Canadian natural gas producers are hoping to spend a minimum $20 billion on shipping Liquid Natural Gas (LNG) to Asia in the next 2-9 years. The size of the prize is huge—spot natural gas in Japan can be as high as $17/mcf—more than 10x Canada’s spot price of $1.50 now.  But competition is fierce from Australia, Qatar, and United States…as I wrote about here.

And those prices could be going higher. Asian demand for LNG is expected to increase 45% from the 20 bcf/d (billion cubic feet per day) now to 29.1 bcf/d by 2016—just four years from now.

In this article I’ll outline:
a.     who the Canadian players are
b.     the estimated size and cost of their projects, and tentative timelines
c.     some simple economics
d.     and what has to happen still for shipments to actually start

Shipping LNG to Asia is not just a great opportunity for Canadian producers, it’s a necessity. US gas production is expected to stay strong—and prices low—for years.  In 2008, the U.S. imported 13% of its total natural gas supply–almost all of it from Canada–but the U.S. Energy Information Administration (EIA) estimates that by 2035 that figure will be lower than 1%. And this shift is already happening.

Now, if all of these projects had been fully operational in 2010, Canada would have been the second-largest LNG exporter in the world, behind only Qatar.  Each of these facilities is now forecast to be built in the small town of Kitimat B.C., located at the end of a long narrow (protected) ocean water inlet… where Alcan has had a large aluminum facility for decades.

Here are the three most advanced LNG export projects in Canada:

KM LNG Operating General Partnership

Who:
Apache Corp. (APA-NYSE)           40%
Encana Inc.  (ECA-NYSE; TSX)   30%
EOG Resources (EOG-NYSE)       30%
Capacity:                                        1.4 bcf/d (11.66 million tons annually)
Projected cost of facility:              $10 billion (but $5.6 billion if only do 0.7 bcf/d)
Approved?                                     Yes—20-year license
Projected completion date:           Late 2015

This group—all upstream producers—is also the only one to have approval for a pipeline to transport the gas from the field to the LNG facility—the Pacific Trails Pipeline. Despite the approvals, the partners haven’t made the final decision to build the project.

What’s left to bring the project together? Money and customers. They’re still looking for money, which should come from, potentially, the pipeline company, but certainly from an anchor customer in Asia who would come in for 20% equity on the project AND the upstream resources; the gas itself.  Everybody would reduce their interest pro-rata in that case.

The Globe and Mail reports that the project has two deals already signed with Japanese power producers, and other potential customers are lined up.

But analyst Gerry Goobie with Purvin & Gertz Inc. told the Calgary Herald that the fact that the partnership is looking for equity shows that it still needs to secure long-term customers.

“The bottom line is they’re still trying to strike a deal,” he said. “The assumption is the deal that they have will be sufficient to cover off all the capital costs that they are going to spend to build this thing and give them a reasonable return.”

BC LNG CO-OPERATIVE

Who:        13-member group (includes LNG Partners LLC of Houston and the Haisla First Nation)
Capacity:                                     0.22 bcf/d (1.8 million tons annually)
Projected cost of facility:           $360 million – $450 million
Projected completion date:        2014
Approved?                                   Yes—20-year license

This proposal has the earliest (tentative) start date—early 2014. This is by far the smallest of the three proposals, and would be unique in that they will be located on a barge 7 km south of Kitimat, and grounded on the shore.

“This thing should be fun to get it off,” Tom Tatham, the managing director of BC LNG (and of LNG Partners LLC of Houston), told Reuters. “There’s really nothing that’s ever been done like this in the LNG industry.”

The project is partially intended to allow smaller natural gas producers to ship LNG abroad to more lucrative markets.

Specifically, an operating company at the facility will liquefy a cooperative member’s natural gas for a fee. Companies can buy into the cooperative for $50,000 or can receive membership for free by writing a letter to the National Energy Board stating an intent to buy or sell gas through the terminal (cooperative members can be buyers or sellers).

What’s left to bring the project together?  Pipeline capacity.  It only makes sense for them to use Pacific Trails (I think it would be politically difficult for Apache et al to not allow small producers access, including those with First Nations ties, for a toll fee), but it may not be ready by then.

Shell

Who:                           Royal Dutch Shell   40%
Mitsubishi                    20%
Kogas                           20%
CNPC                           20% (China Nat’l Petroleum Corp)
Capacity:                                     1.44 bcf/d (12 million tons annually)
Projected cost of facility:           $12.35 billion
Projected completion date:        2020
Approved?                                   Pending

What’s left to bring the project together? Approvals, pipeline capacity and pipeline approvals.  All the players together in that consortium have lots of financial ability.

The project could come online at the end of the decade and might be able to send as much as 2 bcf/d abroad per year. Shell has a lot of experience in LNG, operating 2.4 bcf/d export capacity in other areas of the world, and another 2.9 bcf/d coming into production by the end of 2015.

Shell first announced its plan for the venture last fall, shortly after it (and some of its partners) purchased the Methanex marine facility in Kitimat, which is no longer in use.

That’s the Tier 1 list of Canadian LNG exporters.  Other groups looking include:

Petronas-Progress (PRQ-TSX)

Petronas is a large Malaysian oil and gas company with This 80/20 partnership aims to build a 1.0-1.2 bcf/d LNG plant in B.C., bringing the first 0.5 bcf/d online in 2017-2018 and the rest a year later.  A feasibility study on the project should be complete by the end of Q3 2012.

INPEX-NEXEN (NXY-NYSE; TSX)

Inpex is a large Japanese oil and gas producer.  In November 2011 they joint ventured 40% of Nexen’s holding in the Horn River, Cordova and Liard basins, all in B.C.  There is little doubt they will be going after an LNG license. Do they do it on their own or join one of the three more advanced projects?

