When the price of natural gas tanked due to severe overproduction by operators in shale gas, operators quickly turned their attention to shale oil. Clearly this was a deliberate attempt to salvage ailing balance sheets saturated with natural gas assets and, no doubt, executives hoped that it might serve as an effective diversion from the mismanagement of resources which had occurred. Hyperbole, which had been considerable with shale gas, now became exponential with shale oil. Unfortunately, such hyperbole has once again proved hollow. Shale oil wells are declining even faster than shale gas and revenues generated are falling significantly short of costs incurred due to shale drilling. The Bakken is a perfect example.

According to well production data filed with North Dakota, daily oil production per well in the Bakken shale has already peaked…in June 2010. In fact, the number of wells brought online between June 2010 and December 2011 doubled but production did not grow. So twice as many wells could not add any meaningful amount of production. This is a pattern all too familiar in shale plays across the board. Older wells decline so rapidly that newer wells simply can’t match the concomitant decline. Overall field production, therefore, begins to decline. Shale’s pollution, external costs and environmental degradation, however, do not decline but increase with the growth in wells.

Operators have managed to camouflage these severe decline curves by engaging in a frenzy of drilling which makes it appear in the early days of a play that a field is a significant producer. Nevertheless the numbers always catch up with them and it becomes impossible to maintain flat production profiles or even production profiles which might mimic conventional fields. Indeed, based on actual well histories we now know that all shale fields in the U.S. decline somewhere between 30-50% per annum which is considerable.

And there are other problems in the Bakken as well.

In 2010, state government revenues from oil drilling amounted to approximately $749M. This increased in 2011 to $2.65B. Operators are quick to point out such growth in revenues and take full credit for it. They are not, however, nearly as keen to expose the external costs of their activities which are being off set in every play onto local businesses and taxpayers. These costs are significant and in some cases are multiples of revenue generated by extraction. Were these costs to be fully accounted for by the industry that generated them, shale wells would prove even less attractive. Given the massive asset writedowns, sales and significant drops in revenue in older shale plays, they are unattractive enough as is which, no doubt, accounts for the sale of shale assets by operators in all older shale plays.

While North Dakota has taken in $3.3B in tax revenue from drilling since 2010, road damages are now estimated at $7B as of 2012. But per well production has already peaked. This means the Bakken’s days are numbered and revenues will soon begin to decline. Unless, of course, the operators engage in a further drilling frenzy far beyond the current drilling schedule. In which case, road damages and degradation will increase further. This is not a win, win scenario. One aspect is certain, however. The companies that generated these costs will not be covering these costs.

That will be left to the people of North Dakota…and Texas…and Louisiana…and Arkansas…and Pennsylvania…

Assessing shale production honestly and accurately requires that all externalities, or created peripheral costs, be examined in a circumspect manner. It is imprudent, indeed stupid, to consider oil and gas projects without also considering the externalities which inevitably arise due to its heavy industrial nature. A careful look at costs such as road damages are certainly warranted but road damages are not the only externality with shales. Regions heavily engaged in shale production are now experiencing skyrocketing costs directly attributable to oil and gas production which are significantly outstripping revenues provided by extraction. These costs not only include road damages but also health impact costs and loss of crops. Very little has been said about such costs in the giddy statements made about shales. In fact, it would seem that the states which embraced shales early clearly did not conduct proper due diligence on the activities that they were green lighting. All of them, including the state of Texas which has a long history of dealing with oil and gas, have been caught completely unaware by these skyrocketing costs. Road repairs alone are now estimated, in some cases, to be multiples of what states are taking in from severance tax revenue. And road repairs are only one externality of shales.

The American Lung Association (ALA) quantified the health costs of air pollution from nitrogen oxides (NOx) and volatile organic compounds (VOC). These are two primary constituents of ozone. ALA estimates that the impact of such pollutants on the health of the people who live in regions where ozone is prolific comes to about $1648 per ton of NOx and VOC’s (2010 dollars).

The shale industry emits significant amounts of NOx and VOC’s in their day to day operations. In fact, when shale comes to town, it becomes one of the primary polluters. In Texas, the Texas Commission on Environmental Quality (TCEQ) studied air emissions from gas drilling operations in the Barnett shale region. In December 2011, TCEQ quietly submitted a report to the US EPA which confirmed that gas drilling operations in the region were producing significantly more VOC’s than all the on road mobile sources in this large metropolitan area (DFW). TCEQ estimated that gas drilling accounts for approximately 121 tons per day of NOx and VOC’s. That equates to about $202,000 per day or $73,000,000 per annum. Just for the Barnett region.

