7 Key Points on Investing in MLPs (Master Limited Partnerships)

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1940bkg
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What was the best investment niche in the U.S. energy sector the first half of this year?

Master Limited Partnerships, or MLPs.

Consider one key benchmark, the Alerian MLP Index (AMZ). Since December 31, 2007, the index has returned 66.6% for investors, with about 32% of that from capital gains. Compare that to the S&P 500, where returns slid by 1.55% over the same time frame.

This year has been no exception: over the first six months of 2012, MLPs kept up the pace, outperforming all major investment indexes (as follows):

Index                Return Through 6/30/2012

Alerian MLP     6.4%
Utilities Index   4.1%
REITs                3.9%
DJIA                  2.7%
S&P 500            2.2%

There’s lots to love about MLPs:

  • They combine the income-producing benefits of bonds with the capital appreciation advantages of stocks – and combine them into one energy investment that has outpaced every other leading investment benchmark in 11 of the last 12 years.
  • On top of that performance, factor in a tax element that wipes clean 80%-to-90% of your tax burden on that investment.
  • Combine that performance with an oil and gas industry investment that, historically, makes money no matter what commodity prices are doing

That’s where MLPs may just may change the way you look at investing, altogether… especially in the more conservative part of your portfolio.

They are particularly engaging in a tepid economy, where finding oil and gas investments with reduced downside risk and returns that beat average dividend stocks is no easy task.

Can MLPs be a game-changer for you? Sure – if you know the lay of the land, and if you know how to play them right.

Here are seven key points on MLPs:

1. What are MLPs, exactly?

In short, MLPs are publicly traded investment partnerships. MLPs have unit holders, and not shareholders, and are targeted toward the energy sector (primarily oil and gas), and trade on major exchanges such as the New York Stock Exchange, or Nasdaq.

For Canadians, MLPs are akin to their former Energy Income Trusts, as both can send most of their income—with almost no taxes—to unit holders.

Energy-related MLPs have one critical legal threshold to clear:  In order for a partnership to qualify as one, the partnership must get 90% of its cash flows from commodities (usually oil and gas).

MLPs merge the tax benefits of a traditional limited partnership with the  liquidity of a publicly traded company.  The MLP doesn’t pay taxes from the profit. Instead, the money is only taxed when the partnership’s unit-holders receive their cash distributions.

And yes, MLPs are growing. According to industry figures, over the past 10 years, MLP market cap growth has grown from $25 billion to $350 billion.  MLPs own oil and gas pipelines, transportation and processing, refining, and storage sectors.

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MLP Fact SheetThere are over 100 MLPs actively traded on major global financial markets.MLPs focus on the transport (pipeline) side of the energy market – meaning they earn money no matter the price of oil and gas.

The Alerian MLP Index tracks the performance of 50 MLPs weighted by market capitalization.

 energytrust

BNN interview on Income Trusts — Canada’s counterpart to U.S. MLPs.Click here to watch.
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2. How long have MLPs been around?

While the first MLP, Apache Oil Company, was formed in 1981, the investment vehicle really gained momentum in 1986, via the Tax Reform Act, and in 1987, via the Revenue Act. Both pieces of legislation stated that as long as 90% of MLP revenues originated from natural resources related to the exploration, development land ownership, and investment gains and losses, they would be considered “established” MLP structures.

Later in the decade, MLPs morphed into midstream ownership entities that owned assets that transported, refined and stored oil and gas products. That “asset ownership” feature helped MLPs reduce their exposure to volatile oil and gas prices, and provided a steady and reliable cash flow for MLP investors.

Historically, investors have been drawn to MLPs for two significant reasons:

  • Income generation — In volatile markets, where high investment risk is par for the course, income-generation is a priority.
  • Tax benefits – Since master limited partnerships are considered legal, qualified partnerships by the I.R.S., unit holders earn more income – but pay less tax on that income.

MLPs have taken a pivotal, even leadership role in getting energy to U.S. consumers.  They generally trade at a higher valuation than regular corporations (the industry calls those “C-corps”) and can therefore raise money for big projects more cheaply than them.

As owners of the storage facilities and pipelines needed to transport oil, gas and other commodities from the refineries to consumers, MLPs are ideally positioned to benefit from rising energy demand.

3. How are MLPs structured?

MLPs are generally structured with a General Partner (GP) acting as management, and the Limited Partners (LP) providing the capital.

  • MLPs can have one or more General Partners, who can have a 2% ownership stake in the partnership.
  • MLPs can have thousands of Limited Partners (known as unit holders) who own publicly traded units. Limited Partners play no role in the management of the partnership, and are eligible for quarterly cash distributions.

Most MLPs have a tiered-hierarchy, with a General Partner at the top of the organization, and are tasked to manage the MLP on behalf of unit-holders. Typically, General Partners have a 2% interest in the MLP, while the participation rate varies for individual Limited Partners, and they are tasked with providing financial capital, and benefit from investment gains from the partnership.

Unlike stocks, MLP partners own “units” of the partnership, and the number of units owned represents a Limited Partner’s stake in the partnership. Typically, Limited Partners look for two investment results from MLPs – strong yield and solid growth. In both areas historically, investors have often been rewarded handsomely.

Operationally, MLPs offer investors the following benefits:

  • As a partnership, MLPs aren’t taxed like corporations. That “pass through” structure means unit holders aren’t “double-taxed” on dividends they receive. For the partnership, that tax structure means a lower cost of capital, thus giving MLPs a big advantage in generating more assets.
  • MLP’s unique tax structure allows for more money to funnel to investors. And since MLPs are publicly traded, that enables MLPs to gain access to a wider ranger of investors.

MLP Business Structure


Source: J.P. Morgan

4. How Can Individual Investors Get Going With MLPs?

Historically, MLPs were only available to the public as individual investments, but in recent years they’ve become available as closed-end funds and exchange-traded funds, and are now widely available on financial exchanges.

Some of the most widely traded individual MPs include:

  • Kinder Morgan Energy Partners (KMP)
  • Enterprise Products Partners (EPD)
  • Magellan Midstream Partners (MMP)
  • Linn Energy Corp (LINE)

The most prominent exchange-traded fund is the Alerian MLP (AMLP), which holds over $4.4 billion in net assets. The Alerian ETF invests at least 90% of total assets in its underlying index, the Alerian MLP Infrastructure Index.

Note that individual MLP investors based in the U.S. generally must file a unique IRS tax form annually, called a K-1 form. It’s advisable to consult a professional tax specialist before filing the K-1 form.  Canadians can buy MLPs but may be subject to a withholding tax by the U.S. government—again, check with a financial advisor.

