil resource world. (Alternatively, one could imagine that we’re in the no-exports world for five years because of weak global demand, and then in a modest-exports world after that.) Then, on average, we’d expect 10 million tons a year of additional carbon dioxide emissions on average over the next decade. Now put that in context: Ten million tons is roughly 0.2 percent of annual U.S. emissions. The Clean Power Plan (PDF) is estimated to reduce U.S. emissions by about 240 million tons a year by 2025 (and about double that by 2030). The fuel economy standards (CAFE) are estimated to reduce U.S. emissions by about 320 million tons a year by 2025 (and by about 170 million tons a year on average between 2016 and 2025). These policies dwarf the impact on carbon emissions of allowing oil exports. Geopolitics What about the impact on geopolitics? Allowing oil exports shouldn’t hit world oil prices much. The price collapse over the last year has far bigger consequences for oil exporters’ budgets than removing the oil export ban would. Allowing oil exports would, however, marginally strengthen the U.S. position in arguing for more liberal energy trade worldwide. It also would be welcomed by allies who believe (usually without justification) that access to U.S. oil will improve their national security. On the flipside, several European countries were hoping to gain access to U.S. oil exports though a Transatlantic Trade and Investment Partnership (TTIP). This prospect would have given U.S. negotiators some leverage to get other concessions in return. Allowing oil exports now would retire that card. Bottom Line An oil-exports-for-renewables-tax-credits deal looks likely to be a win-win. (I’ll reserve final judgment pending details of an ITC/PTC extension.) Removing the oil export ban is good policy. Supporting zero-carbon energy innovation, including through appropriate deployment subsidies, is good policy. Readers of this blog know that I’ve been arguing for a “most of the above” energy and climate strategy that supports some fossil fuels and some zero-carbon energy for several years. Congress has been too deadlocked to make the sorts of deals such a strategy prescribes. But the rumored budget deal looks like it would fit the “most of the above” approach nicely. [Post-publication update: The folks at Oil Change International reasonably point out that I’m considering only the supply side market response. So here’s a slightly more full-blown analysis. Let’s assume that oil supply elasticity is 0.5 and demand elasticity is 0.2. Then supply side policies get hit with a rebound of around 70% and demand side ones suffer about 30%. The impact of lifting the oil export ban becomes 0-15 million tons annually with a central estimate around 7 million tons. The impact of CAFE becomes 120 million tons annually. The impact of CPP is unchanged at 240 million tons in 2025 (leakage through coal markets has been small so far; leakage through gas markets is ambiguous, and could actually reduce world emissions in some cases). One still finds roughly a 50:1 ratio of impacts between the policies cited.]

This post was co-written with Cole Wheeler, CFR’s research associate for energy and the environment.  Unfettered access to U.S. liquefied natural gas (LNG) was reportedly a prime motivation behind Japan’s decision to join the Trans-Pacific Partnership (TPP) trade talks. The United States already gives automatic approval of exports to 18 other countries with which it has special free trade agreements (FTAs), but requires distinct permits for exports to others, including Japan. Yet there has been scant (if any) reporting on this issue since the release of the final TPP text two weeks ago, and there appears to be considerable confusion about what the deal actually does. A look at the text of the agreement in the context of U.S. law confirms that it grants automatic approval of exports to Japan and the other TPP member nations. The confusion seems to stem from the fact that the TPP text doesn’t mention natural gas at all. Rather, the critical element of the agreement is its language on “national treatment,” a trade law status which the TPP member nations commit to granting to each other’s goods, with no enumerated exception for natural gas. While national treatment doesn’t in itself provide the green light for all LNG exports to Japan, it triggers existing U.S. law in a way that does. Under the Natural Gas Act, any company wishing to export natural gas first needs authorization from the Department of Energy, which determines whether exports are “in the public interest.” For countries with which the U.S. has established an FTA including national treatment for natural gas, however, the law effectively waives this process, and requires DOE to grant authorization “without modification or delay.” A quick comparison of the TPP to the 2012 U.S.-Korea Free Trade Agreement, which is widely agreed to provide blanket approval for LNG exports, provides further confirmation of the TPP’s impact: like the TPP, the U.S. Korea agreement does not mention natural gas exports, but the language on national treatment is virtually identical to that of the TPP. The TPP’s approach to approving LNG exports shouldn’t come as a surprise. A January 2015 paper from the National Bureau on Asian Research, for example, described the “national treatment” recipe for automatic LNG export approval, and predicted that it was likely to be part of the deal. Other observers, from the Congressional Research Service to the International Business Times, also foresaw this outcome. All this said, it’s important to remember that the biggest barriers to LNG exports have always been commercial rather than legal. Several LNG exporters in the U.S. have already received authorization to export to non-FTA countries, and Japanese companies have signed contracts for the purchase of at least 100 billion cubic feet per year of U.S. LNG by 2020. But building LNG export terminals is expensive, and export capacity has lagged behind the massive increase in North American supply. Indeed, U.S. companies have had blanket FTA approval to export LNG to South Korea, the world’s second largest LNG importer, since 2012, but the first deliveries of U.S. LNG to South Korea are not expected until 2017. Moreover, even if export permits for Japan become easier to acquire, companies will still apply for permission to export freely, giving them the valuable option to sell to growing markets in China, India, and beyond. So why does this aspect of TPP even matter? Because of the confidence it provides. What Japan would gain from the TPP isn’t a sudden, massive increase in imports. It’s confidence in U.S. LNG as a reliable source of energy, insulated at least somewhat from the vicissitudes of U.S. energy politics. That matters not only for commercial dynamics and market flows, but for the broader U.S.-Japan relationship too.

