Floating LNG: The Revolution in Natural Gas

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Many investors are aware of the technological innovation – fracking – which has brought about a natural gas boom in North America. But the new technologies just keep coming…and the latest technologies will again REVOLUTIONIZE the global natural gas industry.

The latest significant breakthroughs have to do with the production of natural gas in offshore areas that had been previously deemed to be too far from shore or too small to develop on an economic basis. Many offshore gas discoveries have not been commercially viable due to high capital expenditures required to bring the gas onshore. So in many cases, the gas is simply flared or re-injected back into the offshore reservoir.

Notice the similarity here to what happened with shale gas. The industry knew the gas was there in the shale fields for a long time, but it was simply not economical to exploit such fields until fracking technology became widely available, allowing shale gas fields to be exploited in a cost-effective manner.

FLNG Technology

Needless to say, as with any technological revolution, there are massive profit opportunities for investors who become aware of new technologies at an early stage. The technology we are speaking about, which is set to open up offshore gas fields is floating LNG (liquefied natural gas) terminals, which serve as floating liquefaction, storage and offtake facilities.

LNG Front Low 2

The number of offshore natural gas discoveries has climbed dramatically in recent years. It is estimated by Royal Dutch Shell that there is at least 300,000 billion cubic feet of natural gas lying in offshore fields. This is a conservative estimate that does not include gas that is stranded in shallow water, very small fields, ice-prone areas, or obviously fields yet to be discovered.

In order to make many offshore gas discoveries profitable, over the past few years several companies have been developing floating liquefaction technology to allow the offshore liquefaction of natural gas. These offshore floating LNG production facilities, called FLNG, reduce the capital expenditure required to produce LNG as compared to land-based terminals, where such expenditures are generally higher because of the cost involved in building onshore facilities and the pipeline necessary to bring the gas onshore. FLNG also reduces the carbon footprint of LNG production.

One of the leaders in developing FLNG technology is international oil giant, Royal Dutch Shell which has spent the last 15 years working to perfect the technology. Its groundbreaking nearly $200 billion Prelude project is located in the Browse Basin offshore of northwest Australia (which has about 100,000 billion feet of natural gas or 5 times US annual consumption) and is expected to come online by 2016 or 2017. Once operational, Prelude is expected to produce at least 5.3 million per year of liquids. 1.3 million tons per year of condensates and 3.6 million tons per year of LNG.

FLNG Rear Very High 2

The sheer scale of the Prelude vessel, being built by Korean shipyard Samsung Heavy Industries, is impressive. It will the world’s biggest offshore facility, weighing 600,000 tons, will be six times bigger than the largest aircraft carrier (534 yards long and 81 yards wide), be anchored by an 11,500 ton turret and will be moored offshore Australia for at least 25 years.

It cannot be emphasized enough as to what a major step forward in gas production Shell’s Prelude is…..

Energy research firm Wood Mackenzie said about the project, “This is a key milestone in the development of the LNG business. This will change the business.” Another energy research firm PFC energy goes even further, saying that FLNG is the future of the global LNG industry. It believes most planned fixed LNG facilities will not be built and that the industry will move rapidly toward FLNG.

And they may be right. In addition to Shell, companies like Petrobras are moving swiftly to using FLNG to exploit gas fields lying in the rich waters offshore Brazil. Forecasts from most energy analysts are that by 2015, the liquefaction capacity of FLNG projects around the world will be 6.7 million tons per year or about one-tenth of global capacity. If Prelude is successful, FLNG usage will expand even further after 2017.

FSRU Technology

Investors should also not forget about another technology on the horizon in the global gas industry. It is called FSRU, which stands for Floating Storage and Regasification Unit. These are basically LNG carriers with onboard regasification equipment. FSRUs receive, store and convert LNG into ‘warm’ natural gas that is suitable for pipelines or use onshore.

FSRUs can be built new or converted from existing LNG vessels. The technology to convert a regular LNG carrier into a FSRU has been pioneered by Golar LNG Limited.

FSRUs have distinct advantages over land-based LNG facilities. One primary advantage is time – it takes only 2-3 years for an FSRU project versus 5-7 years to build an onshore terminal. Another advantage is cost – it takes about $150-$350 million to build an FSRU versus $300-$700 million for an onshore facility. And obviously, a FSRU is offshore (not seen by most of the public as are unsightly onshore facilities) and can be moved from location to location.

It is believed there will be between twenty and thirty potential FSRU projects globally, many of which are feasible and likely to be completed and begin operating before the end of 2015.

One of these projects is located in China, which is predicted to be the second largest LNG importing nation in a few years trailing only Japan. China’s national offshore oil company and top LNG importer CNOOC just recently announced it started construction on the country’s first floating liquefied natural gas receiving and storage facility near the northern city of Tianjin, a nearly $1 billion FSRU project.

New Technology Leads to a Bright Future for LNG

New technological facilities like FLNGs and FSRUs are setting the groundwork for massive future growth of LNG as a major part of the global energy framework.

The International Energy Agency forecasts that within a few years, LNG imports will meet about a fifth of the total incremental demand in the world for gas. In 2010, LNG accounted for about 10% of the total global demand for natural gas. This implies a double-digit growth rate for LNG over the next few years and possibly even longer with most of the demand growth coming from Asia and the Middle East.

Shipments of LNG to the Asia-Pacific region is growing at 20% per year says Bernstein Research. Overall global demand for LNG, according to Bernstein, will nearly double over the next decade to 408 million tons a year.