5. How do MLPs offer energy investors special tax advantages?

Master Limited Partnerships earned a unique benefit from the Tax Reform Act of 1986, as it largely exempted MLP investors from corporate taxes. Investors may look to real estate investment trusts (REITs) as a blueprint. Like REITs, MLPs are considered pass-through entities by Congress and by the Internal Revenue Service. In that regard, any profits or losses are “passed along” to MLP unit-holders, who pay any associated taxes at their individual, ordinary income tax rate.

Due to what accountants refer to as “depreciation allowances,” MLP investors may receive up to 80% to 90% of investment distributions without paying immediate taxes on the income, thus providing an ample tax deferral advantage for investors.

*Non-U.S. residents get hit with a 35% withholding tax by Uncle Sam.  There is paperwork to ensure there’s not double taxation on what you do receive.

6. What are the major risks associated with MLPs?

MLPs do present some risk. For example . . .

  • Commodity risk:  MLP returns can be impacted if there is a slide in oil and gas exploration and production due to gyrating energy prices.
  • Correlation risk:  This just means that MLPs go up and down with the market and with commodity prices more now than ever before.
  • Liquidity risk:  MLPs don’t always offer the same easy liquidity prominent with stocks, mutual funds, and exchange traded funds.

Of course, you have to throw in the regular volatility of the oil and gas industry, macro events, changes in legislation etc—which aren’t always good for the oil and gas industry.

7. Outlook for MLPs going forward

Energy-related master limited partnerships are positioned positive for substantial investment growth over the next few years.

You see, a lot of MLPs transport energy, and as more oil and gas are produced by the U.S., it has go somewhere—and the oil and gas transport services MLPs provide is influenced energy volume, not price.  And there’s a strong argument that the lower oil and gas prices go, the more demand there will be for it.

Put another way, pipeline-oriented MLPs are paid to move oil and gas, no matter if it’s priced at $100 or $25 per barrel.

That’s a big advantage for MLP unit holders, who already enjoy some of the best investment returns on the global financial markets over the past 25 years.

More and more investors are becoming aware of that fact.

– Brian O’Connell, guest editor

 

The Huge Risk-Reward Scenario with East Africa Oil

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1940bkg
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by Jen Alic

Welcome to East Africa—home of a potential 28 billion barrels of recoverable oil, 440 trillion cubic feet of gas and 14 billion barrels of natural gas liquids.

Recent success by Africa Oil (AOI-TSX; AQIFF-PINK)—the stock went from $2-$11 in just two months in the spring of 2012 on just one drill hole—has made East Africa the most exciting exploration play in the world right now.

But that excitement is tempered with some political instability, social conflict and a lack of energy infrastructure.

Still, this vastly untapped region is the fast-rising favorite for Canadian juniors. The obvious question is: Why?

The potential prize is too big to ignore:

· ~5 billion in proven reserves in the Sudans and major discoveries elsewhere, with only a fraction of the potential explored
· Enough gas has been discovered in Mozambique to supply half of Western Europe for nearly a decade and a half—still, the country has barely been explored.

· Recent offshore discoveries of some 33 trillion cubic feet of gas put Tanzania on the map, and the risk here is relatively low. Tanzania has a natural gas processing plant on Songo Songo Island, with a 70 million cubic feet/day capacity. It is also planning an LNG terminal.

· Uganda discovered more than 2.5 billion barrels of oil in the last decade. This year alone, it discovered more than 1 billion barrels.

The risks fall into three categories:

1. A lack of infrastructure—pipelines, processing plants and refineries. You can make a big discovery, but how do you get it to market and monetize it?

2. Government greed.

3. Social/tribal tensions.

Sudan is a good example. Blessed with an abundant oil supplies, authorities recently announced that the country would double production in the next 2-3 years. However, it will miss its 2012 production target of 180,000 bpd due to social conflict.

Still, Canadian juniors like Calgary-based Emperor Oil (TSX-V: EM) and Statesman Resources Ltd (TSX-V:SRR) remain optimistic in Sudan.

Emperor Oil was a pioneer in Sudan, and recently signed an MOU to acquire 85% of a 50% interest in the 10,000 sq km concession Block 7 in Sudan. The other 50% is owned by the state’s National Oil Company, Sudapet.

“East Africa wants oil development,” says Emperor CEO Andrew McCarthy. “Infrastructure is an issue, though Sudan is in much better shape than most here.”

Infrastructure in this part of East Africa should improve in the coming years, with the big project being the $24.7 billion Lamu Port-South Sudan-Ethiopia Transit corridor (LAPSSET). LAPSSET includes a massive pipeline that would carry South Sudanese oil for refining in Ethiopia and Kenya and give the entire region another oil outlet.

Is it feasible? Yes, but capital is always difficult for this area, and McCarthy points out that the capacity of the Sudan-South Sudan pipeline could go to 1 million bopd at a fraction of the costs. The good news—competition creates lower costs for everyone.

McCarthy added that the new wealth being created by energy companies is a strong incentive for the different ethnic groups in East Africa to work together. He points to Sudan and South Sudan breaking apart peacefully, and any skirmishes after the fact have been stopped quickly once the oil—and hence the money—stopped flowing.

“Rather than fight over existing production they have chosen to expand their resource development so that there is a larger pie to share.”

Infrastructure is also the issue farther south in East Africa. Major energy producers are eyeing 130 trillion cubic feet of gas in the Rovuma basin offshore Mozambique, discovered by Andarko (US) and Eni (Italy). The government estimates there may be another 150 trillion cubic feet left to discover. Shell, ExxonMobil and Chevron are eyeing this as well.

But for now, there is no way to bring extracted gas onshore, no facilities to liquefy it and no infrastructure for export.

We’re talking about $20 billion in investment to build the necessary infrastructure.

And ironically, the phenomenal success of the some of the pioneering juniors causes another problem: the governments start changing terms.

Several years ago East African countries were luring foreign oil companies onto their territory with desperately attractive deals. This trend is changing. Recent reserve discoveries have empowered these nations to ask for more.

There is pressure on juniors to foot the bill for ambitious infrastructure projects. East African states want the juniors to speed up their plans—drill more wells; build pipelines—get the money flowing! It can put the juniors with limited resources in a difficult spot.

But again, The Prize is big enough that several juniors have been able to attract major oil companies into their play.

For its next licensing round in oil and gas, Kenya is planning to switch to bidding for exploration blocks, rather than its usual one-on-one negotiations. While more transparent, which is good for business, this also reflects the new impatience. Kenya is also planning to rewrite its energy policy to reflect its greater negotiating power as a result of recent discoveries.

