In the US natural gas (NYSEARCA:UNG) industry there are numerous players. Most of the producer are actively involved in the shale oil and gas development. What is the collective financial performance of the shale development industry as one group?
I decided to survey a group of shale gas developer to sum their financial data together into one collective financial statement, including cash flow, income statement and balance sheet. The data comes from Yahoo Finance. I wrote a computer program so that I can retrieve and tabulate tens of thousands of data items at a click of a computer button, without spending hundreds of hours.
The Collective Financial Statement of 30 Shale Gas Developers
Here is the result I got after tallying everything together into three tables: cash flow, income statement and balance sheet:
I picked the companies from NGSA's top 40 NG producers list, with big oil and foreign names removed. The 30 companies surveyed are:
- Chesapeake Energy (NYSE:CHK)
- Anadarko (NYSE:APC)
- Devon Energy (NYSE:DVN)
- Southwestern Energy Co. (NYSE:SWN)
- WPX Energy Inc. (NYSE:WPX)
- EOG Resources (NYSE:EOG)
- Occidental (NYSE:OXY)
- Apache (NYSE:APA)
- Ultra Petroleum (OTC:UPL)
- QEP Resources (NYSE:QEP)
- Cabot Oil & Gas (NYSE:COG)
- EQT Resources (NYSE:EQT)
- Exco Resources (NYSE:XCO)
- Range Resources (NYSE:RRC)
- Newfield Exploration (NYSE:NFX)
- Noble Energy, Inc. (NYSE:NBL)
- Pioneer Natural (NYSE:PXD)
- Marathon (NYSE:MRO)
- Cimarex Energy (NYSE:XEC)
- SM Energy Company (NYSE:SM)
- Plains Exploration & Production Co. (NYSE:PXP)
- Quicksilver Resources (NYSE:KWK)
- Forest Oil (NYSE:FST)
- Linn Energy (LINE)
- Energen Resources Corp. (NYSE:EGN)
- SandRidge Energy (NYSE:SD)
- W&T Offshore, Inc. (NYSE:WTI)
- Unit Corporation (NYSE:UNT)
- MDU Resources (NYSE:MDU)
- Stone Energy (NYSE:SGY)
Further, the production data is not shown in the above table. The total NG production rates of these 30 companies are listed below:
Let's have a look at the numbers.
What kind of Numbers Can We Trust?
I repeatedly warned people that NG producers routinely over-estimate EURs (Estimated Ultimate Recovery) of their shale wells and grossly under-calculated the fair amortization of their capital expenditures in developing shale wells. Productions from shale wells fall far below projections in the long term, as wells decline faster than projected by the classical Arps formula. Drilling shale wells is very capital intensive. Producers love to pitch rosy pictures in order to attract investment money and bank loans so they can continue to drill wells. How do we know if the industry is realistic or not in making those long term production projections?
We cannot look at just the models. Any one can propose a model and cherry pick good wells to show how legitimate these models are. We cannot look at just the shale wells that producers pitched in their press releases. Out of tens of thousands of wells drilled, there are always some wells with exceptional performance.
What numbers told by producers can we trust?
We need to look at the totals with little room for fuzzy math. If you look at just a subset of the data, those numbers could be carefully selected and tailored to make them look good. But the company-wide or industry-wide numbers, the totals that the producers file in their SEC reports, are more reliable.
If a producer says that one rig drills one will in 6.5 days and costs only $3.2M per well, and that the wells have an initial production of 750 BOE/Day, I will hold these numbers with skepticism. There are too much fuzzy room in how they come up with such averages. The "average" numbers can not stand up when they are checked against the total figures. Ask them: If one well costs $3.2M and they spent $500M in capital spending, shouldn't there be 156 new wells? Why there were only 80 completed? If 80 new wells each brings in 750/Day, production should gain 60 MBOE/Day. Why it gained only 4 MBOE/Day quarter-over-quarter? And so on.
If they say that they have 22 rigs in operation; completed 80 wells in the quarter; and incurred capital spending of $500M; and that production grew from 66 MBOE/day to 70 MBOE/day. Such numbers are more likely accurate. These totals have no room of manipulation. They must be reported as they are. If they spent $500M, they cannot claim they spent $400M or $600M. If they completed 80 wells, they cannot say 79 or 81. If production was 66 MBOE/Day, they cannot say it was 67 MBOE/day.
So I spent time to get the total figures in the two tables above.
Data Analysis and Discussion
The 30 companies listed produced gas at 20.874 BCF/day in Q2 2012, versus the US total of 68.9 BCF/day. So they represent 30% of the US NG production sector. But these 30 companies represent almost the entire US shale gas industry, as they are picked from the top 40 US producers, with only a few big oil companies removed. The total gas production from these producers was 20.874 BCF/day. That roughly equals to total US shale gas production, 26 BCF/day, minus royalty payments of about 20%, or 5.2 BCF/day.
