Powering Myanmar: FDI, Geopolitics, and the Appetite for Risk

In the last article of Breaking Energy’s series on Myanmar, we take a look at the state of foreign investment. For more on the challenges facing the government and how the country uses electricity, see the first article. For details on the government’s pricing structure and demand projections, see the second article.

While residents of Myanmar protest over electricity â€" sometimes on pricing, other times on access and most recently on environmental concerns and Chinese involvement â€" foreign investors are watching Myanmar’s opening economy with hungry eyes. It’s a country with a huge population, low electrification rates and a robustly growing GDP that desperately needs more reliable energy. Myanmar allows power producers to export the bulk of the power produced domestically to neighboring countries, despite its own unmet demand. But legal roadblocks, opaque regulatory structures, a highly subsidized electricity program and an angry populace only boost the risk profile for independent power producers (IPPs) and foreign investors.

With the loosening of sanctions, interested investors are arriving from outside Myanmar’s neighborhood. While investments from China, Thailand, Japan and South Korea remain strong â€" and analysts say interest is as much about a geopolitical play for dominance in the region as it is about financial returns and producing power â€" the US, European countries and to a lesser extent, Australia have all shown interest.

Foreign investment in the country brings up more questions than can be answered; those involved in the power sector say the basics â€" a legal infrastructure, a sensible pricing scheme and a clear decision making process â€" do not exist, yet companies are vying to break into the market and gain access before competitors. In 2012, Myanmar passed a foreign investment law (see here for a breakdown), but there hasn’t been anything since dealing specifically with foreign investments in power production. That law set out parameters to encourage investment in the country, mainly through tax exemptions, a vow not to expropriate investments and an agreement to use international dispute resolution instead of domestic courts, according to Singapore-based attorney Nomita Nair. The World Bank and Asian Development Bank (ADB) are both working closely with the government on developing the industry and putting the right regulatory structures in place. Although approval for the National Electrification Program is likely in the fourth quarter of this year, Michael Spolum, a Fulbright-Clinton fellow working with the President’s Office in Myanmar, told Breaking Energy, developing the legal and policy frameworks to support the program takes time.

The Americans Return

In April of last year, after opening its Asian operations, Florida-based APR Energy identified Myanmar as a key area for growth. According to Clive Turton, head of business development for Asia at APR Energy, supplies of high-quality indigenous gas, a low electrification ratio and a vast market â€" Myanmar has a population of 60 million people, slightly larger in size than England â€" all make Myanmar an attractive market.

This is the first American power company to enter since the sanctions were eased. APR Energy is building a 100MW gas-fired power plant about 50 kilometers (31 miles) outside of Mandalay that it expects to have up and running by the end of March. This will make it one of the largest thermal power plants in the country and likely, one of the most efficient (see previous article for more on efficiency). The speed at which APR Energy can set up power plants is likely one of the factors that helped them win the contract.  “In the case of Myanmar, it was very important to put it together quickly,” said Turton.

APR will build and maintain the plant, selling electricity to MEPE. Turton wouldn’t give details on pricing, but said it was in line with other independent power producers in the country. Having allocated domestic natural gas for the project, Turton said the government “awarded the contract on the basis of who could use that gas most efficiently.”

Despite the legal uncertainties and lack of a regulatory framework, being first through the door didn’t prove especially difficult for Turton. According to him, the government “announced the invitation back in September last year and we were invited, along with several other companies to submit bids. The process was simply a process of preparing the bids and selecting the suppliers. Bidding was very transparent.”

Nair says this type of investment â€" from Western countries â€" is particularly welcome. The country wants “Western technology, know-how and higher standards, in terms of environmental standards and training,” she said. Historically, the country partnered with North Asian investors for power plants. And the Chinese, as active as they are, might be wearing out their welcome. Of 48 identified planned projects, 33 involve Chinese investors, according to a presentation by MEPE and YESB given in 2012. The most recent protests on energy aren’t over the recent price hike, but over a Chinese hydropower dam. It was originally meant to export 90% of the energy outside the country’s borders, but was stopped in 2011. Now, citizens are concerned the project will move forward after the 2015 election and cause ecological harm.

The Risk Profile

Myanmar is open for business, but investing remains a complex process. Still, the government has a powerful ally with the World Bank working on an investment prospectus. Of the two billion dollars the World Bank committed to the country, “half is earmarked for electricity,” said Dejan Dostojic, leader of the bank’s Myanmar power project. While the development plan is still in the early stages, Dostojic couldn’t comment on how all the money would be used, but he did say the bulk would go towards improving the distribution system. This should be welcome news to both producers and customers.

Without a legal framework or a set agreement on PPAs (these are set on a per project basis), investors face significant risk. While Nairsays the government has set out parameters to encourage investors, other experts seem more skeptical, pointing to the lack of institutional frameworks and some ambiguity in the system. But the government is getting help, said Spolum: “The government has the full and unwavering support of the donor community and is firmly committed to expanding the power sector in a manner that is transparent and equitable, however, developing effective and intelligent institutions, laws and regulations takes time.” Still Nairwarns that sanctions remain on certain Myanmar entities that companies need to be aware of, but investment is possible.

Myanmar is under tremendous pressure to get the framework and laws right. An expert close to the issue, who asked to not to be identified for fear of angering the government, says the “bureaucratic risk aversion” is pervasive in the country, and “decisions are always passed to the top.” This translates to a slow bureaucratic process. Dostojic emphasized the need for internal work on the government. On top of their efforts to help the government extend electrification across the board, “institutional building and capacity building in the government is a major task,” said Dostojic.

Not only that, but the government body in charge of investments â€" the Myanmar Investment Commission â€" is bombarded with projects from small-scale timber mills to big oil and gas projects.

All of this leads to an “intense administrative burden, which has, despite the best cooperative efforts of many capable and committed officials, slowed the flow of FDI into the country,” said Spolum. “Authorities are of course aware of the challenges and are proactively working to tweak MIC approval processes to accelerate FDI inflows without compromising accountability or transparency,” he added. And indeed, if APR Energy’s experience is anything to go by, the process has the potential to be transparent and smooth.

Despite the challenges, there is no lack of interest in the country, say experts. In terms of pricing, some developers won’t care if the price is ultimately passed onto the consumer or if its subsidized by the government, argues Nair (for more on pricing, see this article).Even though the government isn’t in a position to give “significant financial incentives on its own to attract FDI,” with help from international organizations, “this makes [Myanmar] an attractive FDI destination for investors,” according to Vikas Sharma, associate director at Frost & Sullivan.

In the countryside where the need for electricity is great, the perceived risk is even higher. Spolumsays he’s working with private and public sector stakeholders and NGOs to bring “upland rural areas with high agricultural potential where many investors won’t go because the risk profile is a bit too high for them.” In rural areas with access to some electricity from mini-grids, feedstock is diesel and tariffs are as high as $0.31 â€" $0.52 per unit, compared to $0.03 â€" $0.05 for households connected to the national grid. Spolum says this proves that many rural areas are able to pay higher rates for electricity, however the tradeoffs are high, with some households spending up to 30% of their income on power. Spolum optimistically notes that, “opportunities exist to harness donor and private sector support simultaneously, and in doing so reduce the high tariff burden while still delivering quality, life-transforming electricity to the poorest segments of society”.

Investing only in the urban areas instead of the rural areas, where electrification rates are dismally low, even by Myanmar’s standards, runs the risk of exacerbating the rural/urban development divide. Some analysts expressed concern that such disparities may fuel conflict between the lowland populations â€" likely to be the first to benefit from grid-connected electricity â€" and ethnic areas, where geography will slow the grid’s expansion.

