Fracking: Economic and Environmental Considerations

If the market price for natural gas in the United States remains at its current level for any length of time, can shale gas resources currently under lease be exploited economically? Given variations in lease terms and numerous other factors, the answer may well be no. To understand why this is so, an explanation of the economic facts of life in shale gas production is in order. As in most things, it all comes down to costs versus revenues.

As far as costs are concerned, there are three basic components to the cost equation (at least from the producers’ point of view): (1) the cost of obtaining the drilling rights, generally referred to as the “signing bonus”; (2) the royalties paid on the amount of gas produced; and (3) the cost of drilling and operating the extraction wells.

Regarding the cost of obtaining drilling rights, historically, in order to secure drill rights, a production company (or a “landsman” (who can be a man or a woman), a middleman between the production company and the property owner) offered a per-acre payment commonly known as a signing bonus to the holder of the mineral interest. Prior to 2000, signing bonuses in Ohio, Pennsylvania, New York and West Virginia, where the shale formations that are rich in natural gas – including the Utica and Marcellus – are located, ranged from $2 to $5 per acre. As speculative interest in shale gas production in the eastern United States grew, that number jumped to $30 per acre in 2005. By 2008, production companies were paying more than $2,000 per acre. Today, signing bonuses ranging from $5,000 to $10,000 or more per acre are being offered.

In contrast, in the United States, “royalties” are the share of the gross (not net) production income realized by the production company from the sale of oil and gas produced by a well that the producer pays to the mineral rights holder (usually in lieu of payment of the per-acre signing bonus once production commences). Historically, in the eastern United States, oil and gas royalties were in the range of 12 to 14 percent. Some states, such as New York and Pennsylvania, require by statute that the producer pay the mineral holder a minimum royalty of 12.5 percent. Again, as speculative fever grew over the exploitation of the shale plays, so, too, did the royalty amounts the producers agreed to pay. In Bradford County, Pennsylvania, it is reported that one production company recently offered a 20 percent royalty to secure oil and gas rights.

Regarding production costs, the cost of producing oil or gas from any of the shale plays is high – much higher than the cost of producing oil and gas from a conventional (vertical) well. This is so for a variety of reasons. First, the shale plays involved are several thousand feet deeper than many of the geological formations from which conventional wells historically extracted oil and gas (at least in the eastern United States). The deeper the well, the more expensive it is to drill. More importantly, the effective porosity of the shale formations involved is relatively nil. A layman’s definition (without the mathematics) of the term “effective porosity” is the number of pore spaces in the rock formation that are interconnected, such that fluid flow through the pore spaces in the formation may be readily induced. The pore spaces in the Utica, Marcellus and other shale formations that have garnered so much attention are largely not connected, rendering the formations “tight” in geological parlance – fluid flow cannot be readily induced.

To overcome this porosity problem, companies drilling wells into the shale plays combine vertical well drilling techniques with horizontal drilling techniques that only came into common use in the last decade. Also used is a process for fracturing, also known as “fracking” or “hydrofracking,” the shale formation through the injection of high-pressure water laced with sand and other ingredients to keep the pore spaces from closing once the “fracking fluids” are extracted. This interconnects the pore spaces so that fluid or gas flows freely through the formation. First, a vertical well is drilled down to the depth of the targeted shale formation (a mile or more below ground level in most instances in the eastern United States). Then the drill bit turns horizontally, parallel to the earth’s surface, creating a horizontal well. After that, the high-pressure fracking fluid is introduced to fracture the shale formation. Once the fracking fluid is withdrawn, the gas or oil extraction process can begin.

All of this is much more expensive than conventional oil and gas drilling techniques. While a conventional well might cost $1 million to install, a well placed into one of the shale plays utilizing these various techniques may cost several times that.

Moreover, there are other costs above and beyond the costs to drill the vertical and horizontal components of the well and to inject fracking fluids to fracture the target formation that are more than de minimis. The cost of constructing and maintaining the surface installations necessary to support hydrofracking, including huge retention basins for the storage of the fracking water, is not insignificant, nor is the raw materials cost (cost of fracking water, etc.). The total drilling area involved in a hydrofracking well (or series of wells) is also much larger than the total area involved in a conventional drilling operation, which leads to additional leasehold, maintenance and other costs.

