What Kind of Umpire Is the Pennsylvania Public Utility Commission?

The Social Psychology of Organizing (Weick 1979) is a classic, cited more more than 12,700 times according to Google Scholar. The book opens with a series of vignettes about organizational events. One of my favorites is about balls and strikes:

“The story goes that three umpires disagreed about the task of calling balls and strikes. The first one said, ‘I calls them as they is.’ The second one said, ‘I calls them as I sees them.’ The third and cleverest umpire said, ‘They ain’t nothin’ till I calls them.'” (Simons 1976: 29 as cited in Weick 1979: 1).

What are we to make of this quote? Of course a number of interpretations are possible. But one straightforward interpretation is that the three umpires operate from different ontologies. Or as Michel Callon (1998) proposed: ontologies vary. In this case, the first umpire might be called a positivist; the second an interpretivist; the third a constructivist. Or to be more alliterative: realist, relativist and relationalist.

I thought of this illustration while reading StateImpact Pennsylvania’s description of the Pennsylvania Public Utility Commission (PUC). Among other things the PUC is responsible for assessing fees on spud unconventional gas wells under Act 13 of 2012. In this regard, Pennsylvania Senate President Pro Tem Joe Scarnati, “who shaped the majority of the impact fee, has said he envisions the commission serving as an umpire, ‘calling the balls and strikes’ of whether local regulations fit within the law’s framework.”

That got me thinking: Just what kind of umpire is the PUC?

What Counts as an Unconventional Gas Well Spud?

As I have delved deeper into Act 13 of 2012, I’ve realized that one critical question is: what counts as an unconventional gas well spud?

According to Act 13 an unconventional gas well fee is “imposed on every producer and shall apply to unconventional gas wells spud in this Commonwealth regardless of when spudding occurred. Unconventional gas wells spud before the fee is imposed shall be considered to be spud in the calendar year prior to the imposition of the fee… (Ch. 23 §2302(b)).”[1]

The population of wells liable for these fees is circumscribed by three interdependent definitions (see Ch. 23 § 2301). First, a spud is “the actual start of drilling of an unconventional gas well.” Second, an unconventional gas well is “a bore hole drilled or being drilled for the purpose of or to be used for the production of natural gas from an unconventional formation.” Third, an unconventional formation is “a geological shale formation existing below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval where natural gas generally cannot be produced at economic flow rates or in economic volumes except by vertical or horizontal well bores stimulated by hydraulic fracture treatments or by using multilateral well bores or other techniques to expose more of the formation to the well bore.”

Criterion 1: Formation Geology

One critical determinant of unconventional gas well fees is formation geology – wells spud in shale formations below the base of the Elk Sandstone or its stratigraphic equivalent. The Elk Sandstone is late Devonian-age, or more than 360 million years old (Ma) (Carter, 2007). Accordingly, shale formations older than the Elk Sandstone qualify as unconventional formations under Act 13. In Pennsylvania, at least 12 formations containing 19 different shale members meet this requirement according to recent subsurface nomenclature (see Table 1).[2]

Table 1. Shale Formations in Pennsylvania Below the Elk Sandstone


Source: Gehman et al., 2012

Criterion 2: Well Timing

The second determinant of unconventional gas well fees is well timing – any unconventional well spud regardless of when spudding occurred. Devonion-age shales have been spud in Pennsylvania since at least 1860, the year after the famous Drake well. Since the 1880s, formations older than Upper Devonian-age have been drilled, with at least 36 wells drilled to the Marcellus Formation or deeper before 1930 (Fettke, 1950).

For instance, in 1889 the Presque Isle Natural Gas Company drilled a well to the Trenton Limestone (i.e., penetrated all 12 formations listed in Table 1). Starting in 1930, exploration of formations older than Upper Devonian grew dramatically, with 559 such wells drilled from 1930-1949 and another 1,391 drilled from 1950-1959 (Fettke, 1950, 1956; Lytle et al., 1961).[3] Thus, Act 13 requires that fees be imposed on unconventional gas wells drilled, even as far back as 1860, with a subset of these wells more visible and prevalent from 1930 onward.

Criterion 3: Spud Interval

The final determinant of unconventional gas well fees is spudding – the start of unconventional gas well drilling. In the oil and gas industry spudding is clearly differentiated from completion and production, both of which are activities that can only occur, if at all, after spudding. Indeed, not all spud wells are completed or placed in production.

By anchoring its definition of an unconventional well on spudding, Act 13 requires that unconventional gas wells be identified without reference to completion or production activities – as wells may never undergo such activities. But in that case, how does one differentiate unconventional and conventional wells, as both are essentially identical at the start of drilling?