It seems like a distant memory now, but just one month ago, the international community was lauding China for stepping up its commitment to address climate change by pledging to initiate a cap-and-trade system for CO2 by 2017 and contributing $3.1 billion to a fund to help poor countries combat climate change. Now, however, the talk is all about the release of a new set of game-changing Chinese statistics on coal consumption. A New York Times headline blared: “China burns much more coal than reported, complicating climate talks.”  And the Guardian reported: “China underreporting coal consumption by up to 17%, data suggests.” What does all this mean? The short answer is nothing good. Here are just a few of the implications: Chinese statistics are as unreliable as ever. China analysts, myself included, often say, “We don’t necessarily trust the statistics, we just look at the trend line.” This coal consumption recalculation, however, means that even this somewhat weak effort at analytical credibility no longer holds. Seriously, how does one ignore six hundred million tons of coal consumed in just one year? There have been some terrific articles on the problems with Chinese statistics over the past month by Gwyn Guilford and Mark Magnier. And there was a great report by Bloomberg that laid bare the metrics that different economic analysts use to arrive at their calculations of Chinese gross domestic product (GDP), some of which use data such as rail traffic and electricity production. Unfortunately, China’s massive coal gap suggests that even these analyses are relying on questionable data. Assuming that Chinese industrial production and manufacturing statistics are accurate, the dramatic increase in coal consumption that is now reported suggests that the gains in Chinese energy efficiency, as well as the reductions in energy intensity (the amount of energy consumed per unit of GDP), that have been touted over the past decade are much less than assumed—or perhaps they are nonexistent. China’s pledge that its CO2 emissions will peak around 2030 is suddenly much less significant than it was one year ago—and even then many analysts argued that it wasn’t significant enough. After all, we are now dealing with a baseline of CO2 emissions that is substantially higher than we originally believed. The question now is whether China will adjust its commitment to meet its newly revealed contribution to the problem. It is now all the more important that whatever steps China commits to take to mitigate its contribution to climate change are in fact realized. Doubts already have been swirling around China’s promise to implement a cap-and-trade system and to ensure that 20 percent of all its energy derives from renewables by 2030. China needs to put these doubts to rest. Once you head down the rabbit hole of what is fact in China and what is fiction, it is very difficult to crawl back out again. If one is looking for a light at the end of the tunnel, however, let me suggest two: first, the U.S. Energy Information Administration (EIA) had already released statistics on Chinese coal consumption in September that suggested that China had underreported its coal consumption by 14 percent during 2000-2013. It also, however, suggested that coal consumption was nearly flat in 2014. If the EIA is right on that score, then there may be some merit to all the reporting that China is turning the corner on its coal consumption, and the world could see a plateau in CO2 emissions (albeit at a much higher level) earlier than 2030. Second, the mere fact that the Chinese government actually reported the change in coal consumption is a positive. The timing of Beijing’s announcement, right before the Paris climate talks, may be unfortunate. However, greater transparency from a government that thrives on opacity is always welcome.

