- November 22, 2015
- Posted by: Art Berman
- Category: The Petroleum Truth Report
Lynn Pittinger is co-author on this post. He is a consultant in petroleum engineering, economic evaluation, and decision analysis.
The Haynesville Shale play needs $6.50 gas prices to break even. With natural gas prices just above $2/Mcf (thousand cubic feet), we question the shale gas business model that has 31 rigs drilling wells that cost $8-10 million apiece to sell gas at a loss into a over-supplied market.
We first evaluated the Haynesville Shale in 2009 and the conclusion then was the same as it is today: the average well by top operators will produce about 4 Bcf and is not commercial at gas prices below $6 or $7 per Mcf. The play has two insurmountable geological problems. First, the shale is not brittle and, therefore, does not respond well to hydraulic fracturing. Second, the reservoir is over-pressured and compacts when gas is produced.
We have heard fairy tales from operators over the years about how they will improve the miserable performance of Haynesville Shale wells. These included choking back production, re-fracking old wells and, recently, drilling 10,000 foot laterals. None of these approaches worked because bad geology cannot be improved with expensive technology.
We evaluated well performance for the 5 biggest producers in the play based on cumulative gas production and the number of producing wells (Table 1).
Table 1. Key operators in the Haynesville Shale play based on number of producing wells
and cumulative gas production.
Source: Drilling Info and Labyrinth Consulting Services, Inc.
(click image to enlarge)
We did standard rate vs. time decline-curve analysis by operator and by year of first production (an example is shown in Figure 1).
Figure 1. Example of Haynesville Shale decline-curve analysis showing standard log of rate vs. time,
rate vs. cumulative production and log of rate vs. log of time plots for a group of XTO Energy wells
with first production in 2011.
Source: Drilling Info and Labyrinth Consulting Services, Inc.
(click image to enlarge)
The matches of decline-curve forecasts and production histories were generally excellent providing good confidence in resulting estimated ultimate recoveries (EUR). The decline trends were consistently hyperbolic with relatively low b-exponents (0.4-0.6) reflecting higher decline rates compared with other shale gas plays.
BHP has the best well performance with 5.4 Bcf (billion cubic feet of gas) per average well and Chesapeake has the worst with 4.2 Bcf per well among the evaluated companies (Table 2). Break-even gas prices vary from a low of $5.29 per Mcf for BHP to a high of $6.82 per Mcf for Chesapeake. The average EUR for all evaluated companies is 4.3 Bcf and the average break-even price is $6.57 per Mcf.
Table 2. Summary table of weighted average well EUR for the Haynesville Shale companies evaluated,
the number of wells used in the analysis, and the break-even gas price per Mcf based on their respective EUR.
(ECA=Encana and CHK=Chesapeake).
Source: Drilling Info and Labyrinth Consulting Services, Inc.
(click image to enlarge)
Economics were based on the lowest drilling and completion cost ($8.6 million) that we could find, standard operating expenses and production taxes, and an 8% discount factor (Table 3).
Table 3. Haynesville Shale break-even economic assumptions and break-even prices and percent of Haynesville wells for a range of EURs.
Source: Labyrinth Consulting Services, Inc.
(click image to enlarge)
At $6 gas prices, only 17% of Haynesville wells break even (Table 3) and approximately 115,000 acres are commercial (Figure 2) out the approximately 3.8 million acres that comprise the drilled area of the play.
Figure 2. Haynesville Shale EUR map showing the commercial area at $6/Mcf gas prices (>5.5 Bcf) in yellow and orange.
Source: Drilling Info and Labyrinth Consulting Services, Inc.
(click image to enlarge)
The Haynesville Shale play is a commercial failure. Encana exited the play in late August. Chesapeake and Exco, the two leading producers in the play, both announced significant write-downs in the 3rd quarter of 2015.
And yet, Chesapeake is operating 6 rigs and Exco is operating 3 rigs in the play (Table 4).
Table 4. Haynesville Shale rig count for key operators.
Source: Drilling Info and Labyrinth Consulting Services, Inc.
(click image to enlarge)
What we see in the Haynesville Shale play are companies that blindly seek production volumes rather than value, and that care nothing for the interests of their shareholders. The business model is broken. It is time for investors to finally start asking serious questions.