In Uganda, potential is vast and exploration just getting underway, but regulatory challenges are mounting.

Uganda wanted its oil and gas investors to pitch in for a massive refinery in the western area of Hoima. For investors, it was an unnecessary project with unnecessary expenses. Foreign oil companies would rather see Uganda’s oil refined elsewhere, more cheaply.

With new exploration technology (FTG, 3D seismic) being used on relatively virgin reservoirs, there’s a lot of potential for big new discoveries. But there are definitely challenges for energy producers looking to move into this are.

However, the Size of The Prize trumps all—the huge capital gains enjoyed by shareholders of Africa Oil, and before them Heritage Oil (HOC-TSX), attest to that.

Investors should be watching this area to see who’s next.

A New Yield Growth Model in the Junior Oil Patch

By
1940bkg
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0

Dear OGIB Reader,

The leading Canadian junior oil companies are doing whatever they can to create value for their shareholders.

Three of the top junior oil companies in Canada are turning away from high growth and into dividend plays this morning. These are all well-respected, leading junior management teams. One was no surprise, and one was a big surprise.

Whitecap (WCP-TSX) announced on Tuesday night—but management had been broadcasting their intent to the market for several months. This 15,000 bopd oil producer will yield 6.8% based on Tuesday’s close and grow production by 3-5% per share per year. They are 49% hedged at $100/bbl and have net debt of $335 million on a $450 million debt line.

The big surprise was the merger between Pinecrest (PRY-TSX) and Spartan Oil (STO-TSX). Pinecrest was THE market darling from late 2010 through 2011, trading near $400,000 per flowing barrel at one point (vs. a peer average of $75,000), but the stock has a miserable chart in 2012.

The PRY/STO merger will have 9100 bopd of 90% light oil, net cash of $35 million with a $225 debt line, and a sustainability ratio of just over 100% (dividends + drilling costs / cash flow).

Investors have to wonder—if the companies considered to be the best producers are having a hard time creating shareholder value to the point they feel the need to change, what does that say for everyone else in the sector?

And is this new business model sustainable? Is size, income and slower growth the answer for these companies and their shareholders? It hasn’t done much for dividend payers like Enerplus (ERF-TSX), Bonavista (BNP-TSX) or Pennwest (PWT-TSX).

With uncanny timing, Canadian brokerage firm National Bank (who have the best and humorous daily energy letter in the country) issued a small report yesterday outlining what they think will work for junior growth companies turning to an income model. They’re a little self-evident but here it is:

Any failure in any one of the 8 components could cause dividend cuts… which are painful.

This move does have some risk here—growth via acquisition is now their mantra. These companies need the institutions to support their stock and give it a premium valuation over other juniors—or else they can’t buy anything accretively. They still have to show great capital efficiency—meaning they have to bring a lot of oil out of the ground real cheap—cheaper than the next guy.

The market doesn’t pay for just size or growth; it pays for accretive growth.

Personally, I don’t see a sub 5% yield on a junior stock with a sustainability ratio near 100% (capex + dividends / cash flow). There is still a treadmill of production—fast declining wells—they have to deal with, and now they have a big chunk of their cash flow going out the door every month. Cost discipline is key

The results of this trend so far are mixed—Twin Butte (TBE-TSX) has enjoyed a nice chart since it transformed into a dividend payer last year—but Renegade Petroleum (RPL-TSX) has been treading water in its share price since it announced it was turning to income.

Both new income companies (WCP and PRY) have a large drilling inventory—years—and upcoming potential from waterfloods where costs are only $10/barrel vs. $35-$45 for primary production. But they both have high payout ratios, which will make them vulnerable to commodity price swings. And again, they both have very highly respected management teams.

Here’s my quick take on these two new companies:

Whitecap

Shares Issued 127 million

2013 cash flow $240 million

2013 Capex $152 million

2013 dividend $0.60/share or $76.2 million

Yield from Nov 20 6.8%

Capex + dividend $231.2 million

Sustainability ratio 95%
LIKES
-low decline rate—under 30% on production

-49% hedged at $100/bbl on oil

-38% hedged at $3.26/mcf gas

-cheap wells give them flexibility if commodity prices turn down

-waterflood potential

DISLIKES

-still a high sustainability ratio (arguably best in the group)

-market hates any debt right now—they have $335 M on $450 M line

PINECREST

Shares Issued 513.4 million

2013 cash flow $200 million

2013 Capex $130 million

2013 dividend $79.6 million

Yield from Nov 20 8.3% or $0.155/share

Capex + dividend $231.2 million

Sustainability ratio 103.8%

LIKES

-high netback over $60/bbl

-low debt—0.2x cash flow

-waterflood potential

DISLIKES

-high sustainability ratio over 100%

-high share count—over 500 million—that’s a lot of volume needed to trade up

-not much production hedged yet

-40% decline rate—high

BACKGROUND

Stepping back, the junior sector has been adapting to several changes in the last 12 years—both geological and business.
The end of income trusts—no more easy exit strategy/buyouts
The shale revolution
Super low natural gas prices. Juniors are still in a “hangover phase” from when the Canadian income trust sector was raging in the last decade. (American readers: income trusts=MLPs, roughly speaking.)
Management teams didn’t have to build companies anymore, they only had to build “plays”—one area of decent production growth and suddenly they could get bought out much sooner, and for a lot more money, than they ever could before.

The income trusts traded at a premium to the market in a low yield environment. Then a financial genius came up with the idea of paying monthly dividends, not quarterly, and valuations really ramped up. Income trusts could buy anything and it was accretive.

Before the income trust game, there were intermediate producers in Canada—those between 10,000-30,000 bopd. They either turned into trusts or were gobbled up by one.

Junior teams came to have a much shorter time horizon in their public-company-building visions.

As the income trust game ended over the last few years the shale game kicked in—especially up until April 2010. As investors realized the low-risk development potential of tight oil plays after discovery, there was a series of buyouts by companies like Crescent Point (CPG-TSX) and Petrobakken (PBN-TSX).

But the change was that these plays are incredibly expensive, with wells costing $3-$10 million. A lot of money needed to be raised—and shares printed—to pay for the acquisition and development of these new tight oil plays like the Cardium, Bakken, Slave Point and Beaverhill Lake.

And then after the market thought Petrobakken overpaid for three Cardium juniors, the M&A game slowed down a lot.

The end result after billions thrown at tight oil is that only a few companies have enjoyed strong per share growth in production and cash flow.