That is the (admittedly) simplified cost side of the equation. As far as the income side is concerned, due to the increasing supply of natural gas in the United States (owing in large measure to gas production from fracked wells installed during the past decade, as well as a drop in demand because of the economic decline over the last several years), wellhead prices for natural gas in the United States have dropped to a 30-year low. In 1980, the average wellhead price for natural gas in the United States was $1.71 per 1,000 cubic feet (MCF). In 2012 dollars, that is $3.31 per MCF (applying the Consumer Price Index). In March 2012, reported U.S. wellhead gas prices averaged $2.50 per MCF, having climbed as high as $13.00 per MCF in 2008 when the shale gas boom was significantly under way. Since March 2012, wellhead gas prices have declined even further. Even if the industry estimate that a wellhead price of $8.00 per MCF is necessary for a gas well to break even is off by more than half, it is plain that escalating costs coupled with dropping gas prices means that it may not be economically feasible to develop shale gas resources currently under lease, at least for the present.

There are other complicating factors that should be considered. The first is that, unlike conventional wells drilled into other strata, preliminary production data suggest that wells placed in shale plays employing hydrofracking techniques produce as much as 70 percent of the total recoverable gas within the first year or two of production, and most of what remains by the end of year three or four. As more and more of these wells come into production, the market will be flooded with supply, thereby further depressing wellhead prices.

A countervailing consideration may be that no one really knows for sure how much gas or oil can be recovered from the various shale plays, or for how long. The U.S. Department of Energy estimates for the Marcellus shale alone have ranged from 410 trillion cubic feet to 141 trillion cubic feet of gas. In contrast, the U.S. Geological Survey estimates that the Marcellus shale formation contains 84 trillion cubic feet of undiscovered natural gas. The explanation for these wildly divergent estimates is either that hard data are unavailable or those who have such data aren’t telling.

While supply uncertainty is always a factor in commodities pricing, this range of uncertainty may be beyond expected levels and may reduce the number of producers willing to enter into the leasing and production competition currently raging in the oil and gas fields of western Pennsylvania and eastern Ohio.

A third complicating factor is that as of the date of this writing, New York remains out-of-bounds for hydraulic fracturing. Whether the New York moratorium is lifted will have a definite impact on wellhead pricing, although not for several years.

Valuing Oil and Gas Mineral Resources In Situ

The basic problem with placing a value on natural gas resources in situ is that there is no good way to project how much recoverable gas is in any of the shale plays, at least not with any proven degree of reliability. Industry experience gained since oil was first discovered in the United States in the mid-1800s has afforded some basis for calculating reserves, but the problem is that the oil and gas industry’s experience is in conventional oil and gas production from deposits that are not bound up in tight shale formations that must be fracked in order to produce commercial quantities of oil or gas. Hydrofracking wells throughout the various shale plays in the United States is a relatively recent phenomenon, and a relatively few number of such wells (in comparison with all other wells drilled in the United States) have come into production. While exploratory wells have been drilled to allow production companies to gauge the possible extent of recoverable oil or gas in the Barnet, Utica, Marcellus and other shale plays, they have been fairly tight-lipped about their data.

This problem is especially acute for those who want to place a value on companies involved in the leasing and extraction of oil or natural gas from any of the shale plays, such as potential investors.

To address this problem, at least from the potential investor’s perspective, on December 31, 2008, the U.S. Securities and Exchange Commission (SEC) adopted amended rules to modernize oil and gas reporting in general, and the valuation of in situ reserves in particular, the first such amendment in more than 25 years. These rules became effective for registration statements filed on or after January 1, 2010 and for Form 10-K and 20-F annual reports for fiscal years ending on or after December 31, 2009. They include the following provisions:

  • In estimating reserves for disclosure purposes, an oil and gas company will use a 12-month average of the closing prices for the commodity on the first day of each of the 12 months preceding the end of the company’s fiscal year.
  • Oil and gas companies will be permitted, but not required, to disclose probable and possible reserves.
  • Companies that produce oil and natural gas from nontraditional or unconventional sources, such as bitumen extracted from oil sands and oil and gas extracted from coal and shale, may report these resources as oil and gas reserves.
  • Oil and gas companies may use any “reliable technology” to establish reserves volumes in addition to those established by production and flow test data.
  • Oil and gas companies may classify proved undeveloped reserves any distance from known proved reserves (rather than only in immediately offsetting units), based on a “reasonable certainty” standard.
  • An oil and gas company that discloses that a third party prepared or audited its reserves estimates or conducted a process review must file with the SEC a prescribed report of the third party.
  • Oil and gas companies must disclose generally the internal controls used to ensure objectivity in reserves estimation and disclose the qualifications of the technical person primarily responsible for reserves estimates of any reserves audit.