A short and to the point article. Unfortunately I was expecting more of a look forward. You’ve made a good case for how uneconomic the shale gas play is. OK, fair enough, point understood. What I’m missing here is a look forward on the realistic options for these companies. Is the only option to keep pumping just to cover the interest payment? or how long can they go on losing $4.50 an MCF (costing them $6.50 but paying them less than $2.00)? When do the banks say NO MORE to requests for loan extensions or roll overs? In amongst the pure nuttiness of their “cost-is-$6.50-and-they-sell-it-for-less-than-$2.00-but-they-make-up-for-it-in-volume” is there an investment play here, some way to benefit from what is otherwise uneconomic behavior? I realize you’re not in the business of giving investing advice, but with this degree of nuttiness, you must have given thought to how the train wreck ends and ways to monetize their crashing and burning business, once the music stops. I’m simply trying to understand what the motivations are for the players in this uneconomic business. The companies keep pumping it out to cover their interest payment? and the banks keep rolling over the debt so as to not start a cascading waterfall of debt defaults? So how do you see this bad cartoon ending? As I mentioned at the start, I had hoped for more of a look forward by you as to how you see this ending, and was disappointed when the article didn’t take a stab at presenting whatever options these companies have left to them. Any added clarity would be helpful. Thanks.
Razz,
I stick to what I know in my posts and not what I imagine may or may not happen.
Have you read The Big Short? Lots of smart people knew that the real estate bubble would burst but no one knew when. Some really smart people invented credit default swaps as a way to bet on this belief and limit the short-term risk that stupid money would keep flowing.
That is similar to what has been happening in the shale gas business at least since gas prices collapsed in 2008-2009. I have no more idea what will happen to the shale gas business than the brains behind the big short did because I cannot predict what stupid money will do.
My guess is that the U.S. will start to run short on natural gas in the next 5-10 years. Shale gas production is already flat or declining. The guys who run the E&P companies are smart and they know that if they can survive until this happens, they will win.
If I knew how to bet on that, I would but I don’t.
Art
what are the implications for SW PA a and NW WVA where decline curves look like 4-6 BCF EUR’s and rotten liquids prices are not producing the gravy all the operators were touting?
Buffalo,
You are right about the EURs for SW PA and NW VA although Harrison County WV looks stronger, and 2013 well performance for Greene & Washington counties PA is in the same ~7 Bcf per-average well.
The big difference is that Marcellus well costs are only about $6.5 million instead of $8-10 million for the Haynesville and that is a very big difference for NPV.
All the best,
Art
Art,
Thank you for your article. I hope that many investors would take your advice seriously. There is much talk about a flood of new production coming to the market by December. Is this just pipeline capacity or is it also new production?
Heinrich,
I believe the supply surplus that some discuss is because of anticipation of a warm winter following a record storage volume. I will write a post soon showing the larger gas supply problem.
All the best,
Art
Sabine Pass operational in January?
http://news.heartland.org/newspaper-article/2015/11/23/us-lng-exports-begin-january
Euan,
The Cheniere model has no risk for the company on a point-forward basis (I don’t know how much they have to pay in debt service, etc). They charge the buyer Henry Hub + 15% and have agreements with they buyer in place to cover the approximately $3.50 in liquefaction and $2.35 in transport. So, at $2.50 Henry Hub price, the total package is about $8.70 plus degasification. With European spot prices at $6.71 today, that doesn’t look like such a good deal for the buyers. Energy security is, of course, a consideration along with projected prices.
My guess is that about the time that companies like Cheniere have fully developed their export capacity, the domestic price will be much higher and producers will prefer to sell the gas in the U.S. market. Cheniere has no calls on gas as far as I know so, if they can get enough gas when prices are higher, it will be up to the buyers to decide whether the higher price is worthwhile. I don’t know what options their contracts allow to opt out.
All the best,
Art
It appears to me that the villain in this sorry mess is the company management compensation plan based on increased production growth.
I have been told by a trusted PE manager in a company that Bone
Springs’ 30 day IP rates are managed to increase 30 day IP rates so that quarterly production growth increases quarter-to-quarter. Cummulative production is the next Guy’s problem.
You have been right along Art. It is a retirement party! The manager with the most stock wins.