And even fewer companies are getting rewarded for it. Charts like DeeThree (DTX-TSX), my #1 junior producer pick for 2012, are very rare.

Now, on top of all that, the market has started to factor in lower oil prices next year for both American and especially Canadian producers. The American benchmark WTI price is $23/barrel below Brent pricing in England. Canadian, Bakken and now Texas oil prices are $10-$20 a barrel below WTI—and with clogged pipelines and refinery shutdowns, that could play out throughout 2013. (Canadian heavy oil is almost exactly half the price of Brent today.)

If you consider it takes an average $40 to produce a barrel of oil, a $9 reduction in oil price from $90-$81 is only 10% drop in revenue, but it’s an 18% drop in profit.

What we’ve seen in the markets lately is the generalist institutional money—especially in the US but also Canada—leave the junior oil sector. Growth and good management is not getting rewarded.

So maybe income and good management will. Is this a sustainable business model now? Other dividend payers like Petrobakken, Pennwest, Enerplus, etc. are down in share price this year. Time will tell.

But I think it’s a major turning point for the entire sector.

by +Keith Schaefer

Golar LNG: Designing the World’s First Floating LNG Export Terminal

By
1940bkg
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It’s been a big year for LNG – Liquefied Natural Gas.  The possibility for west coast exports of LNG in Canada started off very hopeful in 2012, with both Shell and Apache making bullish statements.

But what’s happened is an unexpected twist – it looks like the “little guy” is going to be the first out of the gate.  A small group called the BC LNG Cooperative, which includes several junior producers, will be the first in North America to export LNG.

And they’re using a new technology to do it.  It’s a kind of David and Goliath story that can get lots of attention. Last week I talked with Andy Bell at Vancouver’s BNN (Business News Network – Canada’s equivalent of CNBC) studio on the subject of LNG, including an update on OGIB portfolio pick Golar LNG – which is at work on the world’s first floating export terminal. Here’s the transcript of my interview…

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Andy:  Okay let’s talk about liquefied natural gas. Golar LNG is getting a jump apparently on the competition in BC.  The company is converting an LNG carrier into an LNG export terminal, and the idea is that it is going to float in the Douglas Channel and funnel the gas to Asian markets. Now the ship is still a year or two from finding its way to the region, but the company could have first mover advantage.  As our next guest, we’re joined by Keith Schaefer,editor, Oil & Gas Investments Bulletin – great to see you, Keith.Keith: Thanks for having me, Andy.Andy:  So tell us quickly who Golar is, and what’s their Norwegian role?

Keith:  Well, Golar has been a real innovator in the sector for the last several years, they’ve been pioneering a lot of new technology and one of the things they did a couple of years ago was create the first floating natural gas import terminal, and those are called FSRUs, Floating Storage and Regasification Units. Here in Canada what they are going to do is design the world’s first floating export terminal, Floating Liquid Natural Gas. So as you said they’re going to design this over the next couple years and hopefully the Douglas Channel project dug by Kitimat will be the very first in the world where you have floating liquid natural gas terminals.

Andy:  I thought that Shell was working on a giant thing called Prelude of Australia.

Keith:  Yes, it’s going to be a massive project.  It’s going to be the largest ship in the world about the size of six aircraft carriers. The beauty of this project with Golar here on the west coast of Canada is that it is going to make a lot of small amounts of gas economic. Prelude only works on massive TCF projects Trillion Cubic Feet. This is going to work in a lot of places around the world where it’s only small amounts of gas.   And I’m excited for Canada — I think it’s going to give us a big leg up on the race to supply LNG to Asia.

Andy:  And will they actually liquefy the gas on board this vessel?

Keith:  Right, so now when gas gets liquefied, it goes like 600 to one… a huge condensing, and that gets done on these huge land-based import terminals that cost billions of dollars, and take up hundreds of acres.   And now this is going to get done on a much smaller scale, economically, on a ship.  And it’s not just to say that there’ll be one ship, they could end up having two or three or four ships in the channel, depending on how big they are able to make this project.

Andy:  How will the natural gas be able to get to the BC coast, or is there a pipeline there already?

Keith:  Right now the Spectra pipeline isn’t that big; it’s just a little over 100 million cubic feet a day, but there are plans to make it as big as either one to even 4 Bcf a day, billion cubic feet a day over the next few years as the bigger players in the sector Shell and Apache get ready with their projects, but I think what’s exciting here is that for the scale of project that they are looking at, they need that big pipeline and they need all that infrastructure…

Golar and the BC LNG cooperative here they can do this on a very small scale and make money. So they think they can, they think they can deliver gas to Asia for $6 to $7 per Mcf, so and have that ready in two or three years. So, like I said, pretty exciting stuff for Canada, really.

Andy:  Fascinating, because I think the giant projects are talking about the end of the decade to get those going.

Keith:  It has been a big year for LNG in Canada.  They started off this year saying, yes — we’re going to have it ready by 2015. Then in the spring they moved it back to 2017, and now they’ve already moved it back to 2019.  So for Golar to come in with a small BC LNG cooperative and say, hey – we think we can get this done on a much smaller scale and get it ready for 2015, that’s a big deal for Canada.

Andy:  Got to leave it there. Keith Schaefer – thanks very much. Keith is editor of the Oil & Gas Investments Bulletin.

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Editor’s Note:  The key to finding Golar – and having it turn into a bona fide winner for the OGIB portfolio – was figuring out the LNG market early, and knowing where all the pieces fit. You see, LNG is going to be a savior for North American natural gas producers, but the problem is time:  it might be the end of this decade before any significant shipments get sent overseas.I’ve found a play, though, that doesn’t need LNG to make great money.  I expect it will be making very strong profits and cash flow as early as next quarter – in fact they have one of the highest netbacks (profit per barrel) of any natural gas company I’ve ever seen.  Their economics are even as good as some oilcompanies.And it’s all because of a mega-profitable “freak of nature” resource.  You can read all about it, including the junior company with the most leverage and upside, here in my brand-new research.

by +Keith Schaefer

A Pipeline Reversal in the North American Oil & Gas Markets

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1940bkg
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It’s hard to believe how North America’s oil and gas industry—a conservative bastion—has been turned upside down in such a short period of time. And it’s all because of the Shale Revolution.

Look at pipelines. They cost billions, take years to plan, get approvals, sign up committed customers with take-or-pay provisions etc.—and now some are being made redundant within a few years.

GAS PIPELINES

I think the BIGGEST change in pipelines is happening because the industry discovered a massive new shale gas deposit in the northeast US—the Marcellus Shale.

Marcellus shale mapFor decades, western North America has produced gas and shipped it to the populated east coast.