Option 1 is to differentiate between two spud dates – the start of surface drilling and the start of subsurface unconventional shale drilling. Thus, unless and until a well penetrates a shale formation below the Elk Sandstone or its stratigraphic equivalent it would not qualify as an unconventional gas well spud. Although Act 13 does not explicitly distinguish between surface and subsurface drilling, this distinction is implicit in the Pennsylvania Department of Environmental Protection’s (DEP) (2012a) interpretation of Act 13:

An unconventional gas well is a well that is drilled into an unconventional formation, which is defined as a geologic shale formation below the base of the Elk Sandstone or its geologic equivalent where natural gas generally cannot be produced except by horizontal or vertical well bores stimulated by hydraulic fracturing.

In other words, once a well is drilled into a shale formation below the Elk Sandstone it counts as an unconventional gas well. Because one or more unconventional shales (i.e., formations 1 through 3 in Table 1) occur throughout the areal extent of Pennsylvania’s extant oil and gas production, the population of wells liable for unconventional gas well fees under this interpretation would minimally include any wells that penetrate the Tully Formation, as there is no way to reach this formation without first going through (i.e., spudding) an unconventional shale. By way of example, all 1,986 deep wells known to have been drilled before 1960 would owe unconventional gas well fees under this interpretation, plus any similar wells drilled since then. Additionally, any wells spud in the three formations described above would be liable for fees, whether or not they reached the Tully Formation.

Option 2 is to only count wells as unconventional spuds if the formation targeted for production is an unconventional formation. In other words, spudding an unconventional shale formation en route to a deeper formation would not automatically result in unconventional well fees. Instead, only in cases where the intended production formation contained shale would the well be liable for unconventional gas well fees. Under this interpretation any wells ultimately spud in any of the 12 formations listed in Table 1 would owe unconventional gas well fees.

Finally, for analysis purposes only, Option 3 would entail counting wells that have been spud and completed in an unconventional shale formation. This is a far more stringent standard than Act 13 requires, and thus, violates its requirements. Nonetheless, such an approach may be analytically useful in establishing the minimum number of unconventional well spuds that any complete analysis would have to exceed to be credible. Said another way, any report from the DEP to the Pennsylvania Public Utility Commission (PUC) with less than this number of wells is necessarily deficient.

Together these three criteria – geological age, well timing, and spud interval – determine the population of wells subject to unconventional gas well fees under Act 13 of 2012. The scope of these requirements can be visualized by constructing a matrix of the 12 formations by the 152 years (1860-2011) over which unconventional gas exploration in Pennsylvania has potentially occurred, resulting in a total of 1,824 formation-years.

In sum, it is not possible to calculate the total unconventional gas well fees due under Act 13 without first determining the number of unconventional wells spud in each and every one of these 1,824 formation-years. Obviously, the results of this calculation are likely to vary considerably depending on which of the three spud interpretations is utilized.

[1] Under Act 13 the PUC is responsible for determining the fee an operator owes based on several factors, including whether the well is vertical or horizontal, the average annual price of natural gas, the age of the well, and potentially, the urban consumer price index if the number of wells drilled in the current exceeds the number drilled in the preceding year.

[2] This nomenclature was not necessarily operant historically, as a result, any analysis must also consider alternative designations for these formations over time. For instance, the Medina Group (Carter, 2007) was known as the Albion Formation (e.g., see Fettke, 1950) until as late as 1995 (Ryder, 2004).

[3] It is worth noting that already by the middle of 1954, hydraulic fracturing was “used extensively” in Pennsylvania, including in wells to the Oriskany and Medina Formations, among others (Moore, 1955).

DEP May Have Omitted at Least $49 Million in Medina Group Unconventional Well Fees

This post continues my series on unconventional wells that have been omitted from the Pennsylvania Department of Environmental Protection’s Act 13 reporting, with a look at wells in the Medina Group. In Northwestern Pennsylvania the Medina Group consists of three lower Silurian-aged members: Grimsby Sandstone, Cabot Head Shale, and Whirlpool Sandstone.

Figure 36 of Oil and Gas Developments in Pennsylvania in 1987 provides summarized records of 391 well completions that penetrated formations of Middle Devonian age or older (i.e., to the Marcellus Formation or lower). The majority of these wells were categorized as producing from the Medina Group. Details on the depths to and thicknesses of each of these three members, together with the depths of the producing interval, were provided for approximately 350 Medina Group completions. Using these data it is simple (if tedious) to calculate whether or not the Cabot Head Shale was completed. If my math is correct, 198 out of 350 Medina Group wells were completed in the Cabot Head Shale.

The Appalachian Basin Tight Gas Reservoirs Project, a three-year project sponsored by the U.S. Department of Energy and undertaken by the West Virginia Geological and Economic Survey and the Pennsylvania Geological and Topographic Survey, reported on 10,906 Medina completions in Pennsylvania through approximately 2007. Assuming the ratio of Cabot Head Shale to Medina Group wells from 1987 holds for other time periods, this would suggest approximately 6,170 Cabot Head Shale completions.

