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Elliott Gue

 
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  • Why Linn Energy Is Not A Ponzi-Like Scheme [View article]
    Linn Energy (LINE) has NOT cut its distributions. The partnership has simple switched from a quarterly distribution to a monthly distribution but pays the exact same $2.90 per year.

    As I have argued in several posts on SA and elsewhere in recent months, the author is quite right in indicating that the arguments from the short sellers concerning Linn are deeply flawed.
    Jul 9 05:06 PM | 36 Likes Like |Link to Comment
  • Mounting Evidence Suggests Linn Energy LLC Is In The Clear [View article]
    Not much changes actually.

    First, the vast majority of Linn's production is hedged for 5 years in the future at prices much higher than that.

    Second, the Berry acreage they're acquiring is in California where oil prices are tied to waterborne markets like Brent, not the WTI prices you reference. Brent is currently at over $105/bbl.
    Nov 4 04:11 PM | 8 Likes Like |Link to Comment
  • Australia: What Recession? [View article]
    Thanks for all the great comments -- these are what make Seeking Alpha such a useful website. Obviously there are some parallels to be drawn between Canada and Australia in the sense that both have significant exposure to natural resources and commodity prices.

    But my colleagues David Dittman and Roger Conrad, recently pointed out to me that while China’s share of Canadian trade has tripled since the mid-1990s, only 2 percent of Canadian exports went to China in 2007, while nearly 80 percent went to the US. Canada’s foreign direct investment (FDI) in China is 0.3 percent of its total FDI, while China’s FDI in Canada is just 0.1 percent of its total.

    While Canada has more China exposure than these figures would suggest thanks to China's influence on commodity markets, Canada's biggest trading partner is her southern neighbor. Australia has a much bigger direct trade relationship with China and the rest of Asia. To me, that makes Australia a purer play.

    Elliott
    Nov 17 06:35 PM | 8 Likes Like |Link to Comment
  • Master Limited Partnerships for Your Portfolio: Three Key Questions and Answers [View article]
    Thanks for all the great comments. You are quite right to point out that incentive distribution rights (IDRs) are an important consideration when investing in MLPs. I do think a few additional points are worth noting about MLP's GP/LP relationship.

    First, I do think IDRs incentive the GP to act in the best interest of the LP holders. The reason is that IDRs are based on the amount of money paid out to LP holders -- the split with the GP increases only when the payout to LP holders rises. In most cases, the GP will totally forfeit any IDR if a certain minimum distribution isn't met.

    Second, while you are absolutely correct about the high split set at 50% for most MLPs and 25% for EPD, the calculation is a bit more complex than straight multiplication so the actual percentage take is not as high as that. Rather than bore readers with a lengthy comment, I'll try to post a blog in future with the exact calculation details. For now, suffice it to offer an example: Enterprise Products has a high split of 25% but in the first quarter of this year, the company paid a distribution of 53.75 cents to LP holders and just 9.22 cents per unit to the GP.

    Third, there are some alternative partnership structures that do not have a GP/LP relationship. An example is Linn Energy (NSDQ: LINE), a limited liability company (llc). Linn is taxed similarly but has no IDR structure.

    Fourth, it is extremely important to look at exactly who the GP is for a particular MLP and how capable they are of supporting the partnership in bad times. For example, last autumn Richard Kinder who controls Kinder Morgan's (NYSE: KMP) GP stated that he and the GP would step up with additional cash needed to fund expansion if credit markets remained constrained. And some MLP GPs are actually energy firms with assets they can "drop-down" to the MLP when times are troubled to shore up cash flows. On the other side of the coin are GPs controlled by private equity firms that may be overly reliant on debt.

    Fifth, you can actually play the other side of the IDR coin if you wish -- there are a handful of publicly traded GPs that are taxed like MLPs. Enterprise GP Holdings (NYSE: EPE), GP for Enterprise Products Partners, is one example.