The only way for energy companies to meet the ever-growing demand for natural gas by the likes of China and India is through the use of new technologies such FLNGs and FSRUs. From onshore facilities to offshore floating facilities. That is the future of the global natural gas industry which faces investors in the years ahead.

Follow me on Twitter at OilandGasInvest

by +Keith Schaefer

How To Invest in LNG Shipping

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1940bkg
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In Part 1, I explained how LNG shippers will be one of the best investments—and THE best way to play cheap natural gas—right through to 2015. A combination of fast-rising demand from Asia and almost no new ships before the end of 2015 will keep cash flows and stock prices high for investors.

And then: one of the most abundant and cheap sources of natural gas in the world—American—could extend investors’ run right through to 2020.

Demand for LNG is soaring now—and dayrates for shippers are going up even faster. Industry analysts expect global LNG demand will jump 40% to 300 million tons between 2010-2015. But dayrates are already up more than 200% (that’s a triple, by the way ;-)) to $147,000 per day.

Operating costs for these ships are as low as $14,000 per day. That’s greater than a 90% margin for the best operators! How many companies—or sectors—can boast of that? Very few. And I believe these margins will stay strong for at least three years due to the lack of new ships. (This also helps explain the large Price:Earnings ratios this industry has.) All-in operating costs including amortization is closer to $60,000/day.

Industry observers suggest U.S. LNG export capacity will exceed 6 billion cubic feet per day (6 bcf/d). Six bcf/d is about 9% of the current U.S. daily gas production of 64 bcf/d, the largest output in the world. This translates into demand for 85 to 100 more LNG carriers just for the US export market.

And if even only one-third of the US LNG export terminal projects go through, Norway’s Arctic Securities says the industry will still require 28-37 additional vessels – the equivalent of 50-60% of the current order book (which is roughly 64 new ships).

The US has actually already delivered its first LNG export—one ship has gone from Louisiana-based Sabine Pass LNG terminal owned by Cheniere Energy (NYSE:LNG) to the UK.

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Last October, the United Kingdom’s BG Group signed the first contract to export LNG from the United States once the first liquefaction terminal is ready in 2015. (Liquefaction is the process of turning gas into LNG—gas gets compressed to 600:1 in a liquid. A liquefaction plant IS an LNG export terminal; LNG import terminals are called Regasification plants.)

BG said they’ll buy 3.5 million tons per year of LNG (1 million tons=0.12 bcf/d) over a 20 year period from Cheniere at Sabine Pass. Construction on the project is expected to start in April. Private equity fund giant Blackstone is helping to move the project along by providing $2 billion of the $5 billion needed for project financing (in exchange for an equity stake) to Cheniere subsidiary, Cheniere Energy Partners.

“There’s always a bull market somewhere.” There is more truth to this than most investors realize. And right now one of the biggest — if not THE biggest — bull markets in the entire Energy Patch is quietly taking shape. I’m referring to the technological revolution in oil & gas — the technologies, for example, that can increase yields by 4 to 7 times… launch huge new “discovery” fields… or even “extend the lives” of older fields. It is exactly these kinds of innovations that are creating triple-digit profit opportunities in the Oil & Gas Investments Bulletin portfolio. To learn more about what’s driving these opportunities in my OGIB personal portfolio — and how it all works, keep reading here.

 

Spain and India have also signed deals with Cheniere. Five LNG export terminals in the US are now actively being discussed and applied for, which would total about 8.4 bcf/d. The three Canadian proposals for Kitimat B.C. total 2.9 bcf/d. As context, consider the average LNG carrier holds just under 3 bcf.

Energy consultancy PFC Energy spoke about the deal, “Lots of companies that have been skeptical about U.S. LNG exports will look at the BG deal and wonder whether they should be studying this more closely.”

(For you history buffs, the first LNG carrier, the Methane Pioneer, was built in 1959… and transported LNG from Lake Charles, Louisiana to Canvey Island in the United Kingdom.)

LNG exports from the US are NOT expected to have a material increase in US natural gas prices, however.

Robert Brooks of Los Angeles-based RBAC Inc., which develops energy market models, told the Oil and Gas Financial Journal (www.ogfj.com, great resource):

“Using RBAC’s GPCM model, we ran five different scenarios with export volumes from 0 to 6 bcf/day, all originating from LNG export terminals along the Gulf Coast,” he said. “We found that the average impact on price at the Henry Hub varied from $0.13 for 1 bcf/day to $1.33 for the extreme 6 bcf/day case.”

At current prices of $2.35-ish in the US, an extra $1.33 will only allow the lowest cost producers to be profitable. The article talked like this would be a big deal—sorry, I don’t see sub-$4 gas as a big deal.

In fact, this should help permitting of these LNG export terminals if politicians know that even at maximum capacity of 6 bcf/d leaving American shores won’t really increase input costs for industry or residential home heating.

As yet, the development of six massive LNG export facilities in Australia has not had a significant impact on domestic natural gas prices.

(Please remember all this thinking assumes that the bulls are wrong and the shale gas wells won’t deplete in 5-6 years.)

I think the global LNG shipping market will STILL BE UNDERSUPPLIED even with no US LNG exports.

LNG tanker
Morgan Stanley suggests that even though liquefaction capacity is ONLY increasing at 6-8 bcf/d from 2011-2015, that still means the industry needs another 75-100 LNG tankers. The current order book is only 60 and if you can get a spot in the production line in the shipbuilders’ schedule at all (drillships and offshore rigs are your competition) it’s a two-year build. Liquefaction capacity is the #1 restraint on the global LNG market developing even faster; the demand is there in spades.