However, given the oil and gas industry’s limited experience with the exploitation of gas reserves in the various shale plays, as well as the relative newness of the technologies involved, and the dearth of guidance provided by the SEC thus far, in particular concerning what it will accept as reliable technology for purposes of estimating and reporting oil and gas reserves, it remains to be seen whether these new rules, or any disclosures made under them, will provide a reliable guide to the value of the oil and gas interests producers have acquired in any of the shale plays.

Future Environmental Regulation of Fracking

A continuing complaint of the environmental community is that oil and gas production generally, and fracking in particular, is largely exempt from the provisions of most federal environmental laws and their state analogues. There is a grain of truth to this complaint. For example, when Congress enacted the Energy Policy Act of 2005, it included a provision that exempts gas drilling and extraction from the requirements of the Underground Injection Control Program of the Safe Drinking Water Act. Similarly, the Resource Conservation and Recovery Act’s definition of regulated hazardous wastes does not extend to oil and gas production wastes. Also, the Emergency Planning and Community Right-to-Know Act, the federal law that mandates reporting of hazardous materials storage and releases at industrial sites, exempts oil and gas wells from various of the Act’s reporting obligations. The Clean Water Act, in turn, exempts oil and gas wells from storm water regulatory requirements. While the Clean Air Act requires that the emissions from small but related sources of air pollutants be aggregated for purposes of determining whether various regulatory requirements pertain, drilling sites are generally not treated as an aggravating unit for air pollution regulatory purposes. Finally, the federal Comprehensive Environmental Response, Compensation and Liability Act, the so-called “Superfund Act,” the federal cleanup statute for abandoned hazardous waste sites, expressly excludes petroleum-related wastes from the ambit of the Act.

But all of that may be changing. For example, in May 2012, the Obama administration announced new rules to bolster oversight on public lands of oil and gas drilling that uses fracking technology, including a rule that would require production companies operating on federal lands to reveal the chemical constituents of the fluids they use in fracking after they complete the process. In April 2012, the United States Environmental Protection Agency (USEPA) issued its first-ever rules governing air pollution emissions from hydraulic fracturing operations. And on November 23, 2011, USEPA announced that it was granting, at least in part, a petition filed by environmental group Earthjustice under Sections 8(a) and 8(d) of the Toxic Substances Control Act, which will require chemical manufacturers and processors to submit broad and detailed reports on all aspects of the manufacture and use of chemicals used in fracking fluids.

Ultimately, expect to see a consensus emerge somewhere between no regulation and over-regulation. The driving force, at least at the federal level, may either be an environmental incident that gains national attention, such as a series of small earthquakes that occurred in the vicinity of Youngstown, Ohio that the Ohio Department of Natural Resources (ODNR) has attributed to the injection of oil and gas production wastes in a nearby Class II well, or the unwillingness of other industrial sectors to absorb the regulatory burden posed by the lack of regulation of oil and gas wastes (both the Clean Air Act and Clean Water Act impose limits on the amount of pollution that can be released into the environment in any given area based upon the total pollution released by all contributing sources; if contributions from oil and gas operations go unregulated, other industrial sections may be forced to “overcontrol” to “pick up the slack.”).

If the feds don’t do it, the states may. While some of the exemptions from federal regulation are preemptive (i.e., barring states and localities from regulating where the feds have not), not all of them are, and those that are may fall to public pressure should anything untoward happen.

A case in point may be Ohio’s decision to impose a moratorium on underground injection wells that receive oil and gas production wastes.

Following the earthquakes near Youngstown that ODNR ultimately attributed to the injection of oil and gas production wastes into a well in the area, a moratorium on new Class II wells was imposed while ODNR studied the issue. After completing its study, ODNR announced that it would adopt rules that limited the depth of Underground Injection Control (UIC) wells, as well as imposed other regulatory restrictions (including possibly requiring the submittal of seismic survey information as part of a UIC permit application).

Whether the ultimate source is state or federal, more restrictive environmental regulatory requirements, warranted or not, are coming.