Musings: Separating Wheat from The Chaff of Unconventionals

Increasingly, petroleum industry executives are speaking out about the significance of the unconventional hydrocarbon resources in this country, although they do not always agree about the longer term outlook for the resources.  In some cases we question the extrapolations speakers are making about the importance of unconventional resources in the nation’s long-range energy mix and, for that matter, the world’s mix. 

Recently, several senior energy executives spoke at industry meetings about their views of these trends.  One presentation that received media attention was by Mark Papa, CEO of EOG Resources, Inc. (EOG-NYSE).  His presentation was to a joint meeting of the Houston chapters of the IPAA and TIPRO.  With respect to the success of unconventional drilling and production, Mr. Papa called it a “game changer” for the industry, something about which most industry participants would readily agree.  Horizontal drilling and hydraulic fracturing technologies have dramatically altered the near-term supply picture and have forced energy prognosticators to recast their forecasting models.  Most of them now are calling into question the need for the U.S. to import as many hydrocarbons as previously thought.  Optimism is fine, but euphoria can be dangerous as it tends to create blind spots that become our downfall. 

According to Mr. Papa, “There is clearly sufficient North American gas supply to last for a bunch of years; 50 years at least.  And there is clearly no need for us to import LNG (liquefied natural gas) for multiple years to come.”  At the present time, natural gas supplies are swamping the market due to the drop in demand associated with an overall decline in energy consumption due to the lasting effects of the recession and the surge in unconventional supply due to accelerated drilling dictated by the need for producers to hold leased acreage for which they have offered huge bonuses. 

This view of huge potential supplies of natural gas in this country due to the unconventional resources was prompted by the release of the Potential Gas Committee report last year suggesting that the U.S. has 1,836 trillion cubic feet (Tcf) of potential natural gas resources, of which 616 billion cubic feet (Bcf), or 33.5%, is unconventional.  The total increase in potential resources since the Committee’s prior report was due to the recognition of the gas shale resources.  The report stunned many in the industry and has led many to calculate that the country has 100+ years of gas supply.  But as Gil Goodrich, Vice Chairman and CEO of Goodrich Petroleum Corp. (GDP-NYSE), speaking to a group of young energy professionals in Houston, said, “Shale gas reserves and shale gas supply are not the same thing.”  Finding gas trapped in the shales underlying oil and gas producing basins and extracting it is one thing, but getting it out in an economically profitable manner is something entirely different.  Ignoring gas shale profitability today might seem acceptable because of the need for companies to establish large lease acreage positions early, but destroying shareholder capital is never a good business strategy.

As Mr. Papa pointed out, five years ago the consensus called for natural gas prices to trade in the range of $7 to $10 per thousand cubic feet (Mcf) because domestic supplies were falling short of meeting demand and we were increasingly dependent on gas supplies from Canada and LNG from abroad.  At that time, the prime focus of the large integrated petroleum companies was on tapping the huge gas deposits in the Middle East and Southeast Asia to supply the fuel needs of developed economies.  Today, those strategies appear to have been turned upside down as the U.S. has stopped adding new LNG receiving terminals and has actually sought and received permission to begin exporting LNG from the lower 48 states. 

Similar events are occurring in the oil market, although not to the same magnitude.  After nearly 40 years since U.S. oil production peaked, we are importing about two-thirds of our oil needs.  The emergence of the Bakken oil play in North Dakota and other oil shale plays in the Permian Basin and Niobrara has improved the outlook for domestic oil production.  As a result of the Bakken production, North Dakota is currently producing 500,000 barrels per day, up from 100,000 barrels a couple of years ago.  North Dakota is now the fourth largest oil producing state having passed Louisiana. 

Texas has three prospective oil producing formations – the Eagle Ford in South Texas, the Avalon in the Permian Basin and the Barnett Combo in North Texas.  Mr. Papa believes each will become very large fields with the smallest having reserves of at least 500 million barrels.  In fact, he believes that when the Eagle Ford is fully developed it will rank as the nation’s sixth largest field including Alaska and the deepwater Gulf of Mexico. 

Mr. Papa finds himself on opposite sides of certain issues being debated within the industry.  First, he believes that we still have shale formations left to find and that the list will certainly grow after 2012.  This is in contrast to Aubrey McClendon of Chesapeake Energy (CHK-NYSE) who has publicly declared that all the shales have been identified.  Mr. Papa also is optimistic that unconventional gas production won’t collapse in a few years because of the sharp decline in well productivity.  This stands in contrast to Mr. Goodrich who says that unconventional gas production can only grow with increased industry activity such as drilling more wells and drilling wells with longer laterals and increased numbers of fracturing stages.  He says this conclusion comes from the 70% to 80% first year decline in well production.  His biggest concern about near-term production is a slowdown in activity due to low gas prices and high well costs, especially those in the Haynesville with price tags of $8-$10 million including fracturing operations that cost $2-$3 million per well.