But now—they don’t need it. They have their own source.

They used to buy Canadian gas, and shipments from the U.S. Gulf Coast, and had LNG imports. However, the highly-populated northeast U.S. now has enough local production to keep the lights and heat on with no help.

In fact, they’re exporting gas now.

Marcellus production clocked 9 billion cubic feet per day (bcf/d) in September, from under 2 bcf/d a couple years ago, and almost none in 2006. Today it is 22% of U.S. natural gas production—up from just 5% in 2011. That’s remarkable!

It also means less need for long-haul pipelines and more demand from localized systems. All told, new pipeline projects in the Northeast region are expected to add about 3.2 bcf/d capacity by December, taking Marcellus shale to mid-Atlantic markets, Canada and even Florida.

Only two years ago, Kinder Morgan (KMP-NYSE) finished spending over $4 billion building the 1.8 bcf/d Rockies Express (REX) pipeline to take more western gas from Colorado into Ohio. At the same time, Canadian production was dropping because of increased domestic demand and natural declines of aging fields.

The 2,700 kilometre line now is running far below capacity because of the unexpected explosion of Marcellus shale volumes reducing the call for western gas.

TransCanada Corp. (TRP-NYSE; TRP-TSX), which operates the largest natural gas pipeline in Canada, is already reversing its Niagara pipeline in southern Ontario as a result of the cheaper American shale gas coming onstream. The switch, expected to be active in November, will move about 0.4 bcf/d of U.S. gas north to Ontario, instead of flowing Western Canadian gas south to Pennsylvania.

That’s the east coast. In the west, two new natural gas pipelines in 2011 changed market conditions for both Canadian and U.S. producers. One was the Ruby pipeline, which flows “Rockies” gas west from Wyoming to Oregon and into California markets.

The second—Bison—also started in Wyoming, but flows gas east to the Midwest—a traditional market for Canadian natural gas.

Since its start up, Ruby has been moving about 1 bcf/d, and taking an average 700 million cubic feet per day in natural gas sales from Canada.

But demand for natural gas in California is flat because power demand growth is being met by renewables, said Ed Kallio with Ziff Energy in Calgary.

Canadian natural gas used to be cheaper and more desirable before Ruby, but now it has to be sold at a discount to Rockies gas, Kallio said.

“The Canadian gas is being pushed back into Western Canada and has to find other export routes since demand from the oil sands can only take so much,” he noted. “So producers have tapped into Alliance, and Northern Border pipelines to U.S. Midwest and eastern markets.”

OIL AND CONDENSATE PIPELINES

Pipeline flows aren’t just being changed—so are the commodities that flow inside them!

Condensate flows are also being affected by shifting supply. Kinder Morgan plans to reverse its Cochin pipeline flow between Kankakee County Illinois and facilities near Fort Saskatchewan, Alberta.

The plan would also involve changing the commodity. Now it ships propane from Canada to the US. Soon it will flow to condensate from the U.S. to Canada—because Canada needs it to dilute the fast-growing heavy oil production out of the oilsands.

On the oil side, pipeline disruptions and reversals are also happening because of fast growing production in the huge new Bakken shale oil deposit in North Dakota, and in Alberta’s oilsands.

Enbridge Inc. and Enterprise Product s Partners’ changed their Seaway pipeline—which used to run south-to-north from Houston to Cushing Oklahoma—to north-south, to help respond to a price-crushing glut of crude at Cushing.

Seaway upstream pipeline
New production out of the Bakken and Alberta’s oil sands are now flooding Cushing, which had few pipelines going OUT.

That created another upside down event in the global energy patch:

The American benchmark oil price, called WTI for West Texas Intermediate, started to trade $10-$15 a barrel cheaper than Europe’s Brent crude pricing. WTI always used to trade at a small premium.

“Because of the recent development of new oil supplies from the Bakken but also from Western Canada… there was a lot of new crude supply arriving in Cushing with essentially nowhere to go,” said Patricia Mohr, vice-president, economic and commodity specialist at the Bank of Nova Scotia.

And in an upcoming story, I’ll tell you why I think that discount is here to stay for a lot longer than the market expects.

But there are more oil pipeline reversals happening:

Further east, Enbridge will be reversing a portion of its 250, 000 bopd Line 9 from Sarnia, Ontario to Montreal, Quebec.

The plans will see a section between Sarnia and Westover, Ontario reversed to serve Imperial Oils’ Nanticoke refinery with Western Canadian crude, rather than pricier imports. Enbridge is considering a full reversal to Montreal in the future.
North Dakota Bakken Production 2
Are you dizzy yet?

And the change is still happening.

But I have to say I’m impressed with how fast the industry is adapting at almost every new turn of events. At the end of the day consumers and investors should have a more efficient energy grid and lower energy prices.

But right now, the pace of change makes it hard for investors to figure out medium to long term trends and consequences. New technology and new supply basins seem to be popping up across the continent, flipping pricing scenarios on their heads.

by +Keith Schaefer

Kurdistan Oil: My Property Tour with Western Zagros Resources

By
1940bkg
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0

Flying into Erbil is deceiving. This capital city of semi-autonomous Kurdistan province in Iraq has a modern but very small airport-not what you would expect, by western standards, for a capital city of nearly 1 million people. And the flat rocky desert surrounding the airport makes you think you flew into a small Nevada mining town, not the capital city of one of the newest and fastest growing countries in the world.

Kurdistan isn’t recognized as a country yet by anyone, but it exists in all but name.

Canadian-listed Western Zagros Resources Ltd. (WZR-TSX) had arranged a security pick-up for me at the airport in advance of their three day property tour, which was attended by 20-some fund managers, analysts, key shareholders and me.

Driving out of the airport, the two gentlemen taking me to my hotel did a quick left turn into a parking lot, where the front passenger, clearly the boss, strode into a trailer, and returned two minutes later checking and holstering his pistol.

No pistols allowed at the airport. I thought that was a good idea.

Security was never an issue for me while in Kurdistan, though their April 2012 property tour was cancelled due to an unnamed security issue. WZR has a full time security staff of at least three ex-pats and hire over 100 local Kurds who are part of their police force to patrol and watch their sites.

One of the speakers Zagros had come in to present to us was an ex-American diplomat who now was helping broker energy deals in Erbil, and was a geopolitical expert. He said he and many other expats walk around the city free of fear, and hang out drinking in the bars in the evening.

The drive to the Rotana hotel was a surprise for me-we drove by several new gated communities (which are titled English Village, Italian Village, American Village, etc.) — very modern and neat.