In Arkansas, emissions from shale gas production in 2008 were estimated by the Arkansas Department of Environmental Quality to be approximately 5979 tons per annum. In a mere four years (2012), emissions had grown to approximately 20,347 tons per year based on current extrapolations. This means that health costs soared from $450,000 to $33,500,000. And this annual expense is not covered by the industry that caused it.

In the Marcellus shale in Pennsylvania, the Department of Environmental Protection (DEP) estimated NOx and VOC emissions from shale production in 2011 at 19,300 tons per year. That translates into health costs of nearly $32,000,000 per annum. Again, none of the costs are covered by the industry that perpetrated it.

Further, much of these calculations from the various state regulatory agencies are based on self reported emissions inventories provided by industry. Unfortunately, states simply do not have the man power or resources to adequately check and verify such estimates. Because self reporting is suspect by its very nature, particularly when done by an industry that stands to gain monetarily through underestimation, it stands to reason that these costs could conceivably be much higher. For instance, industry self reported their methane emissions in Colorado and claimed in inventories that they never exceeded 2%. But the University of Colorado, Boulder and NOAA conducted a three year study on gas fields north of Denver and found that emissions were running about 6%. They then found emissions from a gas field in Utah running about 9%. So self reporting, for obvious reasons, has its issues.

Add these health impact costs to the estimates of road damages and the taxpayers burden continues to grow exponentially. Moreover, ozone also affects crop production. Cumulatively for the Barnett, Fayetteville and Marcellus, based on very conservative estimates, we can add another $26,000,000 on to the businesses of the region for crop losses and damages.

And, yes, that would be businesses other than the one that created the problem.

Does industry think that it has a responsibility to cover the costs or take responsibility?

When a paper issued by the Houston Advanced Research Center (HARC) was released last October it caused quite a stir. HARC scientists concluded that significant levels of formaldehyde, a known human carcinogen and precursor for ozone, were being emitted from gas operations. This is one of the primary reasons that the remote Jonah-Pinedale gas field found itself with ozone spikes that were higher than the worst day recorded in the City of Los Angeles.

The Texas Pipeline Association (TPA) made the following statement upon perusal of HARC’s paper:

“TPA and its members desire to be good stewards of our environment and are not opposed to regulation grounded in good and supportable scientific bases. The technical paper does not provide that type of support.”

Really?

This is an interesting interpretation by TPA if only for the following reason. The Chairman Emeritus and Founder of HARC, the entity that conducted and released the paper, is none other than George Mitchell. It was Mitchell Energy that perfected the technology of horizontal drilling and hydraulic fracture stimulation more popularly known as “fracking”. The current Chair of HARC is John Butler who also serves on the Board of Anadarko Petroleum. Other industry executives serve as well. It becomes a bit tricky to dispute findings from an entity whose board reads like a “who’s who” of energy academia and oil and gas.

Nevertheless, TPA stuck to its guns and stated:

“…the four significant problems identified…effectively render the conclusions meaningless”.

Billions of dollars in road repairs, tens of millions of dollars every year in health costs and agricultural damage is anything but meaningless. Unless of course, you consider privatizing profits and socializing damages an ethical way to do business.

The past few years have brought endless glowing reports about the benefits and promise of shales, both oil and gas. We have been assured of a prolific supply that will continue to be cheap and abundant for decades to come. Unfortunately industry rhetoric has proven overtly optimistic. Reserves and economic benefit are short-lived but perhaps most importantly are the negative externalities which are becoming more and more obvious. Once such externalities are factored in shales look even less attractive.

In 2012, the State of Texas took in approximately $3.6B in severance taxes from all oil and gas produced in the state. That would be wonderful if it weren’t for the fact that TxDOT estimated that the damage to Texas roads from drilling operations now totals $4B.

Interestingly, the same pattern has emerged in the Fayetteville shale play in Arkansas. Since 2009, Arkansas has taken in approximately $182M in severance taxes but estimates its road damage from drilling to be $450M.

