A draft version of an article published in the December 2012 issue of the journal Environmental Practice of an article claiming the PA Dept. of Environmental Protection undercounted the number of unconventional shale wells in the state, thereby forfeiting $100 million in impact fee (tax) revenue it could have collected. The DEP strongly denies it, saying the authors misunderstand the Act 13 law and what constitutes an unconventional well under that law.
This document summarizes a presentation on regulating water and air impacts from shale gas operations. It discusses the drilling, fracturing, and production processes. It then covers current federal law and regulations regarding water impacts, including EPA studies on water usage and disposal. It also discusses proposed and existing state regulations on water usage, discharge, and disposal. For air impacts, it outlines the EPA's proposed standards and regulations regarding emissions from equipment and activities at well sites.
The USGS Powell Center is conducting a study analyzing water quality data from areas experiencing unconventional oil and gas development involving hydraulic fracturing. Over 750,000 water quality samples from 110,000 surface and groundwater sites are being analyzed to describe baseline water quality, identify changes over time where sufficient data exists, and determine gaps in spatial and temporal data coverage. The goals are to better understand the impacts of energy production on water resources and inform future monitoring and research needs.
Hydraulic Fracturing and Marcellus Shale Gas 11 22 2011Michael Klein
The drilling technique of Hydraulic Fracturing has allowed natural gas producers to extract natural gas economically from deep shale formations. This innovative drilling technique has made enormous quantities of natural gas available in wide areas of the United States from Texas, Louisiana, Pennsylvania, New York, Wyoming, North Carolina, and Colorado. The drilling technique of hydraulic fracturing accounts for roughly a quarter of total natural gas production in the United States as cited by the Energy Information Administration. With the increased emphasis on the use of natural gas in our federal energy policy, there will be new regulations, processes, and resources that will be required to mitigate the risks to human health and the environment from this new drilling technique. The presentation discusses the process of hydraulic fracturing; the threats that are posed to human health and the environment, areas in the USA where the process is used with an emphasis on the Marcellus Shale formation, current and new regulations being put into place, and plaintiff challenges to the process.
This document investigates co-locating a desalination plant with the Joslin Steam Electric Station in Point Comfort, Texas to provide a drought-proof water supply for regions L and N. A reverse osmosis desalination plant is proposed that would treat 180 million gallons per day of seawater to produce 90 million gallons per day of drinking water and reject hypersaline water. Reject water and solids from pretreatment would be returned through the existing plant discharge. Environmental impacts were found to be minimal. The estimated cost of the desalinated water is $1.75 per 1000 gallons. Combining this supply with 100,000 acre-feet of existing surface water supply would provide 200,000 acre-feet
1. The document discusses recent developments regarding nuclear waste policy, including a court case challenging the NRC's Waste Confidence Decision, the recommendations of the Blue Ribbon Commission on nuclear waste management, and congressional activity.
2. The Blue Ribbon Commission recommended establishing a new consent-based process for siting nuclear waste facilities and a single-purpose organization to manage the nuclear waste program.
3. A court vacated the NRC's Waste Confidence Decision and rulemaking, requiring the NRC to further analyze the environmental risks of nuclear waste storage and disposal.
DSD-INT 2019 Keynote - A National Flood-Guidance Programme for Canada - Pietr...Deltares
Presentation by Dr. Alain Pietroniro, Executive Director, National Hydrological Service of Canada, Meteorological Service of Canada, at the Delft-FEWS User Days, during Delft Software Days - Edition 2019. Wednesday, 6 November 2019, Delft.
This document is a report from the Texas Comptroller of Public Accounts discussing water issues facing Texas. It notes that while the Earth has abundant water, only a small portion is fresh water available for human use. Texas is experiencing drought that is straining its water supplies as the population grows. The report examines different sources of Texas' water and funding for water projects. It discusses new technologies that could help maximize existing supplies and the potential for desalination to provide new sources of water. The report makes recommendations for the Texas Legislature to help ensure adequate water supplies for the state's continued growth.
S&P: How The Marcellus Shale Is Changing The Dynamics Of The U.S. Energy Indu...Marcellus Drilling News
A new report by Standard & Poor's which looks at the Marcellus Shale and the key role it's playing in the U.S. natural gas market, as well as America's larger energy picture. In many ways the Marcellus is the "king of the shale plays" and this report details why. Full of great information, including the Top 15 Marcellus producers, a breakdown of the rate of return producers make on the Marcellus vs. other shale plays, and more.
This document summarizes a presentation on regulating water and air impacts from shale gas operations. It discusses the drilling, fracturing, and production processes. It then covers current federal law and regulations regarding water impacts, including EPA studies on water usage and disposal. It also discusses proposed and existing state regulations on water usage, discharge, and disposal. For air impacts, it outlines the EPA's proposed standards and regulations regarding emissions from equipment and activities at well sites.
The USGS Powell Center is conducting a study analyzing water quality data from areas experiencing unconventional oil and gas development involving hydraulic fracturing. Over 750,000 water quality samples from 110,000 surface and groundwater sites are being analyzed to describe baseline water quality, identify changes over time where sufficient data exists, and determine gaps in spatial and temporal data coverage. The goals are to better understand the impacts of energy production on water resources and inform future monitoring and research needs.
Hydraulic Fracturing and Marcellus Shale Gas 11 22 2011Michael Klein
The drilling technique of Hydraulic Fracturing has allowed natural gas producers to extract natural gas economically from deep shale formations. This innovative drilling technique has made enormous quantities of natural gas available in wide areas of the United States from Texas, Louisiana, Pennsylvania, New York, Wyoming, North Carolina, and Colorado. The drilling technique of hydraulic fracturing accounts for roughly a quarter of total natural gas production in the United States as cited by the Energy Information Administration. With the increased emphasis on the use of natural gas in our federal energy policy, there will be new regulations, processes, and resources that will be required to mitigate the risks to human health and the environment from this new drilling technique. The presentation discusses the process of hydraulic fracturing; the threats that are posed to human health and the environment, areas in the USA where the process is used with an emphasis on the Marcellus Shale formation, current and new regulations being put into place, and plaintiff challenges to the process.
