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I have written a lot about my theory of maladjusted markets and poorly functioning pump and dump crony capitalism. Shale natural gas is one market that takes the cake, and is one big bagunca (mess) now. I have bitten my tongue on the shale gas mania which has been going on for awhile. For background, The New York Times reported on it last summer in “Insiders Sound an Alarm Amid a Natural Gas Rush” and “Behind Veneer, Doubt on Future of Natural Gas.” Now Bloomberg has weighed in on the inflated prices paid for drilling mineral rights. This blogger lays out the boom-bust clearly with links to all the MSM talking points. I thought it was wise to defer to the “law of bubbles,” meaning they go on longer than one expects. I thought that the crazy uneconomical production would swamp the market, and that with global warming, we could see a warm winter. Sure enough here we are, see chart 5. Now with this mania long in the tooth, and with nat gas (NG) far below equilibrium prices, I feel it is time to weigh in.
First some NG history:
- 1978, Congress perceives shortage and essentially outlaws new gas power plants
- Next 9 years, major build-up in coal plants
- Gas surplus results, Congress reverses, many gas power plants built
- In about 2000, worries over supply again became prominent, resulting in build-up of LNG import infrastructure
- Since about 2007, the excitement over unconventional gas has created a surplus, and the LNG infrastructure is mostly idle
There are two primary factors that explain the collapse of NG gas: a surge in production because of aggressive shale gas and oil production plays (using fracking) in 2010-2011, and a warm winter. Also because of hydraulic fracking, the market sees the potential for even more drilling in places like the Marcellus basin. There is an environmental cost to fracking, and growing political opposition, but given the mania behind it, I very much doubt anything will be done about it.
Spot NG:
http://charts.market...,0&size=650X314
The market for liquefied natural gas (LNG) exports internationally is building, but only gradually. Estimates range from 10-17% of US nat gas being exported by 2015, with maybe 3-4% in 2012. This is a gamble because this gas has to compete with foreign supply and assumes very low domestic NG prices. Right now it costs $9 per mm BTU (will use this as simply $9 here) to ship to Japan, and $7 to Europe and those regions are scrambling for supplies to bring prices down. In the intermediate term LNG tankers are in tight supply. There are only four new tankers to be launched in 2012. The bulk of LNG tankers arrives on the scene with 15 launched in 2013 and 27 in 2014 (global LNG fleet). Although there are plans in the works, at the present time there is not one single LNG export terminal under construction in the US (list of LNG terminals). For purposes of discussion I don’t see US LNG exports to be a major determinant until at least 2014, and frankly wonder about its real sustainability.
In addition, prices for NG are highly favorable for natural gas liquids (propane and ethane) and four new plants are coming on stream this year that will use 1bcf a day. There are 74 LNG fueling stations opening in the US in 2012 intended for trucking. If 10% of trucks began using NG, that would be 1.7 bcf/day, but is little factor for the period we are talking about.
Still among the variables, I think there are several factors that may strengthen nat gas to a point. One is weather, just as winter was impacted by global warming, so could the cooling season, which could deliver both drought and scorchers. This hot weather might also deliver big hurricanes that could shut down GoM production. I think a big one is due, even a Cat 5 plus. This weather aspect is part of my ag play, and is also applicable to NG.
The other factor, and the main one, is equilibrium economics. Prices now are well below all-in cost, which conventional analysts estimate at $4-$4.50 in the better fields. Producing at variable cash cost (which will be discussed later in this post) makes O&G companies gunslingers and not long for this world. In terms of timing, these firms will blow up for financial reasons, not because they are voluntarily disciplined. It now costs the industry about $22 billion each quarter just to replace the annual depletions and maintain current volume levels. Yet those producers are seeing only about $12-billion a quarter in cash flow. “The resulting capital gap is now on the order of $10 billion a quarter, or a phenomenal $40 billion a year — and that was last year before the latest NG price drop. Once the capital to fund this gap is removed, so does the activity. Since 1/2010, the top twenty producers have cut back 11% of gas directed drilling, but the rest including speculative names have increased by 30%.
Neal Anderson of Wood MacKenzie writes that the sector is being ramped by Wall Street “analysts/cheerleaders” and has all the flavor of the day characteristics of the Internet mania. In the aforementioned New York times article last July:
“Money is pouring in” from investors even though shale gas is “inherently unprofitable,” an analyst from PNC Wealth Management, an investment company, wrote to a contractor in a February email. “Reminds you of dot-coms.”
These corporate giants are having an Enron moment,” a retired geologist from a major oil and gas company wrote in a February email about other companies invested in shale gas. “They want to bend light to hide the truth.”