    On Aug 30 04:17 PM Uncle Pie wrote:

    > When investing in MLPs, be aware of the "incentive distributions"
    > paid to the general partner. Most MLPs have a provision that once
    > the distribution per share rises above certain levels, the general
    > partner is entitled to a larger percentage of the cash flow. After
    > a certain point is reached, the "incentive distribution" often maxes
    > out with an extra 50% of the cash flow going to the general partner.
    > This is referred to as the "high splits". Some MLPs, to their credit,
    > have capped the incentive distribution at 25%. Enterprise Products,
    > EPD, referenced in the article, is an example of an MLP with a 25%
    > max. It's all in the prospectus, but you should know that when you
    > invest in a "high splits" MLP, you are basically putting up 100%
    > of the capital for 50% of the return. The author owns units of EPD
    > and several other MLPs. The author was pleased with the performance
    > of his MLP securities during the recent market meltdown relative
    > to many other holdings!
    Aug 30 07:05 PM | 8 Likes Like |Link to Comment
  • Near-Term And Intermediate-Term Outlook For U.S. Natural Gas Prices [View article]
    Louisiana gas production WAS is decline prior to late 2008 and early 2009. Consider that in August 2008 the State's gas production was about 120,788 million cubic feet. When it hit its highs in late 2011 production was over 275,000 million cubic feet. So, that's more than a double in just three years.

    The EIA changed the way it reports Louisiana gas production in 1997 (started breaking our production from the Gulf of Mexico). But, late 2011 Louisiana gas production was likely at least a two decade high, hardly a characteristic of a State with production in "terminal decline."

    Since late 2011 Louisiana gas production has backed off to around 200,000 to 220,000 million cf per month. But, that's not really because producers can't increase production it's because they don't want to at current low gas prices -- the rig count in the State has dropped from a high of about 220 to a recent low of just over 100 (a two decade low).

    The largest shale field in Louisiana is the Haynesville, which is a dry gas field meaning that it doesn't have much natural gas liquids (NGLs) content. That means that producers with major acreage in the Haynesville just aren't drilling there and are deciding to target liquids-rich plays like the EagleFord in southern Texas or the Marcellus instead.

    If natural gas prices ever do rise over $5/MMBTU, I suspect you'd see drilling activity pick up again quickly in the Louisiana Haynesville and, given how prolific that play proved to be back in the 2008-2011 period natgas production would rise quickly to new highs.

    At any rate, the idea that Lousiana or US natgas production are in a state of terminal decline is just plain incorrect and has no support in the data.
    Jul 18 08:48 AM | 7 Likes Like |Link to Comment
  • Near-Term And Intermediate-Term Outlook For U.S. Natural Gas Prices [View article]
    I am not passing a death sentence on natural gas. Not do I lack enthusiasm for the benefits of rising American energy production; on the contrary, cheap energy prices are enabling a real renaissance in US manufacturing and represent a major advantage over virtually any other country around the world.

    Rather, I'm just saying that it will take a lot longer for gas prices to rise significantly again because the US faces a glut of gas. It will be years before a significant capacity of LNG export terminals will be constructed to move the needle on US gas. It will be even longer before the US makes a major switch to gas (or electricity for that matter) as a transport fuel.
    Jul 18 08:34 AM | 7 Likes Like |Link to Comment
  • Why Energy Transfer Partners Is Cheap: It's Complicated [View article]
    Thanks for the comment. Although it isn’t illegal to hold MLP units in a retirement account, we’re firmly of the opinion that these securities are better-suited for taxable portfolios.

    For one, we prefer to hold securities that offer no tax protections in a retirement account and keep our MLP positions in a taxable account to take full advantage of their tax-deferral characteristics.

    Also, some of the net income that MLPs allocate to their unitholders is classified as unrelated business taxable income (UBTI). Each taxpayer has a $1,000 total annual allowance for UBTI paid into a 401(k) or IRA account; annual UBTI over this threshold could incur a tax liability. However, many MLPs generate negative or modest levels of UBTI, ensuring that you likely won’t have to lose sleep over this issue.

    If you exceed your annual UBTI exemption, you don’t need to file any additional forms with the IRS; the custodian of your IRA or 401(k) is responsible for filing a Form 990 and paying the tax out of your account’s funds. Most investors find that the above-average yields offered by MLPs more than compensate for any UBTI-related taxes.