So even at the end of 2015, the industry will not likely have caught up with demand yet.

To sum up—the fundamentals for the industry are sound until at least 2015. According to the Oslo-based investment bank RS Platou Markets AS, demand for LNG carriers will expand 12% this year while the fleet will grow little. The world’s largest shipbroker, London-based Clarkson PLC, said that only two tankers will join the fleet of 374 ships, an expansion of less than 1%.

An analyst for Morgan Stanley, Fotis Giannakoulis, said “This bottleneck cannot be corrected overnight. It will take years, and it is an opportunity for a lot of LNG shipowners to generate premium returns.”

Then in the period from 2015 onward, the anticipated arrival of the United States as a major exporter of its abundant and low-cost shale gas could mean boom times for the industry until 2020, as the number of ships needed continues to struggle with the ever-increasing demand for LNG vessels.

by +Keith Schaefer

 

The LNG Shipping Sector: High Demand, High Profits

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1940bkg
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We are witnessing the birth of an entire new global industry, right before our eyes — liquefied natural gas (LNG).

Like oil, LNG is now shipped all over the world.

It has become one of the most profitable parts of the global energy patch.  Shipping LNG is the most profitable sector in the global shipping industry.

Dayrates are soaring for these large ocean tankers. According to Fearnley LNG, a unit of Norway’s second largest shipbroker, LNG tanker rates rose to $97,630 last year from $43,663 in 2010.

Daily rates are expected to average $147,000 in 2012 — a big rise from the low $40,000s in early 2010.  The gross operating profit is now very high for ship owners at the 2012 price levels.

It wasn’t always such a profitable business, though…..

In the middle of the last decade, most shipping firms avoided running LNG tankers. The sector was written off as expensive, moribund and not likely to earn anyone a profit.

The LNG industry bottomed out in 2006 — 2010.  The shipping industry had geared up for huge LNG imports into the US, ordering a lot of ships.  They were delivered on time, but then, to (almost) everyone’s surprise, US gas production started to increase (sound familiar?) because of the shale revolution, and gas prices in the US started to go down—making LNG imports into the US uneconomic.

And so that liquefaction capacity—where LNG is returned to its regular gaseous form that is used to heat your home—was never built. I’m talking about LNG import terminals.

Asia did start ordering a lot of LNG contracts, but with a glut of supply, they were able to offer the ship owners only marginal returns. Nearly all gas was moved on ships signed on with charters of 20 or 25 years.

A short-term and more profitable spot market never really developed for such vessels. This forced many tanker owners to idle their ships — These are vessels that had cost them about $200 million+ each. As recently as two years ago, roughly one-third of the world’s 374 LNG carriers were laid up or out of use.

(Today, every single LNG ship that is seaworthy is active. There is ZERO spare capacity, anywhere in the world.)

With high costs to build new ships, and low returns, the industry has not ordered new ships for a few years.

Then events occurred which shook the industry. The devastating earthquake and tsunami in Japan in  January 2011 forced the closure of many of its nuclear power facilities. This forced Japan, which was already the world’s largest importer of LNG, to import even more. Luckily for the country, it had already embarked on a major project to expand its existing LNG terminals and to build new ones.

The CEO of Norway’s Hoegh LNG said in May “I’ve been in the LNG market for more than 20 years and I’ve never seen the market change this rapidly or this strongly.”

In addition to Japan, the next two biggest importers of LNG are South Korea and China. In total, Asia accounts for about 60% of global demand for LNG, and their imports are still rising. So after the Japanese earthquake, in particular, the industry’s supply/demand fundamentals – which were already turning positive – accelerated the revival in LNG shipping.

Demand for LNG—particularly from Asia where natural gas ranges from between $15 and $20 per million BTUs—rose due to the Japanese disaster and economic growth.  To take advantage of the higher prices in Asia, energy companies vied for unused LNG tanker capacity around the world, offering tanker owners higher prices and an unprecedented range of short-term contracts in the spot market.

The CEO of one of the world’s biggest LNG carrier owners BW Gas, Andreas Sohmen-Pao, spoke of the change in the market, “What has happened… is that the destinations have become more flexible, to the extent that cargoes will move according to price differentials.”

“There’s always a bull market somewhere.” There is more truth to this than most investors realize. And right now one of the biggest — if not THE biggest — bull markets in the entire Energy Patch is quietly taking shape. I’m referring to the technological revolution in oil & gas — the technologies, for example, that can increase yields by 4 to 7 times… launch huge new “discovery” fields… or even “extend the lives” of older fields. It is exactly these kinds of innovations that are creating triple-digit profit opportunities in the Oil & Gas Investments Bulletin portfolio. To learn more about what’s driving these opportunities in my OGIB personal portfolio — and how it all works, keep reading here.

 

Translation:  Shippers can now choose where to ship LNG for the most money.

Just in the last month, according to Bloomberg, there were 13 ships redirected to Asia from Europe. For the first time in history there is now a truly global natural gas market thanks to LNG.  In fact, LNG imports into Japan alone this year are expected to hit a record of 79 million metric tons, according to Norway’s Arctic Securities.

Now all of the world’s LNG ships were brought back into use after the Japanese earthquake. Rates in the once-sleepy spot market for transporting the commodity revived to a level where owners are again able to operate their ships profitably—very profitably.

As I said, LNG shipping is now one of the most profitable subsets of the global energy sector. (I will tell you exactly how obscenely profitable it is in our next story ;-).)

LNG shipping companies are now ordering new vessels in order to meet the surging demand. But there will be a very tight LNG shipping market for several years.  That means dayrates, company cashflows and investor profits in this sector should increase as well.