This document investigates co-locating a desalination plant with the Joslin Steam Electric Station in Point Comfort, Texas to provide a drought-proof water supply for regions L and N. A reverse osmosis desalination plant is proposed that would treat 180 million gallons per day of seawater to produce 90 million gallons per day of drinking water and reject hypersaline water. Reject water and solids from pretreatment would be returned through the existing plant discharge. Environmental impacts were found to be minimal. The estimated cost of the desalinated water is $1.75 per 1000 gallons. Combining this supply with 100,000 acre-feet of existing surface water supply would provide 200,000 acre-feet
1. The document discusses recent developments regarding nuclear waste policy, including a court case challenging the NRC's Waste Confidence Decision, the recommendations of the Blue Ribbon Commission on nuclear waste management, and congressional activity.
2. The Blue Ribbon Commission recommended establishing a new consent-based process for siting nuclear waste facilities and a single-purpose organization to manage the nuclear waste program.
3. A court vacated the NRC's Waste Confidence Decision and rulemaking, requiring the NRC to further analyze the environmental risks of nuclear waste storage and disposal.
DSD-INT 2019 Keynote - A National Flood-Guidance Programme for Canada - Pietr...Deltares
Presentation by Dr. Alain Pietroniro, Executive Director, National Hydrological Service of Canada, Meteorological Service of Canada, at the Delft-FEWS User Days, during Delft Software Days - Edition 2019. Wednesday, 6 November 2019, Delft.
This document is a report from the Texas Comptroller of Public Accounts discussing water issues facing Texas. It notes that while the Earth has abundant water, only a small portion is fresh water available for human use. Texas is experiencing drought that is straining its water supplies as the population grows. The report examines different sources of Texas' water and funding for water projects. It discusses new technologies that could help maximize existing supplies and the potential for desalination to provide new sources of water. The report makes recommendations for the Texas Legislature to help ensure adequate water supplies for the state's continued growth.
S&P: How The Marcellus Shale Is Changing The Dynamics Of The U.S. Energy Indu...Marcellus Drilling News
A new report by Standard & Poor's which looks at the Marcellus Shale and the key role it's playing in the U.S. natural gas market, as well as America's larger energy picture. In many ways the Marcellus is the "king of the shale plays" and this report details why. Full of great information, including the Top 15 Marcellus producers, a breakdown of the rate of return producers make on the Marcellus vs. other shale plays, and more.
Submission to the CNSC regarding the geological risks of the proposed deep geological repository planned to be placed along the shores of Lake Huron in Ontario. Karst moraines and geological risks, seismic risks etc. (Project cancelled)
Letter Sent by 25 Anti-Fracking Organizations to Gov. Tom Corbett on DEP Wate...Marcellus Drilling News
A letter sent by 25 known anti-drilling groups to PA Gov. Tom Corbett rehasing unsubstantiated allegations that the state Dept. of Environmental Protection withholds testing for certain chemicals that may be tied to shale gas drilling.
1. The document discusses recommendations for addressing the environmental and public health impacts of hydraulic fracturing. It outlines two policy options - mandating disclosure of fracking fluid chemicals or taxing water consumption in fracking.
2. It provides background on the history and rapid expansion of fracking since 2003. While fracking has economic benefits, there are concerns about potential long-term environmental impacts on water.
3. The first recommended policy option is to incentivize fracking companies to disclose the components of their fracking fluids to increase transparency and public trust. A six-month period would allow companies to modify potentially toxic chemicals before full disclosure is mandated.
A 119-page response submitted by Brad Gill, Independent Oil & Gas Association of New York to the NY Dept. of Environmental Conservation about the DEC's latest revision to draft fracking rules for the state. The IOGA response is highly critical of the new revisions and makes detailed recommendations on how to fix the proposed rules to ensure drilling actually happens in NY. According to IOGA, they are forced to now be "adversarial" in their stance after working closely with the DEC over the past 4.5 years on this issue.
Friends of the UNB Woodlot - 2nd Presentation to the Public Safety and Enviro...friendsoftheunbwoodlot
Friends of the UNB Woodlot made a presentation to the Public Safety and Environment Committee on April 06, 2012 this week.
Shale gas is an issue for Fredericton residents. It is an issue with the parents of children with asthma. It is an issue for a growing number of residents who read the health reports now coming out about the certainty of air pollution from shale gas operations, especially for residents living in a low-lying valley such as Fredericton. And it is an issue with the family physicians of New Brunswick who recently called on the Province for a moratorium.
We now know that the danger of air pollution is equal to the danger of water pollution. Unless you cover our city in a dome, air pollution from shale gas development that impact human health is a certainty. Known carcinogens & asthma-causing smog from shale gas wells, compressor stations, and pipelines will travel downwind over long distances and settle in low-lying valleys such as Fredericton.
Our presentation to City Council on April 10, 2012 stressed at the very beginning that our health concerns were about the shale gas development areas that surround Fredericton. The message to City Council was that with a formal ban using our zoning by-law, Fredericton City Council could push for a similar move by the Province. Fredericton has a Municipal Plan in place, and under the Community Planning Act of New Brunswick, our city has the right to make a zoning by-law or amendment against any high-impact industrial activity such as shale gas operations.
We are disappointed that our present Mayor and Council refused to take a leadership role in asking the Province for a ban or moratorium on shale gas. Our present Mayor and Council are pro-shale gas and our city is surrounded by shale gas exploration areas 10+kilometres in all directions.
In order to impose a ban on shale gas, we first need to reverse the vote already taken by the City of Fredericton. The public has been deliberately misled that the City of Fredericton has not taken a formal stand on shale gas. In fact, Fredericton voted against the shale gas moratorium resolution at the Union of the Municipalities of New Brunswick meeting last September 2011, a meeting attended by Mayor Brad Woodside and Councillor Stephen Chase. This resolution was put forward by the Town of Sackville for the Union to lobby the Province for a moratorium on shale gas but the resolution was narrowly defeated 22-to-18.
This 3-page document discusses the potential environmental and health impacts of hydraulic fracturing for shale gas extraction in British Columbia. It outlines 3 options for managing BC's shale gas reserves: 1) rapid expansion, 2) maintaining current extraction rates, or 3) a temporary moratorium. The authors recommend option 2, allowing extraction to continue at current rates in less ecologically sensitive areas, while further monitoring and studying impacts. This balances economic benefits with environmental and health risks given current uncertainties.
PennEnvironment: Marcellus Shale Gas Drilling Violiations in PA 2008-2011Marcellus Drilling News
This document analyzes environmental violations by Marcellus Shale gas drilling companies in Pennsylvania between 2008-2011. It found a total of 3,355 violations by 64 companies, with over 2,300 posing a direct environmental threat. The top violations related to erosion/sedimentation plans and pollution prevention. The companies with the most violations were Cabot Oil & Gas Corp, Chesapeake Appalachia LLC, and Chief Oil & Gas LLC. Stricter penalties, bonding requirements, and increased funding for enforcement are recommended to curb violations.