Exhibit 1.  There Are A Large Number Of Shale Plays
There Are A Large Number Of Shale Plays
Source:  Marko, Jefferies

Another optimistic presentation about natural gas shales was presented by William Marko of Jefferies & Company, Inc. (JEF-NYSE).  He focused on the impact that gas shales have had on the merger, acquisition and divestiture (M,A&D) market for producers and properties.  His firm has been actively involved as an advisor in eight of the 15 largest gas shale transactions in the past few years.  As Mr. Marko sees it, gas shales are world-class resources with low finding and development costs.  He estimates that each shale play has the potential to contain at least 500 trillion cubic feet equivalent (Tcfe) gas reserves or more with finding and development (F&D) costs in the $1.00-$1.25 per thousand cubic feet equivalent (Mcfe) range. 

In order for these large shale resources to be developed, Mr. Marko estimates $1.5 trillion will need to be invested over the next 30 years, or $50 billion a year.  Since the biggest initial holders of this acreage are undercapitalized, they will need to raise capital to fund their development needs.  They will have to form joint ventures, sell their conventional assets or merge/sell to larger, better capitalized companies in order to meet their capital needs.  Clearly, M,A&D transactions in the past 12 months would support that conclusion.

He went on to point out that the M,A&D market had been a $50 billion a year business for each of 2005 through 2007.  The pace was continuing in early 2008 until the financial crisis hit and the market collapsed.  Between the fourth quarter of 2008 and the first quarter of 2009, a total of only $1 billion in transactions were completed. 

The attraction for companies to get involved in gas shale joint ventures is that the super integrated oil companies largely missed the shale development because they were focused elsewhere – deepwater Gulf, international offshore and/or Middle East LNG opportunities.  Joint ventures are helpful to the sellers because they allow them to obtain capital for drilling and development despite low gas prices, the transactions give the seller’s valuation a boost, and they provide a way for the acquirer to obtain expertise in gas shales they could not get otherwise.  As Mr. Marko put it, just as the Gulf of Mexico in the 1940-1970 period was the incubator for offshore developments worldwide, the North American gas shales will be the incubator for gas shales worldwide.  Given the increasing focus on Eastern European, Chinese and Australian shales, this would seem to be an insightful observation.

Exhibit 2.  The Popular View Of 100 Year Gas Supply
The Popular View Of 100 Year Gas Supply
Source:  Marko, Jefferies

Mr. Marko’s presentation highlighted some of the driving forces for the flood of capital into gas shales.  For most of the past 40 years, the U.S. was challenged to keep its gas reserves to annual production at a ten to one ratio.  That ratio has changed dramatically as the U.S. now has over 100 years of gas supply at current consumption levels, according to Mr. Marko.  By confusing resources with economic production, this calculation becomes misleading, but then again when you are building a case to attract buyers of acreage or companies focused on gas shales, the misstatement merely slides by.  On the other hand, the petroleum industry has been characterized by a history of original reserve estimates growing over time.  There is a strong likelihood that current gas shale resource estimates will grow over time, but that assumption is currently unproven and a dangerous one to embrace.  This generous view of 100+ years of supply as a result of the recognition of gas shale resources has been challenged by Art Berman and rests on distinguishing the difference between resources and economically justified production.

Exhibit 3.  Why 100 Years Of Supply Is Wrong
Why 100 Years Of Supply Is Wrong
Source:  Berman, ASPO

The troubling conclusion from Mr. Marko’s presentation arrives when he calculates the required price to yield a 20% return on investment for the nine shale basins.  At current gas prices, only one – the Marcellus – yields the targeted return.  But then, everyone believes that current low gas prices are merely a short-term phenomenon caused by too much drilling driven by lease considerations that will ease up by 2012 when the economy is expected to have rebounded from the recession boosting gas demand. 

Exhibit 4.  $4/Mcf Gas Prices Kill Gas Shale Economics
$4/Mcf Gas Prices Kill Gas Shale Economics
Source:  Marko, Jefferies

One presenter we recently heard referred to the current gas oversupply situation as “a period of abundance.”  But he commented that he didn’t dare use the term “gas bubble” because we all know that the last time the term was employed, the outcome for the natural gas industry was pretty bad!  I guess this is the opposite of “build it and they will come.”  If you don’t call it what it is, then it won’t happen.

Exhibit 5.  Shale-Focused Rig Count Has Surged
Shale-Focused Rig Count Has Surged
Source:  Land Rig Newsletter, PPHB

The key question for the natural gas market is the pace of drilling in the shale basins.  Over the past two years, there has been an explosion in gas shale drilling and now in the more oily-shale plays.  Mr. Marko suggested that there are 100 rigs drilling now in the Eagle Ford basin but that rig count will peak next year at 200 rigs.  Of course, as he acknowledged, the rig count in the Haynesville is dropping due to the poor economics from high cost wells and low gas prices.  According to one questioner in the audience, his company’s drilling engineers had checked with the trucking companies and found that 40 rigs currently drilling in the Haynesville are scheduled to move upon completing their current contracts.