There are several reasons for this:  One is that there are few LNG shipping companies. Another is that Rome wasn’t built in a day and neither are LNG tankers— It now takes two years from start to finish. (Only ONE more vessel will be delivered in 2012.)  Third, very few companies make LNG tankers, and getting a spot in their production schedule is now very difficult.

AND — the large capital cost of a ship is a barrier to more competitors entering the industry.

In conclusion, there is growing demand for LNG from the likes of Japan, South Korea and China… keeping natural gas prices high.  And there is increased production of cheap natural gas from Qatar and  Australia—so shipping LNG to capture that price gap makes huge economic sense right now.

What’s more — If the US can permit LNG export terminals to bring its super cheap gas into the global LNG mix, the LNG shipping sector will get busier… and become more profitable yet.

– Keith

NEXT STORY —  Part 2: A look ahead to what the future holds for the LNG shipping industry, and how it has become a global proxy for investors as a way to play cheap natural gas.

by +Keith Schaefer

The Companies Looking To Solve Fracking’s Water Issues

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1940bkg
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The water dilemma around fracking in the oil patch is valued in the billions.

And entrepreneurs are quickly developing a suite of technologies to solve it.

The issue is both the quality of water — residents near oil and gas wells want 100% comfort that fracking does not contaminate their groundwater — and quantity.  These wells use anywhere from 2 million to 13 million gallons per well, leaving parched states like Texas scrambling to encourage water conservation in the energy sector.

Which technologies will get adopted and be the winner in this multi-billion dollar industry?  For investors, the stakes are high.  As a company gets discovered, its share price can have big runs — Both GreenHunter (GRH-AMEX) and Ridgeline Environmental (RLE-TSXv) have seen their share prices double in the last four months as investors begin to understand the potential of this space.

Wall Street and Canada’s Bay Street are both just starting to wrap themselves around this sector — deciding which horse (the technology) and which jockey (the management team) — to bet on.

As I explore this hot new sector, I’ll periodically update you on new technologies I see getting some traction in the market.  Here’s a first look at a group of contenders in the water space.

Produced Water Absorbents (PWA)

It sounds like science fiction. The company actually invented a glass that can absorb organic material — such as hydrocarbons — from water, making it safe enough to drink.

“Osorb,” as the glass substance is called, can swell to eight times its size as it absorbs materials from water.

Produced Water Absorbents CEO Stephen Spoonamore says that Osorb can be used for a variety of applications… but its ability to not affect salt and metal while performing its function makes it ideally suited for the oil and gas industry, according to industry trade mag RigZone.

One of the top benefits of Osorb is that it doesn’t leave toxic by-products, doesn’t require landfilling, and — on top of that — minimal energy is needed to use it. This presents an advantage, Spoonamore says, as disposal wells will not be needed for companies managing their water.

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The substance was discovered by a graduate student working for Dr. Paul Edmiston, chairman of chemistry at the College of Wooster in Ohio, while trying to create a bomb-detection device.

“It works like a nanomechanical sponge,” he says. “I’ve done trace analysis, and the water’s totally clean.”

Edmiston has an online video shows him mixing motor oil with water in a bottle, inserting some grains of Osorb, shaking it up, straining the swollen particles and then drinking the water.

Practical testing has also revealed positive results, as a prototype system using Osorb treated 60 gallons of water per minute, reducing its petroleum content from 227 milligrams per liter to just 0.1 milligrams per liter, according to Popular Mechanics.

The water is treated and then given back to customers as brine, which can be used for fracking, according to Rigzone.

PWA is in the process of opening a water treatment facility in Ohio to treat flowback water from the Utica shale, and has plans to open additional facilities in the coming years. Spoonamore says that the company is “very interested” in promoting Osorb for the Bakken and EagleFord plays as well, reports the news provider.

PWA’s web site:  www.pwabsorbents.com

VIDEO: http://www.youtube.com/watch?feature=player_embedded&v=czZD-meOfkU

 

“There’s always a bull market somewhere.” There is more truth to this than most investors realize. And right now one of the biggest — if not THE biggest — bull markets in the entire Energy Patch is quietly taking shape. I’m referring to the technological revolution in oil & gas — the technologies, for example, that can increase yields by 4 to 7 times… launch huge new “discovery” fields… or even “extend the lives” of older fields. It is exactly these kinds of innovations that are creating triple-digit profit opportunities in the Oil & Gas Investments Bulletin portfolio. To learn more about what’s driving these opportunities in my OGIB personal portfolio — and how it all works, keep reading here.

 

Rettew Flowback, Inc.
 
Chesapeake Energy Corp. recently unveiled a new wastewater treatment system in Ohio that it has been using to treat water from its operations in the area.

Rettew Flowback Inc. designed and operates the facility for Chesapeake. According to the Beacon Journal, the facility is the first of its kind in the state and can handle as much as 300 barrels of waste per hour.

General manager of the facility Chris Foreman told the news provider that chemicals and filters clean about 95 percent of the wastewater, with the remaining 5 percent needing to go to a landfill for disposal.

The chemical used in the treatment is reportedly proprietary, but a 20-
micron filter and a 5-micron filter are also used in the process.

Keith Fuller, Chesapeake Energy’s director of corporate development, says there are plans to add additional water treatment facilities in Ohio.

Consequently, it’s worth noting that recycling water in the Marcellus formation has reportedly saved Chesapeake some $6 million per year.

Rettew’s web site:  www.rettew.com/oil-and-gas/

Ecologix Environmental Systems

Atlanta based Ecologix uses air flotation in a mobile treatment system, which is easily transported and set up on site.