Concerns voiced for Darlington Nuclear Plant extension. Concerns of economics and environmental issues and need to review economic risks currently being externalized during the planning process.
This document contains a forwarded email discussing an op-ed published by the Competitive Enterprise Institute analyzing recent notices of intent to sue the EPA Administrator by several state Attorneys General over regulating carbon dioxide emissions under the Clean Air Act. The op-ed argues that the Clean Air Act does not give EPA authority to regulate carbon dioxide and that the Attorneys General's legal arguments are based on taking words out of context and ignoring legislative history. It concludes that regulating carbon dioxide under the Clean Air Act would be an absurd exercise that is plainly at variance with Congressional intent.
Enbridge provides a summary of its liability insurance coverage for environmental damage from pipeline releases. The coverage amounts are consistent with industry standards but are not disclosed. Enbridge reviews its pipelines for risks from factors like erosion but does not detail its mitigation strategies. In the event of a spill contaminating aquifers, Enbridge would develop a remediation plan with regulators, but the potential spill size depends on many incident-specific variables.
A letter from Dan Fitzsimmons, president of the Joint Landowners Coalition of New York (JLCNY) to NY Gov. Andrew Cuomo expressing profound disappointment that Cuomo intends to let the Nov. 29 date slip by without releasing new drilling rules to allow shale gas drilling in the state.
Letter from enviro-leftist groups requesting LPG fracking not go forward in N...Marcellus Drilling News
A letter sent by 15 environmental leftist groups to NY DEC Commissioner Joe Martens requesting that the DEC not allow waterless LPG fracking to begin in New York without filing an environmental impact statement first. They are asking, in essence, for Martens to kill a promising new fracking technology before it's even tried.
This document discusses several issues related to hydraulic fracturing including water usage, fracking fluid disclosure, infrastructure concerns, wastewater discharge, groundwater protection, and other side effects like earthquakes and air pollution. It outlines recent federal actions by the EPA to regulate air emissions and require reporting. It also discusses a study by the National Academy of Sciences on fracking and earthquakes. Finally, it provides updates on state actions and regulations in places like North Carolina, Vermont, New York, Maryland, and Mississippi regarding hydraulic fracturing and related activities.
A critique of New York's draft drilling regulations for hydraulic fracturing submitted by Judith Enck, Region 2 Administrator for the federal Environmental Protection Agency. The critique was submitted on Weds, Jan 11 just hours before the filing deadline closed at the New York State DEC.
This dissertation examines the development of hydraulic fracturing technology for shale gas extraction in the UK. The author conducts a literature review and event history analysis to understand the drivers and barriers to developing the UK's Technological Innovation System for fracking. The analysis finds that entrepreneurial activities are the main driver, while lack of public support is the main barrier. The dissertation concludes by proposing recommendations for further research that could help advance the system and inform UK energy policy decisions regarding fracking.
Texas Aquifer Exemptions - Clean Water Action august 2016John Noël
1) The document discusses aquifer exemptions under the Safe Drinking Water Act which allow oil and gas activity in underground sources of drinking water. It focuses on Texas, which has granted blanket exemptions for producing oil fields without reviewing applications or providing maps of exempted areas.
2) Through FOIA requests, the group found the Railroad Commission of Texas has not implemented the federal requirements for reviewing aquifer exemption applications and has effectively prioritized oil and gas interests over protection of drinking water sources.
3) There is no complete understanding of which aquifers in Texas are exempted. The Railroad Commission has admitted to inconsistent oversight of exemptions and permitting some injection wells into underground sources of drinking water without exemptions.
A letter written from the Independent Oil & Gas Association of New York to Dept. of Environnmental Conservation Commissioner Joe Martens telling him the newly drafted SGEIS (drilling rules) for New York are too strict and unacceptable to drillers in the Empire State as written.
Study: Estimation of regional air-quality damages from Marcellus Shale natura...Marcellus Drilling News
A study conducted by private research firm Rand Corporation. A first-order estimate of conventional air pollutant emissions, and the monetary value of the associated environmental and health damages, from the extraction of unconventional shale gas in Pennsylvania.
The arguments put forth by the American Petroleum Institute (API) against a proposed fracking rule from the Dept. of Interior's Bureau of Land Management (BLM). The API says the rule is unnecessary, duplicative of state rules, and would add a burdensome layer of bureaucracy not needed and that will not add any additional protection of the environment.
The document is an op-ed piece arguing that the EPA has no authority under the Clean Air Act to regulate carbon dioxide as a pollutant. It summarizes arguments made by state attorneys general that the CAA requires EPA to regulate CO2, and rebuts those arguments. The op-ed argues that the CAA provides authority only for specific air pollution programs, not a general climate program, and that attempting to regulate CO2 under existing CAA provisions would be an "absurd exercise in futility." It concludes the attorneys general are engaged in a "transparent power grab" to expand their enforcement authority.
The document summarizes five key facts about the recovery of US shale oil production:
1) Rig counts have increased by 90% since bottoming out in May 2016 and are up 30% year-over-year, signaling increased drilling and production capacity.
2) While decline rates remain steep, production profiles have increased substantially due to technological advances, meaning aggregate supply will be stronger.
3) Preliminary data shows that net new shale supply turned positive in December 2016 for the first time since March 2015, recovering just 7 months after rig counts increased.
4) Increased drilling activity is supported by a large stock of drilled but uncompleted wells, demonstrating the recovery and expansion of the shale sector.
5)
Quarterly legislative action update: Marcellus and Utica shale region (4Q16)Marcellus Drilling News
A quarterly update from the legal beagles at global law firm Norton Rose Fulbright. A quarterly legislative action update for the second quarter of 2016 looking at previously laws acted upon, and new laws introduced, affecting the oil and gas industry in Pennsylvania, Ohio and West Virginia.
More Related Content
Similar to Draft: An Analysis of Unconventional Gas Well Reporting Under Pennsylvania's Act 13 of 2012
Submission to the CNSC regarding the geological risks of the proposed deep geological repository planned to be placed along the shores of Lake Huron in Ontario. Karst moraines and geological risks, seismic risks etc. (Project cancelled)
Letter Sent by 25 Anti-Fracking Organizations to Gov. Tom Corbett on DEP Wate...Marcellus Drilling News
A letter sent by 25 known anti-drilling groups to PA Gov. Tom Corbett rehasing unsubstantiated allegations that the state Dept. of Environmental Protection withholds testing for certain chemicals that may be tied to shale gas drilling.