Potential issues with Canadian LNG projects

There are still potential speed bumps for Canadian LNG exports.  These pipelines need to get built, which means passing through areas that have attracted so much opposition to the Northern Gateway oil pipeline.

Where will all the electricity and power that’s needed come from, and what infrastructure is required for that?

The economics of Canadian LNG exports to Asia should be similar to those of Australia, says Canadian brokerage firm CIBC Wood Gundy in a report earlier this year.

Japan is the largest LNG market, and the shipping route from Canada to there is 4300 km, vs 3100-4300 km for Australian projects.  They add that Japan will want to have several sources of LNG.

Long-term LNG contracts are usually priced at 12-15% of Brent crude, which at $100 Brent means US$12-$15/mcf—still 8-10x Canadian spot prices.  CIBC is forecasting Canadian LNG exports can earn a 17% internal rate of return at $4/mcf gas.  That would be higher at today’s low gas prices.

They broke down how the costs of getting the gas from the field to a Kitimat LNG facility, liquefying it, and shipping it to market would cost:

So you can see a 50% gross margin here, under their pro forma model.  If cost inflation doesn’t escalate out of control, and Asian demand meets expectations, then the size of the LNG will make a very healthy return for Canadian exporters.

The top LNG exporters are Qatar, representing nearly 25 percent of global LNG exports with 7.3 bcf/d.  Then there’s Indonesia (23.7 million tons, 3.03 bcf/d), Malaysia (23.1 million tons, 2.96 bcf/d), Australia (19.1 million tons, 2.45 bcf/d), Algeria (18.7 million tons, 2.39 bcf/d), Nigeria (18 million tons, 2.31 bcf/d) and Trinidad and Tobago (15.4 million tons, 1.97 bcf/d).

Note how Canada – the world’s third-leading natural gas producer – is nowhere to be found on this list. However, that could soon change with the three projects in Kitimat.

- Keith

Part 2: The Permian Basin – Cline Shale Resource Play

In Part 1, I explained how the Permian Basin in Texas was exploding with industry and investor interest—because of all the new tight oil plays being discovered and developed.

And that has me excited about the prospects for one Canadian junior—though all this excitement is happening a year later than I thought it would.

But at the end of the day, and the end of the play, all this should all be good news for one of my OGIB portfolio stocks, Lynden Energy (LVL-TSXv).

Lynden has 6500 net acres in the Wolfberry trend in the main Permian Basin, and is producing just over 500 bopd from that land base.  When I bought it a year ago, I thought the value of other Wolfberry transactions made the stock worth $0.90/share alone.  I still believe that—but it was really their Mitchell Ranch property on the eastern shelf of the Permian that I saw as the catalyst to make the stock a double or a triple.  And it’s two formations that could give the stock a chance – the Cline Shale and the deeper Mississippian.

Devon Energy’s map of where the Cline shale is pervasive has Lynden’s Mitchell Ranch very close to the middle of play.  That is clearly getting some market attention in the last week.

As background, I bought 67,000 shares of this stock a year ago at 66 cents, thinking the world was about to discover the eastern shelf of the Permian and both the play and Lynden’s stock was about to take off.

Well, I sure timed that wrong as the stock has spent the last year well below my purchase price.   But now, a full year later, market interest has arrived, based on newfound enthusiasm for a large resource play in the Cline/Lower Wolfcamp.

Here’s a map by Lynden of where their property sits:

Lynden is drilling 31 gross Wolfberry wells this year, where success rates are high and they are steadily adding production.  They are producing just over 500 bopd now, and expect to exit this year at 900-1200 bopd. Their partner, a private company called CrownQuest LLC, is the operator.

A net minority, non-operated interest could be the reason the stock has languished (other than a rotten market for junior oil stocks), plus the fact that Lynden and CrownQuest LLC have been very conservative in drilling Mitchell Ranch, where the two partners are 50/50.  There are two vertical drill holes into Mitchell Ranch, but only one is producing, and that is from only one zone—the Spade 17 well.

There are only two more (gross) wells in the 2012 budget for Mitchell Ranch, which will be targeting primarily the upper, shallower zones—not the big Cline Shale.  They have drilled through the Cline, but don’t have the resources—or the interest—in going horizontal here.

Lynden is a land play, and management will leave the expensive horizontals for whoever acquires them and partner CrownQuest LLC’s interest in Mitchell Ranch.

Lynden has been able to pull off two big corporate moves this year that got me and the market excited—only to see the stock pull back on no volume after a flurry of interest—which makes me cautious in buying more.

One was bringing Chesapeake (CHK-NYSE) into Mitchell Ranch to joint venture 35,000 acres, one-third of the 103,400 acre Mitchell Ranch play (leaving Lynden with a 50% WI in 68,400 acres, or net 34,200 acres).  Chesapeake is specifically interested in a deeper zone, the Mississippian at 7500 feet, where they have had great success in eastern Oklahoma.  There is no public data on how their first well is going.

But Lynden got Chesapeake to pay enough cash to get in that they were able to pay the underlying land owner their option payment, and Chesapeake shares the data with them.  So Lynden gets a free look at how the upper zones they’re targeting look, and a free learning curve on how to drill the Mississippian on their remaining acreage.
The second was securing a $50 million credit line, so the company didn’t need to raise equity again. But like I said, Lynden is a land play first and my fervent hope is that Chesapeake or some other major or large intermediate will come in and buy Lynden and CrownQuest LLC’s position out.