This is a guest post by Luis Ferreira Alvarez, an analyst with Stratas Advisors’ Global Biofuels Assessment and Global Alternative Fuels divisions covering Latin America.  As Brazil’s Petrobras corruption investigation continues to roil its economy and politics, the ethanol sector is emerging as a clear beneficiary. New government policies are boosting ethanol sales, chipping away at gasoline’s market share. Brazil’s ethanol comes from sugarcane. Each year producers look to market prices and expectations to decide where to direct their crops. When sugar prices fall, ethanol production increases (and vice versa). Producers must also bet on what type of ethanol will bring higher returns: anhydrous or hydrous. Anhydrous ethanol production is more costly, but demand is guaranteed by Brazil’s laws requiring it be blended into gasoline at the pumps. Hydrous ethanol is a neat fuel that’s cheaper to produce, but competes directly with gasoline. It also has a lower energy content, translating into fewer miles per gallon and meaning that prices must stay below 70 percent of gasoline prices to make it competitive.  The vast majority of Brazilian cars are flex fuel, capable of running on blended gasoline or hydrous ethanol. In 2014, Brazil produced 7 billion gallons of ethanol, making it the world’s second largest producer after the United States. Nearly all went to transportation, with anhydrous and hydrous ethanol accounting for nearly 50 percent of all vehicle fuel consumption (Figure 1). Figure 1: Gasoline and Ethanol Market Shares in 2015F  Stratas Advisors, "Global Biofuels Outlook," 2015. The last several years have not been easy for ethanol producers. The federal government reduced credit lines provided through the Brazilian Development Bank. Droughts hit harvests in the Center-South region, where some 90 percent of sugarcane is grown. Debt burdened companies, as many had taken out loans during former President Lula da Silva’s quest to make Brazil the “green Saudi Arabia.” And falling global sugar prices hurt an industry still recovering from the 2008 financial crisis. Government policies also undermined the ethanol sector. In its bid to control inflation, the government capped gas prices and removed the infrastructure tax (CIDE) on gasoline, making hydrous ethanol uncompetitive at the pump. Consumers quickly switched fuels, leading to a 10 percent decline in 2012 (Figure 2). As a result, many producers invested in anhydrous ethanol or switched back to sugar. Some forty other ethanol plants folded. Figure 2: Gasoline C and Hydrous Ethanol Prices in Brazil Stratas Advisors, ANP, August 2015. In the wake of the Petrobras scandal, the government implemented three major policy shifts to improve its finances and those of the state oil company. First, it increased the required ethanol share in gasoline from 25 percent to 27 percent. Second, Petrobras raised gasoline prices in late 2014. Finally, the government re-introduced the CIDE tax on gasoline in early 2015. Figure 3: Market Share of Pure Gasoline and Total Ethanol in Brazil Stratas Advisors, ANP, September 2015. Note: 2015 data is for January to July. These policy shifts, combined with rain in Brazil’s sugar-producing Center-South region, revitalized the ethanol sector. Producers shifted nearly 60 percent of their sugar harvest to ethanol, and sales rose 28 percent between July 2014 and July 2015 (Figure 3). Although challenges remain—producers are heavily indebted, global sugar prices are low, and gasoline price controls are still in place—ethanol may be among Brazil’s few stable sectors in the coming months.

The oil price collapse was supposed to boost the U.S. economy by prompting consumers to spend their savings on other goods and services. During the first half of this year, though, data seemed to suggest that they were saving the windfall instead, damaging economic growth. But new big data research from the newish JP Morgan Chase Institute appears to provide strong evidence that consumers did, indeed, spend most of their savings. It’s an intriguing energy result that also offers a glimpse into how changes in data availability and computational capacity are changing the sort of energy research that’s possible. The conventional wisdom until recently was that consumers had failed to spend a large part of their windfall from the oil price collapse. This first showed up in savings figures: as the oil prices fell, the personal savings rate rose, seeming to reveal that consumers were putting their oil money in the bank. It then appeared to be confirmed by consumer survey data. People took guesses as to what explained the phenomenon: Had a cold winter deterred consumption? Were consumers still skittish after the financial crisis? The big question wasn’t whether or not consumers were reaction timidly – it was whether they would eventually change course. Now the JPMC research concludes that consumers spent roughly eighty cents of every dollar they saved. They did this by using a database of transaction records from twenty five million credit cards that give them an extraordinary window into individual consumption patterns. They then applied some clever analysis to distinguish spending increases that were spurred by lower gas prices from ones that weren’t. This wouldn’t have been possible without the massive number of detailed records they had or the computational capacity to crunch through them. On its face, the result is good news: lower gasoline prices are stimulating the economy. But things aren’t quite so simple. Had consumers been hoarding their savings, we might have hoped that they’d eventually start spending them, boosting the economy as a result. The JPMC results suggest that that’s not a significant possibility. The research also implicitly raises questions about the reliability of consumer survey data. Researchers should also be left puzzling over why the savings rate jumped earlier this year. The new research is also a striking example of what big data analytics is making possible when it comes to energy research. We’ve seen a glimpse of that through companies that are studying behavioral responses to energy efficiency interventions. Now we have an application to an important macroeconomic question. One could imagine leveraging the kind of data that JPMC and other similar institutions have to understand more about how energy price volatility affects all sorts of consumer and business decisions; to gain insight into why American driving and gasoline consumption is rising again; to see how changes in drilling activity affect local economies; and, I’m sure, much more. The same is true for a whole host of economic questions that go well beyond energy. It’s worth staying tuned.