1. The document discusses recommendations for addressing the environmental and public health impacts of hydraulic fracturing. It outlines two policy options - mandating disclosure of fracking fluid chemicals or taxing water consumption in fracking.
2. It provides background on the history and rapid expansion of fracking since 2003. While fracking has economic benefits, there are concerns about potential long-term environmental impacts on water.
3. The first recommended policy option is to incentivize fracking companies to disclose the components of their fracking fluids to increase transparency and public trust. A six-month period would allow companies to modify potentially toxic chemicals before full disclosure is mandated.
A 119-page response submitted by Brad Gill, Independent Oil & Gas Association of New York to the NY Dept. of Environmental Conservation about the DEC's latest revision to draft fracking rules for the state. The IOGA response is highly critical of the new revisions and makes detailed recommendations on how to fix the proposed rules to ensure drilling actually happens in NY. According to IOGA, they are forced to now be "adversarial" in their stance after working closely with the DEC over the past 4.5 years on this issue.
Friends of the UNB Woodlot - 2nd Presentation to the Public Safety and Enviro...friendsoftheunbwoodlot
Friends of the UNB Woodlot made a presentation to the Public Safety and Environment Committee on April 06, 2012 this week.
Shale gas is an issue for Fredericton residents. It is an issue with the parents of children with asthma. It is an issue for a growing number of residents who read the health reports now coming out about the certainty of air pollution from shale gas operations, especially for residents living in a low-lying valley such as Fredericton. And it is an issue with the family physicians of New Brunswick who recently called on the Province for a moratorium.
We now know that the danger of air pollution is equal to the danger of water pollution. Unless you cover our city in a dome, air pollution from shale gas development that impact human health is a certainty. Known carcinogens & asthma-causing smog from shale gas wells, compressor stations, and pipelines will travel downwind over long distances and settle in low-lying valleys such as Fredericton.
Our presentation to City Council on April 10, 2012 stressed at the very beginning that our health concerns were about the shale gas development areas that surround Fredericton. The message to City Council was that with a formal ban using our zoning by-law, Fredericton City Council could push for a similar move by the Province. Fredericton has a Municipal Plan in place, and under the Community Planning Act of New Brunswick, our city has the right to make a zoning by-law or amendment against any high-impact industrial activity such as shale gas operations.
We are disappointed that our present Mayor and Council refused to take a leadership role in asking the Province for a ban or moratorium on shale gas. Our present Mayor and Council are pro-shale gas and our city is surrounded by shale gas exploration areas 10+kilometres in all directions.
In order to impose a ban on shale gas, we first need to reverse the vote already taken by the City of Fredericton. The public has been deliberately misled that the City of Fredericton has not taken a formal stand on shale gas. In fact, Fredericton voted against the shale gas moratorium resolution at the Union of the Municipalities of New Brunswick meeting last September 2011, a meeting attended by Mayor Brad Woodside and Councillor Stephen Chase. This resolution was put forward by the Town of Sackville for the Union to lobby the Province for a moratorium on shale gas but the resolution was narrowly defeated 22-to-18.
This 3-page document discusses the potential environmental and health impacts of hydraulic fracturing for shale gas extraction in British Columbia. It outlines 3 options for managing BC's shale gas reserves: 1) rapid expansion, 2) maintaining current extraction rates, or 3) a temporary moratorium. The authors recommend option 2, allowing extraction to continue at current rates in less ecologically sensitive areas, while further monitoring and studying impacts. This balances economic benefits with environmental and health risks given current uncertainties.
PennEnvironment: Marcellus Shale Gas Drilling Violiations in PA 2008-2011Marcellus Drilling News
This document analyzes environmental violations by Marcellus Shale gas drilling companies in Pennsylvania between 2008-2011. It found a total of 3,355 violations by 64 companies, with over 2,300 posing a direct environmental threat. The top violations related to erosion/sedimentation plans and pollution prevention. The companies with the most violations were Cabot Oil & Gas Corp, Chesapeake Appalachia LLC, and Chief Oil & Gas LLC. Stricter penalties, bonding requirements, and increased funding for enforcement are recommended to curb violations.
Concerns voiced for Darlington Nuclear Plant extension. Concerns of economics and environmental issues and need to review economic risks currently being externalized during the planning process.
This document contains a forwarded email discussing an op-ed published by the Competitive Enterprise Institute analyzing recent notices of intent to sue the EPA Administrator by several state Attorneys General over regulating carbon dioxide emissions under the Clean Air Act. The op-ed argues that the Clean Air Act does not give EPA authority to regulate carbon dioxide and that the Attorneys General's legal arguments are based on taking words out of context and ignoring legislative history. It concludes that regulating carbon dioxide under the Clean Air Act would be an absurd exercise that is plainly at variance with Congressional intent.
Enbridge provides a summary of its liability insurance coverage for environmental damage from pipeline releases. The coverage amounts are consistent with industry standards but are not disclosed. Enbridge reviews its pipelines for risks from factors like erosion but does not detail its mitigation strategies. In the event of a spill contaminating aquifers, Enbridge would develop a remediation plan with regulators, but the potential spill size depends on many incident-specific variables.
A letter from Dan Fitzsimmons, president of the Joint Landowners Coalition of New York (JLCNY) to NY Gov. Andrew Cuomo expressing profound disappointment that Cuomo intends to let the Nov. 29 date slip by without releasing new drilling rules to allow shale gas drilling in the state.
Letter from enviro-leftist groups requesting LPG fracking not go forward in N...Marcellus Drilling News
A letter sent by 15 environmental leftist groups to NY DEC Commissioner Joe Martens requesting that the DEC not allow waterless LPG fracking to begin in New York without filing an environmental impact statement first. They are asking, in essence, for Martens to kill a promising new fracking technology before it's even tried.
This document discusses several issues related to hydraulic fracturing including water usage, fracking fluid disclosure, infrastructure concerns, wastewater discharge, groundwater protection, and other side effects like earthquakes and air pollution. It outlines recent federal actions by the EPA to regulate air emissions and require reporting. It also discusses a study by the National Academy of Sciences on fracking and earthquakes. Finally, it provides updates on state actions and regulations in places like North Carolina, Vermont, New York, Maryland, and Mississippi regarding hydraulic fracturing and related activities.
