Natural Gas NG1
March 14, 2013 - 6:13pm EST by
2013 2014
Price: 3.83 EPS $0.00 $0.00
Shares Out. (in M): 1 P/E 0.0x 0.0x
Market Cap (in $M): 1 P/FCF 0.0x 0.0x
Net Debt (in $M): 0 EBIT 0 0
TEV ($): 0 TEV/EBIT 0.0x 0.0x

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  • Natural gas


I’m going to say something unusual: we’re not producing enough natural gas. Don’t let the 3-handle fool you, we’re simply not producing enough. The price of gas is going to go a lot higher in the next 12-24 months and I think investors will pile back into this trade. We are at the inflection point.


Let’s start with the supply picture since that’s what most people focus on. Unless you’ve been living in a cave you’ve probably heard about shale gas. It’s kind of a thing these days. With an abundance of resource, the capital in place, and the incentives to produce it, the industry nearly drilled themselves out of business between 2008-2012. All it took was one warm winter to send prices to $2 and scare everyone half to death. But it turns out that $2 gas was a blessing in disguise. Just like how $145 oil forced airlines to get religion and raise prices and charge extra fees, $2 gas forced E&P’s to drastically reduce drilling, to the point where production didn’t just decelerate but decline…very big distinction here.


So what’s happened since gas hit $2? Companies have dropped rigs, either stacking them or moving them to oily plays. They haven’t tip-toed into it. Since fall of 2011, the gas rig count is down 60%. There haven’t been this few rigs drilling for gas since 1999, but we’re still not seeing the full effects of this yet. With oil and gas drilling there is always a several-quarter lag between changes in the rig count and seeing the effects in production. It takes time to complete drilled wells and hook them up to the gathering system. This is the “flash-to-bang” phenomenon that you experience with lightning – you see the flash, but you don’t hear the thunder for a few more seconds. Most states are now in decline. Even Texas is declining…this is the state where gas production is booming with the Eagleford Shale (even if it’s not the desired resource) and it’s still showing annual production declines. The only places where gas production is actually rising are Pennsylvania (Marcellus Shale), Ohio (Utica Shale), and Oklahoma (Miss Lime). The Marcellus is the big outlier in the country, it’s ridiculous how much gas is coming out of it and how good the wells are. Luckily it’s still somewhat infrastructure-constrained so there is a lid on the growth.


The issue today is that many people are skeptical whether we’ll see large production declines despite the drastic reduction in rigs. This is exactly what happened in 2009, and I encourage anyone to re-read my old CHK writeup for a little background on what happened there. In 2009, the gas rig count declined from 1,600 to 700, but unfortunately this occurred during the peak of technological improvements in drilling and completion, so the rig decline was more than offset by efficiency gains. With these wounds relatively fresh, it’s hard not to blame investors for being skeptical in 2013, but I think there are some reasons to be encouraged that the production response will be real this time around:


  • Technological advancements have tapered off in most basins.  The major leaps in fracking have already occurred, so improvements are no longer on hydrocarbon recovery as much as drilling locations and cost management. Drilling longer laterals or employing larger frack jobs is no longer leading to incremental returns…in many cases it’s actually leading to declining economics. A look at Southwestern Energy (SWN) is a good case study. Southwestern has been active in the Fayetteville Shale since 2003 and they’re one of the industry pioneers for fracking. Despite being extremely well run and very creative on the engineering side, Southwestern hasn’t been able to show any kind of meaningful recovery efficiencies since 2009. Wells still cost about the same, but they’ve clearly hit a wall in terms of optimization. Other operators say the same thing about most other areas, although I admit there are still a few basins such as the Utica and Marcellus that are showing meaningful improvements, although many people believe that’s merely because of the rock quality rather than technology.  The point is, this time around I don’t believe the industry will be able to offset a lower rig count with production efficiency gains. 
  • Most importantly, E&P companies are no longer guiding to higher capex budgets and gas production. Contrast this with 2009 when everyone predicted huge declines in aggregate production while virtually every E&P was guiding capex and production higher. By my count, E&P onshore capex budgets will decline 10-12% in 2013, although commentary from management teams suggests that the portion of capex directed at gas plays will decline much more. The same companies I’ve polled are expected to show about a 1% decline in overall gas production. This is the same analysis I used in 2009 when I said that gas was going lower.
  • The rush to hold acreage by drilling wells (HBP) was a major problem in 2009-2011, but it’s irrelevant today. After the insane land grab in 2008, companies were in a hurry to drill a bunch of wells to ensure that they didn’t lose the leases. Most of that drilling was uneconomic. It’s hard to say how responsible this industry-wide issue was for excess production, but I believe it played a large role. It’s a thing of the past.