Total capital spending averaged $225.866M/day in 2011, and increased to $243.253M/day in first half of 2012. How much production gain did they achieve after such heavy spending?
In one year from Q1 of 2011 to 2012, production increased from 18.997 BCF/day to 20.413 BCF/day, a gain of 1.416 BCF/day. The average daily gain is 3.88 MMCF/day. That is a rather modest production gain for an average of $226M/day capital spending.
In first half of 2012, production went from 20.345 BCF/day in Q4 2011 to 20.874 BCF/day in Q2 2012, gaining 0.529 BCF/day in 182 days. The average daily gain is 2.91 MMCF/day, thanks to the $243M per day capital spending.
That's $83.50 spent to gain just one CF per day production. You read it right, one cubic feet per day. At $3.35 per thousand cubic feet today, $83.50 can buy 24925 cubic feet of gas, or 68 years worth of production at 1 CF/day. The new production of any shale well hardly last 2 years, let alone 68 years. As I summarized before, a shale well likely will produce about 500 days worth of production at its IP (initial daily production) rate.
Of course, the bulk of $243M spent per day does not contribute to production gain. It was spent merely to bring in new production to counter the decline from existing wells. Let's calculate how much is spent maintaining the production, and how much is spent growing it.
Using my 500 days rule of thumb, or -0.20%/day collective decline, the existing 20.6 BCF/day (average of H1 2012) production rate will lose 0.20% per day, or 41.2 MMCF/day. Net production gain is 2.91 MMCF/day. So new production must have brought in 44.11 MMCF/day capacity, with 41.2 MMBCF/day lost to the declines, resulting in a net gain of 2.91 MMBCF/day. But $243M/day spent to gain 44.11 MMCF/day new production capacity is still expensive. Since the new capacity will bring in a lifetime production worth 500 days of initial production rate, 44.11 MMCF/day is worth 22 BCF.
The capital cost of the gas is $243M/22BCF = $11.05/mmBtu!!! The shale gas industry loses money at gas price below double digits!
Conventional Gas Wells vs Shale Gas Wells
How did the US NG Industry fund the shale gas development if it is such a huge money losing adventure? The answer begins to emerge once you look at the US conventional gas production:
For years, the US NG industry has maintained flat conventional gas production at roughly 1500 BCF/month. But it started to decline in 2007 at a rate of losing 7% per year. The NG industry was able to maintain flat conventional production by continuous conventional gas well drillings, as shown in the chart below:
From 2000 to 2008, the industry was adding an average of 15,280 conventional wells per year to maintain conventional gas production at a flat 1500 BCF/month. That averaged 42/day new wells to maintain 50 BCF/day production. Based on fair replacement, each conventional well has a lifetime production of about 50/42 = 1.25 BCF. The decline rate of conventional wells after 2007, was 7%/year, or -0.02%/day. On each day existing conventional wells lost 0.02%*50 BCF/day = 0.01 BCF/day. The lost production is replaced by 42 new wells. So the well IP (initial production) was (1/42)*0.01 BCF/day = 0.238 MMCF/day:
- Conventional wells have an effective IP of 0.238 MMCF/day.
- The initial decline is much less steep than shale wells.
- They settle to the long term slow decline much faster.
- Collective decline of all conventional wells is -0.02%/day.
- The well has an EUR=1.25BCF, or 5000 days worth of IP.
- Drilling cost is much cheaper. You only need to drill a hold straight down. No horizontal laterals to drill. No fracking.
Let's compare those metrics with the shale gas wells:
- Shale wells have a typical IP of 3.0 MCF/day.
- They start with very steep decline for a year or so.
- After the initial decline, the decline rate slowly drops.
- Collection decline rate of all shale wells is -0.2%/day.
- The well has a typical EUR = 1.5 BCF, or 500 days of IP.
- Drilling cost is much higher than conventional wells. You have to drill the horizontal laterals. You have to do multi-stage fracking.
Here are the differences. Shale wells have remarkably high IPs ten times higher than a conventional gas well. But they also decline ten times faster. So by the end of their life cycles, shale wells do not deliver much higher EURs than conventional gas wells.
Capital Destruction in the US NG Industry
It puzzles me how the US NG industry manage to fund development of shale gas for these years, if the adventure is deeply unprofitable?
Let me return to the collective financial statements of the top 30 USNG producers as presented above. Let's look at the cash flows from beginning of 2009 to end of Q3, 2012, or for 3.75 years:
- Capital expenditures were $265.539B, or $194M/day.
- Cash flow from operations $224.590B, or $164M/day.