A critique of New York's draft drilling regulations for hydraulic fracturing submitted by Judith Enck, Region 2 Administrator for the federal Environmental Protection Agency. The critique was submitted on Weds, Jan 11 just hours before the filing deadline closed at the New York State DEC.
This dissertation examines the development of hydraulic fracturing technology for shale gas extraction in the UK. The author conducts a literature review and event history analysis to understand the drivers and barriers to developing the UK's Technological Innovation System for fracking. The analysis finds that entrepreneurial activities are the main driver, while lack of public support is the main barrier. The dissertation concludes by proposing recommendations for further research that could help advance the system and inform UK energy policy decisions regarding fracking.
Texas Aquifer Exemptions - Clean Water Action august 2016John Noël
1) The document discusses aquifer exemptions under the Safe Drinking Water Act which allow oil and gas activity in underground sources of drinking water. It focuses on Texas, which has granted blanket exemptions for producing oil fields without reviewing applications or providing maps of exempted areas.
2) Through FOIA requests, the group found the Railroad Commission of Texas has not implemented the federal requirements for reviewing aquifer exemption applications and has effectively prioritized oil and gas interests over protection of drinking water sources.
3) There is no complete understanding of which aquifers in Texas are exempted. The Railroad Commission has admitted to inconsistent oversight of exemptions and permitting some injection wells into underground sources of drinking water without exemptions.
A letter written from the Independent Oil & Gas Association of New York to Dept. of Environnmental Conservation Commissioner Joe Martens telling him the newly drafted SGEIS (drilling rules) for New York are too strict and unacceptable to drillers in the Empire State as written.
Study: Estimation of regional air-quality damages from Marcellus Shale natura...Marcellus Drilling News
A study conducted by private research firm Rand Corporation. A first-order estimate of conventional air pollutant emissions, and the monetary value of the associated environmental and health damages, from the extraction of unconventional shale gas in Pennsylvania.
The arguments put forth by the American Petroleum Institute (API) against a proposed fracking rule from the Dept. of Interior's Bureau of Land Management (BLM). The API says the rule is unnecessary, duplicative of state rules, and would add a burdensome layer of bureaucracy not needed and that will not add any additional protection of the environment.
The document is an op-ed piece arguing that the EPA has no authority under the Clean Air Act to regulate carbon dioxide as a pollutant. It summarizes arguments made by state attorneys general that the CAA requires EPA to regulate CO2, and rebuts those arguments. The op-ed argues that the CAA provides authority only for specific air pollution programs, not a general climate program, and that attempting to regulate CO2 under existing CAA provisions would be an "absurd exercise in futility." It concludes the attorneys general are engaged in a "transparent power grab" to expand their enforcement authority.
Similar to Draft: An Analysis of Unconventional Gas Well Reporting Under Pennsylvania's Act 13 of 2012 (20)
The document summarizes five key facts about the recovery of US shale oil production:
1) Rig counts have increased by 90% since bottoming out in May 2016 and are up 30% year-over-year, signaling increased drilling and production capacity.
2) While decline rates remain steep, production profiles have increased substantially due to technological advances, meaning aggregate supply will be stronger.
3) Preliminary data shows that net new shale supply turned positive in December 2016 for the first time since March 2015, recovering just 7 months after rig counts increased.
4) Increased drilling activity is supported by a large stock of drilled but uncompleted wells, demonstrating the recovery and expansion of the shale sector.
5)
Quarterly legislative action update: Marcellus and Utica shale region (4Q16)Marcellus Drilling News
A quarterly update from the legal beagles at global law firm Norton Rose Fulbright. A quarterly legislative action update for the second quarter of 2016 looking at previously laws acted upon, and new laws introduced, affecting the oil and gas industry in Pennsylvania, Ohio and West Virginia.
An update from Spectra Energy on their proposed $3 billion project to connect four existing pipeline systems to flow more Marcellus/Utica gas to New England. In short, Spectra has put the project on pause until mid-2017 while it attempts to get new customers signed.
A letter from Rover Pipeline to the Federal Energy Regulatory Commission requesting the agency issue the final certificate that will allow Rover to begin tree-clearing and construction of the 511-mile pipeline through Pennsylvania, West Virginia, Ohio and Michigan. If the certificate is delayed beyond the end of 2016, it will delay the project an extra year due to tree-clearing restrictions (to accommodate federally-protected bats).
DOE Order Granting Elba Island LNG Right to Export to Non-FTA CountriesMarcellus Drilling News
An order issued by the U.S. Dept. of Energy that allows the Elba Island LNG export facility to export LNG to countries with no free trade agreement with the U.S. Countries like Japan and India have no FTA with our country (i.e. friendly countries)--so this is good news indeed. Although the facility would have operated by sending LNG to FTA countries, this order opens the market much wider.
A study released in December 2016 by the London School of Economics, titled "On the Comparative Advantage of U.S. Manufacturing: Evidence from the Shale Gas Revolution." While America has enough shale gas to export plenty of it, exporting it is not as economic as exporting oil due to the elaborate processes to liquefy and regassify natural gas--therefore a lot of the gas stays right here at home, making the U.S. one of (if not the) cheapest places on the planet to establish manufacturing plants, especially for manufacturers that use natural gas and NGLs (natural gas liquids). Therefore, manufacturing, especially in the petrochemical sector, is ramping back up in the U.S. For every two jobs created by fracking, another one job is created in the manufacturing sector.
Letter From 24 States Asking Trump & Congress to Withdraw the Unlawful Clean ...Marcellus Drilling News
A letter from the attorneys general from 24 of the states opposed to the Obama Clean Power Plan to President-Elect Trump, RINO Senate Majority Leader Mitch McConnel and RINO House Speaker Paul Ryan. The letter asks Trump to dump the CPP on Day One when he takes office, and asks Congress to adopt legislation to prevent the EPA from such an egregious overreach ever again.
Report: New U.S. Power Costs: by County, with Environmental ExternalitiesMarcellus Drilling News
Natural gas and wind are the lowest-cost technology options for new electricity generation across much of the U.S. when cost, public health impacts and environmental effects are considered. So says this new research paper released by The University of Texas at Austin. Researchers assessed multiple generation technologies including coal, natural gas, solar, wind and nuclear. Their findings are depicted in a series of maps illustrating the cost of each generation technology on a county-by-county basis throughout the U.S.
