The Energy Report – Economy Watch

Why China & Japan Need American Shale

The Energy Report — Wed, 09 Oct 2013 05:09:43 +0000

Please note that we are not authorised to provide any investment advice. The content on this page is for information purposes only.

Thanks to the advent of hydraulic fracturing, or fracking, the U.S. is expected to be the world’s largest producer of oil and natural gas next year, eclipsing production in Russia and Saudi Arabia. Meanwhile, U.S. energy exports to Asia have grown by a third this year, with greater demand coming not just from Japan – a traditional buyer of U.S. fuel – but from China as well.

If there’s a gun on the table in the first act, it will be fired by the end of the play. The way legendary portfolio strategist Don Coxe sees it, the potential to bring on vast U.S. energy reserves is the gun. . .or is it a safety valve?

Don Coxe tells The Energy Report that the fracked oil and gas boom has saved the U.S. from endless recession and explains why he remains bullish on China and Japan as sources of energy demand. Coxe also shares his preferred portfolio allocation ratios between industrial and financial stocks, bonds, metals and energy, with a weight on fossil fuels.

Don Coxe has 40 years of institutional investment experience in Canada and the U.S. From his office in Chicago, Coxe heads up the Global Commodity Strategy investment management team, a collaboration of Coxe Advisors and BMO Global Asset Management. He is advisor to the Coxe Commodity Strategy Fund and the Coxe Global Agribusiness Income Fund in Canada, and to the Virtus Global Commodities Stock Fund in the U.S. Coxe has consistently been named as a top portfolio strategist by Brendan Wood International; in 2011, he was awarded a lifetime achievement award and was ranked number one in the 2007, 2008 and 2009 surveys.

The Energy Report: The consensus of The Street for the last 18 months has been that the slowdown of China’s economic growth is not temporary. Do you agree?

Don Coxe: Since the current commodity boom started up in 2002, critics of my strong belief in the future of China’s growth have said, “It’s not real. The numbers are phony. China is about to collapse. There is too much corruption in Beijing.” And China just kept on growing at double-digit rates! The reason China stopped growing at double-digit rates is the economic collapse in the Europe and the United States – the principal customers for Chinese exports.

But even during the rolling recessions in the U.S. and Europe, China has grown its GDP at 7 percent, which means that it is experiencing substantial internal growth. Admittedly, China has added dramatically to its government debt, but because the country had a 30 percent savings rate before the 2008 crash, its financial system has been able to draw on a huge pool of savings for sustenance, instead of borrowing money to sustain consumer growth.

China has a built-in method of achieving GDP growth: When peasants on 1½ hectare farms are barely able to feed themselves, they migrate to industrial cities. The small farms are amalgamated into larger, more efficient farms, which produce more food and increase China’s GDP. When the farmers flock into the cities, housing is built for them. There are no ghost towns in China. A real ghost town is downtown Detroit, where skyscrapers reflect the demand of the past, but not the present.

This basic model of economic growth has carried China through the worst industrial recession since the Great Depression. Rising iron ore prices alongside increased consumption of oil are growth indicators. And China’s 10-year plan is to move from being the world’s main producer of goods to being the world’s main consumer of goods. China’s leaders are planning to increase imports and to provide all sorts of consumer goods for the populace.

As for energy: People who live on farms where the air is fresh are reluctant to move into cities choked with coal smoke. The Chinese are cutting back on the use of coal and using less-polluting hydrocarbons for power generation. On the other hand, people are buying more cars. And even 10-lane highways are getting congested, which means that more highways will be built to accommodate more cars. All of this growth requires oil.

TER: Where will the oil come from?

DC: Back in the sixties, oil sold for $4 per barrel ($4/bbl). Now, a new oil field cannot be opened up if oil is priced under $60/bbl. The low-hanging fruit, the oil that’s really cheap to produce, is no more. But there is still plenty of oil available through fracking in California and in the Alberta oil sands and offshore drilling. That means spending a lot of money on refining, because processing heavy crude to light crude to gasoline is a very expensive process.

TER: Where’s the capital going to come from for expanding the fracking and refining sectors?

DC: The oil industry can borrow capital to expand because it can easily grow its output. U.S. refiners are aggressively taking leadership from the European refiners. The Swiss did not retool for heavy oil after the collapse of Libya removed the country’s light crude source. The Saudis expand refining capacity for heavy crude, not light crude. The only good supply of light oil on land is from fracking. But the oil industry can only grow fracking so fast, and each oil field has different characteristics. Big oil cannot meet total demand with fracking alone. The next 25 years of growth in the oil industry will be a combination of light oil from under the ocean floor and light oil from fracking.

TER: Will China be able to develop its internal oil fields, or will it be forced to import large amounts?

DC: Down the line, China has a lot of potential for growing a fracked oil and natural gas industry. In the meantime, we are seeing growth in exported liquid natural gas (LNG). The oil industry aims to get higher prices for its frozen natural gas by shipping it to China.

If worldwide GDP growth averages 3 percent for the next five years, it is hard to see how oil prices could fall. But the current situation is a really good story for oil—in many ways the best story since the seventies. Despite the fact that there is zero inflation, oil prices have gone from $70/bbl to $100/bbl. In the past, that kind of increase in oil prices would have automatically meant higher inflation, but this time around it did not.

TER: If Europe and Japan continue to grow, how will that affect energy prices?

DC: When the Japanese ambassador spoke in Chicago a few months ago, he began his speech by saying that Japan has no commodities. This is the third biggest economy in the world and it has to import virtually everything. Japan has no oil, no gas and it cannot use nuclear power because of Fukushima. It is not going to coal, because Tokyo does not want to have the kind of air pollution problems that afflict Beijing. It is going to be hydrocarbons, one way or another. The Japanese economy is strong and will continue to grow fast. It is ironic that in less than a year, Japan went from a negative growth rate to a rate 50 percent higher than the U.S. growth rate.

TER: What is driving Japan’s growth?

DC: The fact that Japan devalued the yen is driving its growth. Japanese manufacturing and exporting companies were in a poor position with the yen stuck at 75 to the dollar. Remember that it had fallen from 250 yen to the dollar when Japan was booming in the eighties. The 75 yen to the dollar meant that Japan’s manufacturing companies had to be incredibly efficient to attract exporters. Now the yen is floating, and manufacturing cash flow is available to expand outputs. Japanese manufacturing is now competitive with China and the rest of the world.

The devaluation of the yen is causing Japanese consumers to unzip their wallets for two reasons. First, they see strong economic growth. Second, Prime Minister Abe has announced that a new sales tax will debut in April. Consumers are afraid that prices are going to rise because of the increase in Japanese exports, and also because of higher sales taxes. The double whammy encourages more economic activity, and that activity feeds on itself positively for growth.

TER: You have previously mentioned the positive economic effects of public/private partnerships on economic growth. Would you call that Keynesianism?

DC: Public-private partnerships are a form of Keynesianism because they can use the state to expropriate land to build roads and bridges. Private companies cannot deal efficiently with a farmer who says, “You bought land to my south and to my north, so I am raising my price per acre from $5,000 to $25,000.” Eminent domain takes care of the gouging issue. Capital needs the public sector.

Another example is that public pension funds promote increased cash flow over the decades for retirees. After the crash, the pension funds were in desperately bad financial shape with zero interest rates. Public-private partnerships in energy ventures are now providing long-term investments with a built-in inflation hedge. These types of investments create wealth in both the private and public sectors through the magic of compound interest.