The government won’t be able to stimulate power sector unless it gives certainty on gas, procurement, and tariffs, according to Nair. Even with processes in place, Spolum says large-scale projects are years off. Those projects â€" ones backed by outside financing with large nameplate capacity â€" could take half a decade to complete.

Even with tremendous support from outside sources, Myanmar has a tremendous amount to lose if it doesn’t get this right. Dostojic pointed out that the years of isolation meant the country lacked information about advances in the power sector, environmental and social safeguards and procurement and financial management systems. The coming influx of investments should help ease that, but it remains up to the government to ensure electricity is provided across the country and not just to the urban centers.

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Coal Supplies at Electric Power Plants Drawn Down in Cold Weather

Source: U.S. Energy Information Administration, Electricity Monthly Update, March edition

The average supply of coal held at electric power generators in December 2013 dropped below 60 days of burn (a function of both inventory levels and anticipated consumption) for the first time since summer 2011. Inventory increased slightly in January but remains below a two-month supply. Coal consumption to generate electricity grew during summer and fall 2013 as the price of natural gas, a competing power generation fuel, increased from low levels in 2012. Consumption of coal increased further this winter due to bitter cold weather that drove up power demand.

As coal regained generation market share from natural gas, operators of coal-fired plants drew down inventory levels that had grown abnormally high in late 2012 and early 2013. Receipts of new coal supplies at electric power plants were generally below the five-year range throughout 2013 (see graph below), leading to low inventory heading into this spring.

Source: U.S. Energy Information Administration, Electric Power Monthly, March edition

Over 80% of coal used by electric generators is purchased under multiyear contracts, which give buyers limited options for adjusting delivery volumes. The main avenue buyers have in reacting to short-term market developments is to replace expiring multiyear contracts with shorter-term spot coal supplies. This strategy gives generators more control over the rate of receipts. As shown below, the percent of coal receipts purchased on spot contracts rose throughout 2013.

Source: U.S. Energy Information Administration, Electric Power Monthly, March edition

Principal contributor: M. Tyson Brown

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Conjuring Profits from Uranium's Resurgence: Interview with David Sadowski

David Sadowski is a mining equity research analyst at Raymond James, and has been covering the uranium and junior precious metals spaces for the past seven years. Prior to joining the firm, David worked as a geologist in western Canada with multiple Vancouver-based junior exploration companies, focused on base and precious metals. David holds a Bachelor of Science in Geological Sciences from the University of British Columbia.

The Energy Report: David, the uranium price remains below the cost of production for many producers and the forecasts for uranium production are flat. Why are you optimistic about the uranium space?

David Sadowski: In the current price environment, supply won't be able to keep up with demand growth. That's really the core to the uranium investment thesis. The cost of uranium production spans a pretty wide range, from the mid- to high-teens per pound for the cheapest in-situ leach mines in Kazakhstan, to $50â€"60/pound ($50â€"60/lb) for some of the lower-grade, conventional assets in Africa, Australia and East Asia. So we're looking at about $40 to produce your average pound of uranium. That number is climbing on cost inflation and depletion of the best mines.

The current spot price is under $36/lb, so many operations are underwater right now. That's why we've seen numerous deferrals of projects and even shutdowns of existing mines, the most significant of which was Paladin Energy Ltd.'s (PDN:TSX; PDN:ASX) Kayelekera at the beginning of February. That's on top of operations that are at risk for other reasons. In just the last few months, we've seen four of the world's largest mines owned by Rio Tinto Plc (RIO:NYSE; RIO:ASX; RIO:LSE; RTPPF:OTCPK) and AREVA SA (AREVA:EPA) shut down on operational and political hiccups. Then you look at where the supposed growth is coming from over the next several yearsâ€" Cameco Corp.'s (CCO:TSX; CCJ:NYSE) Cigar Lake and China's Husab. Those are technically very challenging, too. All of this is occurring in a world no longer benefitting from a steady 24 million pounds per year (24 Mlb/year) supply of uranium from downblended Russian warheads. In short, the supply side is a basket case.

Yet demand growth keeps chugging along. European Union (EU) and North American growth perhaps isn't what it was a couple of decades ago. Pressure from competing energy sources like liquefied natural gas (LNG) in the U.S. is causing some operators to switch off their older, smaller reactors. But reactor retirements are being more than offset by new reactor construction not only in the U.S. and EU, but much more important, in Asia and in Russia. China, India, Korea and Russia are collectively constructing 70 reactors right now.

TER: Japan and the United Arab Emirates (UAE) just announced a program to cooperate in developing nuclear technology. What's the market significance of that?

DS: There is a push toward nuclear in many of these nations in the Middle East. Not only do they have pretty strong population growth and urbanization, thus electricity growth is strong, but some of those oil-rich nations have cited a preference to sell their petroleum into the international markets rather than domestically. The UAE is a very large potential source of demand growth. It is constructing two nuclear power plants at the moment and is imminently going to break ground on two more. There are an additional 41 new nuclear reactors on the drawing board in the Middle East. So in the context of 434 operable reactors today, that's a very meaningful amount of growth potential.

Demand growth remains resilient, and supply is lagging behind. In just a few years, we think this will lead to a deficit that will quickly grow to crisis levels. That's why we're bullish. Uranium prices have to go higher to incentivize more supply to meet this looming supply gap.

TER: Why hasn't that happened yet?

DS: There are just a few forces working against the price. Since the Fukushima accident in Japan, there has been a supply glut in the marketplace. There has been a decrease in demand, with a lower level of buying by some countries, like Germany, Switzerland and, of course, Japan. Additionally, some extra supply was coming out of the U.S. government. There is an extra amount coming from enrichment underfeeding. If you add all that up, there has been essentially more supply than is required, and that puts downward pressure on prices. It's caused the utilities to take a step back from the market.

TER: So do you think conditions in the market itself will materially improve? What will that look like?

DS: For us, it comes down to when the utilities start getting involved again. While the utilities have been sitting on the sidelines over the last couple of years, high-fiving each other for not buying uranium in a declining price environment, their uncovered requirements in the future have actually risen quite dramatically. At some point, they have to resume long-term contracting to cover all those needs. Japan is a key catalyst.

"Fission Uranium Corp. is one of our top picks in the space."

Japan's reactors were slowly shut down after the Fukushima accident. Right now, none of them are operating. The country's inventories have piled up to probably around 100 Mlb. Many of these utilities have asked their suppliers to delay deliveries of fresh uranium. That material ends up in the marketplace one way or another, so it's having a price-dampening effect. In late February, however, the Japanese government announced its final-draft energy plan. Japan will restart at least some of its reactors to stop spending a ludicrous amount of money on imported fossil fuels. There are other economic and environmental benefits, but it’s the country's trade balance that is really driving the restart push.

It's these restarts that we think will spur global utilities outside Japan to resume buying. The signal will be sent that Japan won't be dumping its inventories, it won't be deferring deliveries anymore and, by the way, there is not enough supply to go around in just a few years so you better start contracting again. That's what we think is going to support prices.

TER: That basic energy plan in Japan is a draft, but there is a lot of public opinion against it. You do think its prospects are good?

DS: Consensus is that the plan is going to be approved by the cabinet by the end of March. The opposition is highly regionalized, and many pockets of the country are actually very pronuclear. Nuclear, obviously, provides a lot of jobs and generates a lot of tax revenue in these regions.

TER: Raymond James has revised its uranium supply-demand balance and anticipates a growing supply deficit beginning in 2017. What is the case for investing in the industry today with a payoff so far in the future?

DS: A shortfall beginning in 2017 doesn't mean prices don't move until 2017. In fact, in a healthy market, they should have moved already. But, again, it comes back to the utilities. They view the nuclear fuel market and their own fuel requirements as a game of risk management.