The amount of construction said how much and how fast this city is growing. There is a large number of buildings in various states of construction, though some looked stalled. But there is a lot of money pouring into Kurdistan-almost all of it because of oil.

A lot of it is Turkish money. Turkey wants an independent Kurdistan. They have their own disgruntled terrorists/freedom fighters wanting their own Kurdish break-away state in eastern Turkey. Now they can tell those Kurds to quite fighting and go home. So they are giving soft help to Kurdistan. And now the first Kurdistani oil is leaving Iraq via Turkey-infuriating Baghdad.

And a lot of the money coming into Kurdistan is black market Iraqi money. There are obvious strains between Erbil and Baghdad as Erbil tries to become a breakaway independent state. There is corruption in both places, but it’s on a much larger scale in Baghdad. These people have few places now to launder the money they skim off contracts etc…..so they put their ill-gotten gains into Kurdistan.

The hotels have a rudimentary form of security, where you must pass through an airport style gate and get patted down with a wand if you set off the alarm. From my 8th floor room that first evening I had a great view of a HUGE city park-with trees!-across the street, with the core of the city in the background beyond.

Driving out the next morning, I was told that the reason I didn’t see a lot of trees in the countryside around there was that deposed Iraqi dictator Saddam Hussein just burned the ground so the Kurds couldn’t hide. And in 55 degree Celsius summer heat, not much grows back.

That next day we all piled into a big bus-with two internal security people on board-and headed out on a four lane highway down to Sulaimaniyah, the southern regional centre. It quickly turned into two lanes.

My first impression was that Kurdistan is a rocky country-almost prehistoric–especially in the north near Erbil. You drive past rocky outcrops for miles, then out of nowhere I would see tilled lines of rocky soil for literally just tens of metres, then more rock. Mountain ranges jutted straight up out of the valleys.

October is the end of the dry season, and the land was all shades of brown-and none of it made for rich looking soil. I grew up in a farming community southwest of Toronto, and I have an idea of what good soil should look like. This wasn’t it. Evidently they had a drought last year and in a lot of places, didn’t even bother trying to taking the crops out of the field.

Driving south to Suli, about an hour south of Erbil, Zagros’ staff told us to look on the other side of the road to see…a pile of rocks. But that pile of rocks is where a Kurdish village used to be before Saddam Hussein brought in bulldozers and backhoes and demolished it. He did this to over 1400 Kurdish villages and displaced tens of thousands of people.

We stopped just a few miles past that abandoned village and looked across to a far mountain range to view London-listed Genel Energy Plc’s, 75,000 bopd Taq Taq operation. It’s the largest Kurdistan producer-and all their production is trucked by over 300 trucks a day to a pipeline. That’s a lot of trucks for those skinny roads.

And it’s an example of how the booming oil sector here is both straining and funding this semi-state of Kurdistan. Other than some sections of the main highway, the roads, bridges and tunnels are all narrow, and get quite windy in the back country. With the economy booming, all the truck drivers are in a hurry and there is no Ministry of Transport-no licenses, brake checks, etc.

Our second stop was just the other side of a mountain range-where we drove up tight switchbacks behind, and then passed, an oil tanker. It was not a road I would want to go up in December, when the mountain passes are icy.

On the other side we could see the Zagros Mountains…where at one point in the last century, 10% of the world’s known oil resources were located. Looking south towards Sulaimaniyah, the mountains stood straight up out of a valley, and narrowed to jagged peaks. It had a stark beauty-like I said, almost pre-historic.

Of course, Zagros staff talked about it being of this and that geologic age belonging to this and that western company and how hard it would be shoot 3D seismic or drill it…it all turned into a foreign language when you stare down the valley.

The valley down to Suli was more fertile than up near Erbil, and it’s a drive I would really like to do in April, at the end of the rainy season, when the crops are ready to be harvested. Because when I was there, you really had to use your imagination to think what all that flat brown rocky ground could really look like with some moisture. Even the tilled lines of soil had LOTS of rocks.

(I did a lot of stonepicking myself in my teenage summers so I can understand wanting to leave them in the field. But this is the cradle of civilization-6000 years of stonepicking should have done a better job than that ;-).)

Suli is booming as well, but not as much as Erbil. The hotel we stayed at had only been open for a short time. While the food was good, the tap water wasn’t. It was the only place I’ve ever been to where I gagged after I brushed my teeth. Even after boiling it in a kettle I had to immediately spit it out.

Next day, during the three hour drive even further south to their Sarqala-1 well site, I again had to use my imagination to see how all these fields of stones I saw would support crops. But then you would cross a bridge over a “wadi”-now an empty, gravel river bed, but in winter it’s where the torrential rains drain into and create a rushing river.

We were on a plateau in the valley, with mountains on other side but you could see for 15 km down the valley floor to the east, where that mountain range rose up to the Iranian border.

Everyone on the bus looked at it like it was Mordor, House of Sauron, from Lord of the Rings. It’s funny how we get politicized.

As a segue, I met one of Zagros’ staff-an Iranian-at a “social club” in Suli on the last night-an engaging young man with two kids and wife in Iran. He commutes to Suli on a work rotation same as everybody does from the UK or Canada-four weeks in, three weeks out.

I asked him if him working here in Iraq/Kurdistan caused him any issues. He said no, that it’s just the government that everybody hates-the people actually all get along. He said he’s worked in other MENA (Middle East North Africa) countries and never had an issue with anyone, and no one ever had had an issue with him or his nationality. It was so refreshing to hear that people are people, and only governments are jerks.

The Sarqala-1 wellsite was just a big, flat piece of nothing where they had put up a compound holding many trailers to accommodate everyone. The onsite Kurdish security people stayed there, along with the expat staff that rotated in and out.

Security is treated very seriously here. They have been shot at in the past; no injuries. They built a large berm around the compound (the actual wellsite is 500 metres away) and there were three cement bunkers with sandbags covering them in case of attack.

But there isn’t much to do around there when you’re not working. No internet, TV etc. The nearest town, Kalar, doesn’t have anything like bowling lanes or that kind of entertainment. It’s a small group of expats there for 35 day rotations. You have to be a certain kind of person to live like that-even if it’s just for 35 days. (Then imagine doing it in their heat!)

There’s not much to see at the Sarqala wellsite itself-pipes, tanks and one unloading facility. There are elevated guard posts on the immediate hills around the site where contracted local security stare out at…nothing…all day. The visually exciting stuff is when the rig is on site.