Lynden’s Mitchell Ranch property has three main plays:

1. The upper shallow zones at 4200-5200 feet that can produce 75-100 bopd IP rates
2. The Cline Shale/Lower Wolfcamp that Devon is chasing, with potential 600 boe/d wells
3. Mississippian formation below that, which Chesapeake is now developing

And there’s another formation, the Ellenburger, beneath the Mississippian that is potentially productive as well.
Let me draw up a hypothetical valuation—with one foot planted firmly in the air.

Valuing these assets at this early stage is very difficult—but because of the size of the asset – 64,000 acres—there is some leverage here with any proof-of-concept from any of these deeper zones at Mitchell Ranch. The market agrees with me because it’s valuing Mitchell Ranch at zero.

But I’m assuming that Devon’s Richel would only farm out 50% of this large resource play for that $1.35 billion, which values the play at $2.7 billion or $5400/acre.

Lynden’s stock trades solely on the Wolfberry assets, and the reason I bought the stock is because I thought those were worth 90 cents a share.

Here are some Wolfberry transactions in the last 12 months:

• April 28 2011 – Antares Energy paid $62 million for 3,109 acres, or $19,942/acre
• April 28 2011 – Berry Petroleum paid $123 million for 6,000 acres, or $20,500/acre
• May 12 2011 – W&T paid $366 million for 21,500 acres, or $17,000/acre
• June 22 2011 – Laredo paid $1 billion for 65,000 acres or $15,000/acre
• Dec 6 2011 – Comstock paid $332.7 million for 44,000 acres for $7,561/acre
• Dec 22 2011 – Concho paid $175 million for 10,200 acres, or $17,157/acre
• Feb 11 2012 – Energen paid $65.8 million for 3,200 acres, or $20,300/acre

The average value per acre in these seven deals is $16,780.  Lynden has 6310 net acres, all of which are in producing areas (especially with the first producing well on their Tubb property).  That would give Lynden’s Wolfberry assets a value of $105,881,800—with 109 million shares out that’s 97 cents value.

Were life so simple.  There’s 42 million warrants between 50 and 70 cents, taking the outstanding balance to 151 million, but with $27.75 million extra in cash.  (Folks, warrants KILL stock prices. Never a good thing.)

But $105.88 million/151 million=70 cents—20% higher than where the stock roughly is today.

And I haven’t started on Mitchell Ranch yet.  The blue sky here is that if Chesapeake can get economic results out of the Mississippian—and at that depth, I’m guessing all-in costs of $7-$8 million will need at least 500 bopd of oil and whatever NGLs and gas on top of that will be required—then Mitchell Ranch is worth potentially $5,000 an acre, and their net 34,200 acres is worth $171 million, or $1.13—which values the company at $1.83/share.

And that doesn’t take into account the Cline shale potential.  You get the picture—lots of leverage if these plays work out.  And that is the type of company I like to invest in—just usually with a lot less shares out.

It will be interesting to see how the market values Mitchell Ranch in the near term, with all the new excitement in the east shelf of the Permian, just because of its address—and in advance of any word from Chesapeake in the Mississippian (at least 3 months away, IMHO).  Because unless somebody really close by shows some Devon-style production levels from the Cline, its prospectivity will be hard to determine.  It’s highly unlikely Lynden will ever drill an expensive horizontal well in the Cline.  They’ve got their land position and they want to monetize it, not drill it.

On another metric, price per flowing barrel, it’s not unusual to see $150,000, which would put Lynden’s year end 1000 bopd worth an even $1/share.  And while that’s a theoretic value for Lynden as the stock has never traded close to that, increased market awareness could change that.

So my conclusion here is that I expect the market to heat up, but there is no telling how much, and I’m not buying any more stock here—but I’m not selling any now either.

- Keith

The Cline Shale in Texas is one of the hottest new shale plays in the USA.  Devon Energy (DVN-NYSE) is suggesting it’s a huge play, pervasive over a very large area on the eastern shelf of the Permian Basin.

In fact, the Permian is bursting with new resource plays—what’s old is not only new again, but pistol hot.

One analyst report last week said several new resource plays in the Permian are being “unleashed,” and that there are so many multiple horizons or formations that are stacked on top of each other in the Permian—that are just now being accessed with horizontal drilling—that it’s like having 10 or 11 EagleFord shales stacked on top of each other.

And interestingly, there is one Canadian listed junior with a large land position close to the middle of Devon’s Cline Shale map.  More on that later.

Source: Devon presentation Apr 2, 2012

Devon got the market’s attention earlier in April when they said they had staked over 500,000 acres and had an unrisked 3.6 billion barrels of oil there.  “Unrisked” is a fairy tale number that could be right if every single well hits their type curve.  Devon President John Richels also said the acreage was worth $1.35 billion from a partner—presumably for 50%.

Devon gave a “type curve” for a Cline Shale well—a guess at how much the well would produce over time—of total production 570,000 barrels of oil equivalent—and 85% of that would be oil and liquid rich gas.  (The industry calls that the EUR—Estimated Ultimate Recovery.)  The well would flow an average 600 boe/d for the first month (that’s called an “IP30”—the Initial Production rate for the first 30 days the well is on production) and cost $6.5 million.

It’s early days in the Cline—Devon’s goals right now are to get more core data, figure out the best way to complete, or frack it (how much pressure, do you use water or oil or propane, what direction do you drill, what chemistry do you use etc.).