Last week, the British authorities arrested former oil minister Diezani Alison-Madueke for corruption, bribery, and money laundering. She has been released on bail. Often lauded as “among Africa’s most powerful women,” she was the first female Nigerian Minister of Petroleum, and the first female President of the Organization of Petroleum Exporting Countries (OPEC), a position she currently holds. A product of the Nigerian old-line establishment, Diezani Alison-Madueke’s husband is a retired Nigerian Navy admiral. Notorious for her over-the-top luxurious life style, for many Nigerians she was the face of corruption at the highest levels and on the Nigerian "street" she was widely hated for her arrogance. She was close to President Goodluck Jonathan, and it is often alleged that she diverted state oil revenue to the candidates and causes of his then-ruling Peoples Democratic Party (PDP). Her mother lives in London. She traveled there after the inauguration of President Buhari to seek medical treatment. The British press reports that British law enforcement had opened an investigation on her for corruption as early as 2013. Her arrest appears to be for the violation of British, not Nigerian, law. British police have seized over forty-one thousand dollars from her in London. At about the same time, Nigerian police sealed her residence in Abuja. It is unclear how much cooperation there is between the British and Nigerian law enforcement authorities on this case. In an earlier, notorious case of corruption, the British authorities arrested, charged, convicted, and jailed former Delta state governor James Ibori for violation of British law after a Nigerian prosecution failed. On October 7, Nigeria’s Economic and Financial Crimes Commission announced the arrest of Olajide Omokore, the chairman of Atlantic Energy. Forbes in 2012 listed him among Ten Nigerian Multi-Millionaires You’ve Never Heard Of. According to Forbes, his business interests include steel, oil, dredging, haulage, and property development. He, too, has been a major financial angel of the now opposition PDP. Meanwhile, President Buhari has issued another warning about corruption. It is likely that anxiety among some in the Nigerian political class is rising. In an environment that has been riddled with corruption, who is innocent? Where will the prosecutions stop? However, Buhari has signaled that a line will be drawn, that there will be no witch hunts. But, people remember when he was military chief of state and the federal military government’s vigorous prosecutions for corruption. It was during Buhari’s first administration that Nigerian authorities tried to kidnap from London Umaru Dikko to stand trial for corruption. Nailed into a crate labeled “diplomatic baggage,” he was freed by the British airport authorities. The result was a major diplomatic incident.