Annual report issued by the U.S. Energy Information Administration showing oil and natural gas proved reserves, in this case for 2015. These reports are issued almost a year after the period for which they report. This report shows proved reserves for natural gas dropped by 64.5 trillion cubic feet (Tcf), or 16.6%. U.S. crude oil and lease condensate proved reserves also decreased--from 39.9 billion barrels to 35.2 billion barrels (down 11.8%) in 2015. Proved reserves are calculated on a number of factors, including price.
The document is a report from the U.S. Energy Information Administration analyzing oil and gas production from seven regions in the U.S. It includes charts and tables showing historical and projected production levels of oil and gas from each region from 2008 to 2017, as well as metrics like the average production per rig. The regions - Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica - accounted for 92% of domestic oil production growth and all domestic natural gas production growth from 2011-2014.
Velocys is the manufacturer of gas-to-liquids (GTL) plants that convert natural gas (a hyrdocarbon) into other hydrocarbons, like diesel fuel, gasoline, and even waxes. This PowerPoint presentation lays out the Velocys plan to get the company growing. GTL plants have not (so far) taken off in the U.S. Velocys hopes to change that. They specialize in small GTL plants.
PA DEP Revised Permit for Natural Gas Compression Stations, Processing Plants...Marcellus Drilling News
In January 2016, Gov. Wolf announced the DEP would revise its current general permit (GP-5) to update the permitting requirements for sources at natural gas compression, processing, and transmission facilities. This is the revised GP-5.
PA DEP Permit for Unconventional NatGas Well Site Operations and Remote Piggi...Marcellus Drilling News
In January 2016, PA Gov. Wolf announced the Dept. of Environmental Protection would develop a general permit for sources at new or modified unconventional well sites and remote pigging stations (GP-5A). This is the proposed permit.
Onerous new regulations for the Pennsylvania Marcellus Shale industry proposed by the state Dept. of Environmental Protection. The new regs will, according to the DEP, help PA reduce so-called fugitive methane emissions and some types of air pollution (VOCs). This is liberal Gov. Tom Wolf's way of addressing mythical man-made global warming.
The monthly Short-Term Energy Outlook (STEO) from the U.S. Energy Information Administration for December 2016. This issue makes a couple of key points re natural gas: (1) EIA predicts that natural gas production in the U.S. for 2016 will see a healthy decline over 2015 levels--1.3 billion cubic feet per day (Bcf/d) less in 2016. That's the first annual production decline since 2005! (2) The EIA predicts the average price for natural gas at the benchmark Henry Hub will climb from $2.49/Mcf (thousand cubic feet) in 2016 to a whopping $3.27/Mcf in 2017. Why the jump? Growing domestic natural gas consumption, along with higher pipeline exports to Mexico and liquefied natural gas exports.
This document provides an overview of the natural gas market in the Northeast United States, including New England, New York, New Jersey, and Pennsylvania. It details statistics on gas customers, consumption, infrastructure like pipelines and storage, and production. A key point is that the development of the Marcellus Shale in Pennsylvania has significantly increased domestic gas production in the region and reduced its reliance on other supply basins and imports.
The Pennsylvania Public Utility Commission responded to each point raised in a draft copy of the PA Auditor General's audit of how Act 13 impact fee money, raised from Marcellus Shale drillers, gets spent by local municipalities. The PUC says it's not their job to monitor how the money gets spent, only in how much is raised and distributed.
Pennsylvania Public Utility Commission Act 13/Impact Fees Audit by PA Auditor...Marcellus Drilling News
A biased look at how 60% of impact fees raised from PA's shale drilling are spent, by the anti-drilling PA Auditor General. He chose to ignore an audit of 40% of the impact fees, which go to Harrisburg and disappear into the black hole of Harrisburg spending. The Auditor General claims, without basis in fact, that up to 24% of the funds are spent on items not allowed under the Act 13 law.
The final report from the Pennsylvania Dept. of Environmental Protection that finds, after several years of testing, no elevated levels of radiation from acid mine drainage coming from the Clyde Mine, flowing into Ten Mile Creek. Radical anti-drillers tried to smear the Marcellus industry with false claims of illegal wastewater dumping into the mine, with further claims of elevated radiation levels in the creek. After years of testing, the DEP found those allegations to be false.
FERC Order Denying Stay of Kinder Morgan's Broad Run Expansion ProjectMarcellus Drilling News
The Federal Energy Regulatory Commission denied a request to stay the authorization of Tennessee Gas Pipeline Company's Broad Run Expansion Project. The Commission found that the intervenors requesting the stay did not demonstrate they would suffer irreparable harm if the project proceeded. Specifically, the Commission determined that the environmental impacts to forest and a nearby animal rehabilitation center would be insignificant. Additionally, conditioning authorization on future permits did not improperly encroach on state authority. Therefore, justice did not require granting a stay.
El Puerto de Algeciras continúa un año más como el más eficiente del continente europeo y vuelve a situarse en el “top ten” mundial, según el informe The Container Port Performance Index 2023 (CPPI), elaborado por el Banco Mundial y la consultora S&P Global.
El informe CPPI utiliza dos enfoques metodológicos diferentes para calcular la clasificación del índice: uno administrativo o técnico y otro estadístico, basado en análisis factorial (FA). Según los autores, esta dualidad pretende asegurar una clasificación que refleje con precisión el rendimiento real del puerto, a la vez que sea estadísticamente sólida. En esta edición del informe CPPI 2023, se han empleado los mismos enfoques metodológicos y se ha aplicado un método de agregación de clasificaciones para combinar los resultados de ambos enfoques y obtener una clasificación agregada.
Here is Gabe Whitley's response to my defamation lawsuit for him calling me a rapist and perjurer in court documents.
You have to read it to believe it, but after you read it, you won't believe it. And I included eight examples of defamatory statements/
An astonishing, first-of-its-kind, report by the NYT assessing damage in Ukraine. Even if the war ends tomorrow, in many places there will be nothing to go back to.
04062024_First India Newspaper Jaipur.pdfFIRST INDIA
Find Latest India News and Breaking News these days from India on Politics, Business, Entertainment, Technology, Sports, Lifestyle and Coronavirus News in India and the world over that you can't miss. For real time update Visit our social media handle. Read First India NewsPaper in your morning replace. Visit First India.
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Acolyte Episodes review (TV series) The Acolyte. Learn about the influence of the program on the Star Wars world, as well as new characters and story twists.
Essential Tools for Modern PR Business .pptxPragencyuk
Discover the essential tools and strategies for modern PR business success. Learn how to craft compelling news releases, leverage press release sites and news wires, stay updated with PR news, and integrate effective PR practices to enhance your brand's visibility and credibility. Elevate your PR efforts with our comprehensive guide.