In Pennsylvania, in the heart of the Marcellus, the state finally began imposing a fee on drilling. In 2012, approximately $204M was collected in “impact fees”. Impact fee is an appropriate name because Pennsylvania has significant impact from drilling now. New numbers are emerging on the appalling condition of Pennsylvania roads. In 2010, PennDOT estimated road damage from drilling to $265M. But by 2013, the state estimated that $3.5 billion would be needed just to maintain the states existing assets and $8.7 billion to make all the necessary bridge repairs. Admittedly, not all these costs are directly attributable to drilling operations. But interestingly, roads that are in acute disrepair are most susceptible to flooding and peripheral problems from flooding. During Hurricane Sandy, the roads that were hardest hit were in the areas most heavily drilled. According to the Times-Tribune:

“Luzerne, Wyoming, Bradford, Susquehanna, Sullivan and Lycoming counties were among the hardest hit…”

It is not at all surprising that roads in these areas would be in such dismal shape. In June 2012, TxDOT issued their findings of potential damage done by gas drilling operations. What they found was truly astonishing. It takes 1,184 loaded trucks to “bring one gas well into production,” plus 353 loaded trucks per year for maintenance and 997 loaded trucks every five years to re-frac a well. TxDOT estimates that to be the equivalent of about 8 million cars, plus 2 million cars per year for maintenance.

In addition, it is recognized across the board by every state where drilling occurs that roads that were designed for 20 years are lasting a mere 5 due to overweight vehicles transporting drilling rigs and water for fracking operations. Further, drillers are not abiding by weight limits. Not even close. Over two weekends in June and September 2010, Pennsylvania State Police inspected 2,300 gas-drilling trucks. Of those, more than 1,600 trucks were given citations for weight limit and safety violations.

The question, of course, then arises as to who should pay for this damage. Not surprisingly, industry does not want the burden.

In July 2012, Deb Hastings executive VP of the Texas Oil and Gas Association, stated to the Ft. Worth Star-Telegram when asked about road damage caused by her industry:

“Who should pay for it? That’s the kind of questions we in the industry are asking ourselves.”

It is curious that most of us think if we damage something it is our responsibility to make it right. Somehow that logic is lost here. Perhaps this is a good argument that corporations are not people.

In the Marcellus, Katherine Klaber, head of the Marcellus Shale Coalition, an industry funded public relations entity, stated:

“Businesses are looking at the return on the significant investment to explore and extract a resource and their overall costs, including what they’re being asked to pay in taxes and fees. Governments are looking at it from kind of the other side of that coin, which is how much can we extract revenue for government needs and position this revenue in a politically salient way. Those two perspectives often result in a real mismatch of interests.”

So did I understand this correctly? Did Ms. Klaber just admit that if her industry had to pay all the associated costs “to explore and extract a resource” then their return on investment would most decidedly be “a real mismatch of interests”?

Unfortunately, after engaging in such rhetoric industry, without fail, pulls out its trump card. If you continue to burden us, they argue, with your tiresome threats of taxes and impact fees for the damage we have done, we will simply move our operations to another state where they like us (hint: call their bluff here because those “states” are becoming harder and harder to find). This is the adult equivalent of threatening to take your marbles and go home.

If this industry refuses to take responsibility for the damage they have done then someone should help them pack and politely open the door. It will save the taxpayers billions.

The University of Texas (UT) issued a press statement recently about a new report examining production data from the Barnett shale in North Texas. Pro-Industry groups proclaimed the report as definitive proof of the abundance of natural gas in the U.S. and its ability to sustain not only domestic demand but also exportation capacity. While this is typical of the bullish sentiments surrounding shale gas in some circles, there are certainly underlying anomalies in the report which need to be addressed before such proclamations can truly be made.

Firstly, UT’s release states:

“The data in the model stop at the end of 2010, after approximately 15,000 wells were drilled in the field.”

It seems curious that UT scientists chose a data set which is several years old. Other independent analyses have examined data which runs up through September 2012, nearly a full two additional years. One such analysis, conducted by J. David Hughes for the Post Carbon Institute, examined well production for this longer time frame and concluded that the Barnett has an annual field decline rate of approximately 30%. Based on this more current data, Dr. Hughes has stated that the UT decline projections are “over-optimistic”.

Secondly, as the UT study admits, production peaked in the Barnett at the end of 2011, a year after their chosen data set. So none of this new information is included.

And thirdly, Dr. Scott Tinker, lead investigator and director of UT’s Bureau of Economic Geology, admitted that there is a great discrepancy in well performance with many wells significantly underperforming. It is well known now that shale fields cannot sustain production levels without resort to continuous and prolific drilling. Dr. Tinker acknowledged this phenomenon. According to MoneyNews, he is quoted:

“To get all of the gas that the pro-energy groups want to develop will require tens of thousands of new wells in rural and urban parts of the country”.