But initially, they’re saying the Cline is an organic rich shale, with Total Organic Content (TOC) of 1-8%, with silt and sand beds mixed in.  It’s about 60-150 metres (200-550 feet) thick.  Contrast that to the Bakken where the payzone is often only 10-25 m thick.
It lies in a broad shelf, with minimal relief (that means it lies nice and flat), and it’s in the “oil window” (a depth where the right temperature and pressure allow the ancient organic matter to turn into oil—gas is below oil) and has nice light oil of 38-42 gravity with excellent porosity of 6-12%.  So there are lots of holes in the rock containing oil, but all those holes aren’t well connected, meaning it has low permeability.  That is normal in these tight oil plays.

And there are frack barriers above and below the shale—rock types that are really hard and would likely halt any fracturing beyond the Cline—this is important because it means that water will not likely be able to come into the well (and water supersedes oil in coming back up the well—most of the time it’s a real negative) from other formations.

“We’re very excited about the Cline,” Andy Coolidge, Devon’s vice president for the Permian Basin, said recently. “We expect to deliver highly economic and robust production growth.”

Technically, the Cline Shale—also called the Lower Wolfcamp formation—looks like a great play.  And because it’s in the Permian Basin, services like drilling rigs and fracking spreads are inexpensive and easy to access.

It’s fascinating for me to watch all these new plays get discovered and developed in Texas, particularly the Permian, because I keep thinking—but it has been explored for years…how do they keep finding new stuff?

The reason is mostly the Shale Revolution.

The Permian Basin is already one of the most prolific oil areas in North America, producing 35 billion barrels from multiple zones.  But now there are even more zones, but they’re all “tight oil.” They’re being made productive by companies who can find the time and resources (qualified people and money) to test more expensive and time consuming horizontal wells—which are usually $5-$9 million now—and quietly assemble a land position without bidding up prices.

Horizontal technology and hydraulic fracturing are old news now, in one sense, but the oil and gas industry is conservative and prior to 2008 it was mostly early adopters in the industry that used it.  Only since 2009, after oil prices moved back up sharply, did horizontal technology become truly mainstream.

All the new productive zones—what the industry calls “stacked pay”; payzones (or productive oil formations) that are stacked on top of each other—can now make a well extremely profitable, as it can often produce from several formations over time.  This chart from Devon’s April 2 presentation shows as many as 15 productive zones:

The Cline is actually the “source rock,” the bottom layer of the Wolfcamp formation, which has been drilled with great success vertically for years.  But like other formations, exploration slowly moves out from a core area.

The Wolfcamp was originally thought to be 20 miles wide and 60 miles long, but now it’s 40×100 miles… and exploration continues.

This should all be good news for a fast-growing junior producer with a big land position, the details of which I will share with you in my next Free Alert.

- Keith

Intermediate natural gas weighted stocks in Canada are valued higher—sometimes a LOT higher—than oil stocks, despite oil being worth 35 times more than gas.

And that could mean significant price weakness for already battered natural gas stocks, says Haywood Securities analyst Alan Knowles.

“People think (the stocks of) gas companies have corrected, but they’ve only partially corrected,” he told me in a phone interview.  “The correction hasn’t kept pace with how far it should have gone,” given how low natural gas prices have moved.

At first glance, Knowles’ says the gas companies are NOT valued more highly than the oils—but that’s comparing the two groups at the industry standard of 6:1; where 6 barrels of natural gas are considered equal to one barrel of oil.  See his chart below that shows this.  The green dots are the leading intermediate oil producers—Crescent Point, Legacy Oil and Gas, Baytex and Petrobakken, and the red triangles are the gas weighted companies.

The gas stocks are clearly cheaper on this chart, which measures them in terms of the value of their production — $50,000 per flowing barrel up to $250,000; again all based on the industry standard 6:1 ratio.

So this is how you would read the above chart…

Look at the red triangle symbol TOU, Tourmaline Energy, a heavily weighted gas producer. This chart shows they make just over $20/barrel profit, and for that they are valued at roughly $70,000 per flowing barrel of production.

Crescent Point (CPG), which is Canada’s leading intermediate oil and arguably the most successful and most respected management team in their sector, generates a profit per barrel of over $55… and the market values them at roughly $160,000 per flowing barrel.

But the big problem is that the value of gas is, on average, 35x less than oil—so Tourmaline and all these other gas producers should have their daily production levels divided by 35 to get an accurate comparison to oil producers, not 6.    And that creates a HUGE valuation gap for these stocks to contend with.

Knowles went through each producer under coverage to get a customized oil:gas ratio based on cash flow generated for each commodity—and the ratios for the gas stocks ranged from 29.9 – 41.5.  When you compare the valuations of all the companies on their true cash generating ratio of gas to oil, this is what the chart looks like:

Look where Tourmaline is now—at the top!

“Why should a gas company get so much more value than oil-weighted value?” asks Knowles.  “Almost all the gas guys are valued higher than CPG, and does that make sense?”

This chart shows that the 6:1 ratio of oil to gas is outdated. In fact, most people in the industry have been saying that for years.

“We have to rethink the 6:1 ratio,” says Knowles. “Two 50,000 barrel-a-day companies are not the same.  If one is half natural gas, all of a sudden they’re a 25,000 bopd company, from a revenue point of view.”

Knowles says his chart should be a warning to investors bottom fishing for natural gas stocks now.

“This is kind of a warning.  Gas prices were down 33% in Q1 and they’re down even more now.”  He says investors will finally understand how bad things are getting when natural gas companies start reporting their quarterly financials.

“It takes hard reality of financial results before it really hits home for a lot of people.  When we see it in black and white it will get crystallized—there will be some companies whose cash flow is devastated—especially on the juniors, they’ll be hard hit.”

He expects a lot of Canadian natural gas producers just won’t re-start production after this year’s spring break-up—the 4-6 week stretch where big trucks are banned from the thawing roads in western Canada.