TER: You talk about “Chekhov’s gun” as the implied threat of the Federal Reserve to allow interest rates to rise. How is that threat affecting energy markets?

DC: The Russian playwright, Anton Chekhov, said that if there is a gun on a table in the first act of a play it will be fired later in the play. That creates a certain amount of suspense. Chekhov’s gun was spotted last spring when Ben Bernanke said, in effect, that the Federal Reserve cannot continue adding $85 billion each month to the balance sheet forever. At some point, the Fed will start tapering down the stimulus project. That tapering down is Chekhov’s gun. Initially, the bond market sold off. Ben must have thought, “We are only in act one of a play that is going to last for several acts.” So the gun is still hanging there, unfired.

For the energy markets, however, Chekhov’s gun operates in reverse: The gun is the threat of bringing on vast new energy resources. But everybody knows now that there are enough hydrocarbons in the ground to spur economic growth for a long time. In regard to energy, the gun is a safety device, as opposed to the bond market, where it functions as a threat.

TER: You appeared at the Casey Research Summit last week. Can you give us a preview of your talk on the energy front?

DC: The U.S. would be back on the edge of recession if it were not for fracking. Fracking produces cheap natural gas and high-quality light crude oil. Thanks to fracking, we have been able to reduce the use of coal without shutting down the utilities. In the past, it was risky to rely on conventionally produced natural gas because natural gas prices could rise monumentally in times of shortage. Recall what happened after Katrina when natural gas went to $15 per thousand cubic feet!

Fracking will provide cheap natural gas for the next century without importing a cubic foot. It is a tremendous guarantee of stability to the U.S. economy. It also means that economic growth can be energized by light crude without having to rely on heavy crude. Without fracking, we would be spending trillions of dollars refining Venezuelan and oil sands heavy crude. We would still be in recession without fracking. The energy industry has done more for the U.S. economy than anybody except … Ben Bernanke.

TER: It is always informative talking to you, Don.

DC: It’s been great fun.

By Peter Byrne, The Energy Report

Don Coxe: China, Japan and Chekhov’s Gun—Where Does Fracking Fit In? is republished with permission from The Energy Report.

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The US Shale “Boom”: A Fantasy Concocted By Politicians & Industry Bigwigs?

The Energy Report — Mon, 23 Sep 2013 08:34:32 +0000

Please note that we are not authorised to provide any investment advice. The content on this page is for information purposes only.

The numbers don’t lie—but politicians and industry bigwigs do. While pundits still wax poetic about an era of American energy independence, Bill Powers, author of the book “Cold, Hungry and in the Dark: Exploding the Natural Gas Supply Myth,” sees productivity plummeting in almost every major shale play.

In this interview with The Energy Report, Powers tells us to forget about LNG exports and a manufacturing boom and get positioned for a bust. How? Invest in energy equities. Powers names his favorites for maximum returns when the bubble bursts.

The Energy Report: Your last interview in May stimulated more discussion on how much natural gas supply we actually have in North America. Have there been any significant developments since then to support your views on the long-term supply picture?

Bill Powers: More data points have come in supporting my views and making it very clear that the Fayetteville and Haynesville shales are now in decline and the Barnett had a very steep, 17 percent decline in H1/13 on a year-over-year (YOY) basis. It is now producing about 4.6 billion cubic feet a day (Bcf/day), which is substantially down from its peak of near 6 Bcf/day. The facts are starting to show that declines for the older shale plays such as the Barnett, Haynesville, Fayetteville and Woodford are very serious. More important, once production growth from the Marcellus slows down, it will no longer be able to offset declining production from shale plays as well as conventional, offshore, CBM and tight sands production, which are all in terminal decline.

TER: Have companies been overproducing?

BP: There are still about 40 rigs running in the Haynesville. That’s dry gas with no associated liquids. Virtually every one of those wells will be uneconomic at under $6 per thousand cubic feet ($6/Mcf) and probably closer to $7/Mcf. About 80 percent of production will come within the first two years for most Haynesville wells, so current gas prices have an outsized influence on an individual well’s economics. There are still a number of companies out there willfully drilling uneconomic wells, which boggles my mind. These companies are continuing to drill to keep their production from collapsing entirely.

Last year, Chesapeake Corp. wrote down 4.6 trillion cubic feet (4.6 Tcf) of proven reserves from its Barnett and Haynesville shale wells. At the end of 2012, Southwestern Energy Co. wrote down the proven reserves of its Fayetteville Shale assets from 5 Tcf to 3 Tcf. Other companies, such as BHP Billiton Ltd. and BP Plc, took huge write-downs. BG Group Plc also took a big write-down due to poor performance of its Haynesville wells. The list goes on and on. These reserves were supposed to have a 90 percent confidence level of being producible and generating a 10 percent rate of return using existing technology.

The low price of gas alone isn’t causing these write-downs. A lot of it has to do with the poor performance of these wells. There’s been a lot of evidence put forward by myself, Art Berman, who wrote the forward to my book, and David Hughes, that the shale industry has overbooked its reserves by approximately 100 percent. The write-downs of the last few years have largely proven this out. More importantly, if shale operators are writing down reserves at the rate we’ve seen, this also speaks volumes about the total recoverability of all shale gas in the United States.

The two really bright spots right now are the Marcellus and the Eagle Ford. There have been thousands of wells drilled through the Marcellus over the years for both the Oriskany, directly underneath the Marcellus, and the Trenton Black River Trend, also below the Marcellus. Operators have had the advantage of using a very good cheat sheet to know where to drill first for the best wells. Additionally, all the knowledge operators gained in developing other shale plays has greatly accelerated the ramp-up in Marcellus production. For example, operators began drilling horizontal wells early in the lifecycle of the Marcellus due to experience gained in the Barnett, Fayetteville and Haynesville. The strong growth in the play has really been the only thing that has kept gas production even close to flat this year in the U.S. As I discussed earlier, it will not be long before future shale wells will not be able to replace production from older wells.

The decline will become more evident once the aerial extent of the Marcellus fields becomes more clear. This is starting to happen in southwestern Pennsylvania, where Range Resources Corp. (RRC:NYSE), one of the most aggressive producers in the region, is now saying in its investor presentation that it and other operators have defined the outer limits of some fields. Once you run out of the high-quality, liquids-rich drilling locations in Washington County (southwestern PA), you will get a very large fall-off in productivity.

TER: Why all the production overestimates regarding U.S. shale reserves?

BP: Many of the people promoting the 100-year myth were doing it for either financial or political reasons. Let’s look at why the U.S. government promoted the myth. The government has the idea that if the U.S. were to become an LNG exporter through the rapid development of shale, we would lessen the importance of Russia on the world’s stage. Ernest Moniz, who’s the head of the Department of Energy, is a big advocate of exporting LNG. He recently granted the fourth LNG export license to Dominion Cove Point LNG to open an export facility in Cove Point, Maryland.

Industry mainly wanted the ability to sell acreage to latecomers. Chesapeake Energy championed this model by generating a lot of excitement after making a discovery and then selling out a significant chunk of that acreage to a latecomer, who would almost always overpay. This strategy was actually discussed by the former CEO, Aubrey McClendon, in an October 2008 conference call. Industry needed money to develop its own acreage and also to generate higher stock prices so they could acquire other assets or companies more cheaply. David Hughes has talked about how it would require $42 billion to keep gas production flat in the U.S., while shale operators only generate around $32–33 billion dollars a year in revenue, and probably closer to only $8–9 billion in cash flow. They are far outspending their cash flow to drill additional wells.