This, of course, raises the spectre of environmental concerns, aquifer depletion and encroachment.

Fourthly, it is interesting to note that this study confirms operators have indeed substantially over-estimated reserves. A point which has been entirely glossed over by pro-industry groups. And is not mentioned in the least in UT’s release. Dr. Tinker’s team estimates the average EUR for a Barnett well to be about 1.44 Bcf rather than the 3.0 Bcf claimed by many operators, a significant revision.

And lastly, it is admitted that industry was asked to comment on the chosen methodology. According to the UT press release:

“Scientists and engineers from two of the larger producers in the Barnett — Devon Energy and ExxonMobil — offered critical feedback on the methodology…”

Unfortunately, one has to ask the question whether two of the largest players who have significant monetary interests in the Barnett would truly give reliable advice on methodology, particularly when it supported an optimistic perception using outdated production numbers.

One of the primary metrics used to assess an oil and gas company is its reserve replacement ratio. Investors use this as an indicator of operating performance, good or bad. It is a relatively simple metric which measures the amount of proved reserves added relative to the amount of hydrocarbon produced. So if the ratio falls below 1:1 for instance, then the company is depleting its own reserves and will eventually run out of oil. For these reasons, Exxon Mobil’s announcement of the underlying components of its 2012 ratio is grounds for alarm.

According to the company press release:

“Exxon Mobil Corporation (NYSE:XOM) announced today it replaced 115 percent of its 2012 production by adding proved oil and gas reserves totaling 1.8 billion oil-equivalent barrels, including a 174 percent replacement ratio for crude oil and other liquids.”

This sounds great on the surface which is precisely what press releases are designed to do. But a closer inspection is warranted because down in the body of the release it is admitted that:

“Reserve additions in 2012 from the liquids-rich Woodford and Bakken plays in the United States totaled almost 750 million oil equivalent barrels.”

So approximately 40% of the replacement reserves (750 million of 1.8 billion) for the world’s largest oil and gas company are coming from two unconventional plays with known exceedingly steep declines and short lives.

Since the Woodford play has already dropped from 84 rigs a few years ago to a mere 4 today and production is plummeting like the proverbial lead balloon, it is not worth examining. So let’s examine actual data from the Bakken.

Several independent assessments have been released on the Bakken in the past few months. A recent report by the Post Carbon Institute examined production data on approximately 60,000 wells in every shale play in the U.S. including the Bakken and the following characteristics of the play emerged:

“Bakken wells exhibit steep production declines over time….The first year decline is 69 percent and overall decline in the first five years is 94%. This puts average Bakken well production at slightly above the category of “stripper” wells in a mere six years, although the longer term production declines are uncertain owing to the short lifespan of most wells.”

So Exxon Mobil is relying heavily on two fields, one of which is already in steep decline and the other with wells that have exhibited the propensity to be at “stripper well” status in a mere 6 years, 94% played out by year five.

And it gets worse.

PCI continues:

“The yearly overall field decline rate is about 40 percent…The lack of growth in IP’s (initial potential) in new wells indicates that the increases from “better” technology have [already] been achieved and the sweet spots have been located and are being drilled off. These are the symptoms of an early-middle-aged shale play.”

Is it any wonder that financing could not be obtained for building the pipeline infrastructure out of the Bakken? Industry has committed to shipping the crude by rail at three times the cost instead. A pipeline simply would not pay for itself. Further, by the time it was built, the play would be done. Based on EIA estimates of available well locations left to drill plus existing wells, this yields calculations which, according to PCI, estimate the average well production for the entire play to fall to stripper well status by 2022 or less than 10 years. Further, these calculations are corroborated by the USGS estimates as well.

And yet Rex Tillerson, CEO of Exxon Mobil stated in the press release:

“Replacing production with new sources of oil and gas enables ExxonMobil to develop new supplies of energy that will be critical to support future demand, economic growth and improved living standards.”

Replacing production would indeed support future demand, economic growth and improved living standards if it was long lived and exhibited consistency. The fact that the world’s largest oil and gas company is reduced to relying on such fields for a significant portion of their reserve replacement is alarming at best.

As one geologist put it: these companies appear to be in slow liquidation.