"I'm very hopeful that UEX Corp.'s new CEO will continue the company's trend of excellent work."

Today, many utilities are sitting on near-record piles of material, so there's not a great deal of risk to the utilities with respect to supply availability over the next couple of years. However, as these groups start to look out beyond that period to 2017, 2018 and so on, they'll realize that it could become more challenging to get the uranium they need. Given that the utilities typically contract three to four years in advance, we're very close to that window where we expect buying to ramp up again and prices to move upward. Again, critically, we expect Japanese restarts to be an important catalyst in that resumption of buying. We expect first restarts in H2/14 with a half-dozen units online by Christmas. So from an investor's point of view, we're already seeing the benefit of this outlook. That's been driving the uranium equities upward over the past couple of months.

TER: You're forecasting spot uranium prices averaging $42/lb in 2014, but three months into the year, the price is still struggling to break $36. What will drive it over $42? When do you expect that to happen?

DS: We think the move this year is likely to happen toward the end of this year, as Japanese restarts spark a return of normal buying levels by utilities. The uranium price should really start moving in 2015.

TER: What indicators should investors look for in watching the uranium price trend?

"Uranium prices have to go higher to incentivize more supply to meet the looming supply gap."

DS: One of the best indicators is Uranium Participation Corp. (U:TSX). Since the fund's inception, this stock has been a remarkably accurate predictor of where the uranium spot price is headed. When Uranium Participation's share price is above its net asset value (NAV), the market is baking a higher uranium price into its valuation of the stock because the NAV is calculated at current uranium prices. For even more precision, you can divide the company's enterprise value by its uranium holdings for a rough dollar/pound estimate on what the market is ascribing. So right now, we calculate the fund is implying $40/lb, and that's over $4 above the current spot price. This is by no means a bulletproof measure, but absent a black swan event, history tells us that this could be the destination for the price in the near future.

TER: You have said you see $70/lb as the price that will incentivize new mining. What should investors do while they're waiting for the price to reach that level?

DS: Buy uranium equities. It's that simple. We think prices are going higher, so buy uranium stocks well ahead of the upswing.

TER: Do you have a target time that you expect the price to reach that level?

DS: We're looking for the price to reach $70/lb in 2016. We forecast prices flat forward at $70 from that year onward.

TER: Which mining companies are the best investment prospects in this environment? Which are the weaker ones?

DS: They say a rising tide floats all boats. We think all the uranium stocks are probably going higher, or at least the vast majority of them. But we also believe being selective will provide the greatest rewards. Most investors should be looking at names with quality assets, management teams and capital structures.

Among producers, our preferred companies are focused on relatively high-grade projects with solid balance sheets and fixed-price contracts that can buffer them against near-term spot price weakness. After all, we think the spot price could remain weak for most of the balance of 2014.

On the explorer and developer side, the theme is the sameâ€"companies with cash and meaningful upcoming catalysts and, again, in good jurisdictions. But if you can tolerate an increased level of risk, I'd be looking at companies with lower-grade assets in Africa. Those are probably the highest-leveraged names out there.

TER: What other favorites can you suggest?

DS: Our top picks at the moment in the space are Fission Uranium Corp. (FCU:TSX.V) and Denison Mines Corp. (DML:TSX; DNN:NYSE.MKT).

Fission has been a top pick in the space for some time. We have a $2/share target and a Strong Buy rating. We view Patterson Lake South as the world's last known, high-grade, open-pittable uranium asset. It has immense scarcity value. There are not very many projects in the world that can yield a drill intersection of 117 meters (117m) grading 8.5% uranium, as hole 129 did in February. There is only one project in the world where you would find an interval like that starting at 56m below surface, and that's Fission's Patterson Lake South. It's in the best jurisdiction, has a management team that has executed very well and has huge growth potential. We think that property probably hosts over 150 Mlb uranium. We would be very surprised if the company was not taken out at some point in the next two years.

"The uranium price should really start moving in 2015."

Denison is another story we like a lot. We have a $2/share target and Outperform rating on the stock. Denison has the most dominant land holding of all juniors in the world's most prolific uranium jurisdiction, the Athabasca Basin in Canada, the same region as Fission Uranium's Patterson Lake South. The company will run exploration programs at 20 projects in Canada this year, including an $8 million ($8M) campaign at Wheeler River, the world's third-highest-grading deposit, which continues to grow in size, and with a new understanding of its high-grade potential uncovered last year.

Denison has a stake in the McClean Lake mill, which is also one of its crown jewels. It's the world's most advanced uranium processing facility, and it's located a stone's throw from hundreds of millions of pounds of high-grade Athabasca uranium deposits. It's a big part of the reason why we think Denison will get bought out at some point, particularly given that to permit and construct a new mill in the basin would be a herculean task. Denison has a very strong management team and cash position and, once again, big-time scarcity value. It's one of the only three North American uranium vehicles exceeding a $0.5B market cap. Denison has been and will continue to be a go-to name in the space.

TER: What is another interesting name in your coverage universe?

DS: UEX Corp. (UEX:TSX) owns 49% of the world's second-largest undeveloped, high-grade uranium asset in Shea Creek and 96 Mlb in NI-43-101-compliant resources. It's the biggest deposit with that kind of junior ownership in the Athabasca Basin. It's a strategic asset and the company's main value driver. But with the uranium price where it is, the company is also focusing on shallower assets near what is now the southern boundary of the Athabasca Basin, closer to Fission's Patterson Lake South. We're really interested to see what comes of the Laurie and Mirror projects this year.

We have a $0.60 target price on shares of UEX.

TER: Is any of that influenced by the fact that it has a new CEO?

DS: The target price is not heavily influenced by the recent change in CEO. I think the outgoing CEO, Graham Thody, did an excellent job. I'm very hopeful that Roger Lemaitre will continue that trend. Under the new CEO, I would anticipate that the company may ramp back up the level of work intensity at Shea Creek, to build on the achievements of AREVA and the UEX team as well as Thody. But given Lemaitre 's background, including his experience as head of Cameco's global exploration, I wouldn't be surprised to see UEX extend its view beyond the Athabasca Basin as a potential consolidator in some other jurisdictions that may be lagging behind a bit on valuation.

TER: You raised your target for Cameco from $25/share to $26/share. Are you expecting the rise to continue there?

DS: Despite the recent run-up in shares, we think there's a good chance of further strength. Cameco is the industry's blue-chip stock. It's the one everyone thinks of when they think of uranium. Given its size and liquidity, it is the only stock many of the big institutional fund managers can invest in. With that backdrop, we think it's going to be the first stock for fund flows as the space continues to rerate, especially as we get more confirmatory news about Japanese restarts and as Cigar Lake passes through the riskiest part of its ramp-up. We think it should be a very good 24 months for the company.

TER: What other companies do you like in the uranium space?

DS: We recently upgraded Kivalliq Energy Corp. (KIV:TSX.V) to an Outperform rating. Our target price there is $0.50/share. The company has been a laggard in the last few months, but it has Angilak, a solid asset in Nunavut with established high-grade pounds and huge growth potential. Current resources stand at 43 Mlb, but we think there is well over 100 Mlb of district-scale potential. The company is derisking the asset by moving forward with engineering work, like metallurgy and beneficiation, ahead of a preliminary economic assessment potentially later this year. We're also excited to see what comes with the newly acquired Genesis claims that sit on the same structural corridor that hosts all the mines of the East Athabasca Basin.

We also like Ur-Energy Inc. (URE:TSX; URG:NYSE.MKT), on which we have an Outperform rating and $2.20/share target price. This stock has been on a major tear. We continue to expect great things from Lost Creek in Wyoming. Early numbers from the mine, which just started up in August, have been hugely impressive to us, a testament to the ore body and execution by management. And the financial results should be equally strong, given the company's high fixed-price contracts. In all, it's a solid, low-cost miner in a safe jurisdiction, which we think should be in a good position to grow production organically or, using cash flow, buy up cheap assets in the western U.S., a region ripe for consolidation of in-situ leach uranium assets.