Knowles is quick to point out valuations aren’t just in the numbers.  There are a lot of intangibles, like the Street’s opinion of management—that counts for a lot.

Take my example of Tourmaline.  Chairman and CEO Mike Rose is a legend, successfully selling Duvernay Oil and Gas to Shell for $5.6 billion in 2008. Few CEOs have as good a track record.  And that’s a big part of that stock’s valuation.

Later this year, Knowles sees the oil:gas ratio increasing to over 40 as Canadian oil prices increase.  He says that the reversal of the Seaway pipeline in the US—which will now take oil from Cushing OK instead of delivering it, will help Canadian gas prices.  Refinery turnarounds will also be a plus.

He sums up: “We think people have not adjusted to the reality of gas stocks.  They’re still looking at it as 6:1.”

- Keith

Where will the wealth created by the fast growing Liquid Natural Gas (LNG) market be concentrated in the coming years?

In a word–Australia. It’s the #4 exporter of LNG in the world already, and seven new plants are in various stages of planning and development, which would require $200 billion in capital investment–and lots of jobs.

By comparison, America, which produces massive amounts of natural gas, sends a shockingly small amount of the resource abroad.

Both are close to markets – Australia is closer to Asia, which imports vast quantities of LNG, but the U.S. is also relatively close to these markets and closer to Europe, which holds some major LNG consumers, like Spain and France. Both also have robust natural gas production.

And yet Australia is light years ahead of America in sending LNG overseas. How far? about 800 billion cubic feet (bcf) per year.

Now before we explore that gap further, here’s a short-version background on LNG…

LNG is created by cooling natural gas to minus 256 degrees Fahrenheit, which transforms the gas into a liquid. This liquid has about 1/600th the volume of natural gas, making its transport over long distances much simpler —and much more economic.

While turning a gas into a liquid may seem to be the stuff of science fiction, it has its roots in the 19th century when Carl Von Linde, an engineer in Munich, built the first practical compressor refrigeration machine. The first LNG plant was built roughly a century ago in West Virginia.

It’s not the Bakken most investors have come to know.

But I expect that all to change, especially now that one small company operating here has just hit TWICE on a HUGE new play–validating thousands of acres.

That’s why company insiders have been loading up on shares… AND why brokerage firms have price targets 50% to 100% higher than today’s share price.

As an OGIB reader, you can get the full update on this high-potential growth play — here in my new findings. Go here for free access.

Of course, large-scale users of natural gas prefer to deal with the regular kind–not liquid and frozen. Since gas is easier to move and doesn’t need to be refrigerated, companies had to then develop ways to reverse the process. So you have to liquefy the gas to move it, and then “re-gasify” the natural gas to use it.  That’s a lot of work and means large infrastructure investments are required.

The gas is converted to liquid at liquefaction plants (LNG export terminals.) It is then transported in special ships that use auto-refrigeration. These LNG ocean tankers actually use a small amount of the LNG – 3%-4% during an average voyage—to power the ships. These tankers can carry around 135,000 cubic meters of liquid natural gas, which works out to about 3 billion cubic feet of warm natural gas.

To give you an idea of how much gas that is, 23 ships a day could feed ALL the US demand for natural gas.  There are now roughly 375 ships in service worldwide.

The ships then go to an LNG import, or regasification, terminal where the LNG is converted back to a gaseous state and then either stored in tanks or sent through pipelines.

The Asian market is a major destination for LNG exporters. Japan is by far the world’s largest importer of LNG, bringing in nearly 71 million tons (8.52 bcf/d)—or almost 31 percent of all global LNG imports, according to Unit Economics.

South Korea is #2 at 34.5 million tons (4.14 bcf/d), or roughly 15 percent of global imports. Taiwan (11.3 million tons/1.36 bcf/d) and China (9.7 million tons/1.16 bcf/d) also account for a significant portion of LNG imports.

Asia isn’t the only major LNG import market, though. Europe brings in large amounts as well.  Spain is the third largest importer of LNG with 27.3 million tons (3.28 bcf/d) coming in during 2010. The United Kingdom and France are also major importers, bringing in 13.4 million tons (1.60 bcf/d) and 10.2 million tons (1.22 bcf/d) in 2010, respectively.

According to the U.S. Energy Information Administration (EIA), the U.K. received 55 percent of its LNG exports from Qatar in 2009. That same year significant quantities of the hydrocarbon entered the U.K. from Trindad and Tobago (a surprisingly robust LNG exporter with 15.4 million tons (1.85 bcf/d) sent abroad in 2010), Algeria, Egypt and Australia.

Now that we’ve covered the basics of LNG, we can dive into the LNG industry in Australia to see what the U.S. might learn from the Land Down Under.

Australia only trails Qatar, Indonesia and Malaysia in LNG exports. In 2010, Australia sent 872 billion cubic feet (about 19 million tons) abroad, which was a substantial improvement over the 714 BCF exported in 2009, says the EIA.

That’s just over 8% of the world’s LNG exports. By comparison, Qatar does 25% of all LNG exports. Unit Economics states that Australia could contend with the Middle Eastern country for top spot as early as 2016.

Not surprisingly, most of Australia’s LNG exports go to the Top 4 importing countries—all in the Far East. Japan gets about 70% of Australia’s LNG exports, China gets 21%, South Korea 5% and Taiwan 4%.

There are only two LNG liquefaction plants in Australia right now, but seven additional export facilities are under construction, and four more are planned. Unit Economics reports that if all of these facilities come on line and produce their projected capacities, Australia will send a staggering 95.7 million tons (11.5 bcf/d) of natural gas abroad per year, versus the 19 million tons (2.28 bcf/d) it is exporting now—a five-fold increase!