Looking at academia’s role, there was a case where Penn State put forward a very optimistic report that was paid for by the industry and that payment was not disclosed. After a community group discovered this, the dean of the Earth Sciences Department redacted the report and reissued it with numerous changes and proper disclosure as to the source of the funding. The report discussed the economic impact on Pennsylvania from the Marcellus and made some very optimistic projections.

Unlike a lot of people who make statements about the amount of gas that’s out there and provide little or no empirical evidence to support their claims, I have almost 600 footnotes in my book that explain exactly where my estimates of future shale gas recoveries come from.

Other promoters of the 100-year supply myth include people such as T. Boone Pickens, who has a very self-interested agenda to get natural gas vehicles onto the road. Pickens, who said on CNBC in 2011 that the U.S. will recover 4,000 Tcf and has never provided any support for this statement, promoted this patriotic idea that we should convert our vehicle fleet to natural gas rather than buying oil from the “enemy.” Pickens has been known to refer to certain oil-exporting nations as the “enemy.”

However, Pickens almost never discusses the fact that he is one of the largest owners of Clean Energy Fuels Corp., a company that is one of the biggest providers of natural gas refueling stations and that stands to benefit significantly from the growth of natural gas vehicle adoption. The legislation that T. Boone Pickens is advocating for in the Pickens Plan, which includes large tax credits and grants to the natural gas vehicle (NGV) and NGV refueling industry, would benefit him uniquely because he owns approximately 18.1 million shares of Clean Energy Fuels stock. Pickens’ shares are currently valued at around $230 million. There are very few people, and you can count them on one hand, who want to discuss the reality of shale gas, which my book does.

In addition, the Securities and Exchange Commission (SEC), after heavy lobbying, changed its rules in 2010 to allow for a significant increase in proven undeveloped reserves to be booked, so the SEC was also complicit in the perpetuation of the shale gas myth. Without this change in how shale gas reserves were booked in 2010, most shale operators would have been forced to take large write-downs rather than booking increases in reserves. I believe this rule change by the SEC grossly distorts the value of a company’s reserves since it allowed for a large increase in the booking of proven undeveloped reserves.

TER: What other economic consequences do you see if and when your views become reality?

BP: I think it will be similar to the housing crisis, where a handful of people saw it coming and profited from it. There was significant evidence that housing prices were unsustainable, but most people were surprised when the housing bubble popped. People from Alan Greenspan to Ben Bernanke and others had a lot of information about the economy and how unsustainable house prices were, but did not want to talk about it publicly. There’s a saying that “the impossible can become the inevitable in the blink of an eye.” I think this will happen with natural gas. For example, in the first week of December 2000, gas prices went from around $4/Mcf to over $10/Mcf in only a few trading sessions. This was due to falling production, lower storage levels and a cold spell that set in across much of the United States. This price spike was the first of numerous spikes during the last decade.

In the late 1990s, Enron and other companies like Calpine Corp. built dozens of natural gas-fired power plants on the belief that the price stability between 1984 and 1999 would continue for several more decades. The build-out of gas-fired power plants was led by large demand increases from the electricity generation industry at a time of falling production. Few remember that U.S. gas production fell from 2002 to 2007.

Shale gas is a finite resource. When prices start to escalate, unfortunately, the situation will be even worse than the spikes we had in the early part of the 21st century, and even more so than the 1970s. From 2000–2010, we were able to increase our imports of LNG, and in the 1970s we built dozens of nuclear-fired power plants and hundreds of coal-fired power plants to reduce demand for natural gas. Now we are seeing the nuclear industry in decline, with five plants shutting down this year out of 104 plants, and many more closing in the next two to three years. Dozens of coal-fired power plants will be shutting down before mercury emissions laws take effect in 2015 and few new plants are likely to be built given the stringent emissions standards.

Even worse, for the first time in the industry’s history, world LNG trade shrank last year. We are seeing record-high global prices for LNG with no sign that this is going to slow down or reverse. When the U.S. is forced to go back out and try to secure cargos to import LNG, the prices we will be forced to pay are going to be much higher. The current price of LNG in Chile, Brazil and Argentina is $14–15 per million British thermal units ($14–15/MMBtu). In Japan and Korea it’s been over $16/MMBtu. Even Mexico is currently importing LNG at $16/MMBtu due to demand outstripping supply and lack of pipeline capacity to connect to U.S. markets. The U.S. is going to be forced to pay much higher prices when it will not be able to meet its own domestic needs, as shale gas rolls over and Canadian imports decline as the country begins exporting LNG to Asia via British Columbia.

TER: If we don’t have excess gas supply, will that lead to a bust in the planned LNG export terminal business?

BP: Barring a major new shale gas discovery in the very near future, the future of U.S. LNG exports will have to do with how much domestic demand falls off. A lot of these terminals will probably get built only to lie dormant when the government declares force majeure and cancels overseas contracts. Politicians will look at their constituents and see all sorts of suffering, from higher electricity bills to higher food prices to higher home heating bills, and say they are going to pull the export licenses from all these LNG plants. As I say in my book, “Overseas customers do not vote.”

TER: To address your earlier analogy to the housing bust, what are some actual investments that could be profit opportunities in the event of a shale gas crisis?

BP: Right now I think there are some great ideas out there. Three of my favorite Canadian companies are Bellatrix Exploration Ltd. , Advantage Oil and Gas Ltd. and Arsenal Energy Inc. —I’m a director with Arsenal and the company just had some very good news. My favorite company in the United States would be Denbury Resources Inc. , which is very active in CO2 flooding in the Gulf Coast as well as in the Rocky Mountain region.

Advantage has a great Montney play at Glacier, where it has built out its infrastructure. However, the company is not overproducing its fields at a time of low Canadian gas prices. I think management’s done a great job and as gas prices rise, the company has tremendous leverage.

Bellatrix is a significant producer that will have room to grow. It has great Cardium acreage and is very leveraged to the Duvernay Shale. The company has significant upside from here.

Arsenal Energy trades at a very low multiple of valuation on any metric and has enjoyed very strong results in North Dakota as well as in central Alberta. It’s 75 percent oil. Again, I am a director and shareholder.

In the United States, Denbury has a very large inventory of projects it continues to develop and is far and away the industry leader at tertiary oil recovery. It gets Louisiana Light pricing for its oil and generates very significant cash flow, even at substantially lower prices. There’s almost no exploration risk for the company given that it is reestablishing production via CO2 flooding from previously depleted fields.

TER: What should investors be doing now to benefit from or protect themselves from what you believe lies ahead?

BP: I think that energy equities will provide some of the best returns available anywhere over the next 10 years, similar to what we saw in the 1970s. Shortly after the U.S. eliminated convertibility of the U.S. dollar into gold in 1971, which I consider a default, we saw massive inflation. Oil and gas and precious metals and equities related to these two sectors were among the very few investments that paid off in that era. The returns in those investment classes were fantastic, whereas just about everything else, from government bonds to general equities to tech stocks, got destroyed. I think we’re heading toward a similar period. Even though natural gas has been one of the only commodities left behind by the flood of liquidity over the last five years, it is also one of the most volatile commodities. I am looking for a period of serious outperformance by natural gas over the next decade.

TER: Care to take a shot on where you think gas prices may end up in the next few years?