“Dissolved air flotation” removes oil that is suspended in water by dissolving air into the wastewater under pressure and then releasing that air into a tank at atmospheric pressure. The air then forms bubbles that sticks to the oil, floating to the surface where they are removed by skimming.

This system — which is focused on treating water from fracking — can treat up to 900 gallons of water per minute. (42 gallons=1 barrel.)

A re-design of the system allows the treated water to be used again for fracking in a short period of time.

Website: http://www.ecologixsystems.com/system-its.php

Abanaki Oil Skimmers

Most wastewater treatment methods require that the affected water at least be brought back to the surface before it is treated, but one Ohio-based company gets the process going before the water even sees the light of day.

Abanaki Oil Skimmer’s use a High Temp Polymer Belt for fracking sites. This belt — which is able to withstand temperatures of 180 degrees Fahrenheit continuously — is attached to an engine of sorts and is put down into the well. The machine is turned on and the moving belt pulls oil and other contaminants from the flowback water as it reaches the surface. It may be useful to think of it as a long belt attached to an out-board motor that you put down the well.

“Oil skimmers work by making use of the differences in specific gravity and surface tension between oil and water,” says the company. “These physical characteristics allow the belts to attract oil and other floating hydrocarbon liquids from the surface of the fluid. Abanaki belt oil skimmers can be used in applications as deep as 100 feet.”

According to Abanki this method is economical due to its low-energy use, low maintenance and can be operated 24 hours a day, seven days a week.

Website: http://www.abanaki.com/industries-fracking.html

Product Animation: http://www.abanaki.com/petrox_animation.html

Ridgeline Energy Services (RLE-TSXv; RGDEF-OTCQX)

The nature of science is such that it is common that the initial intended use of a technology is not what it is ultimately used for. That is the case for Ridgeline Water Inc. – a division of Ridgeline Energy Services Inc. – and its water treatment solution… which uses a method developed for extracting biofuels from fat.

During the middle of the 2000s American engineer Dennis Danzik created a technology that could extract biofuels from cooking oils deposited in grease traps used by restaurants at a relatively low cost.  Over 90% of the fluid processed is water, which is a by-product that has to be disposed of. In order to keep the process cost effective, Mr. Danzik refined his process so that the water ended up being cleaned enough for safe economical discharge.

Here, Ridgeline saw an opportunity to address the growing need in the oil and gas industry to treat the tremendous amount of water that returns to the surface after hydraulic fracturing and the larger volumes of produce water that flow to surface.

Ridgeline worked with Danzik to develop the method that relies on electro-catalytic technology. Essentially what this means is that electricity and catalysts – a substance that effects a chemical reaction – are used to cause reactions that enable the bonds between water and contaminates to be separated.

Danzik’s innovation works in a slightly different way than most wastewater treatment methods, as it is used at the beginning of the treatment process. By using the method early, the contaminants are able to be separated from the water. Then the water is better prepared when it goes through a more traditional treatment process such as reverse osmosis, which, in layman’s terms, separates contaminants by passing the liquid through a sieve (membrane). The electro-catalytic step allows for such processes to more efficiently separate the water from, hydrocarbons, Totally Dissolved Solids (TDS) or other unwanted substances.

The company touts the low energy output required by this step as the water does not need to be excessively heated. The bonds are broken, “cracked” without the need of large amounts of energy.

Website: www.ridgelinecanada.com

Regards,

– The OGIB Research Team

DISCLOSURE:  Keith Schaefer owns Ridgeline stock in the Oil & Gas Investments Bulletin portfolio.

by +Keith Schaefer

US Silica: The First IPO in the “Fracking Sand” Industry

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1940bkg
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Investors now have the very first pure play on fracking sand… as US Silica (NYSE: SLCA) went public on the NYSE on February 1st at $17/share, raising $42 million. Prior to this IPO, the only frac sand companies were either private or held by oil companies.

There is a huge — and growing — shortage on the high-quality silica sand required in the fracking industry.  US Silica is the second-largest producer in America.

Thomas Dolley, a mineral commodity specialist for the U.S. Geological Survey, best described what is going on in the industry… “It’s a gold rush. Demand for frac sand is jumping through the roof.”

Fracking an average well in the Marcellus Shale region alone uses about 7 million pounds of sand, worth an estimated $175,000 each to US Silica.

The company’s average cost of production, as gleaned from its prospectus, is only $25 a ton while it can sell the sand for about $50 a ton. US Silica plans to use the funds to do a significant expansion of its commercial silica operations. This makes sense as it looks as if the price for frac sand is not coming down any time soon.

In 2010, U.S. frac sand production doubled to 13 million tons as new mines opened to meet demand from increased drilling activity. Demand for fracking sand soared even more in 2011 — Oilfield market research firm Spears & Associates reported it was about 22 million tons.

The CEO of EOG Resources (NYSE: EOG), Mark Papa, recently told investors, “There’s been a sand shortage in the U.S. Those who have sand or access to sand can pretty much charge what they want for that sand.”  (EOG owns a frac sand company.)

This shortage occurred even though sand production quadrupled in the U.S. between 2000 and 2009.

Fracking Sand Industry

Silica-based sand is a key ingredient to the whole fracking process. The hydraulic fracturing process relies on massive injections of water and chemicals to break open (fracture) rocks. Sand and other “proppants” are pumped into wells as a sort of scaffolding.

Sand specifically is used to stimulate and maintain the flow of gas and oil in horizontally drilled wells.