TER: Do you have any parting words for investors in the uranium space?

DS: I would just say we think the uranium price is going higher over the next 12â€"24 months. So in anticipation of that upswing, we recommend investors take a hard look at high-quality uranium stocks today.

TER: You've given us a lot to chew on. I appreciate your time.

DS: It's my pleasure, as always.

Want to read more Energy Report interviews like this? Sign up for our free e-newsletter, and you'll learn when new articles have been published. To see a list of recent interviews with industry analysts and commentators, visit our Streetwise Interviews page.

DISCLOSURE:
1) Tom Armistead conducted this interview for Streetwise Reports LLC, publisher of The Gold Report, The Energy Report, The Life Sciences Report and The Mining Report, and provides services to Streetwise Reports as an independent contractor. He owns, or his family owns, shares of the following companies mentioned in this interview: None.
2) The following companies mentioned in the interview are sponsors of Streetwise Reports: Fission Uranium Corp. and UEX Corp. Streetwise Reports does not accept stock in exchange for its services.
3) David Sadowski: I own, or my family owns, shares of the following companies mentioned in this interview: None. I personally am, or my family is, paid by the following companies mentioned in this interview: None. My company has a financial relationship with the following companies mentioned in this interview: None. I was not paid by Streetwise Reports for participating in this interview. Comments and opinions expressed are my own comments and opinions. I had the opportunity to review the interview for accuracy as of the date of the interview and am responsible for the content of the interview. This interview took place on February 28, 2014. All ratings, facts and figures are reflective of the date of the interview.
4) Interviews are edited for clarity. Streetwise Reports does not make editorial comments or change experts' statements without their consent.
5) The interview does not constitute investment advice. Each reader is encouraged to consult with his or her individual financial professional and any action a reader takes as a result of information presented here is his or her own responsibility. By opening this page, each reader accepts and agrees to Streetwise Reports' terms of use and full legal disclaimer.
6) From time to time, Streetwise Reports LLC and its directors, officers, employees or members of their families, as well as persons interviewed for articles and interviews on the site, may have a long or short position in securities mentioned. Directors, officers, employees or members of their families are prohibited from making purchases and/or sales of those securities in the open market or otherwise during the up-to-four-week interval from the time of the interview until after it publishes.

( Companies Mentioned: AREVA:EPA, CCO:TSX; CCJ:NYSE, DML:TSX; DNN:NYSE.MKT, FCU:TSX.V, KIV:TSX.V, PDN:TSX; PDN:ASX, RIO:NYSE; RIO:ASX; RIO:LSE; RTPPF:OTCPK, UEX:TSX, URE:TSX; URG:NYSE.MKT, U:TSX, )

Photo Credit: Uranium Resurgence/shutterstock

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Is A Super El Niño Coming That Will Shatter Extreme Weather And Global Temperature Records?

Chart of global temperature since 1950, also showing the phase of the El Niño-La Niña cycle. Via NASA.

Signs are increasingly pointing to the formation of an El Niño in the next few months, possibly a very strong one. When combined with the long-term global warming trend, a strong El Niño would mean 2015 is very likely to become the hottest year on record by far.

El Niño visualization (via NOAA)

An El Niño is “characterized by unusually warm ocean temperatures in the Equatorial Pacific,” as NOAA explains. That contrasts with the unusually cold temps in the Equatorial Pacific during a La Niña. Both are associated with extreme weather around the globe. But, as the above chart from NASA shows, El Niños are generally the hottest years on record, since the regional warming adds to the underlying global warming trend. La Niña years tend to be below the global warming trend line.

Because 1998 was an unusually strong “super El Niño,” and because we haven’t had an El Niño since 2010, it can appear as if global warming has slowed â€" if you cherry-pick a relatively recent start year. But in fact several recent studies have confirmed that planetary warming continues apace everywhere you look.

Remember that 2010, a moderate El Niño, is the hottest year on record so far. And 2010 saw a stunning 20 countries set all-time record highs, including “Asia’s hottest reliably measured temperature of all-time, the remarkable 128.3°F (53.5°C) in Pakistan in May 2010.” Meteorologist Dr. Jeff Masters said 2010 was “the planet’s most extraordinary year for extreme weather since reliable global upper-air data began in the late 1940s.”

Given that the “Earth’s Rate Of Global Warming Is 400,000 Hiroshima Bombs A Day,” the planet is half a billion Hiroshimas warmer than it was in 2010. So even a moderate El Niño will cause record-setting temperature and weather extremes. But a strong one, let alone a super El Niño, should shatter records.

Peru’s official El Niño commission said last week that they are expecting an El Niño to start as soon as April. Peru tracks this closely because “El Nino threatens to batter the fishmeal industry by scaring away abundant schools of cold-water anchovy.”

To be clear, an El Niño is not a sure thing at this point. Some forecasters put the chances at about 60 percent, but one recent study put the chances at 75 percent.

Mashable’s Andrew Freedman (formerly of Climate Central) reports “some scientists think this event may even rival the record El Niño event of 1997-1998.” He cites meteorology professor Paul Roundy:

Roundy said the chances of an unusually strong El Niño event “Are much higher than average, it’s difficult to put a kind of probability of it … I’ve suggested somewhere around 80%”

“The conditions of the Pacific ocean right now are as favorable for a major event as they were in march of 1997. That’s no major guarantee that a major event develops but clearly it would increase the likelihood of a major event occurring,” Roundy says.

The El Niño Southern Oscillation (ENSO) doesn’t change the overall warming trend, but it is a short-term modulation, what NASA labels the largest contributor to the “natural dynamical variability” of the climate system. El Niño and La Niña are typically defined as sustained sea surface temperature anomalies (positive and negative respectively) greater than 0.5°C across the central tropical Pacific Ocean. You can read the basics about ENSO here.

One key El Niño indicator is the rapid rise in upper ocean temperatures in the central and eastern Pacific â€" just what NOAA reported Monday:

Since the end of January, temperature anomalies have strongly increased.

Meteorologist Michael Ventrice had a detailed analysis in late February here on why such warming is significant.

For El Niño junkies, NOAA’s National Centers for Environmental Prediction (NCEP) releases a weekly ENSO report every Monday here. And super-junkies can go to the ENSO page of the Australian government’s Bureau of Meteorology (updated every second Tuesday), which also charts another key El Niño indicator, the Southern Oscillation Index (SOI). For the SOI, “sustained negative values below âˆ'8 may indicate an El Niño event.” The latest 30-day SOI value (through March 23) is âˆ'12.6.

The ensemble mean prediction of NCEP’s Climate Forecast System (CFS) is for an El Niño in early summer, eventually getting quite strong:

When the El Niño forms and then peaks is crucial to whether 2014 or 2015 (or both!) will be the hottest year on record. A 2010 NASA study found “the correlation of 12-month running-mean global temperature and Niño 3.4 index is maximum with global temperature lagging the Niño index by 4 months.”

If we do get an El Niño, and it looks anything like the 1997/1998 one, then 2015 in particular should be the hottest year on record by far. Stay tuned.

The post Is A Super El Niño Coming That Will Shatter Extreme Weather And Global Temperature Records? appeared first on ThinkProgress.

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Joseph Romm

Joe Romm is a Fellow at American Progress and is the editor of Climate Progress, which New York Times columnist Tom Friedman called "the indispensable blog" and Time magazine named one of the 25 "Best Blogs of 2010." In 2009, Rolling Stone put Romm #88 on its list of 100 "people who are reinventing America." Time named him a "Hero of the Environment″ and “The Web’s most influential ...