These corporate giants are having an Enron moment,” a retired geologist from a major oil and gas company wrote in a February email about other companies invested in shale gas. “They want to bend light to hide the truth.”
About the economics:
-Ben Dell, an analyst at Bernstein rips some the silly season economics being applied.
-Devon’s CEO, and others, say the high drilling in the last few years was mainly to secure leases (most leases require that the company actually start producing within 2-3 years); these people say much of recent drilling was not profitable.
-Allen Brooks of Parks Paton Hoepfl & Brown, an energy investment bank, quotes unnamed critics as saying that IP (initial production) is taken to predict EUR (estimated ultimate recovery – an estimate of how much will be recovered from a well in total); but in fact, high IP may be merely bringing production forward. Brooks also suggests that future re-fracking costs are not being realistically included.
-John Dizard, regular investment writer for the FT, said, “American shale gas companies assert that they can profitably produce gas from formations such as the Marcellus in Pennsylvania for $2 or $3 per mcf (thousand cubic feet). But in the fine print you find that represents only the ‘finding and development’ costs, which are only a quarter to a third of the total needed to get a molecule to market.”
- Petroleum geologist Arthur Berman’s most frequent argument is that decline rates are higher than companies are recognizing, and so EUR is too optimistic. Here is one specific quote: “I recently grouped all the Barnett wells by their year of first production. Then I asked, of all the wells that were drilled in each one of those years, how many of them are already at or below their economic limit? It was a stunning exercise because what it showed is that 25-35% of wells drilled during 2004-2006 — wells drilled during the early rush and that are on average 5 years old — are already sub-commercial. So if you take the position that we’re going to get all these great reserves because these wells are going to last 40-plus years, then you need to explain why one-third of wells drilled 4 and 5 and 6 years ago are already dead.”
Berman describes the shale gas mania:
- In the midst of a boom, it is hard to sit on the sidelines. What boosts stock price & leader’s standing, is rapid expansion.
- E&P executives feel compelled to enter shale plays (like securitized mortgages) rather than being punished by investors and risking personal losses.
- Leasing and drilling funded by massive debt — public markets remain enthusiastic based on stock price, reserves and favorable reviews by investment bank research reports.
- Engineering companies willing to certify reserves since the E&Ps are their clients and have the choice to shop (like rating agencies).
- Operators take big risks. Gas price will increase, reserves will be there, investors will fund a vicious cycle of a leasing frenzy followed by a drilling frenzy to save leases and book reserves to borrow more and issue more equity …
CHK’s McClendon repeated Devon verbatim on the leases. In the summer of 2010, he said, “If I had my druthers we’d be running no more than a couple [rigs]…You’d be surprised how much drilling is not voluntary today.” CHK, which now accounts for 8.3% of US nat gas production, has already made a large shift in drilling emphasis to liquid plays, and predicts others will follow suit. McClendon says they won’t go back even at$7. This is a significant story, since as 0f 2000 the other producers grew production by 12% versus 472% for CHK. Most of CHK’s production ramp occurred mid-2009/mid-2010 and tie ins from delayed 2008 projects. That, by design, will flatten over the next two years.
From CHK investor presentation:
- A drilling operator at Seeking Alpha said, “The best wells in our inventory are first, and the shale wells we drill in 2010 and 2011 are not going to be as productive as the wells in the sweet spots… the wells we drilled in 2006 thru 2008.”
-Chevron has said this year, without further elaboration, that shale was not providing positive returns.
Part of the reason for the so-called drilling success of shale gas is because it is a byproduct of oil shale hydraulic fracturing, which has surged. The Energy Bulletin writes:
“Large amounts of natural gas are produced in conjunction with the production of hydraulically fractured shale oil and in association with conventional oil drilling. Given the price differential between oil and gas at present many companies have changed their focus to shale oil or liquids rich shale gas to enhance economic returns. Although much associated gas in the production of shale oil is simply flared, as in the Bakken play in North Dakota, much is also produced into the market even at current low prices. Thus the apparent ‘too- good-to-be-true’ statistics showing growing gas production with declining drilling are simply that – too good to be true. The record drilling for oil, and its contribution to gas production, is masking the high drilling rates required to grow gas production in the EIA statistics (which classify a well as either ‘oil’ or ‘gas’ depending on its principal product).”