    Some investors avoid these problems altogether by purchasing a close-end or exchange-traded fund, neither of which produce UBTI. These investment products also disburse normal, qualified dividends to their shareholders and report these payments on a Form 1099, eliminating any vexation that might arise from dealing with the unfamiliar Form K-1.

    However, these minor conveniences don’t make up for the biggest problem with closed-end and exchange-traded funds: portfolios that skew heavily toward names with the largest capitalization.
    Oct 18 12:23 PM | 7 Likes Like |Link to Comment
  • Why Linn Energy Is Not A Ponzi-Like Scheme [View article]
    Yes, both Linn (LINE) and Linn Co (LNCO) are switching from quarterly to monthly distributions and the payouts are identical. Both went ex-dividend on the 8th for their first monthly distribution.
    Jul 10 12:51 PM | 6 Likes Like |Link to Comment
  • Linn Energy: Don't Believe The (Negative) Hype [View article]
    A look at Note 7 in the 10-K reveals that Linn paid $583 million for put option positions in the year ended December 31, 2012. But it also states that these puts cover the period from 2012 through 2017.

    In 2012, spot natural gas hit a low of under $2/MMBTU in mid-April. But, even with spot and front-month gas prices under $2/MMBTU at the lowest levels in more than a decade, futures expiring in 2015, 2016 and 2017 were trading at much higher prices.

    Using April 19, 2012, an extreme low for spot gas prices, I see that NYMEX gas futures expiring in April 2015 were trading at $4.15, futures expiring in January 2017 more like $4.75/MMBTU. And this was the case if one had tried to hedge on the very day that natural gas prices hit extreme lows.

    Those claiming that Linn is purchasing "in the money" put options fail to recognize that there is a big difference between the spot or prompt price of natural gas and the price of natural gas to be delivered 2, 3 or even 4 years in the future. A look at the five year average futures prices is a far better guide of what's in the money for a company looking to hedge production over a multi-year period.

    So, let's take a closer look at these numbers. According to their 10-K covering the year ended 12/31/2011, Linn had puts covering total volumes of 30,660 due to expire in the year 2014. The average hedge price on those puts was $5.50. By the end of 2012, they had put hedges covering 79,628 MMMBTU due to mature in 2014. The average price on that entire position was $5/MMBTU.

    So, just doing the maths suggests they hedged around 48,968 MMMBTU of 2014 gas production volumes over the course of 2012 at a price of roughly $4.69. This certainly doesn't suggest they're buying deep in the money puts to manufacture earnings; there were several occasions in 2012 when 2014 NYMEX futures prices were trading well above $4.50/MMBTU.
    May 9 04:16 PM | 6 Likes Like |Link to Comment
  • Profiting From A Second Golden Age For Refiners [View article]
    The intent of the article wasn't to detail every cost a particular refiner faces in converting crude into gasoline or diesel fuel but to explain the Crack Spread and the basic way refiners earn their profit. Crack spreads are the single most widely watched fundamental when it comes to the refining sector and if you plot a particular refiners profit margins against the crack spread you will find that they correlate nicely. Ignore them at your own peril.

    Moreover, the costs you mention such as transport, storage, labor etc aren't as relevant to an analysis of these companies. That's because these costs are smaller than the cost of feedstock, tend to remain relatively constant over time (certainly less volatile than oil prices) and would tend to be similar for refiners in a particular region of the country.

    When I analyze a sector or a particular stock, I tend to try and identify which fundamental factors catalyze movement in those stocks over time. In this case, the crack spread is far more important than labor costs.
    Dec 28 04:03 PM | 6 Likes Like |Link to Comment
  • GeoResources: One Of The Stronger North American Shale M&A Targets [View article]
    Thanks for the comment. I agree that debt is an important consideration in evaluating companies.