Art, the shale gas story seems to get worse and worse and while the rig count has dropped significantly, that number still seems way too high given the economics. What is driving these producers to continue to drill? Is there something else besides the produced gas income because that clearly will never pay for these wells? Are these producers subsidized in some way other than simply cheap money such as required quotas, hedged long-term contracts. Or is that they are so far in debt that the only way forward is to continue to spend and eventually either gas prices go way up or the bubble bursts (and then gas prices go up)?
Stan,
As I mentioned to Razz yesterday, I think the plan for companies is to survive to fight another day. They must defend their share price and that means at least maintaining production levels. They also have send-or-pay commitments to pipeline companies. There are some “tight gas” tax credits (relicts from the period before shale gas when shortage was a worry) that companies have been taking all along but there are no subsidies that I am aware of. Some companies still have some volume of gas hedged at around $3.50/Mcf that they locked in during the price spikes of early 2014 but those won’t last long. At $6.50 average break-even in the Haynesville Shale, that doesn’t get them very far but it works fine in the Marcellus.
The end-game, if there is one, is that gas prices will increase some time in the medium term and those companies that survive will look good then.
All the best,
Art
In my view the Operators are continuing to drill for several reasons. They need the production; the stock price depends on it. They are trying to survive and hold acreage they paid a fortune for not long ago. If they can increase infrastructure and survive until prices rebound, they can exploit their HBP acreage and make money. They have drilling commitments or executives with ORRI. On a long enough time scale, this could work with a little luck. Costs will go down (technology), price will go up, and eventually (like Amazon) they will make a profit. At the end of the day, they have to hold their acreage or they have nothing.
Sean,
Thanks for your comments. I agree with all except the holding acreage part. I think that argument has been a red herring all along but by now, if the acreage hasn’t been held by production, the leases have either been renewed or released.
The 5-year rule on proven undeveloped reserves supposedly takes effect in 2015 in which companies must submit a development plan or remove the booked reserves. With gas prices around $2/Mcf, it seems likely that there will be big reserve changes announced some time in the first quarter of 2016. That said, EIA just published 2014 reserves and shale gas added 35 Tcf.
All the best,
Art
All the best,
Art
Art, another great article sir. I remember we had a hot summer in 2006 and there were two
consecutive weeks of storage withdraws. I think they said that was the first time ever to have drawdowns in the summer. We haven’t come close to getting any withdraws in summer since then even though we’ve had hot summers. I presume this was a supply issue, since that was before shale gas really took off. Do you think we could see anymore in the future, maybe with added demand from retired coal plants turning to gas? Thank you sir
David,
Thanks for your comments and question. The storage withdrawals in July 2006 resulted from abnormally hot weather and high electricity usage. U.S. shale gas production had increased substantially by mid-2006 reflected in falling wellhead prices that ended the year a full $1/mcf lower. The withdrawals were small.
Weather is the driver for natural gas consumption so I would not rule out another small summer withdrawal just because of high production. Year-over-year trends for 2006 were pretty normal.
All the best,
Art
Art: Following up on David Ryan’s comments, I think that during this past refill season less gas was put into storage in 2015 than was put into storage in the prior year, despite record gas production. Thus the conclusion would be that demand is up significantly. With production declining in all but one of the major shale plays and with over 1000+ rigs stacked. would you think that sometime in the first half of 2016, prices will begin to adjust upward (maybe dramatically) as the industry begins to appreciate the looming gas supply problem? Finally, thank you for your insightful articles. They are a pleasure to read. JHY
JHY,
You are correct. YOY injections since June are lower. The additional consumption is mostly for electric power generation. Recall that 2015 was the deadline for new EPA coal-plant standards and many smaller, older plants were retired.
I don’t see a price increase in 2016 for natural gas unless the stupid money stops funding non-commercial development projects or adult behavior develops among producers.
Thanks for your comments,
Art
All the best,
Art
Thanks for another interesting article Art!.
FWIW purported production costs (and resource) per company in the Marcellus are listed here:
http://capgainr.com/marcellus-production-breakevens-29-natural-gas-eps/
Ian,
Thanks for the link. It is incomprehensible that CapGrainr expects that the relationship between total company reserves (vs. average per-well reserves) and break-even price is at all clear because it is not, at least without telling us how many wells are required to produce that volume of gas. Also, break-even cost does is not the same as production cost or, at least, we don’t know what it includes–G&A, interest expense, etc.?
