Shale Plays - Good Economics or Irrational Exuberance by tym76564

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									Shale Plays - Good Economics or Irrational Exuberance?
June 7th 2010

J. Cameron Bailey, CFA

Making Sense of Shale Plays

After witnessing natural gas prices of over $9.00 per mcf and more than 1,600 natural gas
directed rigs operating in June 2008, to a low $2.00 per mcf natural gas and natural gas
directed drilling falling to 680 active rigs in the United States, you would logically expect a
significant change in natural gas supply and a corresponding price response. Although a
correction did occur in late 2009, it was modest and short lived, leaving operators in North
America scrambling to reconstruct investment portfolios to more economic projects – oil
and resource plays. The main culprit to the lack of expected recovery has been the
significant supply of gas coming from horizontal drilling of US shale plays.


There has been significant commentary and opinions about the potential economics of
shale plays to justify operators’ claims of robust type curves, but little in the way of hard
facts to demystify the underlying fundamentals driving operators’ behaviors.


These questions are extremely important to Canadian producers when we are pushing
molecules of methane into a pipeline from remote areas of northern Alberta and BC, while
US producers are producing the exact same molecules of methane into a pipeline in closer
proximity to 300 million consumers. The perversity really comes to light when an mcf of gas
located in tight shale formation in the US commands many multiples of value compared to
an mcf of gas located in sand reservoirs 1000 times more permeable in northern Canada.
Canada has always had the perception of being the lowest cost source of supply, but this
‘conventional wisdom’ may have changed in North America, at least temporarily.


The behavior of producers has everything to do with “Ebbs and Flow of Capital” and much
less to do with the good sound economics. The following analysis evaluates some hard facts
that help in understanding the question – Do Gas Shale Plays Make Sense?
Shale Plays Dissected
How Much Do You Pay for Growth? Barnett Shale Experience.
From 2004 to 2009 Chesapeake was able to go from a stand-still to nearly 1 bcf/d of gross
production (660mcf/d net) from robust drilling activity in the Barnett Shales. An absolutely
remarkable achievement considering this came from a very modest land position of
200,000 net acres. This production growth represented 34% of Chesapeake’s growth over
this short period. It is very difficult to suggest another play type anywhere in the world that
could provide this kind of production growth.




During this time, Chesapeake drilled approximately 1,100 net wells at a cost of
approximately $3.4mm per well totaling $3.7 billion of investment (not including land cost).
Did they make money? That depends on your definition…


The on-stream costs were $33,000 per boe/d, great by anyone’s definition of making
money, however almost 50% of the production comes from wells drilled in the past year
with decline rates estimated to be 65% in the first year and two thirds from wells drilled in
the past two years. This production profile is derived from 1,100 separate investment
decisions related to drilling each and every well. The average production profile of
Chesapeake wells drilled over this time is as follows:




Wells drilled between 2004 and 2008 had an average peak monthly rate of 1.8 mmcf/d.
Wells drilled in 2009 and 2010 have reached a peak monthly rate of 2.2mmcf/d. The rest of
the industry’s average wells look as follows:
Of the 9,500 wells drilled by the industry between 2004 and 2008 that were placed on
stream, the average well peak monthly rate was 1.5 mmcf/d. Wells drilled in 2009 and 2010
have reached a slightly higher peak monthly rate of 1.7mmcf/d, lower than the average of
Chesapeake’s, clearly indicating where to drill is important.


Based on these observations we can determine the average decline rates to be as follows:
                                            Expected            High
                             Year One            61%            61%
                             Year Two            34%            34%
                           Year Three            24%            24%
                             Year Four           16%            17%
                             Year Five           11%            17%
                            Thereafter             7%           17%
The decline rates indicated in red are calculated from the observed rates and the later years
are forecasted. Since very few wells actually have production histories past three years, I
have run a sensitivity using higher assumed decline rates in the later years.


The following is the production profile and typical well in the Barnett and the cumulative
production. As can be seen, based on a $5.50 per mcf gas price it takes approximately 93
months for payout to occur resulting average production of 200 mcf/d per well on payout,
then declining at an assumed rate of 7% per annum to generate a positive return.