The capital investments—and the jobs created by it—are enormous.  The Australian major Santos Ltd., along with Petroliam Nasional Bhd., are planning on shelling out $45 billion to create three LNG export facilities that would be able to convert 20.8 million tons of coal seam gas into LNG each year, reports the Wall Street Journal.

Other prominent players in Australian LNG are the BG Group PLC and the Australia Pacific LNG consortium, which is led by ConocoPhillips and Origin Energy Ltd.

“LNG is simply in high demand. and it’s not just the consequence of Fukushima,” Jon Skule Storheill, chief executive officer of Awilco LNG, told Reuters, referencing the nuclear disaster in Japan that has prompted the country to rely more heavily on LNG. “There’s Korea, there’s Taiwan, this market is just strong. Gas is clean, it’s available and it’s cheap.”

America, on the other hand, has only two export terminals. The terminal in Kenai, Alaska, which was built in the 1960s, was idled in November of last year. (At the time, ConocoPhillips’ spokeswoman Natalie Lowman told The Associated Press the plant will be in preservation mode until spring 2012, at which time the company will re-examine the facility.)

The other is Cheniere Energy’s Sabine Pass LNG Terminal, near the border of Texas and Louisiana. This station has 4 billion cubic feet per day of capacity.

Overall, the US exported 0.2 bcf/d of LNG in 2011, according to the EIA—a total of 71.5 bcf.  Australia almost does that in just one month.  The U.S. sends most of its LNG exports to Brazil, China, Japan and South Korea.

So How Does the US Get In On the Global LNG Action?

The LNG market is growing, and its future looks bright.

Some industry analysts predict demand for LNG globally will increase 40% in the five-year period from 2010 to 2015. This would make the annual market for LNG roughly 300 million tons.

The U.S. has the fifth-highest amount of natural gas reserves in the world, with the EIA putting the number at 273 trillion cubic feet. By comparison Australia has the 12th-highest natural gas reserves, with “only” 110 trillion cubic feet. But, as  stated above, Australia was able to ship more than 12 times as much LNG overseas in 2010 than the U.S.

The largest obstacle the U.S. faces in the LNG market is its lack of export/liquefaction terminals. With the Kenai facility going idle, the Sabine Pass terminal is the only facility in America even close to being able to regularly send LNG overseas. And even that could still be a few years away.

Now what about building LNG liquefaction plants?  Unit Economics says it can cost $3 billion for each million tons of annual capacity for the entire liquefaction supply chain, which includes production, pipelines, the port and the facility itself.

The Wall Street Journal reports there are seven additional projects seeking approval from the Department of Energy to ship LNG to most foreign nations. If all of these projects gain approval they could handle about 25 percent of U.S. gas production. However, the news source reports that approval for all of the facilities is unlikely.

An additional hurdle to the LNG market in the U.S. is political opposition to sending the energy source overseas. The American Chemistry Council has warned the U.S. government that it “should not undermine the availability of domestic natural gas,” but is not necessarily against exporting the substance.

The Sierra Club is concerned that exporting more natural gas will cause companies to increase their fracking operations. While there has been little to no evidence that fracking itself harms the environment, a groundswell of opposition to the practice has emerged, making investing in greater production difficult for the industry.

Still, for all the hurdles in exporting LNG, the U.S. also many opportunities.

In mid-March Japanese officials planned to meet with a delegation headed by Deputy Energy Secretary Daniel Poneman to reportedly request LNG exports to Japan. This appears to be a major step, as Japan had previously shied away from American LNG due to uncertainty over whether Washington would allow it to be exported.

As mentioned, Japan’s thirst for LNG is insatiable, and it will only grow stronger as the country scales back on its use of nuclear power following last year’s Fukushima Daiichi nuclear disaster. (Before the disaster, nuclear power accounted for about 30 percent of Japan’s energy production. That’s a large hole Japan will need to fill.)

Other markets that could be exploited by the U.S. are the U.K., France and Spain, all three of which are among the largest importers of LNG in the world. While Australia does send some LNG to these European countries, most of the U.S. competition will come from African countries like Nigeria and Algeria, as well as Qatar.

Another positive sign for U.S. LNG exports is that they appear to have the support of Energy Secretary Steven Chu, who has stated that sending the hydrocarbon overseas would allow America to cut into its trade deficit.

“Exporting natural gas means wealth comes into the United States,” he said, reports The Wall Street Journal.

There is much work to be done in the U.S. LNG industry to help it catch Australia—but the economics are powerful if it can.  The gears appear to be moving in the right direction, as both international markets are opening up, domestic production increases and LNG liquefaction facilities gain approval and come on line.

- The OGIB Research Team

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.

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.

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.

- Keith Schaefer
Publisher, Oil & Gas Investments Bulletin

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.”

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

Chinese energy companies have spent billions joint-venturing North American energy assets in the last two years.  But the money pipeline could reverse under a new Chinese law—North American companies are now being allowed to develop shale gas in China—where natural gas prices are a LOT higher than here.

China recently designated shale gas as an independent resource, which means that smaller energy companies – possibly including some from outside of China – will be able to develop the resource in the country.  As yet, China has NO commercial shale gas—but big reserves.

China’s Ministry of Land and Resources did this to bring more firms into the sector, according to Reuters. The Asian country’s energy sector is currently dominated by massive Chinese companies like PetroChina.

Xinhua News Agency cited a government official as saying China would seek to launch a second round of shale gas tenders in early 2012—i.e NOW.