Exhibit 6.  Rigs In Shale Plays Shifting With Economics
Rigs In Shale Plays Shifting With Economics
Source:  Land Rig Newsletter, PPHB

Another problem for gas production is, and continues to be, a shortage of equipment to perform hydraulic fracturing treatments.  Every company engaged in this business is adding new equipment, but the order backlog has strained the component manufacturers and the equipment fabricators.  In addition, due to the depths and pressures encountered in many of these gas shales basins, pumping equipment is wearing out faster than normally, adding to the pressure to expand fracturing fleet capacities.  The result of the high drilling activity and the fracturing capacity tightness has been an increase in drilled-but-uncompleted wells.  No one knows exactly how large this backlog is, but knowledgeable guesses are that it is in the hundreds, and possibly thousands, of wells – possibly enough to keep the fracturing industry busy for a half a year or more even if all drilling stopped.  That means there will continue to be high volumes of new gas flows coming on line throughout 2011, which will keep gas prices under price pressure.  At the same time, whenever gas prices rise, producers will be incentivized to boost production from wells that currently have their flow choked back in an attempt to ease the economic pain. 

As gas supply grows, the question becomes when might gas demand increase?  The answer depends upon both the weather and the pace of economic activity.  The former factor impacts electric power generation using natural gas while the latter will tell us about likely industrial consumption of gas.  We have witnessed a strong rebound in gas demand this year as the economy has improved, but also due to warmer weather that has boosted electricity consumption.  For the first seven months of 2010, electricity consumption has increased 4.7% over the same period last year.  According to data from Black & Veatch (B&V), heating degree days in December 2009 were 5.2% higher than the prior year while they were 1.9% higher in January 2010.  Last summer was 24.5% warmer than normal boosting air conditioning demand.  The challenge for electricity and natural gas this winter is to overcome the forecast for warmer than normal temperatures in the more populous regions of the country.  The moderate winter is projected to be followed by a cooler summer that will dampen air conditioning demand during 2011.

B&V has estimated that electricity consumption lags the rate of improvement in the nation’s gross domestic production (GDP) by two quarters.  Given the slowing of the U.S. economy in recent quarters and the recently lowered outlook by the OECD, we would expect the recent surge in electricity demand to moderate just as is forecast by the Energy Information Administration (EIA). 

Exhibit 7.  Electricity Demand Rebounding Then Slowing
Electricity Demand Rebounding Then Slowing
Source: EIA

A major issue in forecasting gas demand associated with electricity is to understand consumption trends by end-user.  When we look at total electricity demand from 1973 to now, it appears to have had a healthy growth rate as reflected by demand having more than doubled over the period.  However, when we look at electricity consumed by industrial users over the same period, we see it has increased by only a little more than 50%. 

Exhibit 8.  Industrial Electric Demand Up Less Than Total
Industrial Electric Demand Up Less Than Total
Source:  EIA, NBER, PPHB

Why the slower growth?  One explanation is that the U.S. has lost much of its heavy industrial manufacturing base and the remaining businesses driving our economy are less power-hungry.  When we look at manufacturing employment relative to total employment in the U.S. since the 1930s, we see how the nation’s economy had changed from then to more recent times.  While we may be expecting an economic rebound following the latest recession, there is little likelihood we will reverse the long-term downward trend in our manufacturing sector that would boost electricity consumption.

Exhibit 9.  Manufacturing Employment Not As Important
Manufacturing Employment Not As Important
Source:  St. Louis Federal Reserve Bank

Maybe the more telling chart is the one showing the year-over-year change in total electricity demand.  While there are wide swings in the positive monthly changes in electric demand, we would note those periods when demand turned negative due to economic recessions.  More important is the red trend line for these monthly changes.  As can be seen, the trend line has declined from close to a 4% a year rate to 1%.  This compares closely with B&V’s estimate that the long-term growth rate in future electricity demand will be 1.1% a year.  They see the rate being closer to 1.7% a year for 2010 through 2013 due to the economic recovery, but then they expect it to slow to their long-term growth estimate.  It is interesting to note that electricity demand growth rate has trended lower given that we have been living in an age characterized by huge growth in the number of electric gadgets, computers and appliances in homes.  We have to believe that despite the increased number of household electronic devices, the most power-hungry among them - air conditioners, refrigerators and clothes dryers - have become significantly more efficient over time. 

Exhibit 10.  Electricity Growth Rate Has Declined Over Time
Electricity Growth Rate Has Declined Over    Time
Source:  EIA, PPHB

As more and more people embrace the game-changing nature of shales in North America and decide to wager larger and larger sums of money in exploiting these resources, the absence of a strong U.S. economic rebound will retard any meaningful recovery in natural gas prices.  It may take considerable time for the industry to overcome the imbalances from too many rigs drilling gas shale wells, the working off of the backlog of drilled-but-uncompleted shale wells, and for gas consumption to grow more rapidly.  Without these three conditions being met, gas producers will continue to wonder whether this period of abundance will morph into another gas bubble similar to the one that haunted the industry in the 1980s. 



In the November 9th, 2010, Musings issue, we mistakenly cited Dresser-Rand (DRC-NYSE) as being the target of a takeover when we meant Dresser, Inc.