    I would also say, however, that investors need to look at more than just the total amount of debt a company has, also examining what type of debt they have and their maturity schedule. For example, a lot of companies got in trouble back in 2008 and early 2009 not because they had too much debt but because they had too much relatively short-term debt in the form of credit lines with banking groups. In some cases the interest rates on this debt was indexed to LIBOR, a huge problem when the interbank market ground to a complete halt and rates spiked to unprecedented levels. If you had a credit line to roll over in late 2008, you were probably in dire straits.

    Other companies had issued long-term bonds during the strong credit market environment of 2004 to early 2007, locking in fixed, low rates and extending their maturities out 10 years or more.

    One example of a company I follow that learned its lesson about shorter term debt during the crisis is Linn Energy $LINE. They have been issuing 10-year debt at really attractive ultra-low rates to fund acquisitions.

    Disclosure: I am long LINE
    Jan 28 01:27 PM | 6 Likes Like |Link to Comment
  • Overcapacity In The Oil Services Industry? What You Need To Know [View article]
    I'll try. I've written about the major US unconventional oil and gas fields on a few occasions for Seeking Alpha. To summarize, unconventional fields popularly known as "shale" fields are the hottest oil and gas-producing plays onshore in the US right now. To be produced economically, companies use a combination of horizontal drilling and fracturing (pressure pumping) techniques.

    The first of those technologies is self-explanatory. Fracturing involves pumping a liquid into the reservoir to literally crack the reservoir rock that contains the oil or gas. This aids the flow of oil and gas through the reservoir and into the well.

    Not all of the US shale plays are the same. The Haynesville Shale in Louisiana is a "dry gas" play meaning that what's produced from wells in this field is primarily methane (natural gas). In contrast, the Bakken Shale of North Dakota is mainly an oil play as these wells produce crude oil mixed with a bit of natural gas and significant quantities of so-called natural gas liquids (ethane, propane and butane are the most common NGLs).

    The Eagleford of South Texas produces mainly oil in the northern window, wet gas in the middle part (methane plus lots of NGLs) and mainly dry gas in the lower reaches of the field.

    Crude oil prices are quite elevated right now with brent trading well over $100/bbl and West Texas Intermediate in the upper $90's per barrel. At those prices, as you might expect, producing oil from unconventional onshore fields is tremendously profitable so producers have been drilling like there's no tomorrow in fields lie the Bakken.

    Meanwhile, natural gas prices are depressed and have been averaging in the $3.50 to $4.50 per million BTU range for some time. At those prices, it's not profitable to produce gas from many of the dry gas fields in the US. So, activity in places like the Haynesville Shale is moderating.

    Meanwhile, a barrel of natural gas liquids (NGLs) tends to follow the trend in oil prices more so than the price of natural gas. So, NGLs prices have been robust this year. That means if you have a wet gas field--gas with NGLs--you can produce wells profitably because the value of the NGLS found in the raw gas stream is high.

    I am often asked why producers keep drilling "gas" shale fields with gas prices so weak. NGLs are one of the major factors driving this seemingly paradoxical behavior.

    My quote above is referring to the fact that if a service company is performing work in a region known for oil or NGLs production (ie the Bakken Shale or parts of the Eagleford) they're still raising prices to perform services. That's because activity is still strong in these plays.

    In contrast, as activity in gassy plays slows down, services companies are losing their pricing power for services performed in regions like the Haynesville.

    I hope that helps.
    Nov 18 02:35 PM | 6 Likes Like |Link to Comment
  • On EPS and MLPs [View article]
    Thanks for the comment. There are refineries in the US that have been in operation for a century, long beyond what would be considered the useful life of such an asset. However, over the years, every piece of this equipment has been replaced and upgraded, likely several times.

    To use your example, the effect would be the same as you replacing every part of your car gradually over time including the body itself.

    Maintenance expenses from an MLP are designed to reflect normal replacement and upgrading of equipment surrounding the asset over time. It's likely that these pipelines will not be replaced if, by replacement, you mean totally dismantled, scrapped and rebuilt.

    Adding back depreciation and then factoring in a maintenance expense that reflects the need for ongoing replacement and upgrading is the most relevant measure of an MLP's earnings power in my view. Of course, as I noted in the article, one has to account for the reasonableness of the maintenance expenses the particular MLP uses to calculate DCF.