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New Geopolitics Means Arctic Oil, Mega-Projects' BAU Could be Uphill

Western oil leaders may be worrying that Russian President Vladimir Putin’s actions in the Crimea will lead to a ban on international investment in the Russian Arctic, but if it does, that would be doing US companies a favor. The prospects that such mega-investments will remain profitable over 20 years looks questionable at best, even without the geopolitical risk.  

The new BP Statistical World Energy Outlook (2013) is projected that “new energy” is expected to contribute more than half of the growth in future energy supplies in the coming two decades.  BP defines “new energy” as shale, oil sands, renewables, and bioenergy. BP’s projections for new energy are probably conservative because they don’t take into account how governments are going to react to the new nexus of geopolitical shocks now coming into the oil world.

As I write in a new article on the Mitchell Foundation blog, the need to think about an energy system that is less dependent on oil for mobility and industrialization is pressing. Political instability across the globe from Russia and Ukraine to Venezuela to Iraq has laid bare the false promise of relying on a global oil and gas supply business as usual. Europe is facing the unpleasant choice of choosing between an unacceptable Russian incursion into Ukraine and its own energy security. The United States is facing the hard cold truth that a political devolution in Caracas would open the difficult question of who, should chaos prevail, owns and operates the Venezuela-owned Citgo refining and marketing system that represents 5 percent of the US market.  And the critical challenge of climate change and related severe weather events dictates that governments renew efforts at both mitigation (less carbon intensive energy) and resilience (less large-scale, centralized energy).

As discussed at this year’s World Economic Forum, the oil industry has faced more Black Swans since 2012 than perhaps any other time in its history not only from these geopolitical and severe weather events, but also from disruptive technologies. And, the tech boom is going to continue to change the energy industry, for the better (productivity, safety, and sustainability) and for the worse (cyber-attack). The change is likely to be faster and more transformational than most senior oil industry executives care to admit.

 BP in its 2013 World Energy Outlook acknowledged the high likelihood that oil demand in the industrial economies has peaked. BP’s 2013 outlook also opened the door to the idea that exponential growth in oil demand in China might similarly fail to materialize as the country evolved towards less oil intensive economic activities. The BP forecast cited tremendous gains in energy efficiency, changing patterns in the transportation sector and a rise in new energy such as shale gas and renewables as curbing the world’s future thirst for oil.   

The idea that the world needs to â€"and might actually start toâ€" abandon the age of oil is one that falls on deaf ears inside the oil industry itself which is committed to a business as usual model tied to legacy assets and mega-projects like the Arctic. But it is clear now that the world’s largest oil companies were caught off guard when smaller, more nimble competitors such as Pioneer Natural Resources, Continental Resources, Range Resources, Southwestern Energy, Noble Energy, and Devon, to name a few, cracked the code on US shale oil and gas resources. The industry is also betting on the impossibility of scale-up to new transportation technologies that would challenge oil’s dominance on that sector. However, new consumer technologies are starting to nip at the heels of the colossus that currently maintains oil’s dominance in the energy system. So far, that change is slow. But geopolitical events might drive change to move faster than expected by virtue of necessity as the ability of the oil industry to maintain investment in mega-projects falters due to growing political instability across the globe.

Photo Credit: Geopolitics and Oil/shutterstock

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Amy Myers Jaffe

Amy Myers Jaffe is the Executive Director for Energy and Sustainability at the University of California, Davis, with affiliation at the Graduate School of Management and the Institute of Transportation Studies. Jaffe was formerly the Wallace Wilson Fellow in Energy Studies Director, Energy Forum at the James Baker III Institute for Public Policy. She was also the senior editor and Middle East ...

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Energy Efficiency Investment: Is Europe Open for Business?

So far the European Commission recent climate and energy proposals lack a 2030 target for energy efficiency. In this ManagEnergy interview Dr Steve Fawkes, author and entrepreneur, talks about how to unlock the energy efficiency value opportunity.

Q: Your blog is called ‘Only Eleven Percent’? Why?

A: The 11% referred to in the blog title is the useful energy services we use (light, heat, transport, sound etc) compared to the primary energy input.  We can never achieve 100% due to the laws of thermodynamics but we can certainly improve a long way, probably 25 to 50%.  Therefore we could aim for say 15%.  The world spends $6 trillion on energy, 10% of global GDP, a 10% saving equates to $600 billion p.a.    

Q: Where do you see the biggest opportunity for savings?

A: 40% of global energy use is in the built environment and so there is a huge potential for savings within buildings of all kinds.  In order to exploit this resource (and it is best to think of efficiency as a resource) we will need to mobilise external, private finance.  Traditional efficiency has been thought of as a public good that needs to be funded by the public sector but this is out of date as a) public finances are under real constraints and b) the scale of the opportunity is too big.

Q: How do we unlock these savings?

A: One of the fundamental issues around energy efficiency financing is the small size of projects.  Even a major retrofit for a large hospital may only account for £10 to £20m capital maximum, many projects will be £1 to £5m and in other sectors most projects will be measured in thousands or perhaps hundreds of thousands of pounds.  This is a major problem as low cost finance from the debt capital markets requires massive volume, typically £200 to £300m plus.  There is a major opportunity for aggregators to standardise and bring together multiple small projects.  This is the single biggest challenge for energy efficiency financing.  

Q: Can public authorities play a role here?

A: Local authorities and public agencies could act as aggregators of projects as long as they act commercially and don’t impose bureaucratic processes.  We need to establish programmes that pay for the results we want i.e. kWh saved and not just for complying with a process.

Q: Is there a market for investment in energy efficiency?

A: Particularly in the US, there has been the realisation that energy efficiency in the built environment is a huge value opportunity.  Deutsche Bank identified a $279 billion investment opportunity in US real estate energy efficiency retrofits.  This realisation has opened up a whole new group of entrepreneurs and financiers who are working on developing & delivering innovative energy efficiency technologies, new contract structures and new financing methods.

Q: What do investors need in order to act?

A: Policy is an important driver, and policies such as the Energy Efficiency Directive and its national interpretations will increase the pressure on building owners, both private and public, to increase the rate of building retrofits.  

Standard contracts, due diligence and investor-ready projects are vital. An important initiative for standardisation in the USA, and which we are bringing to Europe, is the Investor Confidence Project (ICP).  The ICP develops protocols for different types of buildings that standardise the process and documentation related to developing a project.  This can reduce transaction costs and ultimately enable the secondary market through the debt capital markets which require standardisation.  In addition over time it will produce actuarial data on project performance.  The ICP is gaining traction in the US and we expect to bring it to Europe in 2014.

Links to more:

Only Eleven Percent

Investor Confidence Project

ManagEnergy

Photo Credit: Europe and Energy Investment/shutterstock

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Clare Taylor

Clare Taylor is a communicator specialised in energy and environment. Her work includes media advocacy for grassroots campaigns, supporting national authorities’ implementation of EU energy directives; micro-enterprise, community entrepreneurship and sustainable development NGOs; writing and research for TV reality series, documentaries and journalism.

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Water-Energy Nexus Critical to Future Water Policy

On March 22 in Tokyo, UN-Water will release its World Water Development Report in conjunction with its annual World Water Day 2014 celebrations. This annual event is meant to raise awareness for water â€" indispensable for human life on earth. This year’s theme is “Water & Energy”. Despite its apparent importance, the issue of water rarely receives the public attention it deserves, at least in developed countries where water is readily available. This initial lack of coverage tends to transition quickly to extensive coverage when there is either too much water (flooding) or too little water (drought) available.