Draft: An Analysis of Unconventional Gas Well Reporting Under Pennsylvania's Act 13 of 2012
1. 1
AN ANALYSIS OF UNCONVENTIONAL GAS WELL REPORTING
UNDER PENNSYLVANIA’S ACT 13 OF 2012
Joel Gehman*
Alberta School of Business
University of Alberta
Diego Mastroianni
Desautels Faculty of Management
McGill University
Angela Grant
Faculty of Agricultural and Environmental Sciences
McGill University
Dror Etzion
Desautels Faculty of Management
McGill University
November 15, 2012
Forthcoming in Environmental Practice
* Corresponding author: 3-23 Business Building, Edmonton, AB T6G 2R6, Canada; (phone) +1-780-248-5855; (e-
mail) jgehman@ualberta.ca.
Electronic copy available at: http://ssrn.com/abstract=2196928
2. 2
AN ANALYSIS OF UNCONVENTIONAL GAS WELL REPORTING
UNDER PENNSYLVANIA’S ACT 13 OF 2012
ABSTRACT
In response to growing concerns about the impact of shale gas development,
Pennsylvania’s Act 13 of 2012 established an unconventional gas well fee and
required the state’s Department of Environmental Protection (DEP) to report on
the number of such wells. In this article, we analyze the extent to which the DEP
complied with its reporting requirements under Act 13. Using publicly available
data, we find that the DEP likely omitted between 15,300 and 25,100
unconventional gas wells from its Act 13 report. Left uncorrected, we estimate
that Pennsylvania’s state, county, and municipal governments could forfeit fees of
$205–$303 million in 2012 and up to $0.75–$1.85 billion cumulatively over the
expected life of these wells. Rather than an isolated incident, evidence suggests
that information management is a systemic and recurring problem within the DEP
and its predecessor agencies. We propose the implementation of a relational
database and geographic information system as a way for the DEP to fulfill its Act
13 obligations.
Electronic copy available at: http://ssrn.com/abstract=2196928
3. 3
Unconventional shale gas grew from just 0.8% of natural gas production in the United
States (US) in 1990 to 29.7% in 2011, according to the US Energy Information Administration
(US EIA, 2012) and could account for 60% of production by 2035 (O’Keefe, 2012). As the pace
and scale of unconventional shale gas development has accelerated, numerous environmental,
health, and informational concerns have been raised (e.g., Cahoy, Gehman, and Lei, forthcom-
ing; Colborn et al., 2011; Howarth, Santoro, and Ingraffea, 2011; McKenzie et al., 2012; Wylde
and O’Neil, 2011). At the epicenter of these issues is the Marcellus Formation, where high-
volume slickwater hydraulic fracturing has been used to extract natural gas from a 95,000-
square-mile formation underlying six mideastern states (US EIA, 2011).
The recent Marcellus gas rush started in Pennsylvania, where 1,920 new unconventional
wells were drilled in 2011, up from just 60 such wells in 2007 (Marcellus Center for Outreach
and Research, 2012).1 But even as drilling in Pennsylvania’s Marcellus Formation was booming,
new questions about its potential impacts began emerging (e.g., Johnson et al., 2010; Osborn et
al., 2011; Volz et al., 2011). As one response, Pennsylvania Governor Tom Corbett (2011) creat-
ed the Marcellus Shale Advisory Commission (MSAC) and charged it with developing recom-
mendations on all aspects of natural gas drilling. After holding 21 public meetings, hearing tes-
timony from 60 experts, and reviewing more than 650 comments, the 30-member commission
issued its final report in July 2011, comprised of nearly 100 policy recommendations (MSAC,
2011). Many of these recommendations were directly reflected in Act 13 of 2012, the most com-
prehensive revision of Pennsylvania’s oil and gas regulations since 1984 [Pennsylvania Depart-
ment of Environmental Protection (PA DEP), 2012b; see also Rabe and Borick, 2012].
Enacted in February 2012, one significant component of Act 13 was the introduction of
an unconventional gas well fee. To facilitate the assessment of these fees, Act 13 directed the
4. 4
DEP to report on “all spud unconventional gas wells” in the state [58 Pa.C.S. §2304(a)]. In this
article, we draw on three unique data sets derived from publicly available sources to analyze the
extent to which the DEP has complied with its reporting requirements under Act 13. We find that
the DEP’s Act 13 report likely omitted between 15,300 and 25,100 unconventional gas wells,
which could be worth up to $0.75–$1.85 billion in fees over their initial life expectancy. We
conclude with recommendations that would enable the DEP to meet its specific obligations under
Act 13 while also better meeting the information needs of its diverse stakeholders more general-
ly.
ACT 13 AND THE ASSESSMENT OF UNCONVENTIONAL GAS WELL FEES
Prior to the passage of Act 13, Pennsylvania was the only one of 28 major gas-producing
states that did not impose a fee on natural gas drilling (Akin Gump, 2012; Fischetti, 2010; Rabe
and Borick, 2012). Starting in 2012, however, unconventional gas wells were assessed
$190,000–$355,000 in cumulative fees over 15 years if drilled horizontally and $33,000–$61,000
in cumulative fees over 10 years if drilled vertically.2 In particular, Act 13’s unconventional gas
well fee is based on four criteria: (a) well timing, (b) formation geology, (c) well purpose, and (d)
unconventional spudding (i.e., drilling). Next, we review these criteria.
Criterion 1: Well Timing
First, fees are “imposed on every producer and shall apply to unconventional gas wells
spud in this Commonwealth regardless of when spudding occurred” [58 Pa.C.S. §2302(b)]. By
imposing fees retroactively, Act 13 implicitly required analysis of the more than 350,000 wells
known to have been drilled in Pennsylvania dating to at least 1858 (Harper, 2008; PA DEP,
2011b).3 Act 13 considers all such wells to have been drilled in 2011 [58 Pa.C.S. §2302(b)].