China only uses clean burning natural gas for 4% of its energy supply, compared to 20% + for most of the modern world—and it is already the third largest consumer of natural gas in the world (after USA and Russia).  They have a goal of getting to 10% by 2020.  China is increasing their gas supply now via pipelines from foreign countries like Turkmenistan, Kazakhstan, Uzbekistan, Myanmar and Russia.

Natural gas prices vary widely across the country, as they are subsidized in some areas to keep inflation low.  But in Shanghai you can now get $12+ per mcf and I have heard as high as $22/mcf—one of the best prices in the world (North American LNG export terminal proponents are salivating…).  Price liberalization is increasing.

Firms from outside of China will not be allowed to participate in the tenders but will be able to partner with the Chinese companies that win them.

This move could have major implications for any companies that partner with the winning Chinese firms as the Asian nation has an incredible amount of shale gas reserves.

The U.S. Energy Information Administration estimated that there was 1.275-QUADRILLION-cubic-feet-worth of “technically recoverable” shale gas in China. By comparison, the U.S. – which has led the way with the development of shale gas – has “only” 862 trillion cubic feet.

China has shown it’s eager to develop its energy resources—they’re on the record saying they want to increase oil and gas output by 23% by 2015 to 360 million tons equivalent—and to 450 million tons by 2030.

——————————————————————————————————————–

In terms of just shale gas, China says it hopes to produce 229.5 billion cubic feet of the resource by 2015. By 2020, the country is targeting 2.82 trillion cubic feet of shale gas production, according to Reuters—almost a ten-fold increase in just five years.

Due to these enormous reserves, whatever foreign companies are able to partner with the winning Chinese firms will be in a strong position.

So far only the large Chinese firms have been winning bids to develop shale gas.

Earlier this month it was reported that China National Offshore Oil Corp, or CNOOC Ltd., which is the biggest Chinese offshore energy producer, began drilling its first shale gas project in the country.

Neil Beveridge, an energy analyst at Sanford C. Bernstein & Co. based in Hong Kong, told Bloomberg that this was a significant move for CNOOC.

“It may take more than five years for CNOOC to turn this exploration into real production, but the key message here is CNOOC signals a new direction on where the company will move in the future,” he said. “CNOOC will count heavily on unconventional oil and gas for growth down the road.”

Large companies dominated the first round of tenders in June.  This second auction will likely see smaller companies get involved in shale gas, due to the resource’s new designation.

Because of the challenges posed by recovering these unconventional resources, Chinese companies have been attempting to gain technical expertise by partnering with foreign firms to develop shale gas abroad.

One of the most prominent such ventures was Sinopec’s acquisition of one-third of Devon Energy Corp. (DVN:NYSE) for $900 million in cash. Bloomberg also reports that the deal could include the Chinese firm paying up to $1.6 billion in Devon’s future drilling costs.

“In these joint ventures, the partner does typically get some education on drilling,” Scott Hanold, an analyst for RBC Capital Markets, told Bloomberg.

The news provider reports that Chinese firms spent over $18 billion in 2011 buying oil and gas companies around the world.

China’s shale gas reserves are massive, as the profits for any company that is able to partner with a firm developing the resource in the country could potentially be.

The stocks of natural gas producers have been hit hard by the low price and bearish outlook for the commodity. But a new report from Denver-based energy analytics company BENTEK makes me think natural gas pipeline stocks, pipeline MLPs and pipeline ETFs/ETNs in the U.S. could come under big pressure in the coming weeks.

And their stock charts are agreeing with me.

Bentek’s report — “West Absorbs Marcellus Shale,” and just released on Thursday — says that the northeast US, the most lucrative retail gas market in North America, can be fed mostly from fast rising natural gas production out of the Marcellus shale —  a “local market” for that shale deposit.

If fact, with so many new shale gas deposits—located all over the U.S.—now every market can be served with “local” gas, greatly reducing the need for pipelines. Dividend paying pipeline companies have been some of the best performing stocks for resource investors, but the shale gas supply glut may drag them down now as well.

“From a fundamental and market point of view, it doesn’t bode well for those (gas pipeline) flows to remain high, due to growth in eastern shales,” says Bentek’s Sheetal Nasta, one of the authors of the report.

“We have local supply to serve local demand, not just in the Northeast, but in the Midwest, with the EagleFord and Granite Wash plays. Local production will serve local demand and long haul pipes are losing favour because of that.”

That is not good news for companies like Kinder Morgan (KMP-NYSE) which just spent $4.4 billion on the new REX pipeline that goes from Wyoming to Ohio—or for TransCanada Pipelines (TRP-NYSE; TRP-TSX), with its main gas line from Alberta to Sarnia Ontario.  To their benefit, many of these companies have long life contracts that get them through market swoons.

Pipeline stocks, ETFs/ETNs, and MLPs fell to their lowest intraday drop in months last Friday.  (MLPs, or Master Limited Partnerships, are tax-advantaged investment vehicles that make distributions similar to dividends; see our earlier MLP report here.)

The listings I saw affected most in Friday’s trading were the Alerian ETF and ETN products:

• MLPL-NYSE—2x Leveraged Long Alerian MLP Infrastructure Index ETN
• MLPI-NYSE—Alerian MLP Infrastructure Index ETN
• AMJ-NYSE—JP Morgan Alerian MLP Index ETN

They were NOT textbook reversals on Friday, but they were larger than normal downdays. (Each of these 3 is down again today.)

Two of the largest pipeline companies in the US also broke stride with recent uptrends after the Bentek report came out. Kinder Morgan’s KMP-NYSE listing had its biggest intraday drop since the market crunch of early October. Enterprise Partners (EPD-NYSE), also had a large intraday drop, but it was not as unusual. (KMP and EPD are both down today.)