BP: The U.S. is heading toward world gas prices. To recap, this means double-digit prices within the next three to five years for a number of reasons. First, in addition to lower U.S. production, our imports from Canada are going to be diverted toward Asia through LNG exports. Canadian production continues to fall, and 2013 will mark the 12th year since it peaked. Canada will be unable to export to both the U.S. and Asia due to lower production and record domestic consumption. Second, the U.S. is now far more reliant on natural gas to generate electricity than it was in the 1970s. The U.S. got out of that gas crisis by building nuclear and coal-fired power plants, not through increased gas production. Last, this time it’s going to be very difficult to destroy demand because we are starting to see manufacturing come back to the U.S. and coal and nuclear plants are closing.

TER: Thanks for joining us today and updating us on your thinking.

BP: Thank you. I greatly enjoyed our interview.

By Zig Lambo, The Energy Report

Bill Powers: Give Up the Shale Gas Fantasy and Profit When the Bubble Bursts is republished with permission from The Energy Report.

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Investing In Lithium: Time To Capitalise On The Future Of Energy Storage?

The Energy Report — Mon, 09 Sep 2013 07:12:34 +0000

Please note that we are not authorised to provide any investment advice. The content on this page is for information purposes only.

In the commodity world, lithium has been a rising star as its use and prevalence has skyrocketed in recent years. Even renowned investment sage Warren Buffett chose to invest in a little-known Chinese battery producer in 2008, eventually earning back nearly $1 billion. Is it too late to jump on the bandwagon, or are there still opportunities for you to capitalise on the trend?

The sleekest, most efficient electronic product is nothing without the battery that powers it. Enter lithium, the raw material battery manufacturers depend on. With electric/hybrid vehicle use on the rise and demand for consumer electronics steadily climbing, lithium producers with quality product should have no shortage of potential buyers. In this interview with The Energy Report, Luisa Moreno, mining and metals analyst with Euro Pacific Canada, names her top lithium picks with both the goods and the customers.

Luisa Moreno is a mining and metals analyst with Euro Pacific Canada. She covers industry metals with a major focus on electric and energy metal companies. She has been a guest speaker on television and at international conferences. Luisa has published reports on rare earths and other critical metals and has been quoted in newspapers and industry blogs. She holds bachelor’s and master’s degrees in physics engineering from Nova University of Lisbon and a PhD in materials and mechanics from Imperial College London.

The Energy Report: Luisa, tell me: What is exciting about lithium?

Luisa Moreno: Lithium has many unique and important characteristics. It is the least dense solid element and the lightest metal. It forms alloys with some of the highest strength-to-weight ratios. Lithium has the highest specific heat of any solid element, and is used in heat-transfer applications. It has neurological effects in humans, and so is used in pharmaceutical applications, such as mood stabilizers. Lithium chloride and bromide are two of the most hygroscopic, or water-absorbing, known materials and are used in air conditioning, industrial drying systems and dehumidifiers.

In the recent years, lithium has gained increasing attention as it has become an essential component in ultralight electronic devices. It is also increasingly the preferred medium for electric vehicle batteries, and that makes lithium important for the development of a greener, cleaner world.

TER: What are the principal industrial applications of lithium?

LM: The major application traditionally has been in the glass and ceramics industry and is used in the manufacturing of grease lubricants. Lately, we have seen an increased demand for lithium in the battery sector. Batteries, glass and ceramics combined account for more than 55% of the world demand. Lubricants and metallurgical applications are also important and account for about 20% of world demand.

TER: Which applications are growing the fastest?

LM: Battery applications are growing significantly faster. We expect to see that sector increasing about 12.6% per year going forward to 2020. The others will continue growing, but more on pace with the global GDP, closer to 3%.

TER: Does lithium have any competitors in these applications among commodities?

LM: There are substitutes for lithium in most of its applications, but it seems that lithium has been consistently the preferred element material because it likely offers the best performance/cost ratio compared to other materials.

TER: How fast has demand for lithium grown in the last decade?

LM: It has grown 7–8% per year. That has been driven significantly by demand in the battery sector, which is related to the adoption of electric vehicles and smart devices like iPhones, iPads and lighter laptop computers.

TER: What companies in lithium are your favorites, and why?

LM: We’ve been following the progress of Nemaska Lithium Inc. (NMX:TSX.V; NMKEF:OTCQX). We like how the Whabouchi project has progressed. The Whabouchi deposit grades are among the highest in the world. While most lithium junior companies are targeting the lithium carbonate market, Nemaska is focusing on lithium hydroxide, which is a higher value product. It can be sold at a price of more than $8,000 per tonne ($8K/tonne) compared to $6K/tonne for carbonate, depending on grade. And lithium hydroxide is an increasingly interesting lithium compound for batteries because it also offers better performance.

Nemaska has also managed to secure strategic partnerships. One of them is with Sichuan Tianqi Lithium Industries Inc., a subsidiary of Chengdu Tianqi Industry Group Co. In addition, Nemaska has a secure partnership with Phostech Lithium (a subsidiary of Clariant Canada Inc. a member of Clariant AG Group [SWL:CLN]), and is fairly close to production now. It wants to develop a modular plant to start producing lithium hydroxide.

So, to sum it up, we like its high-quality deposit, its unique business plan, its new process targeting a not-so-competitive part of the market and the partnerships that it has been able to secure. We have a Speculative Buy recommendation for the stock and a $0.57 target price.

TER: Nemaska has a 100% offtake with Phostech scheduled for 2014. Will the modular construction enable Nemaska to complete a 500 tonnes-per-annum (500 tpa) plant by then?

LM: Yes, contingent on its ability to finance that first plant. Its target is even higher—20,000 tonnes—so that will be the first modular plant of many other ones to follow. The idea is for Nemaska to work together with Phostech Lithium to tailor the lithium hydroxide product to the specifications of Phostech Lithium and other potential customers.

TER: Nemaska Lithium Inc.’s share price dropped very quickly starting in March 2013. What happened then to cause it to drop?

LM: I’m not completely sure why the stock had such a hit. The market for resources has been very volatile and weak. The company has been trying to raise funds for the first plant and, given the markets, the fundraising period was extended. It is possible the market was nervous about that and there was some pressure on the stock as a result.

TER: Is the Cree Nation committed to Nemaska Lithium Inc.’s business plan to exploit the resources up there?

LM: It seems to me that they are committed to the development of the project. I visited the Nemaska Lithium site, and when we were there we had the privilege to meet the chief of the Cree Nation and some of the other members of the community. They own 2.6% interest in Nemaska Lithium. They showed a lot of interest in the mine’s development and believe it could bolster economic development for the region.

TER: Are there any other companies that interest you?

LM: Yes, we launched coverage of Canada Lithium Corp. (CLQ:TSX; CLQMF:OTCQX). We have a Speculative Buy recommendation and $0.90/share target for the company. We like that name, first of all because it’s one of the most advanced, if not the most advanced lithium project right now. The company has completed most of the construction and is starting to produce on a continuous basis. The target production for this year is roughly 3,000 tonnes. It expects to reach its 20,000-tpa target by next year.

Canada Lithium has secured offtake agreements with two different parties. The company has a business plan to diversify its suite of products. The main product is lithium carbonate but it plans to also produce lithium hydroxide and sodium sulfate products. It got a $6.5-million grant from Sustainable Development Technology Canada (SDTC) to develop a lithium metal plant, so that’s another project under development. The company is really one of the frontrunners. It’s very well positioned, has offtake agreements and a strong management and technical team.