This is significant, because any well completed in the Cabot Head Shale meets Act 13′s definition of an unconventional well, and thus, is required to pay unconventional impact fees. Assuming these wells were all vertical, that would be a fee of at least $8,000 for 2011, or a total of more than $49 million in impact fees due under Act 13. And yet, none of these wells were included in the Pennsylvania Department of Environmental Protection’s reports to the Pennsylvania Public Utility Commission as required by Act 13.

As startling as this oversight is, the above estimate likely understates the number of Medina Group wells liable for unconventional impact fees. First, I have been overly conservative in my calculations —  only including wells that explicitly completed the Cabot Head Shale. In many cases the wells reported in 1987 were completed to within a foot or so of the Cabot Head Shale. Because the Medina is generally more than 2,000 feet below the surface, any hydraulic fracturing of the Grimsby Sandstone or the Whirlpool Sandstone will grow vertically, and therefore, penetrate and produce from the Cabot Head Shale. In that case, the number of unconventional wells may include every Medina Group well ever completed. If so, the impact fees due under Act 13 would grow to more than $87 million.

Second, I have only reported on completed wells, but Act 13 requires that impact fees be paid on all spud unconventional wells. A well is spud the moment drilling begins. As a consequence, the number of spud wells is likely to be meaningfully higher than the number of completed wells, but so far I have not found a data source that would allow me to reliably estimate the ratio of spud wells to completed wells for the Medina Group during this time period. Whatever this ratio turns out to be, it simply adds to the magnitude of the reporting failures by the Pennsylvania Department of Environmental Protection.

Third, to estimate the total population of Medina Group wells I used the well database generated by the Appalachian Basin Tight Gas Reservoirs Project. But it is likely that this is actually not the population of Medina wells, but only a sample of them. To the extent that more than 10,906 Medina wells were spud in Pennsylvania in the Cabot Head Shale, then my estimate of the impact fees due is too low.

In sum, my analysis suggests the operators of Medina Group wells collectively owe a minimum of $49 million to $87 million in unconventional well impact fees under Act 13, and the total could be much higher. And yet none of these wells has been reported as required by the Act.

More Early Unconventional Wells

This post continues my series on unconventional wells that have been omitted from the Pennsylvania Department of Environmental Protection’s Act 13 reporting, with a look back at some wells from 1979-1981.

Commenting on this period, Patchen et al. (1982: 1958) write: “The Devonion shales of Pennsylvania, which have produced gas (normally in uncommercial quantities) since 1860, were the target of several successful drilling attempts in 1981.” These drilling attempts resulted in “three new pools discovered in the deeper shale zones, including the Upper Devonian West Falls, Sonyea, and Genessee formations, and the Middle Devonian Marcellus Formation.”

According to the Pennsylvania Geological Survey’s Subsurface Rock Correlation Diagram (Carter, 2007), the West Falls Formation includes the Rhinestreet Shale; the Sonyea Formation includes the Middlesex Shale; the Genessee Formation includes both the Geneseo Shale and the Burket Shale; and of course, the Marcellus Formation includes the Marcellus Shale. All five of these shales are stratigraphically below the Elk Sandstone, and thus, any wells drilled into these formations are subject to unconventional gas well fees under Act 13, CHAPTER 23 § 2302.

One of these wells was the Combustion Engineering Fee #1 well (Permit #003-20980), drilled in Allegheny County on March 25, 1979, and completed that year in the Marcellus and Genesse formations. According the Pennsylvania Department of Environment Protection’s Oil and Gas Reporting website, this well was still producing gas 365 days a year in 2005, 2007 and 2008. But contrary to Patchen et al.’s (1982) report, the well is reported as “N” in the Marcellus Well field.

UPDATE: On February 4, 2015, I received the following email about the Combustion Engineering Fee #1 well.

Joel – Per this article you wrote I was the PM on the job working for Combustion Engineering at the time, and I somehow found this article. The well was fully DOE funded, the only Marcellus we did on it was to do one fracture, at 7,509 feet, that number sticks with me, take a sample to Mellon Institute for testing, and we then re-fractured at the higher sands in order to get enough gas out to heat the facility. The shale was way too tight for 1979 technology! Just thought you may want to know since your article notes there is really no record of Marcellus Production.
Thanks – Bob Necciai

Another two wells were drilled in Clarion County: the Conner #1 well (Permit #031-2076) and the Minich #2 (Permit #031-20864). Both wells were drilled by Gearhart and Odell and completed in the West Falls, Sonyea and Genessee formations (meaning the Rhinestreet, Middlesex, Geneseo and Burket shales). According to the Pennsylvania Department of Environment Protection Oil and Gas Reporting website, the Conner #1 produced gas in 2002, 2004 and 2005. However, these wells were not reported to the Pennsylvania Public Utility Commission by the Department as required by Act 13. I’ve added all three wells to the spreadsheet of missing Act 13 unconventional wells.