The growth in demand for silica-based frac sand has created favorable supply and demand and pricing dynamics for the industry. That’s why the price for commercial silica has gone up an average of 9% since 2000, with an acceleration to double digits in the last year or so.
Hydraulic fracturing consumed roughly 40% of U.S. industrial sand output in 2010, a rise from only 27% in 2009, according to the U.S. Geological Survey. This increased demand from drillers in turn has led to a race among sand mining companies to expand their operations.

The sand most in demand by fracking companies is the pure white quartz sand of the Upper Midwest. These sands are hard enough to withstand intense pressure and are round enough to let oil and gas escape horizontal wells. Wisconsin, for example, now has 31 sand processing plants planned or already running, up from just 18 last August.

“There’s always a bull market somewhere.”  There is more truth to this than most investors realize. And right now one of the biggest — if not THE biggest — bull markets in the entire Energy Patch is quietly taking shape.  I’m referring to the technological revolution in oil & gas — the technologies, for example, that can increase yields by 4 to 7 times… launch huge new “discovery” fields… or even “extend the lives” of older fields.  It is exactly these kinds of innovations that are creating triple-digit profit opportunities in the Oil & Gas Investments Bulletin portfolio. To learn more about what’s driving these opportunities in my OGIB personal portfolio — and how it all works, keep reading here.

 

Transportation Problems

The industry faces possible headaches on the transportation front. In the past, railcars were plentiful and cheap to lease. That is no longer the case, as frac sand companies are today being forced to pay from $500 to $700 each for railcars. It is easy to see how leasing 50 to 100 of these a month could quickly affect the bottom line.

Because sand is heavy relative to its value, the cost of train and truck transportation to remote well destinations is a very real burden to sand mining companies. The trade publication, Industrial Minerals, reported in 2011 that prices for sand were about $50 a ton before shipping, but were over $300 a ton when delivered.

But it might not matter how much money railcars cost – there literally just aren’t enough of them to go around. There is an outright shortage of railcars, so getting the sand to well sites at all could be an issue in the near future.

The industry needs lots of railcars. That 7 million pounds of sand for a Marcellus well needs 35 railcars to deliver it. This has led to a shortage of railcars for use by the frac sand industry.

FTS International, a hydraulic fracturing company also planning an IPO later this year, sees a shortage for at least the next year of railcars needed to haul fracking sand to wells.

Railcars are in high demand nationwide … with railcar orders more than doubling to over 20,000 in the third quarter of 2011. According to the Railway Supply Institute, the order backlog for U.S. freight cars more than tripled in the same period to over 65,000.

For its part, FTS plans to increase its number of railcars leased by 28% to approximately 3,200.

Best estimates are that the railcar shortage will be taken care of by late 2013. If so, this will be great news for companies like U.S. Silica, which can then ship all the frac sand the shale industry demands with no bottlenecks restraining profitability.

US Silica

Despite problems like transportation that are brought about by its rapid growth, the frac sand industry is an exciting new area for energy investors.

The industry has several big players. The largest include US Silica, Unimin, Badger Mining, Fairmount Minerals and Carmeuse Industrial Sands. They were all privately-held companies.

As I mentioned, US Silica is now public via its $212 million IPO, priced at $17 a share. The issue consisted of a total 11.76 million shares, with 8.82 million shares being offloaded by Private Equity firm Golden Gate. They purchased the company back in November 2008. Even after the IPO, Golden Gate will continue to own at least 74.4% of the company.

US Silica traces its origins back to 1900. It traditionally supplied its commercial silica production to a range of industries including the glass-making, building products and oil and gas industries. It now has 13 production facilities in the United States and currently controls 283 million tons of reserves. This includes approximately 138 million tons of reserves that can be processed to meet American Petroleum Institute frac sand size specifications.

Says Brian Shinn, CEO of US Silica, “The U.S. shale revolution is here to stay. We’re in the early innings right now.”

There are still a lot of innings for investors to catch.

– Tony D’Altorio, Guest Editor

DISCLOSURE:  Keith Schaefer does not own shares of US Silica or EOG Resources, and has no intention of initiating a position in the OGIB portfolio.  A link to US Silica’s prospectus can be found here.  The company’s website is www.ussilica.com.

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The ‘Holy Grail’ Business Model for Water

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Last week we discussed why water is one of the industry’s biggest threats… AND one of investors’ biggest opportunities.

To illustrate the problem, consider that well over 90% of the U.S. onshore produced water generated by the oil and gas industry is disposed into an Underground Injection well (UIC)/salt water disposal (SWD) well.

Only 5% is disposed of through either evaporation, pits or regular public-owned facilities. Almost ZERO is recycled right now.

It’s clear to me in speaking with water company executives that their customer base, the producers, truly want to be green—and not just because it’s good for business. But everyone also says it has to make sense economically to recycle and re-use that water.

And when it comes to trucking out water to disposal wells or recycling at the well site, Jonathan Hoopes, President of GreenHunter Energy Inc. (GRH-AMEX), says it will come down to simple economics:

“It will be the lowest cost option that wins.”

Dennis Danzik of Ridgeline Energy Services (RLE-TSXv; RGDEF-OTCQX) agrees, saying that cost pressures in the US are intense. “Most of the companies entering the water sector have unreasonable pricing expectations.”

I think there will be regulatory and public pressure for producers to recycle more water. That will potentially be a HUGE market that somebody—or somebodies—is going to fill. But the low cost technology isn’t in the market…yet.