Nevertheless, water is gaining in importance, highlighted by the increased focus on the issue of water in various meaningful reports. The 2013 OECD’s report “Water Security for Better Lives” identifies water security as a major policy challenge, stating that 40% of the world’s population will face severe water stress conditions â€" increasing water demand, water pollution, and water stress â€" by 2050 and calling on national governments to speed up water management efforts.

It is important to note that stress is relative to the amount of water available in a certain area. The 2030 Water Resources Group report “Charting Our Water Future” estimates that by 2030 the world’s demand for water will be 40% higher than it is today, and more than 50% higher in the most rapidly developing countries. Historic rates of supply expansion and efficiency improvement will only be able to close a fraction of the gap that will likely have widened by that time. The World Economic Forum ranked water crises third among the ten global risks of the highest concern in its 2014 Global Risk report. Finally, the International Energy Agency (IEA) conducted an in-depth analysis of the water-energy nexus identifying ways to use water in energy production and consumption more efficiently and effectively in the chapter titled “Water for Energy: Is energy becoming a thirstier resource” of its World Energy Outlook 2012. Maria van der Hoeven, IEA Executive Director, puts this in a nutshell: “Water availability is a growing concern for energy and assessing the energy sector’s use of water is important in an increasingly water-constrained world.”

Ms. van der Hoeven stresses that water and energy are inextricably linked and mutually dependent, with each affecting the other’s availability, meaning that changes in water availability may significantly impact energy supply. South Africa serves as a cautionary tale. This water stressed country tries to tackle water scarcity and persistent electricity crises simultaneously by allocating about 2% of its water supply to coal mining and another 2.5% to Eskom, the South African electricity public utility. Eskom is designated “strategic water user” of national importance, according to Shanaaz Nel of Greenpeace Africa. Nearly 98% of South Africa’s water resources have already been allocated, leaving “no resilience in the system to respond to extreme weather events, natural disasters or increased energy demands”, explains Shanaaz Nel.

Many aspects of energy production require the use of water to operate as the next chart shows.

Water Use by the U.S. Energy Sector

In the EU, energy production â€" predominantly cooling water â€" is the greatest source of consumption (44%). In 2010, global water withdrawals for energy use â€" currently accounting for about 15% of total global water use â€" came in at an estimated 583 billion cubic meters (bcm), with 66bcm of water (~11%) withdrawn but not returned to its original source, according to the IEA.

It is crucial to understand the two main ways power generation uses water. In the first case of ‘water consumption’, water is permanently taken from a source to be either evaporated (for cooling) or transported to another location for use. In the second case of ‘water withdrawal’, water is temporarily withdrawn from the ground, or a surface source like a river or lake, diverted and then returned to its origin (hydropower). Renewables such as wind or solar PV have the lowest operational and life-cycle water consumption in terms of water use per unit of electricity generated. Interestingly, concentrating solar power (CSP) technology â€" unlike solar PV cells â€" requires considerable volumes of water for cooling purposes.

Global Water Use for Energy Production by Fuel Type

According to research by the Congressional Research Service, the energy sector is the fastest growing water consumer in the US with projected 85% of domestic water consumption growth between 2005 and 2030. This increase in water use is being driven, at least in part, by shifts to more water-intensive energy sources (shale oil and gas) and technologies. The energy sector’s surging demand for water will inevitably compete with rising demand from the agricultural and industrial sectors. Energy infrastructure is highly susceptible to climate change impacts, which could compound the situation, a conclusion drawn by a report by the Government Accountability Office (GAO) released in January 2014.

So what would make a sensible, environmentally responsible and sustainable water management policy? Foremost, policymakers need to take water efficiency into account when designing energy and climate frameworks because climate change can reduce freshwater supplies and lead to uneven “redistribution” of remaining water resources. This in conjunction with pressures from population growth and changing nutritional preferences adds to the challenge. Additionally, a multi-disciplinary approach that recognizes sectoral water use can be highly inter-related is advisable. Diverting water to agriculture could short supplies for local power generation, for example. Effectively dealing with water scarcity requires a an integrated cross-border strategy with systemic solutions to local challenges that remains mindful of the water-energy nexus.

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Jared Anderson

Jared Anderson, Managing Editor at Breaking Energy, covered international oil and natural gas market fundamentals as an Analyst then Senior Analyst in the Research & Advisory division at Energy Intelligence Group. Earlier in his career, Jared spent several years working in the environmental consulting industry. He holds a Master's degree in international relations with a focus on energy from ...

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Powering Myanmar: Investors Watch Closely as Government Cautiously Cuts Subsidies

In the second part of our series on Myanmar’s power sector, Breaking Energy takes a look at the pricing structure and future demand projections. Both are integral to understanding the third installment on independent power producers (IPPs) and foreign direct investment (FDI). See the first installment on challenges facing the newly-democratic nation here.

The government in Myanmar is showing resolve: just months after backing down over price hikes to electricity, the issue is back on the table. On Wednesday, in a move many expected only after next year’s elections, Myanmar’s parliament approved a new block tariff scheme for households and industry. The price hike should stem some of the government’s hemorrhaging from massive subsidies to the power sector, but prices will remain under production costs, according to experts.

In Myanmar, just like many other parts of the world, electricity pricing is as much about politics as it is about economics. Until the government gets the politics right, experts warn that the country’s electricity costs will continue to stifle economic growth.

The Structure

Turning on the lights in Myanmar falls heavily on the government â€" it was designed that way. The country’s power sector is based on a state-owned single buyer model. Under the Myanmar Electric Power Enterprise (MEPE), the government buys electricity from public and private producers. MEPE sells that electricity to two entities: the Electricity Supply Enterprise (ESE) and the Yangon Electricity Supply Board (YESB). The Ministry of Electric Power (MOEP) oversees the transmission and distribution.

An Affordable Price

The adage is buy low and sell high, but as if something was lost in translation, Myanmar does the opposite. When the government announced price hikes last fall, many commentators saw it as the beginning of a transition to more stable output and an impetus for power producers to increase domestic capacity. But once that increase was revoked after protests, analysts warned that investors might be scared away for the time being. It’s too early to tell what impact this latest hike in tariffs will have, but earlier commentary indicates it doesn’t go far enough in solving the country’s problems. Still, an incremental and phased approach to higher prices may be the only way consumers will accept the heavier burden, according to Vikas Sharma, an associate director at Frost & Sullivan in Singapore. Indeed, the best solution is the one that works in the real world.

Even with the higher rates passed on March 19^th, prices are below where the market would indicate. Estimates for production costs vary, with hydropower the cheapest, but some experts put production costs as high as 125 kyats/kWh (almost $0.13/kWh), above the old and most of the new tariffs. That means the government will still have to subsidize costs. Nomita Nair,a Singapore-based attorney with extensive energy and Myanmar experience asks about the government: “What happens when they go bust or can’t meet demand?” It’s a valid question. If the government can no longer subsidize energy, what will happen to production levels and how will the populace react?

The price hike will push household tariffs up by 14% to 30%, depending on the amount of usage. Commercial fees will stay the same for 60% of companies, but for larger users (defined as consuming more than 500 units a month), prices will double. Experts tell Breaking Energy that prices should rise to between 10 and 15 cents from around three cents now, but the new hike only raises tariffs by one to two cents. Still, the new tariffs are “welcome news,” according to Dejan Dostojic, leader of the World Bank’ team on Myanmar’s electricity power project and will “significantly reduce the budget support of the sector.”

Looking back, an example from October 2012 highlights the enormous subsidies and unsustainability of the program. At that time, the government bought electricity at 80 kyats per kWh (approximately $0.08/kWh) while selling it to households at 35 or 50 kyats per kWh ($0.03- 0.05/kWh). Industry was charged 75 kyats per kWh but consumes significantly less than households. That’s a loss of 5 â€" 45 kyats per kWh. And while Myanmar is sitting on significant natural gas resources, this is not Saudi Arabia or another state flush with cash. Nair summed it up by saying “like many other resource rich countrries, they are still electricity poor.”