The main question people will ask is if prices rise, wont the industry throw more capital at gas plays thereby sending prices right back down? This is a complicated answer and I think the best response is yes, but not enough to send prices back into the $3’s. What’s different today is that every E&P has both gassy, oily, and liquids plays in their inventories. The margins on the liquids and oil are still considerably better than the gas, so those gas fields are still competing for capital with much better projects. Then there’s the issue of whether managements will really want to tell the market that they’re going to allocate more capital to gas versus an oily project. Encana did this last month when they said they would add another rig to the Haynesville and they got absolutely crushed because of it. I think it’s a solid warning to management teams – accelerate your oil/liquids projects before you allocate more capital to gas. Besides, they’re all outspending cash flow anyway, so I’m not sure where the extra capital would come from. Foreign JV’s for gas assets are basically dead, although there might be one or two Marcellus deals possible. Since all the E&P’s now have an additional lever to pull, I don’t think the response will be large. A few rigs will get added here and there and it’ll make for lousy headlines, but it wont be nearly enough to arrest the decline and push prices much lower. I think we’re going to overshoot in the other direction this time.


The demand side looks equally interesting. Let’s look at the various components of demand and see what their fundamentals look like:

  • Residential/Commercial (32%) – Residential demand fluctuations are entirely driven by weather. 2012 was a freakishly warm winter and 2013 has been above average. This winter, demand should increase 25-30% as we simply revert back to somewhat normal usage.
  • Industrial (27%) – Until about 2010, industrial usage previously was in decline, but with a rebound in the economy and the manufacturing sector in particular, usage is now steadily increasing. US industrial companies are now viewed as having a structural advantage because of lower energy prices, which is creating incremental demand. I think we can probably bake in 1-2% demand growth going forward, same as 2011 and 2012.
  • Power (35%) – The retirement of coal power plants is a trend that’s expected to accelerate. By 2015, 20% of the existing coal generating capacity will have been mothballed. Assuming the majority of this is replaced by gas, there’s a pretty clear roadmap for 5-7% annual growth in gas demand for power. There’s further evidence in the number of gas turbines on order.  We’re at a ten year high for CCGT orders…the industry hasn’t been this busy since the gas bubble of the early 2000’s, only this time there are legitimate reasons. Power demand was up 19% in 2012 as utilities switched en masse from coal to gas. I expect some of this to reverse, but not to a great extent.


Then there’s the issue of LNG. The LNG picture is extremely bullish for the US. Today we import an immaterial amount of LNG, although there are eight LNG liquefaction terminals already planned for the US. Only the Sabine Pass terminal has been approved while the rest are going through the FERC approval process. Sabine Pass is expected to start in 2015 and its 2.6 bcf/d capacity is already sold out. Even though 2015 seems like a long way off, 2.6 bcf/d is a huge needle-mover for the overall supply picture, especially if it’s against flat production growth. By 2017 we could have another 8-9 bcf/d of liquefaction capacity online. These are giant numbers, and based on these projects working at much higher gas prices, I think the future looks bright for LNG exporters. Recently the DOE released a study commissioned by the Obama administration on the effects of LNG exports. The study concluded that LNG exports would be a net economic benefit to the US. Importantly, FERC was waiting on the results of the study before approving the other projects. With the results showing benefits, FERC has a much easier time approving more of these projects. 


I think the inflection point is right now. Weekly storage numbers are showing massive withdrawals even though this has been a mild winter. Withdrawals should be rapidly declining and instead they’re flat, setting multi-year records. It’s because production is actually falling, and the path we’re on will lead to a huge spike in gas prices. When I put it all together, supply will be flat-to-down 1% while demand will be up ~1%.This might not sound like much but it’ll cause storage levels to be down by 25% or more by the end of the year, to levels not seen since 2005. If production declines again in 2014, even if just little bit like say .5%, the deficit for the end of 2014 will look gigantic and people are going to be talking about shortages. We’re not producing enough gas.


Unfortunately, gas in the ground is still abundant and the people that run these companies are destroyers of capital. The wrong incentives are still mostly in place, although I believe the management teams are showing more signs of discipline. Any response to rising prices will be gradual and the production won’t be felt immediately, so I believe gas has the ability to trade much higher than people realize. The bar is set so low in this space that if gas hits just $4.50, investor sentiment will go from despondent to ecstatic. Seriously, can you think of an entire industry that’s performed as poorly since the financial crisis? These companies are hated, cheap, and levered - when sentiment changes, watch out.


A good equity position from a risk/reward standpoint is WPX Energy.  It trades for 4.2x forward ebitda ($4.8b ev, $3.4b mkt cap) and 3x cash flow…measured on production and reserves it’s trading at a 50% discount to peers. The balance sheet is in great shape and they’re completely undrawn on their $1.5b revolver. Back in April when gas hit $2 and E&P stocks got killed, WPX’s stock was a mere $3 lower than where it is today, so from a trading perspective I don’t see a lot of risk. It’s got tons of leverage to higher gas prices but a good portfolio of assets that aren't pure methane. WPX will generate about $1.2b in ebitda and $.50 in EPS in 2013, but if gas trades to $4.50 WPX would generate $1.7b in ebitda and $1.90 in EPS.  The numbers get stupid at $5-6 gas, which is where I think we’re headed.

I do not hold a position of employment, directorship, or consultancy with the issuer.
Neither I nor others I advise hold a material investment in the issuer's securities.


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