GreenHunter and Heckmann Corp (HEK-NYSE) — another pure play in the fast-growing water market — have more diversified water management systems, vs. more niche lines like Ridgeline. When I look at their financials I see EBITDA margins ranging from 15%-30%. (The niche players have bigger margins.)

But the water treatment business model could be more exciting, as it will likely be based on throughput—customers will get charged so much per litre, gallon or barrel of water put through whatever recycling system is used.

With tens of billions of barrels of water being used, that could be the Holy Grail of the water sub-sector — a per gallon charge.

The reality is, however, that the growth in drilling in the major US shale plays is way ahead of how fast the water recycling/treatment industry can hope to develop. So the simple (but highly regulated) disposal of water through UICs/SWDs will be here for a long time.

Danzik adds that each oil and gas basin in North America has different needs; so solutions will obviously be different.

“Pennsylvania has water but no place to put it; Texas has no water but can dispose of it.”

“In the Marcellus, they’re in trouble, and that will increase as summer gets closer. In the North-east you have a real problem with disposal. The salt water disposal has been moved west; it has to be disposed of in western Ohio and Indiana and Virginia. They’re putting it in pits. They have to do something.”

“They (the producers) will have to pay full price per truckload, as much as $5,000 to $6,000. That will be the disposal charge. That will equal hundreds of millions of dollars.”

Again, that will be music to the ears of one lucky service provider in the new water sector… and their investors.

Longer term, Danzik sees the trucking industry as the most vulnerable to the changes happening in the fast growing water industry, as well-site water treatment increases market share (that’s his business, remember ;-)).

It’s a variable, high-cost service, and local residents don’t like the traffic or the sight of literally hundreds of trucks delivering water tanks and water around their area.

Hauling or recycling water, storing or disposing of it—Hoopes says that the water business is growing so fast that for awhile, everybody in the space should be a winner.

“Everybody’s market share is a small percentage; this is not a winner take all scenario yet. It’s too early. We’re all taking water management systems to a more mature status. I think there is a lot of potential to grow market share before we start butting heads too hard.”

– Keith

Part 1: Water: The Next Great Investment in the Oil Patch

Part 2: The Multi-billion Dollar Water Services Industry

by +Keith Schaefer

The Multi-Billion Dollar Water Services Industry

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There is a multi-billion dollar water industry forming before investors’ eyes in the oil patch.

It’s a huge opportunity for some great capital gains — but changing regulations, and a very attentive mainstream audience questioning business practises which have been in effect for decades, will will make it choppy water for investors.

“In 2008 there were 25 billion barrels of water handled (by the oil and gas industry) in the US—even at 60 cents a barrel it’s a multibillion dollar business,” says Jonathan Hoopes, President of GreenHunter Energy Inc. (GRH-AMEX). “With the big growth in unconventional since then, it’s likely another 5-6 billion barrels.”

GreenHunter is a pure play on the fast growing water market in the oil patch, along with companies like Heckmann Corp (HEK-NYSE), and Ridgeline Energy Services (RLE-TSXv; RGDEF-OTCQX). There are also many private technology companies with new water treatment processes.

Ridgeline is developing a water purification and recycling technology for the oil and gas sector. CEO Tony Ker says the industry is just beginning to put a formal cost structure on their water, and it’s not always easy to see through the mist to a simple business model.

“Customers in the oil and gas industry are finding their way into the water industry,” he told me in a recent interview. “Two years ago customers didn’t know what the water business meant. At some point they knew they would have to clean and re-use it, but didn’t understand how to do it.

“Now we’re watching it form as we speak. Customers are now starting to define what the water business will be. Before, it had no shape or form. Now we’re seeing various companies put cost structure on the business; put costs on storage, treatment, transportation.”

GreenHunter has put some of these costs in their PowerPoint presentation.

In the Marcellus Shale, they say it costs $3 + per barrel (/bbl) to dispose of water — and $7-$10/bbl to haul it away. If a horizontal well uses 4.2 million gallons of water to frack (that would be a slightly bigger than average well, but it makes my math easy ;-)), then that’s 100,000 barrels (42 gallons=1 barrel).

If you get 30% of that back in the first year, that’s 30,000 barrels x $10+ per barrel hauling and disposal costs=$300,000 in water costs per well. But that’s $300,000 in water REVENUE for the right company. Then there’s another 30% of that water you get back over the life of the well—assuming costs are constant, that’s $600,000 in revenue.

And there are thousands of wells getting drilled in North America each year; more than 80% of them are now horizontal, and most of those require fracking. The dollar value of managing that water multiplies out fast.

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GreenHunter is estimating that the 2011 water disposal market in the Marcellus alone was $1.3-$1.7 billion, and in 10 years the market will be $15-22 billion.

In the Eagle Ford shale play in Texas, they’re quoting a disposal fee of $0.80+/bbl and an average $3.00 – $6.00 /bbl hauling fee. And with an estimated 800 new oil & gas wells drilled there in 2011, the market just keeps getting bigger. In 2011 the water disposal market was estimated to be $500-$800 million, and in 10 years they are guesstimating that local market will be worth $6-9 billion.

They estimate the Bakken will be a $10.6 billion market within 20 years.

And there is just storing all that water until it is ready to be used. With the new pad drilling, where producers drill multiple wells that splay out in different directions from one pad, millions of gallons water can be stored in one spot for up to and over one year. Just storing that water has turned into a $150 million + business with incredible profit margins—in just one year. And it continues to have hyperbolic growth.

“I believe in two years you will see moderate sized water facilities of 50,000 to 100,000 barrels a day, that are permanent, that will process water for re-use,” says Dennis Danzik, a director of Ridgeline and the inventor of their water purification technology.