TER: Canada Lithium Corp.’s mine and plant are only in the startup phase, but you expressed confidence that it will be able to produce other lithium products by 2015 and build a sodium sulfate plant. That’s a pretty full plate. What’s the basis for your confidence?

LM: The company is very much interested in developing these other businesses. We did not include these other products in our model and they’re not part of the target price, either. From my perspective, this is potential blue sky for the company. As I said, the company has a grant of up to $6.5M to develop the plant for the metal, so it already has that funded for development of a pilot plant. And it has done extensive work for the production of lithium hydroxide. It worked with SGS Minerals Services, and concluded it would be economic to develop a facility for lithium hydroxide.

TER: What is the term for Canada Lithium Corp.’s offtake contracts?

LM: The contract with Tewoo Group is a five-year agreement to sell a minimum of 12,000 tonnes of battery-grade lithium carbonate, which accounts for 60% of Canada Lithium’s production target of 20,000 tonnes of lithium carbonate. The agreement has a provision that allows the offtake to increase to 14,000 tonnes, which would account for about 72% of the total target for production. The other contract with Marubeni Corp. (MARUY:OTC; TYO:JP-8002) is a three-year distribution agreement. It will start at a minimum of 2,000 tonnes of lithium carbonate this year, and that could potentially increase to about 5,000 tonnes going forward. These are very nice agreements considering Canada Lithium is not at full production yet.

Canada Lithium was likely able to secure a good share of the supply market as it is planning to sell a carbonate product with higher purity and higher value than products sold from existing South American brine producers. South American “commercial” grade lithium carbonate sold for about $4K/tonne in 2012, and Canada lithium expects to sell its lithium carbonate product for $6K/tonne, 50% higher. North American high-purity lithium producers, including Nemaska, benefit from relatively lower energy and reagent costs.

TER: Do you have any other lithium companies under coverage?

LM: We have featured a number of other names that we are watching very closely. We like Orocobre Ltd.’s (ORL:TSX; ORE:ASX) Salar de Olaroz project in Argentina. According to recent announcements, the company is now lining the evaporation ponds and will start the evaporation process very soon. That process usually takes 18–24 months, so we expect the company to start producing some brine concentrate probably by 2015 or 2016. We also appreciate that the company has a partnership with Toyota Tsusho Corp. (JP-8015:TYO) and seems to be well funded.

Back into the hard rock space, we like the names that have the potential for byproducts. We are watching two companies very closely. One is Critical Elements Corp. (CRE:TSX.V), which has a project in Quebec as well. The company has potential to produce a tantalum byproduct out of its spodumene deposit.

Houston Lake Mining Inc. (HLM:TSX.V) is a smaller but very interesting company in the early stage of development. It has shown very high grades from drill results, with byproducts as well of tantalum, and potentially cesium and rubidium.

We have featured a number of companies at different stages of development and with different types of lithium deposits, including those with lithium clay deposits and jadarite-rich deposits with lithium and boron mineralization. We expect some of these companies to become part of a diversified lithium supply market.

TER: I appreciate your time, Luisa. It’s a very interesting field.

LM: Absolutely.

By Tom Armistead, The Energy Report

Two Ways to Capitalize on Accelerating Lithium Demand: Luisa Moreno is republished with permission from The Energy Report.

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Why Peak Oil Pundits Got It Wrong

The Energy Report — Thu, 13 Jun 2013 09:31:50 +0000

Please note that we are not authorised to provide any investment advice. The content on this page is for information purposes only.

Many investors believe that global oil production would start to decline from 2014-15, a prediction based on the so-called peak oil theory that the world demand for oil would soon outstrip supply and send oil prices through the roof. For several years in the middle of the last decade, as oil prices climbed past $100 a barrel and analysts were betting it would cross $200, peak oil pundits were sure they had it right.

Stepping away from the pack, Andrew Coleman of Raymond James Equity Research is making a contrarian forecast for an oil glut in 2014. Shale oil production is on the ascent, with the United States joining Saudi Arabia on the supply side, while China’s hunger for oil may be sliding and demand in developed countries remains in decline. In this interview with The Energy Report, Coleman explains his thinking and names the producers best positioned to capitalize on the turbulence ahead.

The Energy Report: Why are you expecting an oil glut in 2014?

Andrew Coleman: Because of the evolution of North American shale oil plays, we are on track to add about 3 million barrels (3 MMbbl) of new supply over the next five years. Yet we know oil demand has been falling across the developed nations and is still weak coming out of the global financial crisis. Those developments point toward a glut.

TER: Saudi Arabia surprised you last year by cutting production when oil was more than $110 per barrel ($110/bbl). Why would Saudi or other suppliers not do that again?

AC: What hurt production outside the U.S. last year—and helped keep the demand side a little more in balance—was that Saudi cut 800,000 barrels a day (800 Mbbl/d) in Q4/12, sanctions in Iran reduced exports by about 800 Mbbl/d as well, conflict in Sudan took 300 Mbbl/d offline and the North Sea average was lower by about 130 Mbbl/d. These reductions kept last year’s supply more balanced than we thought it would be. Going forward, Saudi’s ability or willingness to cut is certainly going to be tested, because by our model the country may need to cut 1.5 million barrels a day (1.5 MMbbl/d), about double what it cut last year. It would have to do that for a longer period of time, given the amount of excess storage that could show up on the global markets.

TER: But, as you just pointed out, Saudi Arabia’s cut came in the context of actions by other players. The other players are going to be as unpredictable as they were last year, aren’t they?

AC: Certainly. That’s a big risk to our call. The other players are very unpredictable as well. I think Saudi has two years of foreign currency reserves at its current spending level. The country doesn’t have a deficit right now, so the question is, would it be willing to tolerate a deficit? Most other countries have deficits, but that doesn’t mean Saudi will. It is hard to predict because we’re dealing with personalities and governments, as opposed to hard numbers. We’re going to keep watching, and we’ll adjust our forecast if some of those scenarios play out.

TER: Was Saudi Arabia’s production cut driven by a policy change?

AC: Saudi Arabia cited internal demand issues in its production cut. The cut may also reflect an adjustment to offset the start-up of Manifa, which occurred last month.

TER: If the glut does occur, which benchmark crudes will be most affected, whether by going up or going down?

AC: In the U.S., production of light oil will dramatically increase due to the shales. Without the ability to export, we are already seeing prices of West Texas Intermediate (WTI) reflecting that “stranded” lighter barrel. We see light imports being backed out of the U.S. as early as this summer as well. Finally, as infrastructure bottlenecks are removed onshore, we see risk to Gulf Coast prices (e.g., Light Louisiana Sweet). With much of the U.S. refinery infrastructure having been geared to process heavier barrels, the large growth in light barrels has already driven WTI prices to a discount with Brent. Risks to Brent could come down the road if European and Chinese demand remains tepid.

TER: Will Venezuela’s production decline continue?

AC: With Nicolas Maduro running things down there now, we see Venezuelan production remaining flat for the next couple of years. Volumes declined each of the past four years.

TER: What role will other players in the oil space have in either creating or preventing the glut?

AC: Prior to about 2009, we were in a world where there was one marginal producer of oil (Saudi), and one marginal buyer of oil (China). Now we’re in a world that has two marginal suppliers of oil, those being the U.S. and Saudi. We have not added any new marginal buyers of oil. The question remains, is that marginal buyer of oil—China—as hungry for oil as it has been in the past? We also know that as economies develop, they become less energy-intensive. And, factoring in the potential growth of natural gas consumption, that drives our caution.