The village right beside the wellsite has clear signs of prosperity-a few new and colourful homes made of cement blocks, not the regular mud bricks-all thanks to wages earned by working for Zagros. I wondered what people did in these villages, but it turns out that most people have a house in Kalar as well, where they work, and then also have the home place in the village where they grew up.

The next day we drove around the countryside, up to a viewpoint where we could see the Kurdamir-2 well. As I said, Talisman was testing the well so we weren’t allowed in. The backroads on this trip took us past some stunning mountains with gorgeous vistas into the valley where K-2 was being drilled. This is where I was impressed with the fresh pavement and new telephone polls and colourful homes in an area that was far away from everything. Booney-ville.

It’s a good sign when prosperity is reaching out that far into the country.

by +Keith Schaefer

Editor/Publisher
Oil and Gas Investments Bulletin

 

The “Water Alchemists” in the New Wild West

By
1940bkg
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0

Dear OGIB reader,

A 21st century wild-west scenario is developing in Texas.

It all has to do with the fast-rising use of water in the Lone Star state’s energy patch.

There are two “Sheriffs” – state and national regulators – each with conflicting ideas.

And that means the townsfolk—all the oil and gas producers—are spending money like crazy to make sure they’re protected against any future dust-ups.

That’s great news for the growing cottage industry of water disposal, treatment and recycling service providers—and their investors.

“In my mind, we’ve seen this as the Wild West. And it’s probably similar to the early days of the internet, and the technology boom of the mid-to-late 1990s,” says Michael Dunkel, Director of Sustainable Development for Pioneer Resources [PXD: US].

“There were thousands of little companies just starting off. Now this is not the same trend, but it is the same process. But there are plenty of companies out there right now trying to cash in on this big opportunity to treat water.”

Expected to be the #3 driller of oil and gas wells in the United States this year—almost all of which are in Texas—Pioneer needs a lot of water.

“Water is the gold of the future,” says Keith White, Director of Environmental, Health and Safety for Chaparral Energy, a private company focused in Oklahoma and Texas. “The commodity of oil and gas, and energy production in general, is impossible to produce without an adequate supply of water.”

“So as long as you’re able to recycle it to the best of your ability, and have a good business model free of environmental issues, then it’s a long time growth possibility.”

Says Dunkel: “We’re going to need a whole lot of water for completions, frac jobs, and even some in the drilling process itself. We get a large percentage of that from ground water, while some is supplied from surface water… but not a whole lot.”

The issue over who owns the rights to Texan surface water is still ongoing. One recent court ruling stated that a landowner can do whatever they want with their surface water; while another government body claims a goal of trying to plan the entire state’s water use for the next 50 years.

No matter who is in charge of it, the water business in the oilpatch will continue to grow—and fast. The water treatment companies are the ones who stand to benefit the most, says White.

“In Oklahoma, Texas and the rest of the southwestern United States, almost every one of the service providers who can provide water supplies from treated water, you can call ‘alchemists’ ” — alluding to the mythical practice of turning everyday materials into gold.

“These are the people that will try to produce units that will take produced water and clean it up to a level that can be reused for fracking.”

These alchemists are indeed spinning water into gold.

THE WATER ALCHEMISTS

“Texas and New Mexico are very ready for us, very open for business,” says Tony Ker, CEO of Ridgeline Energy Services (RLE-TSXv; RGDEF-PINK), which uses an electro-catalytic technology to treat water that has been used in fracking.

“The key thing they (the public) don’t like is the fracking chemicals, and that’s the easiest thing for us to treat.”

Ker says “flowback” water—water that has been used for fracking—is a potentialwater supply source. The industry presently pays to send all of it down a well called a Saltwater Disposal Well (SWD). Now, companies like Ridgeline can treat that water and and sell it back for reuse to the industry.

“If the patch pays 80 cents a barrel to dispose of water, we’ll do that. We get can get paid to take water in, and get paid to send water out—and we’re a one stop shop. That’s what we’re going to do for of the Kerr Energy facilities. Our goal is they won’t have to spend any more than what they are now spending, be environmentally friendly (by recycling water), and allow E&P companies to get water so they can drill.

“We can recover up to 80-90% of the water—so only 10=20% goes down the well.”

Charles Vinick is CEO and Chairman of Ecosphere Technologies (ESPH-OTCBB), is one of the largest water recyclers in the oilpatch, with revenue growing from $1.76 million in 2009 to $8.96 million in 2010 to $21.09 million in 2011 and the company is providing guidance for $28 million in 2012.

He says Texas is the place to be.

“We are mostly in Permian basin. The demand (for their services) has been in Texas since our first unit.”

Vinick says economics are driving the burgeoning water industry as well as the regulatory side.

“The pressure on the entire industry is to reduce overall costs per well—trucking, chemicals, increase the mixture of recycled flowback water into future wells—to keep costs as efficient or low as possible.

“We really see an advantage in drastically reducing or eliminating disposal costs. We allow for the lifecycle of water to be extended and used over and over again in operation, as opposed to using that water resource only once—we provide customer with both a cost and environmental benefit.

“It’s the economics of things that drive decisions — regulations are likely to be made on a regional basis and water use may be a part of some regulations going forward, but at this point we find that operators are making decisions primarily on cost and efficiency metrics. Saving and reusing water is one of the metrics we increasingly see them considering.”

But there is concern on future regulatory issues.”

Dunkel isn’t totally convinced: “No company will save enough money by recycling for it to be an economic driver. If they can save a little money, it’ll ultimately be insignificant to their bottom line.”

EVEN TRADITIONAL WATER SERVICES WILL SEE INCREASES

But it sure adds to the bottom line of the water service companies—even the traditional companies that operate SWDs. SWDS must be licensed, and with all the controversy surrounding SWDs causing earthquakes, it will be more difficult for the industry to license more wells—and therefore make current SWDs more profitable for the SWD owner. New SWDs have been banned in some areas of the southwest.

“Salt water disposal (SWD) is how we get into a new market,” says Jonathan Hoopes, President and Chief Operating Officer of Greenhunter (GRH-AMEX). “Often the biggest barrier to entry into a new location is owning your own SWD wells. We like to market our SWD services first, and then add the other services we provide on top of that as a value-add for our customers.”

Depending on the area, the price for water services can differ. For instance, Greenhunter was fetching $2.50-$3.50 per barrel of water injected in Appalachia, over near the east coast of the US, while in the Eagle Ford of Texas it’s between $0.60-$1 per barrel.

But the scale of the Eagle Ford is much larger. The top end for pricing in Ohio for some disposal wells get $4-$5 per barrel, but can only handle 2,000-3,000 barrels a day capacity. A West Texan counterpart can take on upwards of 10,000-20,000 barrels a day.