Compared to its neighbors, Myanmar has some of the lowest electricity tariffs in Asia. This has led to a huge subsidy, which the government puts at 185 billion kyats (approximately $191 million) a year, though this should shrink significantly with the new tariffs. With prices below costs, producers cannot expand production to keep up with growth in demand or electrify the entire country. Remember, connectivity rates are abysmally low, with estimates between 20-30%. Low prices also deter IPPs from entering the market, say experts. Even still, foreign companies are lining up for new projects. On the sector, Dostojic told Breaking Energy, “there is no lack of interest in Myanmar.”

“While price increases may lead to widespread protests (like the backlash against the hikes in 2013), the government needs to hold its nerve, and prioritize long-term benefits over short-term populist pressures,” Vikas Sharma said.

For those without access, a diesel-powered generator is an expensive but reliable option: operating costs are as high as $0.50/kWh. For a country so desperate for electricity, its not surprising that diesel fuel is one of the most commonly smuggled imports, according to the US government’s report on doing business in Burma.

Quantifying Demand

If it’s neighbor China can be said to run on coal, Myanmar runs on biomass. Almost two-thirds of primary energy in Myanmar comes from wood, charcoal, agriculture residue and animal waste. This highlights the scope of work the government has to transition its population of 60 million â€" mainly rural â€" away from burning wood and manure to using hydropower, natural gas, coal and renewables for energy.

The government is eyeing increased production, but it will be difficult to get there. Poor distribution systems coupled with inefficient plants and hydropower stations far removed from demand centers have all complicated Nay Pyi Taw’s efforts to increase production. In fact, the government used to control all generation capacity, but local anger over the situation prompted the state to allow private producers into the market a few years back, according to a report by Subha Krishnan.

In 2012, if all power-generating plants were operating at full capacity, Myanmar should have produced close to 34,100GWh. But the country generated just 10,800GWh, according to Sharma. As his analysis demonstrates, it’s not just a matter of increasing capacity. Efficiency, poorly maintained plants, a lack of water, transmission losses and load shedding are all significant areas that must be addressed.

* Data from 2012 presentation by Kyaw Swar Soe Naing of MEPE and U Kyaw Kyaw of YESB

With GDP projected to grow around 6-8% annually (and some enthusiastic estimates show GDP quadrupling by 2030), the country’s electricity demand is set to skyrocket. Beyond increasing capacity, the government has indicated it wants 50% of the population connected by 2020-2025. The World Bank is working with the government to achieve universal access by 2030. While the connectivity rate is abysmal â€" its grown from just 16% in 2006 â€" electricity production grew 14.7% annually for the past four years.

*Data from government estimates

The government’s low growth scenario shows demand doubling every ten years. But more realistic projections show demand growing at 1.5-2 times the rate of GDP, implying 9-14% annual growth. In 2011, the country generated 1,100MW but demand was 1,533MW, showing a huge gap and resulting in load shedding. Even if output doubled every five years, it would take five years to meet today’s needs. During that period, demand would have grown 12%, according to the World Economic Forum.

Despite the problems associated with the country’s hydropower supply, Myanmar’s identified 300 potential hydropower stations with a combined capacity of 46,331MW. Of these, 60 identified sites would each have production capacity above 50MW, providing a total of 45,293MW.

While exporting natural gas, mostly to neighbors Thailand and China, only about half of the country’s gas demands are met. In recent years, natural gas accounted for 40% of total exports, showing how much the country relies on the fuel for economic growth. Plans to increase domestic output are in the works but these are years off, according to experts. According to Nair, the government hinted that oil and gas tenders under review now would prioritize domestic use.

With higher prices and a surging demand structure, Myanmar desperately needs to encourage IPPs to build additional capacity.

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Planned Coal-Fired Power Plant Retirements Continue to Increase

Source: U.S. Energy Information Administration, company announcements since November 2013
Note: One gigawatt (GW) equals one thousand megawatts (MW)

The need to comply with the Environmental Protection Agency's (EPA) Mercury and Air Toxics Standards (MATS) regulations together with weak electricity demand growth and continued competition from generators fueled by natural gas have recently led several power producers to announce plans to retire coal-fired facilities.

Between 2012 and 2020, about 60 gigawatts of coal-fired capacity is projected to retire in the AEO2014 Reference case, which assumes implementation of the MATS standards, as well as other existing laws and regulations. The recently announced 5.4 gigawatts of retirements reflect particular strategies of coal plant operators and provide a view of some key drivers in coal plant retirement decisions.

Tennessee Valley Authority. On November 14, 2013, the Tennessee Valley Authority (TVA) announced that it was retiring eight coal-fired units with nearly 3,000 megawatts (MW) of generating capacity. Two units at TVA's Paradise Fossil Plant (1,230 MW), Unit 8 at the Widows Creek Fossil Plant (465 MW), and all five units at its Colbert Fossil Plant (1,184 MW) are now slated for retirement. The current retirement plans are an addition to TVA's previously reported retirement plans announced in 2011. TVA officials gave no fixed dates for the planned retirements, but they stated that the units will not operate beyond the MATS implementation date (April 2015).

South Carolina Electric & Gas. South Carolina Electric & Gas (SCEG) announced that it had ceased operations at its Canadys Station generating facility earlier in November. The 295-MW plant's closing is part of SCEG's efforts to reduce emissions and to comply with MATS regulations that are scheduled to take effect in 2015. SCEG originally planned to convert the units to natural gas before retiring them in 2018.

Consumers Energy. Consumers Energy (CE) petitioned the Michigan Public Service Commission (MPSC) to approve a bond issue to cover costs pertaining to the closure, decommissioning, and demolition of three coal-fired power plants. The facilities, Units 4 and 5 of the B.C. Cobb Plant (312 MW), Units 7 and 8 of the J.C. Weadock Plant (310 MW), and Units 1, 2, and 3 of the J.R. Whiting Plant (325 MW), would cease operations by April 2016. CE stated that the units would be shut down because the installation of additional emissions controls necessary to achieve compliance with EPA environmental regulations would be uneconomical. It was announced on December 3, 2013, that MPSC had approved the bond issue.

Energy Capital Partners. New Jersey-based Energy Capital Partners (ECP) filed paperwork with the Independent System Operator of New England (ISONE) to close the Brayton Point generating facility in 2017 after it failed to reach a deal on a new power-purchase agreement. Brayton Point currently has agreements with ISONE through May 30, 2016. ISONE voted to reject the retirement of the coal-fired units on December 19, 2013, after which the company stated it would go forward with plans to retire all units. Three of the four Brayton Point generating units, totaling about 1,084 MW, are coal-fired; the remaining 435 MW of generator capacity are powered by oil or natural gas. ECP had just recently finalized the purchase of the 1,520-MW facility from Dominion Resources in September 2013.

Georgia Power. Georgia Power (GP) announced that it planned to file a request with the Georgia Public Service Commission (GPSC) to decertify Unit 3 at its Mitchell generating facility. If approved by the GPSC, GP plans to retire the 155-MW unit before the end of April 2015. GP had proposed to convert the unit to use biomass, but the conversion was determined not to be cost effective.