CONSIDERATIONS FOR TIMING A LONG TRADE IN THE OCT 2012 NG FUTURES. Usually firms hedge a year in advance for about 50% of their production. Starting in November 2011, the NG one year forward fell below $4 and today, the February 2013 trades at $3.30, and 2013 ranges from 3.25-3.45. Anybody unhedged and leveraged on their balance sheet with expensive properties faces bankruptcy this year unless prices spike much higher. Anybody who is hedged buys a little time, but faces huge pressure as the year rolls along. Firms will likely try to continue to produce from existing wells, but one thing that could halt that is a sudden capital revulsion as cash flows don’t support operations. Also the depletion rate on horizontal shale wells is 45%/yr and after four years of active pumping the quality of output is in question. Therefore, unlike the consensus view which see an increase, I think production drops — and if the low price lingers, a lot.
The big NG rout just happened, but even before hand rigs directed toward natural gas in the week of Jan.20th were down 11 at 780. There are 126 fewer rigs currently drilling for gas than last year’s level of 906. Gas exploration is down 13.9 percent. As the financial stresses build, I expect this to fall off a cliff and the shale gas bust to gather steam.
So far Encana is bailing on dry pure gas plays, and says it needs at least $4.50. Talisman Energy Inc., a Calgary-based energy producer, will cut spending on drilling this year by $500 million because of the decline in North American prices. Anadarko: ”For new drilling, the Marcellus [Shale] is the only basin where it makes sense to drill at $2.50[/Mcf] from a return perspective.” Per APC, while both the “wet” and “dry” gas portions of the Marcellus still yield attractive economics down to $3.00/MMBtu in most cases, this is not the situation for most parts of the Haynesville and Fayetteville shale plays.
As far as a floor, I am looking at a marker to support NG prices until the industry bust becomes more apparent. Because inventories are so large, I don’t really expect a huge 2012 spike unless four things happen: an extremely hot summer, a hard-hitting GoM hurricane, a stronger spring draw down, and a big drop in drilling activity. Those are the variables to gauge this trade. Until then, I will use coal equivalents as floor support. I’m expecting a hot summer and modestly cold winter, so I will use the October 2012 NG future expiring Sept. 25. That would pick up almost all of summer and hurricane season.
On a price floor, natural gas trading at $4 per mmBtu and is approximately equivalent to Central Appalachian coal selling in the $49 per short ton range, which is well below marginal mining costs. Natural gas prices would have to stay below $3.25 per mmBtu to be cheaper than Illinois Basin coal and to $2.75 per mmBtu to compete against Powder River Basin (PRB) fuels.
First Enercast Financial chimes in with the key fundamentals. I have seen others quote $2.75 as the PRB equivalent. Right now March futures are at $2.33 and stay below $2.75 until September. This gives the coal plant industry a perfect spring break opening to take care of necessary scrubber retrofitting. Thus, I expect stronger than normal drawdowns in the spring months.
“Powder River Basin coal is the cheapest source of coal in the U.S. and supplies roughly 40% of the nations coal. At current PRB prices, natural gas will begin to be cheaper to burn at prices below $2.50 for many regions in the West and some Midwest markets. This is a huge amount of potential new demand that can possibly materialize in 2012 if natural gas prices remain weak. I f natural gas prices can remain below PRB for an extended period, there is around 4-6 bcf/day of total new demand that could be created over the next year. The impact of this will appear most pronounced in the spring period when coal and nuke generation is offline. The maintenance season will become longer and more heavily support gas demand as coal plants come offline for extended periods to retrofit with scrubbers. There are around 500 coal plants that will be retrofitting with scrubbers over the next 3-4 years and a typical job takes 3-4 months.” [First Enercast Financial]
So in setting up trading in the October 2012 NG futures (do not use UNG) the price as I write tonight is $2.76. NG futures also trade minis, which are 1/4 the regular contract (specifications). There isn’t much open interest, but I haven’t found that to be much of a problem for retail size trading. I would anticipate the specs to be all over themselves, trading the winter crash over the next few warm weeks. With winter winding down, weather until summer will be random and then could get interesting. I don’t expect the Fed to loosen this week either, so commodities in general may sell off, which is why I am short materials via the double inverse SMN. I think the PRB equivalent or $2.50 is the floor, and the $4.50 shale gas play post-tax break even to be the conservative upper band. I would like to see Baker Hughes gas-directed drilling drop to 750 rigs in combination with a price under $2.75 to pull the trigger, and then scale in additionally if there is more of a swoon. I don’t think it can be said that I have been early on these calls, the problem being more pulling the trigger and being conservative, so you can adjust to your risk tolerance accordingly. I have little idea if $2.75 (tomorrow), $2.60 or $2.50 is the bottom. There are option selling strategies that could be used to manage this trade, and I am looking at those.
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