Of the 13,000 Barnett wells identified by the Rail Road Commission of Texas, only 601 or
4.6% have reached estimated payout producing greater than 1.1 bcf of cumulative
production. Of the estimated $30 billion of investment in the Barnett shales, it is shocking
that only 4.6% of the wells have reached payout, although 40% have achieved a peak
production rate of 1.7mmcf/d or better.


The bottom line is that there is a high probability of achieving very robust per well
production rates in every well drilled targeting the Barnett. The concern revolves around
the back end of the production years which drives estimated ultimate reserves, finding and
development costs and rates of return.


If it turns out the decline rates in the later years are higher than estimated, then the
average well will only recover 1.4 bcf versus 1.9 bcf and the well does not achieve payout. It
appears that there is not enough production history to confidently predict the ultimate
recoveries. However Chesapeake and Devon, the two largest operators in the Barnett, have
each added a 1.0 bcf/d of production in five years and spent billions in the process. Today
Chesapeake has 24 rigs operating in the Barnett shales, not necessarily because the
investment decisions make money, but because they must, otherwise production would
begin falling quickly.


I have assumed that Chesapeake drills 23 wells per month with 24 rigs operating and each
well comes on-stream at 2.0 mmcf/d and the annual decline is 65% per month. The
following is Chesapeake’s forecast production profile in the Barnett over the next twelve
months:
Chesapeake must keep 24 rigs active in the Barnett area or its production would fall
dramatically and the stock price right along with it.


Haynesville Shales

The Haynesville shale is deeper and with higher associated pressures than the shallower
Barnett shale and IP rate experienced is much higher. The average well cost is
approximately $7.5 to $9.0 million for drilling and completion. The Haynesville drilling has
been concentrated in an area 50 miles by 25 miles or approximately 1.0 mm acres. To date
there are approximately 1,150 wells drilled into the Haynesville shale of which 758 or 65%
have reached commercial qualities of gas. Of the 758 wells now on stream, the average
peak rate of production is 6.5 mmcf/d but increasing well performance has been achieved
with greater number of frac stages being applied over the past few years.
Chesapeake, the most active operator in the Haynesville, has 22 rigs operating and has 169
wells currently producing. The average production from the wells is as follows:
The average peak production for wells drilled over the past three years is 7.2 mmcf/d
declining 82% in the first year of production and 66% in the second year. These results like
the Barnett are better than industry average, so again, where to drill is important.


For the purpose of generating economics and a well production profile I have used the
following assumptions and plotted the actual wells performance that have been drilled and
placed on stream. The decline rates used are as follows:


                                           Normal                 High
                         Year One           81%                   81%
                         Year Two           47%                   47%
                       Year Three           22%                   24%
                         Year Four          12%                   24%
                         Year Five           7%                   24%
                        Thereafter           7%                   24%
The decline rates indicated in red are calculated from the observed rates and the later years
are forecasted. Since very few wells actually have production histories past one year, I have
run a sensitivity using higher assumed decline rates in the later years.


I have used $9.0mm per well and $5.50 well head price and an average one month IP rate
of 8.5mmcf/d. It takes approximately 82 months to payout a Haynesville well and it
generates a modest 8.9% rate of return.




Chesapeake has 22 rigs operating in the Haynesville shale and considering it is early days,
we will expect to see a very significant growth in production leveling out in 15 months
unless more rigs are deployed to drill.
Over 12 months Chesapeake will spend approximately $1.6 billion and will have 800
mmcf/d of production, albeit declining by more than 80% per annum. The cost of a boe per
day of production – a mere $12,000 per boe/d. Spectacular investment metrics by anyone’s
standard, but hard to conclude from this one measurement alone that the investment
makes money with a very modest 8.9% rate of return. In addition, none of the economics
calculated take into account failed or abandoned wells; only wells that have made a
commercial quantity of gas have been used in the statistical sample.
Conclusion
Do Shale Plays Make Money?
Investors pay for production growth and production growth means increasing cash flow.
The disconnect with shale plays comes when we examine the cost of growing production
and the unsecure footing that production growth has built. When we examine the
individual decision of drilling a shale well, I am hard pressed to see many wells making
payout and generating a positive rate of return unless natural gas prices increase
significantly. Well production histories seem to be suggesting lower ultimate recoveries and
therefore lower rates of return and higher finding costs than the claims made by operators.
As long as the growth rates are maintained which means rig activity must also increase, the
music will play on.
                  Irrational Exuberance = Natural Gas Bubble.

								
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