There are other major revenue sources as well. Sourcing water is a revenue business as municipalities and landowners in the western US sometimes sell their water to the industry for fracking.

Hoopes believes that regulation around water will develop to the point where producers and service companies will have to supply “cradle-to-grave” monitoring of water to prove it is either recycled or disposed of properly–which is great news for GreenHunter and Heckmann.

Next Story: The ‘Holy Grail’ Business Model for Water

by +Keith Schaefer

Water: The Next Great Investment in the Oil Patch

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The next Big Thing in oil and gas is… water.

It’s one of the industry’s biggest threats, and one of investors’ biggest opportunities.  It’s an emotional issue for everybody, and has the potential to be THE galvanizing political force in the North American oil patch in 2012.

Consider these statistics: each horizontal well in North America that uses hydraulic fracturing, or fracking, uses 2-6 MILLION gallons of sweet fresh water. And the entire North American industry will use an estimated 72 BILLION gallons in 2012.

I think the cost involved in handling that water will be in the billions of dollars within a couple years.  That’s a lot of revenue–and  some companies will be smart enough to profit from that.

The single largest profit gain in 2011 for the OGIB subscriber portfolio was WATER.  In a loosely-related three-part series, I’ll examine how the energy complex is tackling this issue as new, but committed, stakeholders join the debate.

PART 1 — Fracking’s Growing Water Problems

Oil and gas producers in Texas will have to disclose how much water they use on each well, starting February 1.  It will be a huge step in shedding light on how the fracking industry affects the water supply.

Last June, a study from the Texas Water Development Board showed that less than 1 percent of the water in the state goes towards fracking.

However, The Texas Tribune reports that this study used data that was several years old. Since then, fracking has increased a lot now that the state’s EagleFord shale play is the nation’s hottest liquid rich gas play — exacerbating the demand on Texas’ water supply.

Indeed, shale gas production in the EagleFord has increased more than tenfold in less than three years, according to numbers from the Texas Railroad Commission which compiles data on production in the EagleFord.

In all of 2009 “only” 19 billion cubic feet of EagleFord shale gas was produced.  That jumped more than five times in 2010 to 110 billion cubic feet, and then it will almost certainly double again in 2011, as just from January through October of last year, 212 billion cubic feet of shale gas was produced in the play.

The same increases are happening with shale oil in the play. The EagleFord produced more than 13.83 million barrels of shale oil in the first 10 months of 2011, compared to less than 4.4 million in all of 2010.

Further, 2,828 Eagle Ford drilling permits were issued in 2011, compared to 1,010 in 2010, according to the Railroad Commission.

From a water standpoint, it gets worse. The Wall Street Journal reports that the play’s geology requires fracking operations to use twice as much water as those in North Texas’ Barnett shale. Additionally, very little of the water used in the Eagle Ford is recycled because it is absorbed into the earth.

Despite the large increases, Dan Hardin, the resource planning director for the Texas Water Board, suggested that water used by the fracking industry is not expected to exceed 2%.

Still, those are state-wide figures. The numbers for specific areas can be… alarming. By 2020, Hardin says that 40% of the water in the EagleFord’s La Salle County will go towards “mining,” a technical designation that for all intents and purposes means fracking.

The big thing holding researchers back from determining more accurate figures, they say, is the amount of data they receive. Geologist Mark Engle with the U.S. Geological Survey’s Eastern Energy Resources Science Center, said that Texas has historically lagged behind other areas in such reporting.

“Texas ranks pretty much dead-last of any state I’ve worked with for keeping track of that sort of data,” he told the Tribune.

And all this is happening as Texas is experiencing devastating droughts.

Reuters reports that the drought has killed as many as half a billion trees, according to the Texas Forest Service.

In fact, some people are saying that this is a drought of historic proportions.

“We are now in the worst drought in the history of Texas,” Joe Joplin, a representative on the board of the North Texas Municipal Water District, told the ACN Papers. “All you have to do is drive on Highway 380 over Lake Lavon and see that we have a very serious problem.”

Texas isn’t the only area that has bumped into concerns over the fracking industry’s water use. Louisiana recently passed a law regulating the sector’s water use, describing the uptick as “unprecedented” and said that if nothing was done about it, there was the “potential for chaos and conflicts,” reports the Journal.

In northern British Columbia, Canada, oil and gas companies must have equipment to recycle the water, in response to public outcry.

The issue has also cropped up in Colorado, which contains a portion of the Niobrara formation. Concerns in the state have arisen over the potential for the fracking community’s use of water to endanger the local agriculture sector.

“This area was called the Great American Desert for a reason,” Sean Conway, a Weld County commissioner who helped start a “Niobrara Working Group,” told the Denver Post. “Long term, we’re going to have to have serious discussions about new water storage.”

In response, Colorado, like Texas, will require operators to report on exactly what goes into their fracking solution and this will also potentially require them to reveal how much water they are using.

While oil and water don’t mix, for the fracking industry, the two go hand-in-hand.

P.S.  I’ll be co-hosting — along with HRA Advisories and Resource Opportunities — the inaugural Toronto Subscriber Investment Summit 2012, on Saturday, March 3.  We’ll be talking about some of the best investment opportunities in the energy and resource markets today — and the summit is free to all paid-up subscribers of the Oil & Gas Investments Bulletin, or HRA Advisories, or Resource Opportunities. Follow this link to learn more.

Part 2:  The Multi-billion Dollar Water Services Industry

Part 3: The ‘Holy Grail’ Business Model for Water

by +Keith Schaefer

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