This post was co-written with Peyton Kliefoth, an economics major at Northwestern University and research intern at the Council. Over the weekend, I published a piece in Fortune Magazine explaining a surprising correlation between falling oil prices and tumbling shares of Yieldcos, which are publicly traded holding companies mostly comprising renewable energy assets in the U.S. and Europe (see chart below).   Comparison of oil price and share prices of the top seven Yieldcos, from June to September, 2015 (NYLD: NRG Yield, NEP: Nextera Energy Partners, TERP: TerraForm Power (SunEdison Subsidiary), ABY: Abengoa Yield, BEP: Brookfield Renewable Energy Partners, PEGI: Pattern Energy Group, CAFD: 8Point3 Energy Partners (joint venture between SunPower and First Solar))   Fundamentally, the value of solar and wind projects should not depend on oil prices, since oil is rarely used in the developed world for electricity and therefore doesn’t compete with renewable power generation. It turns out that the cause of falling Yieldco share prices has less to do with what is being traded than who is doing the trading—I write: Few paid attention to an ironic trend: the same investors holding oil and gas assets had also piled into an obscure but crucial class of renewable energy investment vehicles—so-called “Yieldcos”—driving down the financing costs of clean energy. As it turned out, renewable energy prospects hitched to the conventional energy bandwagon hit a bump in the road. In June and July the bottom fell out of the oil market (again), the Fed strongly hinted at interest rate increases, and a number of renewable energy firms sought large sums from public capital markets. Together, these three unrelated developments conspired to spook fossil fuel investors, who dumped renewable energy Yieldco shares and plunged prices into a vicious downward spiral. Now the stakes are high: if Yieldcos fail, renewable energy could lose access to public markets and the low cost of capital necessary to scale up wind and solar. To recover, Yieldcos may have to restructure, seek help from parent developer firms, and hope for constructive public policy to further de-risk renewable energy investments. Whereas the article focuses on the causes of the recent downward spiral in Yieldco share prices and the remedies for stabilizing and lifting prices, in this blog post I’ll assess the underlying renewable energy industry and the long-term prospects for vehicles like Yieldcos. Even before the collapse of Yieldco share prices this summer, doomsayers predicted that Yieldcos were overvalued and went as far as to call the Yieldco model a “Ponzi Scheme.” To those analysts, this summer has vindicated their conviction that a Yieldco is no more than the sum of its parts, and that the stock market had erred in imputing value over and above the constituent renewable energy projects in a Yieldco’s portfolio. I disagree.  This summer certainly proved that Yieldcos, as currently structured, are unstable vehicles whose share prices are liable to spiral upward or downward without much of a change in the performance of the underlying projects. But if they can weather this perfect storm, restructure, and attract a broader investor base, Yieldcos can add considerable value by reducing transaction costs and providing public investors a diversified portfolio of renewable projects. The renewable energy industry as a whole is doing very well right now. The costs of solar and wind projects have consistently fallen, and installed renewable capacity is growing around the world. But extrapolations that solar will account for thirty percent of the global power market by 2050 will not come true without further reductions in the cost of capital and participation from public markets, which can supply the scale of investment needed for renewable energy to rival conventional energy sources. That’s where Yieldcos come in. How Yieldcos Create Value There are three ways a Yieldco creates value over and above the value of the renewable energy projects it comprises. First, it reduces the risk of investing in renewable energy. To accomplish this, renewable energy developers spin off the least risky part of their portfolio—owning and operating renewable energy installations post-construction—creating a Yieldco, an independent, publicly traded entity. Thus, the Yieldco avoids the riskier elements of project development—regulatory approvals, construction, contracting—and only purchases operating or near operational assets from the parent developer that come with guaranteed revenues from long-term power purchase agreements (PPAs) with utilities. Second, Yieldcos offer public market investors—like institutional and retail investors—an easy way to invest in renewable energy; in other words, they reduce the transaction costs that would otherwise block public market capital in a sector dominated by private capital. This is possible because of the way Yieldcos return almost all of the revenue generated by renewable energy projects back to investors. Similar to Master-Limited Partnerships, which are holding companies for oil and gas infrastructure assets, Yieldcos are able to shield shareholders from double taxation, avoiding corporate income tax on renewable project revenues to distribute pre-tax dividends to shareholders. Since solar projects compose a majority of Yieldco assets, and solar panels require next to zero operating and maintenance expenditure, Yieldcos are able to return most (80–90 percent) of their projects’ operating revenue to investors through dividends. The third way that Yieldcos add value—by promising 8–15 percent dividend growth—is what got them in trouble this summer. Yieldcos depend on high share prices to raise equity on public markets and purchase more renewable projects at returns that exceed their cost of capital, driving share prices up further. I call this a “treadmill of equity issuances and dividend payouts.” Unfortunately, the treadmill can overheat,  and when share prices start to drop, they viciously spiral downward. I suggest that relying less on equity and more on debt—up to responsible credit limits—will enable Yieldcos to avoid spirals, though their share values will not be as high as when they were on the treadmill. Still, even if Yieldcos are less aggressive about dividend growth, they add value to renewable energy projects by unlocking