Finally, Patchen et al. (1982: 1980) report on three failed exploratory wells drilled to the Helderberg Group and another drilled to the Hamilton Group. Very possibly, these four wells are also liable for Act 13 unconventional gas well fees. The Hamilton Group includes the Marcellus Shale and the Helderberg Group includes the Mandata Shale. These wells included Permits MCK-39885, SOM-20103, TIO-20104 and WES-21705.

How Many Unconventional Wells Not Reported?

In a series of previous posts, I identified early Marcellus shale completions by various operators in Erie and Washington Counties, early Rhinestreet shale completions by Wainoco Oil and Gas Company (now HollyFrontier Corporation) in Crawford County and early Rhinestreet shale completions by Great Lakes Energy Partners (now Range Resources) in Crawford County.

Although these wells appear to meet the definition of an unconventional well under Act 13, CHAPTER 23 § 2302, as of April 2, 2012, none were reported by the Pennsylvania Department of Environmental Protection to the Pennsylvania Public Utility Commission as liable for impact fees, an apparent violation of Act 13.

In an effort to begin documenting these missing “legacy” wells in a more systematic and structured fashion I have started a small spreadsheet. To date, I have identified more than 200 legacy wells that likely meet Act 13’s definition of an unconventional well, all drilled prior to Range Resource’s “discovery” of the Marcellus shale in 2003-2005. If you are interested, I have posted these to a Google Spreadsheet.

Assuming the wells in question were vertical and not horizontal, these numbers, if correct, imply about $1.7 million in under-reported impact fees. If I were an elected official in one of the affected counties or municipalities (e.g., Crawford, Erie), this is something I would probably want to look into a bit more closely.

Two More Rhinestreet Completions

This post is a continuation of my research on “legacy” unconventional gas wells in the Marcellus formation and Rhinestreet formation.

In August 2001, Great Lakes Energy Partners LLC (now Range Resources Appalachia) drilled two wells in Crawford County, Pennsylvania, both of which penetrated the Rhinestreet shale — the W. Stein No. 2 well and the S. Preston No. 8 well.

Both of these wells appear to meet the definition of an unconventional well as stipulated by Act 13. But as of April 2, 2012, neither of them were included on the Pennsylvania Department of Environmental Protection’s Pennsylvania Public Utility Commission Act 13 Unconventional Wells Spud Report. In fact, despite the apparent history of unconventional well drilling in Crawford County, not a single well from Crawford County is included on the list of unconventional wells.

Early Rhinestreet Shale Completions

In an earlier post I described some examples of Marcellus wells drilled in Pennsylvania during the early 1980s, and speculated that these wells may be liable for impact fees under Act 13.

In particular, the language of Act 13, CHAPTER 23 § 2302, is quite unambiguous. Regardless of when spudding occurs, an impact fee is to be imposed on every producer of unconventional gas wells, which the Act defines as wells targeting “a geological shale formation existing below the base of the Elk Sandstone or its geologic equivalent stratigraphic interval…”

Considering the potential magnitude of the impact fees related to such “legacy” unconventional wells, yesterday I inquired about this issue with a Deputy Counsel at the Pennsylvania Public Utility Commission. He concurred with my interpretation of Act 13 — any wells targeting shale formations stratigraphically below the Elk Sandstone are liable for impact fees, regardless of when they were drilled — and indicated he would bring the matter to the attention of the Commission at its next meeting.

The Marcellus is not the only unconventional shale formation that oil and gas companies have targeted in Pennsylvania. The Rhinestreet shale is also stratigraphically below the base of the Elk Sandstone. An early example of such a well is the L. B. Southwick No. 1 well. This well was part of a larger project funded by the Department of Energy and the Morgantown Energy Technology Center, and contracted to BDM Corporation. Located in Rome Township, Crawford County, Pennsylvania, the Southwick No. 1 well was drilled in July 1985 by the Wainoco Oil and Gas Company, and the Rhinestreet interval was stimulated in February 1986. During this same time period, Wainoco drilled at least 105 other wells to the Rhinestreet Formation, though how many of these wells may have specifically targeted shales below the Elk Sandstone is not discussed.

Note: Wainoco Oil and Gas Company was incorporated in 1949, and changed its name to Frontier Oil Corporation in 1998. In 2011, Holly Corporation and Frontier Oil Corporation completed a merger of equals, at which point the combined company was renamed HollyFrontier Corporation (NYSE: HFC).