All the best,
Art
“We first evaluated the Haynesville Shale in 2009 and the conclusion then was the same as it is today”
I just want to point out that I don’t see any reference to Lynn Pittinger in that old article. I think you just mean “I” here. 🙂
Anonymous,
Lynn was part of the research for that 2009 article but chose not to have his name on it for personal reasons at the time.
All the best,
Art
And here is another article on Marcellus economics.
http://blogs.barrons.com/incomeinvesting/2015/11/02/economics-of-marcellus-shale-production-weaken/
The unhedged production-weighted gas price for a sample of six Marcellus players in Q3 was $2.07/mcf, or $0.67 below Henry Hub, for the nine months ending Sept. 30. Recent quotes at the Leidy hub of $1.10/mcf are $1.00 below Henry Hub, suggesting continued pricing weakness for Marcellus producers without adequate transportation capacity to higher priced markets.
More unconventional gas with (apparent) very unconventional production economics.
Ian,
Non-commercial production is not unconventional, just stupid.
Art
I find it amazing how over the years Art has been consistently 100% correct ! Wish you would be my portfolio manager!!!
Jeff,
Thanks for your comment.
Art
Jeff, do i note a bit of sarcasm there? Perhaps Art did not count on the investor/creditor willingness to part with billions of dollars…year after year after year.
Kaiser and Yu out of LSU have done extensive work on Haynesville EURs and economics – their 3rd and 4th (last) installments were published Feb and March/2014 – the 3rd one is on economics. At $4 per MCF, the cumulative value of Haynesville wells have an NPV of NEGATIVE $2.2 Billion.
http://www.ogj.com/articles/print/volume-112/issue-2/exploration-development/haynesville-update-mdash-3-low-gas-price-constrains-profitability.html
Dr. Michele Foss, the Chief Energy Economist at the BEG/Univ of Tx seems to be implying we need much more than $6 to breakeven on dry shale gas – see slide 5:
http://www.beg.utexas.edu/energyecon/thinkcorner/CEE producer benchmarks part 2.pdf
…and Bentek is forecasting the we will need 5 INCREMENTAL BCF/day out of East Texas/Louisiana by 2020 to meet ramping demand (…and Bentek is counting on 15 INCREMENTAL out of Marcellus/Utica).
Art,
Thank you for this post and everything else you have shared on the industry. I am not a geologist, but I have followed the industry over the last 8 years or so and discovered your blog and presentations more recently. My interest comes from the accounting/investing perspective (I used to work at the FASB/Big 4 and I now manage investments for family).
I am in the process of reviewing the most recent 10-K’s/10-Q’s for the top 40 gas producers in the U.S. One thing that has struck me based on your comments on free cash flow and my review of their financial statements is the disconnect between depreciation/depletion and investing cash outflows for drilling and completion costs. The cash outflows are 2 to 2.5 times depreciation/depletion for many companies. How is this possible? Are they doing their depletion calculation correctly? It seems like depletion should be much higher, which would make income statements look much worse. Also, their production rates should increase a lot more year over year if their investing cash outflows for well development and completion are that much higher than their depletion expense.
At one company, I saw depletion remain basically the same in 2014 and 2013 even though the company’s production increased almost 25%. Does this come from optimistic estimates of the total gas that will be obtained from unconventional wells?
It is painfully obvious looking at the cash flow statements for many of the unconventional producers that once other people’s money runs out, they will have to either drastically cut back on production or go out of business.
Art , regarding your reply to Euan in comment 10 .
Some components of the cost of liquefaction and shipping of LNG are fixed but both liquefaction and ocean transportation use gas/bunker . As the price of US gas and bunker fuel eventually recovers , the cost of the LNG process increases .
Do you see Europe as being the main market for East Coast LNG ?
Your forecast for medium term trends in US gas prices sound reasonable but as you point out stupid money can keep overproduction going for a long time .
This also damages peoples perception and trust in fiat money which already seems to have become uncoupled from reality .
Do you have any articles which discus probable trends of gas prices over the medium term in Europe please ?
Adsorbed natural gas storage (ANG) doesn’t look to be an alternative for virtual pipelines . Do you see it having a future in road transport as an alternative to compressed natural gas ?
Thanks for your insight of the gas industry, a real eye opener.