public capital markets through reduced risk and lower transaction costs. By focusing on developing a strong asset portfolio, Yieldcos can still play an important role in scaling up renewable energy. Four Questions Underlying the Long-Term Success of Yieldcos As Yieldcos mature and find ways to avoid short-term share price volatility, their long-term prospects will depend on macroeconomic fundamentals and the health of the renewable energy industry—these are far more logical factors to drive Yieldco value than the price of oil. There are four threshold questions that require affirmative answers for Yieldcos to succeed long-term: Question 1: Will solar remain economical after the imminent expiration of the solar Investment Tax Credit (ITC)? Yes. Although important in the near term to U.S.  solar project economics,  the ITC is not crucial to their long-term viability. Currently, the ITC offers developers of U.S. projects 30 percent of the project value in tax credits through 2016 and 10 percent thereafter. The ITC was crucial to incentivize domestic deployment when solar economics were not so favorable, but today, installed solar costs are on a sufficient downward trajectory to make many projects viable on their own, without the tax credit. The expiration of the ITC will likely cause a drop off in project development in 2017, but falling costs will enable project growth thereafter. First Solar, a leading panel manufacturer, has projected highly competitive costs of $1 per installed Watt in 2017, without the ITC, and historically low bids in recent solar PPA auctions below 5 cents per kWh suggest that solar will be competitive in wholesale power markets even after the ITC step-down. Yieldcos comprising solar assets should be able to weather this short-term storm, especially because many are amassing a global portfolio of assets, diversifying their exposure outside of the U.S. market. Question 2: Can Yieldcos survive rising interest rates?  Probably. Rising interest rates will tarnish Yieldcos’ attractiveness as a low-risk, comparatively high return investment, but rates will have to rise considerably to really damage the Yieldco value proposition. Yieldcos can be attractive because of the spread between the market’s “risk-free rate,” often defined as the yield on a ten-year Treasury Bill (about 2.13 percent today), and the Yieldco dividend yield, currently between 5–6  percent. However, the Federal Reserve has signaled that an interest rate hike is likely by the end of the year, possibly marking the end of a historically low interest rate era. Combined with the falling oil price, the Fed’s hints contributed to plunging Yieldco prices over the summer. Still, rate hikes of a magnitude required to wipe out Yieldcos’ return over the risk-free rate are only distantly on the horizon. Michael Liebreich of Bloomberg New Energy Finance warns that if rates return to their 2007 level of 5.3 percent, Yieldco competitiveness as a low-risk investment would fall. Still, for the foreseeable future, modest interest rate hikes will likely not spell doom for Yieldcos. Question 3: Is there room for growth? Yes, resoundingly. The growth potential of renewable energy in the United States and the world is so high that Yieldcos will not run out of projects to acquire anytime soon. A useful point of comparison is the Yieldco’s cousin, the oil and gas asset MLP. MLPs support around 10 percent of the $1.1 trillion U.S. oil and gas sector and have posted an annualized 27 percent growth in market cap over the last 24 years. By contrast, Yieldcos represent less than 1 percent of the burgeoning renewable energy project finance sector, and Yieldco dividend growth targets are considerably less ambitious at 8–15 percent. Fundamentally, there is certainly room for growth. Question 4: Is a Yieldco all that different from a Ponzi Scheme? Yes. Although a Yieldco does depend on continually raising equity to acquire projects and pay shareholders, it is not a Ponzi scheme, because it comprises real, income generating assets just as do other established financial vehicles. However, it is unclear if the accounting practices that enable Yieldcos to distribute high dividends are sustainable. Unlike a Ponzi scheme, in which new cash is raised to pay existing investors, a Yieldco actually invests new cash in income-generating assets en route to paying dividends. Some may quibble that the difference with a Ponzi scheme is semantic, but the Yieldco model is akin to MLPs and Real Estate Investment Trusts (REITs), both of which are considered established, sound investment vehicles. To call one a Ponzi scheme would be to indict all three models. However, questions remain unanswered about the details of Yieldco accounting. In particular, Yieldcos assume a very low rate of depreciation oftheir operating assets, of which solar installations are often the majority. Since the installations have historically proven to be long-lived, in some cases twice as long as the standard twenty-year PPA contract signed with utilities, Yieldcos only deduct a small “Maintenance” sum from their operating revenues before distributing dividends to shareholders. If this assumption is wrong, however, then Yieldcos will have failed to accurately depreciate their assets, so that over time their asset base shrinks because of inadequate reinvestment and excessive dividend distributions. It will be years and perhaps decades before Yieldco claims of asset life are vindicated or disproven. In the meantime, critics will continue to accuse Yieldcos of hiding the need to reinvest in capital expenditure in order to reward shareholders. But the historical record of long-lived and productive renewable energy projects is on the Yieldcos’ side. In summary, Yieldcos do add value to the projects that they bundle together, and the health of the renewable energy sector can underpin Yieldcos’ long-term success. That means that the conclusion I wrote to the short-term story of Yieldco prices tumbling alongside oil prices applies equally well to the long-term story of how the future of renewable energy may depend on the success of Yieldcos: Renewable energy is on the cusp of becoming a mainstream alternative to fossil fuels—getting there requires a mainstream financing tool. Although the Yieldco model must improve after derailing this summer, getting it back on track is in everyone’s best interest.