TER: Do you have any parting thoughts on the oil and/or gas markets that you’d like to share?

AC: Yes. From our macro view, we’re cautious about the oil outlook. We’ve got a lot of production, and we’re unclear about the strength of demand on the oil side in the next 6–18 months, going through 2014. On the gas side, after bottoming last year, gas looks like it is poised to be higher down the road, which makes us more constructive there. We have to see more evolution on the demand side, be it in the short term with power plant construction or in the longer term with the quest for use of compressed natural gas as a transportation fuel.

If the price spread between oil and natural gas remains wide, we’ll see continued evolution toward natural gas use across our economy. That will be good for everybody. It should help unlock value for the manufacturing space. It should also unlock value for consumers, who won’t have to spend quite so much to heat their homes and fuel their cars. It would ultimately kick-start the next big wave of economic expansion on the back of affordable natural gas in the U.S.

TER: Andrew, thank you for your time.

AC: My pleasure.

By Tom Armistead, The Energy Report

This is an abbreviated version of Potential Oil Glut! Raymond James Analyst’s Contrarian Forecast republished with permission from The Energy Report.

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Is The US Shale Boom Already Over?

The Energy Report — Fri, 10 May 2013 06:45:06 +0000

Please note that we are not authorised to provide any investment advice. The content on this page is for information purposes only.

During the last three years, the mantra in the U.S. for shale has been, “Drill, baby, drill.” But the reality is there is only one true gas formation in the U.S. that is increasing production – Marcellus – while every other single shale gas play is now in decline.

Shale oil has been North America’s great experiment, says Oil & Gas Investments Bulletin Editor Keith Schaefer. But in this interview with The Energy Report, he questions the experiment’s success and predicts steep declines ahead, with just a few formations left to supply the market. The question is what shale play will last the longest? Read on to find out how—and when—to get positioned for the end of the shale revolution.

The Energy Report: A number of experts say North American gas supply is peaking. Where do you weigh in?

Keith Schaefer: During the last three years, the mantra has been, “Drill, baby, drill,” for a number of reasons. The price of gas was never one of those reasons. Companies drilled because the technology kept improving. They drilled because they were able to get cheap foreign capital to partner in joint ventures. The market situation was not based upon economic “truth.” It was based on securing the land position and, “Economics be damned, let’s go!” But we are now returning to a real gas market based upon economic fundamentals. Where that’s going to shake out, nobody knows; the market is betting on higher prices.

The reality is, Peter, there is only one true gas formation in the U.S. that is increasing production, and that’s the Marcellus. Every other single shale gas play is now in decline. The industry is now much more disciplined in producing gas, as the rig count has gone way down. But I suggest that the price rise is a year or two away because there is so much gas drilling going on in the Marcellus and Eagle Ford. These two formations are making up the shortfall in other regions. At some point in time—nobody really knows when—the scales are going to tip: Gas production in North America will seriously decline. The gas bulls think it’s going to happen quickly, because the hydraulic fracking wells come in like gangbusters and then rapidly decline. An overall decline in supply could drive up the price.

TER: Are there undeveloped or undiscovered shale gas plays still out there?

KS: The short answer is that we do not know. Explorers are testing new areas. Just outside the Bakken, there is activity in Bowman County. There is play in the Heath Shale. It looks like the Utica will be mostly gas, not oil. But I don’t see any more Marcellus Shales out there.

TER: Is there a limit to exploration?

KS: All of the easy fruit has been picked. Remember, most of the shale plays were already well known geology, so everybody knew where the oil and gas was. We just did not have the technology to get the stuff out of the ground. As the technology has improved, bit by bit, and the politics has improved, bit by bit, the known shale plays are being developed to capacity. Is there another undiscovered giant like the Marcellus lurking somewhere? Realistically, I doubt it. The industry has very good tools for looking underground. A big monster shale play that would keep the gas glut going for another two or three years is a bit of a stretch.

TER: Will we go back to importing gas?

KS: I do not see the U.S. importing much gas for at least three years, and maybe longer, depending on existing wells’ decline rates. Right now, drillers are doing maybe four wells per square mile. With downspacing, they can get down to 8, 16 or even 32 wells per square mile. There is still a lot more domestic gas to be pumped before we need to import a lot of gas again.

TER: Let’s talk about the role of Canadian penny stocks in your portfolio. How is the shale experiment with the oil juniors going in Canada?

KS: All across North America and especially in Canada, the rush into shale oil has been a great experiment. But it really doesn’t work in a junior company. The place for juniors in an investor’s portfolio right now is getting smaller and smaller. The shale, or tight wells cost a lot of money to drill, and the juniors just do not possess the capital necessary to develop many of these plays. The wells will pay out in 12–24 months, and that is simply not fast enough for the junior companies to recycle the cash and drill another well. A junior might have a big land position, but it cannot develop it, particularly on the gas side, without continually raising equity. Many of these companies have stopped or dramatically reduced drilling. It’s a bad spiral: You drill less, you produce less and your declines are high. These smaller energy firms are in a really tough spot—for oil or gas.

TER: Is it reasonable for the management of these struggling companies to hope the price will go up and make staying the course worthwhile?

KS: Well, yes, they have no choice other than shutting down all of their production. It’s just a question of how long the wait is. I was talking with a producer the other day, and he indicated that there will be no new capital available for pure dry gas until it is hedged at $4.50/thousand cubic feet ($4.50/Mcf). Gas has to be at $5/Mcf for a couple of weeks for them to do that. So gas prices have to be $5/Mcf for the market to realistically think about putting more money into dry gas wells.

Could that happen this year? It could, but the Marcellus is still coming on strong. Next year is quite possible. The other thing is that the gas wells with lots of natural gas liquids (NGL) like condensate, propane, butane and ethane have better economics than simple dry gas wells. With NGLs, more production can come on-line at $3.50/Mcf. There is hope; prices are moving higher than most people expected at this time of year, thanks to a very cold early spring. But to say that prices will go much higher from here would be a bit of a stretch.

TER: Which junior names are doing well in Canada?

KS: In no particular order, NuVista Energy Ltd. (NVA:TSX), Advantage Oil and Gas Ltd. (AAV:NYSE; AAV:TSX) and Delphi Energy Corp. (DEE:TSX) are doing well. The market is watching these companies to see which has leverage to gas, and which can really show a huge improvement in its numbers if gas does go up. These companies are heavily gas weighted. So, if gas does turn and stay higher, they have the most torque.

TER: What about old school oil and gas production? Not everybody is fracking—how are the standard vertical wells doing?

KS: That industry has been on hold for three years while the market experimented with the shale plays. On the junior side, it’s very rare to find conventional plays. The one that I like the most on the conventional side is a company called Manitok Energy Inc. (MEI:TSX). It has done a great job of putting together a land package in the Cardium Formation in the Alberta foothills and hitting on all its wells for both gas and oil in regular conventional formations. So the old-style industry is still alive. . .a bit.

TER: Is it more efficacious to do vertical wells in the Cardium than to frack?

KS: Well, where Manitok is, yes. The old-style pools are not in shale, tight rock or tight sandstone, so you can put a regular, old-style vertical hole down. If you hit the pool, splash! That’s a great well. Manitok hit a monster well two years ago and it did 5 million cubic feet per day (5 MMcf/d) gas. Two years later, it’s still doing over 3 MMcf/d. The well has declined less than 40 percent in two years. A lot of producers would give their eye-teeth for a well like that. The unconventional wells typically deplete 65–85 percent in the first year, and another 20 percent during the next couple of years. When you hit a regular, old-style conventional pool with a vertical well, you can book a lot of reserves.