    On Nov 01 02:07 PM Karl Glazier wrote:

    > By adding back depreciation, aren't you assuming the assets will
    > never have to be replaced?
    > If the assets are depreciated over a shorter period than their expected
    > life, an adjustment should be made accordingly.
    > But adding back all depreciation is not reflecting reality.
    > If I am counting only the maintenance expenses on my car, I am fooling
    > myself.
    Nov 1 02:52 PM | 6 Likes Like |Link to Comment
  • The Real Price of Crude Oil [View article]
    While the articles concerning $20 or $40 oil referenced in the comment above contain some interesting points, I would be willing to take the other side of that bet. I am looking for oil to top $100/bbl in 2010 and possibly even challenge those '08 highs in coming years.

    Your comment makes a completely valid point. Basically, at $20 or $40, much of the world's production isn't economic. As global oil demand returns in coming months, the important point to consider is really what is the marginal cost of oil? In other words, what does it cost to bring an incremental barrel into production to meet demand. Reserves like the oil sands and perhaps deepwater would represent marginal barrels -- if production is to actually increase, exploiting these marginal barrels needs to be profitable.

    In its recent conference call Schlumberger (NYSE: SLB) made some interesting comments in this regard. It seems that the company believes oil prices will need to be around $70 at year end if production firms are going to have enough confidence to increase their capital spending budgets. At $40 they'd slash CAPEX plans and global oil production would fall off quickly. And if oil prices look to be too volatile they may also be reluctant to boost CAPEX.

    There is a very real risk that in 2010, the CAPEX cutbacks of late 2008, early 2009 will come home to roost in the form of falling production just as global demand re-accelerates. Then, you have the recipe for a real spike.


    On Aug 27 02:52 PM Donald Ingram wrote:

    > The US gets most of it's oil supply from Canada and most of that
    > comes from the oil sands where the cost of production is $60 to $70
    > USD per barrel. In the event of a down turn in oil to as much as
    > $40 USD per barrel, the amount of oil exported to the US from Canada
    > would suffer cut backs from the oil sands, instigating a short term
    > shortage, which would then have the effect of driving up prices at
    > the pump.
    Aug 27 09:22 PM | 6 Likes Like |Link to Comment
  • Updated Outlook For Crude Oil [View article]
    Not to put too fine a point on it but....

    The premium for California oil isn't due to the size of California's energy (or oil demand) but to a lack of sufficient in-State production, requiring the import of more expensive supplies from abroad.

    I didn't mention natural gas in the article because it was an article about the outlook for oil. I agree that natural gas is an extremely promising fuel long term but oil and gas aren't really substitutes for one another. Oil is a transportation fuel and natural gas is primarily a fuel used for heating and electricity production. The idea that natural gas will become a key transportation fuel in the short-run is unrealistic. Even Exxon Mobil, a company which made a $41 billion bet on the future of nat. gas when it purchased XTO, sees gas accounting for just 4 percent of global transport demand in 2040 compared to 1 percent today.

    Currently, the US imports about 500,000 barrels of gasoline per day and exports 375,000 for daily net imports of roughly 125,000 bbl/day. Since we use 9.3 million barrels of gasoline per day, US net gasoline imports account for 1.4 percent of supply so I think you're exaggerating the importance of cheap US gasoline imports.

    Finally, solar (like most alternative energy sources) isn't really a disruptive technology at all. Solar is expensive and completely unreliable as a baseload power source. The idea that solar (or wind or tide or any other "alternative" energy source) will supplant fossil fuels like oil, gas and coal for the foreseeable future is an unrealistic dream.

    Of course, that doesn't mean you can't make money buying momentum-driven alt energy names from time to time. But, the bigger longer-term opportunity is in efficiency and companies that are making the internal combustion engine more efficient. Also, groups like freight rail are benefiting as its cheaper from an energy perspective to move goods by rail than truck.
    Nov 13 05:37 PM | 5 Likes Like |Link to Comment
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