A few weeks ago, Jack Danchak wrote a letter to the Sullivan County Democrat touting the advantages he sees in natural gas drilling, including, among other things, income from the ad valorem tax on natural gas production facilities permitted in New York State.
The ad valorem tax is a property tax that can be imposed by New York municipalities on natural gas production facilities, to be paid by the drilling companies. There are all kinds of questions that can (and should) be asked as to whether any income from such a tax would be sufficient to offset other costs to the municipality, from damage to residential property values, to health costs, to demands placed on law enforcement and infrastructure. However, before considering those questions about the bottom-line net, it is important to take a look at the top line, and see how much the tax is likely to bring in, and how quickly it might do so.
I’ve done some preliminary research on this issue, starting with the online manual by New York’s Office of Real Property Tax Services (ORPTS, http://www.tax.ny.gov/pdf/publications/orpts/oilgasoverviewmanual.pdf). My provisional conclusion is that, given the way the tax is calculated, the current price environment, and the rapidity with which natural gas production declines, the ad valorem tax would not only take a while to click in, but could do so in such a way that drilling companies could avoid paying the tax on the majority of their production.
The ad valorem tax calculation starts with profiles created by ORPTS for each region or type of well. ORPTS bases these profiles on information provided by all the gas drilling companies in the region in question over the previous five years. From this data, it derives a Unit of Production Value (UPV), which is the net cash flow per mcf divided by a discount rate. This unit is then multiplied by the production of any given well in the year to be taxed to produce the assessed value.
The important point to note here is that to obtain the net cash flow, ORPTS subtracts various expenses including operating costs, depreciation, royalties and the like from gross income. Those who have been following natural gas prices and analysts’ commentaries on unconventional shale production costs know that this could create just a little bit of a problem.
For instance, Arthur Berman of Labryth Consulting, a Houston-based geological consulting firm, says that the breakeven point for unconventional shale drilling is around $8 or $9 per mcf. Now look at a graph of natural gas prices since 1975 (http://www.eia.gov/dnav/ng/hist/n9190us3m.htm). During that entire period, prices only broke the $7.50 level twice, once in 2005 and again in 2008, and for less than a year both times.
If Berman is right, there has never been a five-year period during which there would have been positive cash flow on unconventional shale wells. Of course, we do not know whether ORPTS would take into account all the factors Berman is looking at, and probably won’t until and unless they actually start having to do a profile. But it certainly raises a red flag.*
So what would happen if the DEC started permitting gas wells in 2013? First, the process involves a delay. It wouldn’t be until 2014 that ORPTS would collect the production data from 2013 to construct the appropriate profile; in January of 2015 ORPTS would set tentative UPV values and set hearing dates, and it wouldn’t be until May of 2015 that assessors could put the natural gas properties on their tax rolls.
Second, of course, with horizontal hydrofracking, ORPTS would have to construct a brand new profile, whether for the new formation (Marcellus) or for hydrofracking wells as a class. But of course, they won’t have a five-year history. Most likely, they will just start out with one year, go on to a two-year average in the second, and so on until they cumulate to five years. That’s how they did it with the last class they added, Trenton Black River.
But it is highly unlikely that gas prices will rise fast enough in one year that Marcellus wells will break even in 2013. And that means, the UPV for that year, should production commence in 2013, could very well be 0. In that case, it will not be possible to tax the wells in that year. Indeed, on the basis of the natural gas price chart referred to above, there is a real possibility that the UPV will remain at zero for several years
Meanwhile, wells will be producing gas. And because production drops sharply in the initial years, that means the bulk of the gas may well be extracted from the ground without the municipality being able to collect a dime.
It’s difficult to get a hard number on how severe this effect could be here because, although drilling in the Marcellus has been occurring in Pennsylvania since 2005, the state did not require companies to report production until 2010. We do know that it declines over 60% in the first year in another unconventional shale formation, the Barnett Shale, and another 50%-plus in the second year.
For the Marcellus, I found one preliminary analysis of production declines (http://www.sooga.org/studies/Marcellus%20Shale%20Decline%20Analysis%20-%202010%20-%20Brandon%20Baylor.pdf) that projects that out of 2.3 billion cubic feet produced in the first 10 years in a typical well, about a third will be produced in the first year and more than half in the first three years. If gas prices remain low for the first three years, the municipality could, in effect, forfeit its opportunity to tax the majority of that well’s value over 10 years.
Meanwhile, the town will still have to pay all the expenses incurred by hosting natural gas drilling activity. Unless prices suddenly soar through the $8-$9 per mcf level, that will leave a lot of costs that town taxpayers will be hit with. And though cash flow may rise to a taxable level at some point in the life history of the well, the majority of the well's production value may avoid taxation altogether.
Certainly, there are a number of unknowns here. We need to get more reliable estimates of actual production declines in the Marcellus Shale, for instance. And it would be nice to get some idea of whether ORPTS net cash flow calculations include the various factors Berman is including when he comes up with his $8 or $9 per mcf break-even point. But we think the above considerations, at the very least, should alert municipal officials to the fact that the ad valorem tax may not necessarily be a panacea for a town’s financial woes. Local towns should not let themselves be lured by the tax into hosting an activity that will impose expenses for which they find out too late they cannot be reimbursed.
*Those who are not familiar with the work of Berman, Deborah Rogers et al might be wondering why gas drilling companies should continue to drill if they have a negative cash flow. The answer is that they don’t make their money from selling gas; they make it from flipping leases, expanding and overvaluing their reserves to raise their book value and selling equity. It’s a shell game.