TER: Is the Street being realistic about the depletion rate of the unconventional wells, or do people believe the reserves will last forever?

KS: The Street is acutely aware of what the decline rates are now. At the same time, some of these plays take a long time to peak, and some of them do not. The Haynesville peaked quickly, but plays like the Barnett took more than 10 years to peak. The Marcellus is still growing, with lots of new wells coming onstream. The Street is very aware of the decline rates, and I think that’s why natural gas prices have doubled in a year despite production not going down. But I think the Street is also aware of the amount of wells that can still come on in these plays, and it is sitting back and waiting to see some kind of supply drop before bidding gas up any higher.

TER: What is the science behind the rapid depletion rate with the hydraulic fracking?

KS: Basically, with fracking, once you pump the water, steam, or sand into the formation, only the oil and gas that is sitting right inside those particular fracks surfaces. The shale formation is super oil charged, so there are still huge amounts of oil and gas left in the rock after the first go-round. One can either refrack it multiple times, or perform a water flood to liberate a little bit more oil and gas. But drillers have to be close to the fracks to get the product out. The trick is to plan the optimal size and strength of the initial frack. After the well has depleted for two to three years it might be worthwhile to refrack.

TER: Is it more expensive to frack the second time around?

KS: Remember, the well has already been drilled. If the company has drilled a $3 million (M) well, probably $1M of that is the frack. You don’t have to spend $3M again—only $1M. If the well is doing 10 barrels per day (10 bbl/d), and a refrack gets it back up to 30 bbl/d for a while, there can be substantial payback.

TER: How important is jurisdiction in assessing what companies to buy?

KS: It is very important because prior to the shale revolution, the market searched the world for new sources of oil and gas. We were getting deeper and more remote with all of our exploratory work. We had to; the thinking was that all the easy pickings in North America were long gone. Then along came the shale revolution. Everybody refocused their budgets on North America. And there have been so many discoveries in the last three or four years. Enough to keep the market excited, enough that it has not bothered going back to the international locations. The Street is saying, “Why would I take any political risks when we’re getting great discoveries with fantastic returns in the Texas, North Dakota and Alberta shale plays?”

But now investors are paying more attention to the international plays even though there are some drawbacks, such as the rise of resource nationalism. It’s becoming more difficult for free enterprise to get business done in the rest of the world. All the big discoveries are now in gas. That’s why the majors likeRoyal Dutch Shell Plc (RDS.A:NYSE; RDS.B:NYSE)and Exxon Mobil Corp. (XOM:NYSE) are moving toward gas. They report in barrels of oil equivalents (boe), as opposed to barrels of oil (bbl), because to keep up their reserve base, they have to book gas reserves. Given the situation, it is very difficult for a junior to enter a new jurisdiction. Two things have to happen. A firm has to a) make sure that the geology is good; and then, b) hit a good well; and c) get the market to realize that. However, in Africa for example, a lot of juniors are having fantastic success, such as Africa Oil Corp. (AOI:TSX.V). There are a lot of ongoing junior African plays that are very high-risk, high-reward plays that can see big lifts with a discovery.

TER: Is North Africa a safe place to do business?

KS: It depends where you are in North Africa. The Street tends to wipe an entire area with one brush, and sometimes that’s justified. There are pockets in North Africa that one can operate in, though. Tunisia seems to be fairly safe for business. Obviously, Libya and Algeria are currently fraught with danger, and the Street does not want to go there. Morocco looks relatively safe. Despite the political disruptions, however, some business is done.

TER: Are there juniors in North Africa that investors should look at?

KS: The satellite juniors in the African risk play— Taipan Resources Inc. (TPN:TSX.V) and Vanoil Energy Ltd. (VEL:TSX.V) —are both funded and set to start drilling in the next six months. In Tunisia, there is Africa Hydrocarbons Inc. (NFK:TSX.V) as well as DualEx Energy International Inc. (DXE:TSX.V), which is going to be drilling its big well within 30–60 days. In Angola, there are a couple of drill plays getting funded.

TER: Are North American investors funding African plays?

KS: Most of the money comes from London. The Europeans are much more comfortable drilling in Africa than North Americans are. North Americans are very risk averse on the international scene. They are myopic, in fact.

TER: You also follow refinery stocks. Are the risks lower there than for the producers?

KS: The refinery stocks had a great run over the last year. But in early March, they started to run into a bit of trouble. The stock charts are now consolidating. Even though the refiners are showing great earnings for the last quarter, the market looks forward. And the Street sees a very tight West Texas Intermediate (WTI)-Brent spread. So the refiner stocks are now in full retrenchment mode and not moving forward. They are consolidating the gains they’ve had over the last 9–12 months. For those stocks to move higher, we’re going to need to see the WTI-Brent spread widen again. And that could happen. As light oil production in the U.S. continues to increase, it will overwhelm the refinery complex on light oil, and we will see a drop in light oil prices here in North America.

TER: Are there any companies that you like in that space?

KS: I am watching Valero Energy Corp. (VLO:NYSE) because it has so many refineries. It has a lot of torque to any turnaround. It exports a lot of product, which is very important, and it’s the largest independent refiner.

The other refiner that I follow quite closely is called Northern Tier Energy LP (NTI:NYSE). It has been hit, like everybody else, pretty hard on the tight spreads. So I am watching it from the sidelines as the whole refinery game shakes out. But the sector certainly did give investors a great run for 9–15 months.

TER: What advice do you have for new and veteran investors in the oil and gas space?

KS: Investors need to be very patient. There are lots of good stories out there that are starting to look very cheap. But, it is not wise to run out and buy stuff just because it’s cheap, particularly in Q2/13. The second quarter is generally the weakest for the industry. As we get close to June, there’s a very good chance industry share prices will go lower. The Street wants to see if the rally in natural gas is real. If it is, and we start to see production decline, then making money in this sector should be quite easy, because there are lots of gas stocks with good teams and good assets that are trading dirt cheap. But we are at the seasonal high for gas now. So be careful. Come June and July, though, everybody wants to have their checkbooks open and take another good look at the overall scene.

TER: I appreciate your time.

KS: Thank you, Peter.

By Peter Byrne, The Energy Report

Keith Schaefer Names the Last-Standing Shale Plays is republished with permission from The Energy Report.

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How The Great Recession Fundamentally Altered World Oil Prices

The Energy Report — Fri, 03 May 2013 06:52:52 +0000

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The downturn beginning in 2008 triggered a macroeconomic meltdown that would disrupt all markets, domestic and global. Demand for petroleum diminished just as new technologies were beginning to gush out oil and gas in never-before-seen volumes, creating a perfect storm that would depress prices. Now that oil prices have rebounded, is the worst behind us?

In this interview with The Energy Report, Director of Energy Research Marshall Adkins of Raymond James & Associates discusses the events of the last five years and the near-term prospects for energy-related investments.

Marshall Adkins focuses on oilfield services and products, in addition to leading the Raymond James energy research team. He and his group have won a number of honors for stock-picking abilities over the past fifteen years. Additionally, his group is well known for its deep insight into oil and gas fundamentals. Prior to joining Raymond James in 1995, Adkins spent 10 years in the oilfield services industry as a project manager, corporate financial analyst, sales manager, and engineer. He holds a Bachelor of Science degree in petroleum engineering and a Master of Business Administration from the University of Texas at Austin.