This was originally posted by my colleague John Campbell on his Africa in Transition blog. John was formerly U.S. Ambassador to Nigeria and is currently the Ralph Bunche senior fellow at the Council on Foreign Relations. The Natural Resource Governance Institute, a New York-based think tank and advocacy organization, has issued a must-read report, Inside NNPC Oil Sales: A Case for Reform in Nigeria. The authors are Aaron Sayne, Alexandra Gilles, and Christina Katsouris. The Nigeria National Petroleum Corporation (NNPC) sells about half of Nigeria’s oil, worth an estimated $41 billion in 2013. The report concludes that NNPC’s approach to oil sales “suffers from high corruption risks and fails to maximize returns for the nation.” The report is detailed—it runs to seventy-one pages with additional annexes. It is thoroughly convincing and offers specific recommendations. It notes that “the bad practices that undermine NNPC oil sale performance all have political interference at their root.” The report also argues that the new presidential administration of Muhammadu Buhari has a unique opportunity to tackle the problems at NNPC, which have long been ignored. At almost the same time the Natural Resource Governance Institute issued its report, President Buhari announced a wholesale sacking of the directors and senior management at NNPC. The president relieved the group managing director and the executive vice chairman, who had been appointed by former president Goodluck Jonathan. The following day, he fired the nine NNPC executive directors. Buhari’s choice of group managing director is Emmanuel Kachikwe. He has been executive vice chairman and general counsel of Exxon-Mobil (Africa). Among other academic attainments, he holds masters and doctorate degrees from the Harvard Law School,according to Nigerian media. He has also worked for Texaco Nigeria. Nigerian media reports that he intends to reduce the number of group managing directors from nine to four. As with his appointment of new military service chiefs, Buhari’s choices indicate that he focuses on expertise and experience, rather than on political connection. Inside NNPC argues that reform of NNPC does not require omnibus legislation, but rather a bold agenda with a short timeline. Buhari’s personnel choices fit that prescription.

The Natural Resource Governance Institute, a New York-based think tank and advocacy organization, has issued a must-read report, Inside NNPC Oil Sales: A Case for Reform in Nigeria. The authors are Aaron Sayne, Alexandra Gilles, and Christina Katsouris. The Nigeria National Petroleum Corporation (NNPC) sells about half of Nigeria’s oil, worth an estimated $41 billion in 2013. The report concludes that NNPC’s approach to oil sales “suffers from high corruption risks and fails to maximize returns for the nation.” The report is detailed—it runs to seventy-one pages with additional annexes. It is thoroughly convincing and offers specific recommendations. It notes that “the bad practices that undermine NNPC oil sale performance all have political interference at their root.” The report also argues that the new presidential administration of Muhammadu Buhari has a unique opportunity to tackle the problems at NNPC, which have long been ignored. At almost the same time the Natural Resource Governance Institute issued its report, President Buhari announced a wholesale sacking of the directors and senior management at NNPC. The president relieved the group managing director and the executive vice chairman, who had been appointed by former president Goodluck Jonathan. The following day, he fired the nine NNPC executive directors. Buhari’s choice of group managing director is Emmanuel Kachikwe. He has been executive vice chairman and general counsel of Exxon-Mobil (Africa). Among other academic attainments, he holds masters and doctorate degrees from the Harvard Law School, according to Nigerian media. He has also worked for Texaco Nigeria. Nigerian media reports that he intends to reduce the number of group managing directors from nine to four. As with his appointment of new military service chiefs, Buhari’s choices indicate that he focuses on expertise and experience, rather than on political connection. Inside NNPC argues that reform of NNPC does not require omnibus legislation, but rather a bold agenda with a short timeline. Buhari’s personnel choices fit that prescription.