The reason pipelines exist is to take low price supply to higher priced demand. But the huge supply has depressed gas prices everywhere in North America, so there is little to no price spread on gas between the various hubs in the US. And for the first time in history, some price spreads have gone negative, says Nasta.

“Westbound flows on Ruby (the new Ruby pipeline moves gas west, from western Wyoming to Malin Oregon, on the California border) picked up in November and eastern REX flows dropped off (REX takes gas east, from eastern Wyoming to Ohio).”

The reason REX gas flows dropped was because of all the new gas production out of the Marcellus shale—the east just didn’t need near as much western gas.

“Demand in the west absorbed that incremental gas,” Nasta continues. “Due to a combination of mild demand in the east and increased production in Marcellus, prices on east side of the US (the Dominion South hub in Ohio) got really weak–and the spread between east and west went negative.

“That is historically unusual.  It wasn’t that long ago—a couple years–the price spreads between those two hubs were over $1 (per thousand cubic feet, or mcf).  But I don’t think it’s ever been negative.”

*source: Bentek GIS

“Spreads across the country are flat. We don’t need long haul gas.”

For high REX volumes to keep flowing, she says, the gap, or spread in prices between Wyoming’s Opal hub and Ohio’s Dominion South hub have to widen out again—meaning the western Opal gas price has to get weaker.

But gas production in the Wyoming area is flat; no growth. Combine that with increased pipeline capacity to get gas out of Opal—thanks to the new Ruby pipeline that just started in 2011—Nasta says she doesn’t see Opal’s gas basis falling much anytime soon.

So not only is there a lot of gas, it’s everywhere, reducing the need for pipelines, and that’s all coming at a time when a lot of pipelines have been built. Pipelines are like any other commodity; their pricing goes by supply and demand. It appears that local supply is going up and long haul demand is going down. Competition is almost certainly going to bring pipeline prices—the toll charges they give gas producers—down.

For resource investors, and income investors, pipeline stocks have been a steady to good performer. But if Bentek is right, I see their multiples—if not their actual dividends—being reduced if current trends in the gas market keep going the way they are.

Here’s a link to the Bentek report.

There is a Canadian angle to this story as well, which I’ll cover in more detail in an upcoming OGIB Free Alert.  Meantime, you can read my original story on how all the new US gas pipelines have displaced Canadian natural gas.  Click here for the OGIB report on REX – the Rockies Express Pipeline.

- Keith

DISCLOSURE:  Keith Schaefer is neither long nor short any of the companies mentioned above, and has no intention of initiating a position.

My portfolio, which I use as the OGIB subscriber portfolio, finished 2011 up 48.2% on closed trades (stocks that I actually sold in 2011) and up 36% on open trades that were initiated, or first bought, in 2011.  If I include stocks I bought in 2009 and 2010, my gain on all open positions is 36.7%.

In all, gross gains in the portfolio totaled $449,744… while gross losses came to $52,860.

Strangely, the year didn’t seem that profitable, emotionally or mentally.   There was A LOT of volatility and angst—June and October were particularly harsh months for the junior resource sector.

And I was guilty at times of getting too wrapped up in the market swoons, trading out and trading in again.

HOWEVER — I did find what I think are my best trades of the year in the last two market bottoms in June and October—so I was able to use market panic to my advantage some of the time.

Each January I try to look objectively at my trading and track record and try to determine what I did right and wrong; what can I do better to bring more prosperity to me and my subscribers.

Here’s my list for 2011.  First, here is what made me money.  In my next article, I will share what lost me money in 2011 — and I’ll include my outlook for 2012:

1.      When I found a winner, I kept buying; averaging up.  In my four biggest winners of 2011, I continued to buy the dips as they rose—even after they doubled, I kept buying. I first bought Coastal Energy (CEN-TSX) at $2.50; I bought more in the June swoon at $8.80. Today, all those stocks are above the highest price I paid for them.  Now, when I do that, I listen to both the company and the stock; because sometimes they say different things.  My job is to do the research to see which one is more accurate.

2.       I did not average down on my losers—except one.  But my losing trades were obviously a lot smaller than the winners.  That’s because I don’t allow myself to believe that I’m smarter than the market.  If the market is selling a stock down, I always believe I have made the mistake and I start making calls to figure out what I don’t know.  I don’t say—”the market must be mad”—and start buying with both fists at lower prices—setting myself up for a BIG loss.   (My one average down stock is now back up to near-year highs)

4.      When the market turned negative in the early spring, I was vocal about selling my juniors and moving upmarket, to higher priced, more mature and less risky stocks.  This made me more open to buying additional shares of my higher priced winners — even after they were already up.  (I could also argue that I didn’t sell enough of the penny juniors fast enough and that DID COST ME a lot of money.)

5.       This lesson did cost me money, but it saved me a lot more — Be flexible; be willing to say you made a mistake.  Normally when you make a mistake it means taking your initial loss and moving on—I was able to exit Valeura (VLE-TSXv) and being able to exit the position with only a 6% loss—it’s now down 70%.

But being able to change your mind also means having no ego on a stock that turns around–which you previously sold.  I sold two stocks this year that had horrible charts in a bad market—and days later, they each had something happen that fundamentally changed the company—for the better.  I jumped back into both—well above the prices I just sold them at — for the same reason I originally bought the stock, and they are both 40% higher now—within weeks.

I’m very happy with 48.2% gain in 2011.  But it could have been a lot better if I had practised a couple simple trading rules.  Sadly, even after 25 years of investing, I find myself making some of the same mistakes I made as a rookie.  I’ll tell you about them, and why I have a bullish outlook for junior oil and gas stocks (OK… just oil) — in 2012.