The Energy Report: Marshall, before the Great Recession hit, we appeared to be on target for $150 per barrel ($150/bbl) Brent in mid-2008, and we were hearing forecasts of $200/bbl before the end of that year. But things have changed. I’d really like to get your fix on how you perceive energy markets have been altered over the past five years.

Marshall Adkins: For the oil market specifically, two massive structural changes have occurred since 2008. First, U.S. oil supply from horizontal drilling in tight shale formations has created a reversal of the four decade-long decline we’ve seen in U.S. oil production. When I say reversal, I’m not just talking a minor blip; I’m talking about erasing a 40-year decline within five years. This truly is a massive structural change to U.S. oil markets.

On top of that, in conjunction with the Great Recession, the world has figured out that there’s too much debt, and most of the developed world is going through a deleveraging period. Historically, whenever you deleverage, you get subpar economic growth, and subpar oil demand growth. For the past five years, we’ve seen significantly lower demand growth for oil compared to the prior two decades. I expect that to continue, and I expect U.S. oil production to continue marching higher.

The combination of increased production and decreased demand growth has taken us from a world where we expected steadily higher oil prices, to one where we think there’s going to be meaningful pressure on oil prices over the next several years, both in the U.S. and worldwide.

TER: Classic economic theory would suggest that if oil prices continue to decline, there will come a point when oil prices don’t support further production. How far are we away from that scenario? Even with horizontal drilling in the shales, there has to be a floor in the oil price.

MA: Exactly. We’re facing a structural problem right now with crude oil that should eventually take oil prices low enough to slow drilling. A year ago, you would have begun to run into economic problems at $75/bbl West Texas Intermediate (WTI) crude. Since that time, drilling and production efficiencies have continued to increase and service costs have come down. So I think that number might fall to $60/bbl before producers run into marginal economic problems. That said, the rig count and oilfield activity may slow well before you reach that economic threshold because as WTI comes down from $100/bbl to $85, $75 and then $65/bbl, your cash flows for the industry are squeezed. Oilfield activity tends to follow the cash flows. So as you drift down on the oil price, you’ll see a steady decline in the oil-directed rig counts. That’s not so much because the wells are not economic; they are economic. But the availability of free cash flow gets lower as you move down the oil-price spectrum.

TER: What about China? It must certainly be supporting the global price of oil right now. Would that be accurate?

MA: China has been the main component of global oil demand growth over the past decade. So if China goes into an economic funk or somehow slows its demand growth, then oil is in big trouble. The main thing supporting oil prices right now on a global basis is the fact that over the past 18 months, we have removed 2.5 million billions per day (MMb/d) from global oil supply. That’s over 3 percent of the world’s oil supply eliminated in a short period of time. Saudi Arabia has cut 1 MMb/d, Iran has been forced to reduce its exports by 1 MMb/d, and Sudan’s and Syria’s civil war strife has cost another 0.5 MMb/d. The staggering thing about this massive oil-supply reduction is that the world is still building oil inventories! Normally, if you get a 0.5 percent or 1 percent swing in supply, that’s a huge mover of global oil prices. We’ve had 3 percent of oil supply knocked offline, and we’re still building inventories. To me, that’s an incredibly bearish statement that the market is ignoring.

TER: You’ve indicated that you see this downward trend continuing in oil. But over the past 52 weeks, we’ve seen the price of natural gas ascend 60 percent. My understanding is that if natural gas doubled from where it is today, it would still be cheaper than gasoline. Do you see natural gas supplanting oil as the primary vehicle fuel?

MA: No, not as the primary vehicle fuel anytime soon. For transportation, oil is still the most efficient and readily accessible fuel. Will natural gas begin to make inroads in the next 5–10 years? Yes, but it’s not going to come anywhere close to replacing gasoline and diesel as transportation-related fuels.

However, we do expect to see a surge in U.S. natural gas demand on the petrochemical and industrial side. There is nobody in the world that can compete with the low-energy costs provided by U.S. natural gas when much of the rest of the world is using crude or extremely high-priced natural gas for energy-intensive industrial uses such as manufacture of fertilizer, methanol, petrochemicals or steel. This gives the U.S. a huge competitive advantage over the rest of the world.

TER: Do pure-play natural gas companies offer upside to investors?

MA: I think there’s money that can be made in exploration and production (E&P) and services, but it’s going to be very company specific.

TER: Where then are the opportunities for investors in energy?

MA: The opportunities to make money on the energy side are going to be mainly in the refining and infrastructure spaces. These sectors have a lot more profitability potential than the market currently believes. We’re finding a lot of oil and gas right now, and it needs to be transported around the country and refined into a usable product, so infrastructure and refining are going to be profitable areas. The petrochemical sector, which uses cheap natural gas, is also likely to make investors money.

TER: So you’re looking at midstream and downstream, roughly speaking.

MA: Yes: refining, infrastructure, master limited partnerships (MLPs) and, of course, the petrochemical industries. Companies that can take advantage of the cheap gas stream will compete favorably on a global market.

TER: Your specialty area is oilfield services. Does the services industry have pricing power?

MA: Let’s talk two separate markets—international versus North America. In North America, which houses the majority of the investment opportunities in services, pricing for services has generally been falling. There is excess capacity in services across the board, and you’ve seen a sharp deterioration in pricing and margins over the past year. We think you’ll continue to see pressure on pricing and modest pressure on margins in North America. Every subgroup will act a little bit differently, but we don’t see the overcapacity that exists in most oil service areas in North America being solved for another year or two. On the other hand, we think activity with international and offshore services will see a steady improvement. You’re seeing modest pricing power there. It’s very modest, but certainly solid with slightly improving margins for both the international side and the offshore side.

TER: What about alternative energy? Are any of these going to take off and produce meaningful sources of power in the U.S. or globally?

MA: This takes us back to your first question. In a $200/bbl oil world, yes, solar and wind make sense. Many types of alternative energy make sense in a world where there is not enough oil or natural gas. The reality today, and certainly for the next five years, is that the lower-price environment for hydrocarbons that we foresee makes the alternative energies much less competitive. So, will we continue to get more efficient and cleaner in how we consume energy? Absolutely, and that’s going to have a meaningful impact on our consumption of hydrocarbons. But looking at alternative energies, particularly solar and wind, they just don’t make sense on a large-scale basis under a lower oil price scenario. Now, if you have off-the-grid areas where you can’t get power lines, solar makes sense. But for the mainstream consumption of energy, the alternative energies at this stage don’t make sense.

TER: Do you have any final thoughts to leave with our readers?

MA: I originally started in the industry as a hydraulic fracturing engineer 30 years ago. My pet peeve is these headlines from the popular press these days about this “newfound” fracking phenomenon that is extremely dangerous and could destroy the U.S. as we know it. Fracking is not new. This technology is over 60 years old and we’ve fracked hundreds of thousands of wells safely over the past half century. What’s new is the application of fracking in horizontal and in multifracking stages, but fracking has been around for a long, long time. Some have made it out to be this big, new, evil and dangerous thing that’s only recently emerged in the U.S. It’s just not true.

TER: It has been a pleasure. Thank you.

By George Mack, The Energy Report

Bullish on Oil Prices? Two Reasons You Might Change Your Mind is republished with permission from The Energy Report.

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