Coal-fired electric generator retirementsâ€"announcements since November 2013

Plant / Units	Plant Owner	State	Megawatts (MW)
Paradise / 1-2	Tennessee Valley Authority (TVA)	KY	1,230
Widows Creek / 8	TVA	AL	465
Colbert / 1-5	TVA	AL	1,184
Canadys / 2-3	South Carolina Electric & Gas	SC	295
B.C. Cobb / 4-5	Consumers Energy (CE)	MI	312
J.C. Weadock / 7-8	CE	MI	310
J.R. Whiting / 1-3	CE	MI	325
Brayton Point / 1-3	Energy Capital Partners	MA	1,084
Mitchell / 3	Georgia Power	GA	155
       Total	Â	Â	5,360 (5.4 gigawatts)

Principal contributor: Elias Johnson

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The EV Wedge: How Electric Vehicle Fuel Savings Vary By Country (and Car)

Have you ever heard of the EV Wedge?

No? Me neither. Let’s try to define it then.

If you’d asked me to define the ‘Electric Vehicle Wedge’ a few years ago I would have chuckled a little, and suggested it was the small pile of cash you needed to afford one.  But due to falling EV prices and rising gasoline prices that snark is utterly outdated.

In almost all countries it is cheaper to power an electric vehicle than fuel a gasoline car.  The cost gap between these two fueling options is what I like to call the EV Wedge .  In some countries this wedge is so damn big that EV drivers can’t sit straight for all the cash in their wallet.

Comparing Gasoline and Electric Fuel Costs

This post provides a cheap and cheerful comparison of fuel costs for electric vehicles and gasoline cars.  To keep it simple I thought we’d look at the costs of fuel for driving 10,000 miles.  This is about 25% less than Americans drive each year, or 20% more than Europeans.

The graph below compares the fuel costs of driving 10,000 miles in a Nissan Leaf (electric) and Toyota Prius (gasoline hybrid).  I’ve shown this graph first so we can see how the fuel savings are calculated.  It also shows us that both the electricity price and gasoline price are relevant when estimating the fuel savings.

The first thing to note is that the fuel cost of driving a Prius is greater than the Leaf in all 12 countries we collected data for.  The variation between both electricity and gasoline prices across countries is enormous.

In countries where gasoline is expensive, like Turkey and Norway, the fuel cost for driving a Prius 10,000 miles is pushing $2,000 whereas in Saudi it is just $120.  The fuel cost of driving the Leaf 10,000 miles varies greatly too. From as high as $980 in Germany down to $116 in Saudi.

The difference between the gasoline and electricity costs is what I call the EV Wedge.  By showing this graph first we can see that in places like Germany and Australia high electricity costs can eat into the wedge.  Where electricity prices are high savvy EV owners look to solar, or time of use pricing, to drive down their charging costs.

The EV Wedge: Nissan Leaf vs Toyota Prius

In each of the last three months of 2013 the most popular new car in Norway was either the Nissan Leaf or Tesla Model S.  There are loads of reasons behind this, including no purchasing tax, free tolls and access to bus lanes.  On top of this the EV Wedge is enormous!!

Here’s the data we looked at above but now purely looking at the fuels savings, the wedge that is.

Over the course of driving 10,000 miles a Prius driver in Norway spends $1,544 more on fuel than a Leaf driver.  In Turkey that figure is $1,360, in the UK it’s $986, in the US it’s $410 and in Saudi it’s just $5.  Just add a zero and you’ve got the fuel savings for 100,000 miles assuming constant prices (the problem with any lifetime comparison).

All the figures assume the typical combined fuel economy for each car and the 2012 average prices for gasoline and electricity in each country. In cases where the electricity used to charge is cheaper than the household grid average this figure will be greater.  This is actually a really important point because typically a majority of EV owners use off-peak charging when available.

In the comparison above we’ve compared two compact hatchbacks.  But the 50 MPG Prius is actually pretty damn efficient for a gasoline car.  The EV Wedge only gets bigger when you start comparing less efficient petrol cars to electrics.

The EV Wedge: Nissan Leaf vs Toyota Camry

I know that the Toyota Camry is a bigger car than a Leaf but I find this a fun comparison.  It is basically America’s most popular electric car (the Leaf) against its most popular sedan (the Camry).  Unlike the Prius, the Camry only gets 28 MPG.  So the fuel savings from driving a Leaf are considerable.

When you compare the fuel costs of the Nissan Leaf to a less efficient petrol vehicle like the 28 MPG Camry they really start to stack up pretty quickly. Don’t get hung up on it being an American Camry, these figures hold for any 28 MPG car gasoline car.

In European countries where taxes on petrol are high the savings from going electric are considerable.  The fuel savings of driving a Leaf instead of a 28 MPG petrol car in the UK are $2,260 for each 10,000 miles.  Even in the US where gasoline is relatively cheap there is a $1,000 saving.

Finally, just for a laugh let’s run the numbers for some luxury cars.

The EV Wedge: Tesla Model S vs Mercedes

I know very little about luxury cars.  I’m not even sure if someone spending $100,000 on a car really cares much about fuel costs.  I’m guessing they love the Tesla because of the torque and the ride.  But then again I may be wrong.

You see the Tesla Model S has topped monthly sales in Norway twice recently.  Not just for electric cars, but for all cars. The tax exemption for buying is no doubt a big deal.  As is the ride.

But just check out these fuel savings for the Tesla Model S compared to the 19 MPG Mercedes 550S.

Not only do Tesla Model S drivers enjoy the pleasure of driving the best car Consumer Reports have ever tested, but in Norway they’ll be able to buy the next one using fuel savings from their first.

Throw in some very modest rises in petrol price over the next decade and a Norwegian Tesla driver will save more than the purchase price by the time they’ve driven 150,000 miles.  Even for places like the UK, France and Germany the figures are pretty impressive.

When you consider that Tesla offers free supercharging in many places you start to see why they have waiting lists. With free electricity the US fuel savings versus the 19 MPG Mercedes jump to $2,000 per 10,000 miles.  In the UK, France and Germany they go above $4,000.  In Norway and Turkey it’s above $5,000.

Curiously I actually think the graph above will eventually be more important for the Pickup Truck market than it is for luxury cars. You see those numbers aren’t far off what the sums might look like for a ‘Tesla Truck‘ vs a Ford F-Series.  And while we may be a few years away from batteries cheap enough to justify electric trucks their potential for fuel savings is just colossal when you consider a F-150 gets 19 MPG.

What to make of the EV Wedge?

To keep this post a bit of fun I avoided delving into lifetime cost comparisons and the fuzzy assumptions they involve.  Instead I’m just trying to point out something that should be clear by now.  Powering a car with electricity is cheaper than fueling it with gasoline (unless you live in Caracas).

Here are some basic takeaways:

• Gas prices are key: the higher the gasoline price the bigger your potential savings are.  This makes electric cars attractive in Europe.

• Electricity prices also matter: the potential benefits of going electric can be eroded by high electricity prices.  Germany and Australia are good examples.

• Fuel economy matters too: the poorer the fuel economy of the car you are switching from the bigger your fuel savings will be.  You can see this in the more than doubling of the wedge between the Prius and the Camry.

Because of the varying differentials between gasoline and electricity prices the fuel savings from going electric vary massively from place to place.  But in general the economics for electric vehicles just keep getting better.

If you’re looking at buying an electric vehicle in a couple of years when prices drop some more there is something worth thinking about.  You see electric vehicles are a bit like solar was a few years ago.  There are currently some very attractive grants and tax breaks that take some pain out of the purchase price, and this means EVs look great from a lifetime cost perspective.

As battery prices keep falling and production scales increase there is a good chance electric cars will keep getting cheaper.  As prices go down and sales go up the current level of subsidy will make less and less sense for governments, just as it did for high feed-in tariffs with solar.  In fact in some places they already seem too attractive.

If I was in the market for an electric vehicle I’d be keeping a very close watch on my local EV grants, tax rebates or other incentives.

If I lived in Norway I’d be on a waiting list, because it would also cut a lot of carbon.

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