- Cash flow from financing was $47.441B, or $35M/day.
- Cash and cash equivalent change $6.79B, or $5M/day.
So the Cash flow from operations were short $30M/day to fund the well drillings and developments. The deficiency was funded by net borrowing and stock selling to the tune of $35M/day.
But that is not the entire picture. The $224.590B net cash from operations, or $164M/day, sounds like too high to me. These 30 producer produced an average of less than 20 BCF of gas per day. According to EIA, well head gas price during those 45 months averaged $3.72/mmBtu. So producers took home no more than $74.4M/day from gas sells, not including operation costs and SG&A. How did they report a net positive cash flow of $164M/day?
The operating cash flow is much higher than gas sells revenue as producers have revenues from oil and from foreign businesses. Take Apache for example. APA received only 45% of its revenue from N. America operations. The other 55% comes from overseas. Yet APA spent 62% of its capital expenditure in NA, only 38% overseas.
Here is the problem, the conventional oil and gas, and foreign operations are profitable. But the profits they generate is not spent to grow the profitable business. Instead they are spent to grow the unprofitable US shale projects.
The profitable portion of business does not receive the capital it needs to maintain and grow business. So the profitable business is shrinking. Instead, money is spend to grow the non-profitable US shale projects. Good money is thrown after bad money. This can be seen from APA's Q3 2012 result compared with one year ago:
- Total oil production dropped from 343.4 to 341 MBOE/day.
- Foreign oil production dropped from 210 to 192.9 MBOE/day.
- Domestic oil production grew from 120.4 to 133.0 MBOE/day.
- Most of the growth happens at Bakken (7.9 to 17.0 MBOEPD) and Permian (51.4 to 60.8 MBOEPD).
- The really profitable part of APA's domestic oil play, GOM shelf, dropped from 45.1 to 38.6 MBOE/day.
What did APA gain in allowing its profitable part of business to decline, for lack of capital investment, as they spend the capital instead to grow the non-profitable Bakken and Permian plays?
The same problem exists in the entire US NG industry. Conventional gas is still the bulk of US gas production, contributing 40 BCF/day. Shale gas contributes 26 BCF/day. But my previous chart show that in 2007, the industry completely abandoned its decade long efforts of drilling conventional gas wells to maintain flat production. They turned their entire effort to drill shale gas wells, leaving conventional wells to decline at 7%/year.
Mean while, as conventional gas wells continue to decline as they receive no capital spending, they still generate a lot of revenue. That revenue is spent to subsidize the shale developments.
This is throwing good money at bad money. This is capital and value destruction. How much good money do they throw away? When the industry stopped investing in conventional gas (CG in brief) plays in 2007, the CG sector produced 50 BCF/day and declined at 7% annual rate, or -0.02%/day. At that decline rate, the existing CG wells can produce 50/0.02% = 250 TCF of gas before they are depleted. At $4/mmBtu of gas price, those CG assets are worth one trillion dollars of future revenue, at only little cost of maintenance. Today, CG production dropped to 40 BCF/day, with 200 TCF of gas remaining, or worth $800B. The CG sector already generated $200B of revenue which was wasted in the shale plays with no profits.
The NG industry is on an unsustainable path of capital destruction.
There is an ongoing capital destruction in the shale industry. It will lead to production collapse in the near future, which will send gas price much higher. But what kind of gas price will allow the shale industry to generate $243M cash flow a day, net of costs, from 20 BCF/day worth of shale gas production, in order to maintain current capital spending at $243M/day? The gas price need to be in the double digits. Will such gas price be sustainable? I doubt it.
Investors are better off staying away from the NG sector. Do not be lured back into the NG sector just because gas price is going higher. The sector that will benefit most from the capital destruction in the NG sector, and from rising gas price, is the US coal mining sector.
I have urged people to buy coal stocks for a long time now. The current setup for a big coal rally is much better than the conditions existed at the onset of the 2007-2008 coal rally. This time it will bring more profit to people willing to hold their coal positions firm.
Based on the first 11 months data, China will import 265M tons of coal in 2012, up 45% from last year's 182.4M tons. The naysayers still call it a China demand slow down when China coal import grows at 45%? For the first 11 month, China generated 707.8 billion TWH of hydro-electricity, a gain of 149.2 TWH versus last year, saving China 82M tons of coal demands. This one time weather anomaly will not repeat in 2013. China will need 82M tons more coal just to compensate for hydro-electricity falling back to normal, on top of demand grow. At 4B tons per year demand, any demand grow is huge to the international coal trade market of 800M tons a year.
I am sticking to my coal stocks, and I look for opportunity to short NG players when the time is right, when we reach a high gas price.
Disclosure: I am long JRCC, ANR, ACI, BTU.