As President Dilma Rousseff’s polling numbers fall far into the single digits, the calls for her impeachment grow louder. In Congress, PMDB lower house head Eduardo Cunha has broken with Rousseff, intimating his support for her removal. On the streets protestors too call for a change, marching by the hundreds of thousands to express their anger and frustration. The legal case against her is currently weak. As the Petrobras corruption investigations expand to include dozens of high profile names, among them former President Luiz Inácio Lula da Silva, Eduardo Cunha himself, and construction magnate Marcelo Odebrecht, Rousseff has not—at least yet—been publicly named. Even if she is, impeachment is only possible for crimes committed as president (the Lava Jato scandals primarily occurred while she was chairwoman of Petrobras, from 2003 to 2010). Some political opponents believe they could try her instead for breaking campaign finance rules or for fudging government accounts. To move forward, two-thirds of the lower house of congress would need to vote to impeach; in the case of criminal charges the Supreme Court would then weigh in. If tried on corruption charges, the Senate would preside. Eight of the eleven sitting Supreme Court judges are Rousseff or Lula appointees. In the Senate her coalition, though weakened, still maintains a majority. Politically, impeachment doesn’t necessarily help her most avid opponents in the PSDB. If removed before January 2017, Vice President Michel Temer of the PMDB would take over, strengthening the hand of a potential rival for the 2018 election. And even with the tensions within Rousseff’s own party, the PT, none benefit from her ouster. Finally, Rousseff’s impeachment could set a worrisome historical precedent. This isn’t Brazilian democracy’s first impeachment go round. In 1992, the opposition PT and PMDB pushed congress to impeach then President Fernando Collor de Mello on corruption grounds. Though he resigned in an effort to stop the proceedings, he was found guilty and barred from public office for eight years (today he is a senator and actively being investigated for accepting bribes in exchange for lucrative government contracts). At the time some hailed it as a democratic achievement, taking on the most powerful and corrupt; others saw it as the political backlash of those opposed to Collor de Mello’s austerity and other measures to root out vested interests (none question the actual corruption). Another impeachment, particularly if done for political or popularity (rather than rule of law) reasons, could weaken Brazil’s thirty-year-old democracy. It is this fear that has brought opposition PSDB elder Fernando Henrique Cardoso to the presidency’s defense. In the words of the former president, “You’d need to have a crime, and a political consensus in Congress as well as in the street. I don’t think that’s the situation here.”

What caused the big oil crash of 2014? If you said the U.S. oil boom or Saudi strategy, you’re only partly right. As I argue in a new essay in the July/August issue of Foreign Affairs, if you want to understand current energy developments and future prospects – whether you’re talking about oil or gas or coal or renewables, and about economics or security or environment – you need to pay attention to Asia. Here’s a deep dive into one of the facts I mention in the article. (There’s nothing this technical in the actual piece!) The chart below shows Asia and Oceana oil consumption over the last fifteen years along with U.S. government projections for the next year or so. (All data is from here.) From the end of 2009 through the end of 2012, consumption increased by an average of 1.36 million barrels a day each year. From the end of 2012 through the end of 2014, in contrast, consumption was essentially flat. Why does this matter? The Energy Information Administration estimates that global production exceeded global consumption by about 1.8 million barrels a day during the fourth quarter of 2014. That glut is why oil prices crashed. Had Asian oil consumption growth maintained its pre-2012 pace over 2013 and 2014, global consumption (all else equal) would have been 33.6 million barrels a day in the fourth quarter last year – 2.7 million barrels a day higher than it actually was. There would have been no oil glut and no price crash. Even if Asian consumption had grown at half its previous pace, the production surplus would have been small. These claims remain true even if one excludes 2010 (which featured recovery from the financial crisis) and 2011 (when Japan imported more oil to cope with the Fukushima disaster). Oil consumption is only one way in which Asia remains central to global energy despite all the headlines generated by changes in the United States. This link to my Foreign Affairs article should get you free access for a while. I welcome readers’ thoughts.

Hydraulic fracturing has unlocked huge reserves of shale gas and oil, transforming the energy outlook in the United States and the world, even as local opposition and falling world prices threaten the industry.