Greenhunter’s latest SWD injection facility cost approximately $2 million. At an average of $0.80 per barrel, and 10,000 barrels a day, it’ll only take 250 days to pay off with gross earnings, which would nudge the overall payoff period to be just under a year.

OIL AND GAS PRODUCERS WANT TO DO IT RIGHT (even if they don’t save any money)

Even if the economics are marginal for the producer, they see that doing the right thing allows them to avoid the gunfire of overzealous government agents.

It’s a mistake learned from the previous aggressive drilling of the Barnett Shale in years past, which saw companies brazenly drilling right up against people’s back yards in the Dallas/Ft Worth area, and made local residents uncomfortable.

Says Dunkel: “I think it’s because of the learning experience of what happened in the Barnett, that industry now realizes that it can’t just do whatever the regulations say is admissible; but that they need to go beyond that, in order to make sure that they have the support of the community for their operations,” referring to the aggressive drilling near residential zones, despite being well within the bounds of the law.

“One of things I think is worth putting into context is that all of this has happened so fast, if you think about a legal regulatory front. They went from whatever normal was 10 years ago to now where there’s shale everywhere that’s getting developed. It’s going to take a while for the more prudent regulations to come into place. That said, it’s not like we’re not regulated enough now as it is.”

Mixed signals from water regulators, combined with a need to keep production affordable has left an open range for water service companies to shine. There is a lot of land still left to drill, and a lot of thirsty rigs and frackers that will need water to get the job done.

“Even though today there is not a lot of water treated in Texas, there will be. There’s a whole lot of opportunity out there. You have a whole lot of companies that see that, and are going for it,” says Dunkel.

“There will be a process where some of them win and develop great mechanisms and a great product, along with a great reputation. Twenty years from now, you’ll end up having a handful providing 90% of the water treatment, probably.”

by +Keith Schaefer

Canada Denies Petronas: A Catch-22 for LNG Exports

By
1940bkg
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0

What will happen to junior natural gas stocks in Canada on Monday, following
the Canadian government’s denying Malaysia’s Petronas bid to acquire
Progress Energy (PRQ-TSX)?

A couple days of mild downside is my guess.  Don’t get me wrong-Progress
itself will be down 30% or more (the only good news here is that it’s the
arbitrage funds getting killed Monday, not retail or the regular Canadian
institutions).

But the junior gas stocks I follow (under 20,000 boepd–stocks like
Bellatrix (BXE-TSX), Angle Energy (NGL-TSX) etc have been rising because the
market sees a year-over-year storage surplus eroding quickly, and is hopeful
on better fundamental natural gas prices this fall and winter.  They haven’t
been going up on takeover speculation by anybody-another intermediate or a
major or a foreign company.

Certainly, stocks that are considered take out targets by The Street for
their gas-Painted Pony (PPY-TSX), Peyto (PEY-TSX), maybe Tourmaline
(TOU-TSX) and the recently announced deal of Celtic (CLT-TSX)-could have a
bit more of a dip.

These are the stocks that hold enough liquid rich natural gas in Canada that
they could have been bought out by foreign companies looking to cash in on
Canada’s short shipping lines to Far East LNG customers like Japan and
China.

However, there won’t be anybody looking to buy them out now-at least for
awhile.

The Harper government in Canada was deliberately vague about why the deal
was canned, and rumours focus on two points:

  • they didn’t want to give the same tax breaks Progress was getting to a foreign NOC
  • now they can nix the Nexen acquisition by the Chinese NOC and it appears fair

I certainly don’t know.  But I do know that natural gas is being discovered
everywhere these days in huge quantities-offshore Tanzania and Mozambique,
offshore Australia, onshore Australia-unlike oil, shale gas does not have a
monopoly on new big global supplies.

There is a race-worth tens of billions in infrastructure spending (read:
jobs for pipelines and Liquid Natural Gas (LNG) processing facilities) and
more tens of billions of dollars in sales of natural gas to the Far East.
And the Canadian industry does not have the capital or frankly, the
leadership in industry or government to make this happen.

There are no federal politicians sticking their neck out saying LNG or bust
to Canada’s west coast. All the big LNG proposals in Canada are spearheaded
by foreign companies-Shell (RDS-NYSE) and Apache (APA-NYSE), for example.
Petronas would have been the third-and maybe still could be, if the federal
government can tell the market why the deal was cancelled and what they can
do to have it approved.

The Canadian government, led by Stephen Harper, should hurry up however.

Canada has fallen behind in this race incredibly quickly.  Earlier in 2012
there were three proposals to get LNG to Japan by December 2015.  Six weeks
later the participants said 2017.  Now they’re saying 2019 or 2020.   Five
years went by in just six months.

There are two strikes already with Canadian LNG potential:

1.       Japan wants to de-link natural gas prices from oil (which are now
accepted to be roughly 13% of Brent) and Cheniere’s (CQP-NYSE) willingness
to do that.  I think that is a big reason that the Canadian proposals have
had a hard time getting firm contracts and moving back their timelines.
Forget the fact that the US hasn’t even allowed LNG exports yet.  The market
sees the potential for lower gas prices going to Asia than Canada might be
willing to sell for.

2.       Potential Regulatory and public opposition to an LNG trade on the
west coast.  The provincial BC government has issued permits for LNG
exports-but environmental groups, native groups, and now the provincial BC
government are taking a very hard line on the Enbridge oil pipeline to the
west coast.

As the process moves forward, it would be difficult for them not to give the
same scrutiny to LNG tanker traffic on the west coast.  Even the province of
BC, which has been very vocal in favour of LNG, will have to do lots of
studies and talk the talk on LNG tanker traffic being safe in narrow BC
coastal waterways.

And now, add Resource Nationalism as #3.  Canada has put itself in a
Catch-22-Canada needs foreign capital to capture the booming Asian LNG
market, but it won’t approve foreign capital so Canada can’t capture the
Asian LNG market.

The feds canned the deal even after Petronas publicly increased their bid in
the face of a mystery second bidder that was allegedly behind the scenes
ready to compete (rumoured to be Shell).

I hope the Canadian feds can show the market a clear plan for what they want
to see in a foreign takeover of a Canadian natural gas producer-otherwise
this could be the third strike for Canadian LNG exports.

PS-this issue won’t affect my favourite junior gas producer. That’s because
it has a silver bullet-from both a geological and market perspective-that
makes it THE junior gas play to own in 2013.  My full report should be ready
late next week.  The good news is, its’ share price will likely go down in
sympathy when the fundamentals remain incredibly strong.

by +Keith Schaefer

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