5. 5
Criterion 2: Formation Geology
Second, fee assessment depends on whether the well was spud in an unconventional for-
mation, defined as “a geological shale formation existing below the base of the Elk Sandstone or
its geologic equivalent stratigraphic interval” (58 Pa.C.S. §2301). The Elk Sandstone is a Late
Devonian age formation. According to current subsurface nomenclature (Carter, 2007), at least
12 shale formations are below the Elk and thus meet Act 13’s definition of an unconventional
formation (see Table 1).4
-- INSERT TABLE 1 ABOUT HERE --
Criterion 3: Well Purpose
Third, fee assessment depends on a well’s purpose. In particular, 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” (58 Pa.C.S. §2301). By imposing this require-
ment, Act 13 implicitly exempts certain wells that would otherwise meet the above criteria. For
instance, wells drilled for the purposes of injecting gas, petroleum, or another liquid related to oil
or gas production or storage, including brine disposal, are exempt (58 Pa.C.S. §3203). Wells
related to degasifying coal seams, and monitoring, producing, or extracting gas from solid waste
disposal facilities, and wells drilled to produce potable water are also exempt. By comparison, all
unconventional wildcat, developmental, and dry wells meet this criterion.
Criterion 4: Unconventional Spudding
Finally, fees depend on spudding, or “the actual start of drilling of an unconventional gas
well” (58 Pa.C.S. §2301). In the oil and gas industry, spudding is distinct from activities such as
completion and production, which can occur only after spudding, if at all. By anchoring the as-
sessment of fees on spudding, Act 13 requires the identification of unconventional gas wells
6. 6
without reference to completion or production. But, in that case, how does one differentiate un-
conventional and conventional wells, as both are essentially identical at the start of drilling? And
how can the DEP retroactively determine whether an unconventional well has been spud if the
necessary records were not kept? Next, we explore three possible answers to this question.
Spud interpretation 1: Permit issuance. Option 1 is to determine whether a well is un-
conventional at the time of permit issuance. Consistent with this interpretation, in April 2012, the
DEP revised its well-permitting procedures to require any operator targeting an unconventional
formation to apply for an unconventional gas well permit (PA DEP, 2012c). This revision would
allow unconventional gas well fees to be assessed whenever a well permitted in an unconven-
tional formation is spud, regardless of whether such a formation is ever reached or the well ever
produces gas. However, this approach may not be retroactively feasible. For instance, until 1937,
Pennsylvania did not require well operators to obtain permits before drilling.5 Even after this
date, wells were frequently drilled without permits (Harper, 1982; Lytle, Heyman, and Wagner,
1967), and it was only with the passage of the Oil and Gas Act in 1984 that wells were required
to be bonded. Until the passage of Act 13, operators routinely failed to notify the DEP of spud-
ding, even though existing regulations required them to give the DEP 24 hours notice prior drill-
ing (personal communication, 2012). Thus, in many situations, using this interpretation to deter-
mine the number of spud unconventional gas wells may not be possible owing to a lack of neces-
sary historic data.
Spud interpretation 2: Drilling below the Elk. In the absence of reliable real-time permit
and spud data on unconventional wells, a second option is to retrospectively differentiate be-
tween the start of surface drilling and the start of subsurface unconventional drilling. Although
Act 13 does not explicitly make such a distinction, the DEP’s interpretation of Act 13 appears to
7. 7
do so: “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 geolog-
ic equivalent” (PA DEP, 2012a). In other words, the DEP has interpreted Act 13 to mean that
penetrating an unconventional formation below the Elk constitutes an unconventional gas well
spud. This is noteworthy, because the Elk is surrounded by shale formations (Carter, 2007;
Harper, 2008). Specifically, one or more unconventional shales (i.e., formations 1–3 in Table 1)
exist throughout Pennsylvania’s oil and gas–producing regions. Accordingly, the population of
wells liable for fees under spud interpretation 2 would minimally include all wells that penetrate
the Tully Limestone, as there is no way to do so without first going through (i.e., spudding) an
unconventional shale (see Figure 1). Additionally, wells spud in the three overlying shale for-
mations would be liable for fees, whether or not they reached the Tully Limestone.
-- INSERT FIGURE 1 ABOUT HERE --
Spud interpretation 3: Targeted unconventional formation drilling. In cases where the
data required for either of the foregoing options are unavailable, a third option is to consider
wells as unconventional only when the specific formation targeted is unconventional. In other
words, contrary to spud interpretation 2, spudding an unconventional shale formation en route to
a deeper formation would not automatically result in unconventional well fees. Instead, only
wells where the intended production formation contained shale would be liable for unconven-
tional gas well fees. Because this interpretation is more stringent than Act 13 requires, it yields
the most conservative estimate of impact fees. Nonetheless, it may be the only means of comply-
ing with Act 13 in some historic situations.
In sum, under Act 13, four criteria—well timing, formation geology, well purpose, and
unconventional spudding—determine which wells are subject to unconventional gas fees. As a
8. 8
practical matter, Act 13 considers wells drilled (a) anytime in Pennsylvania’s history, (b) to an
unconventional formation (c) for the purpose of producing natural gas, (d) to be spud upon the
commencement of drilling operations.
ANALYSIS AND FINDINGS
How many unconventional gas wells have been spud in Pennsylvania? To answer this
question, Act 13 required the DEP to report all spud unconventional gas wells to the Pennsylva-
nia Public Utility Commission (PUC) within 14 days of Act 13’s passage, along with updated
reports on a monthly basis [58 Pa.C.S. §2301; 2304(a)]. Pursuant to this requirement, on March
1, 2012, the DEP posted an Act 13 report to its website, covering spud unconventional gas wells
through December 31, 2011 (see PA DEP, 2012d). As shown in Table 2, the DEP reported 4,906
spud unconventional wells to the PUC. The vast majority—4,887 (99.6%)—were Marcellus
wells spud from 2002 to 2011; the remaining 19 (0.4%) wells were spud since 2008 in other un-
conventional formations (e.g., Burket, Utica).
-- INSERT TABLE 2 ABOUT HERE --
Phase 1: The DEP Omitted 1,500 “Recent” Unconventional Spuds
The first phase of our analysis started with the DEP’s Act 13 report and focused on de-
termining the extent to which the DEP accurately reported on recent unconventional well
spuds—those between 2002 and 2011, as this was the time period explicitly covered by its re-
port. In particular, we compared the DEP’s Act 13 report with its previously published reports
covering the same period. Essentially, we used the DEP’s existing reports to assess the accuracy
and completeness of its Act 13 report. This entailed downloading five additional DEP reports—
permits, spuds, production, wastes, and compliance—all of which were publicly available on the
DEP’s Office of Oil and Gas Management website. We combined these data with the DEP’s Act
13 report to form a single Structured Query Language (SQL) database. Within this database, we
9. 9
used American Petroleum Institute (API) well numbers as unique identifiers, enabling us to con-
struct a master table of unconventional wells. We considered a well to be unconventional if it
was coded as a Marcellus (unconventional) well or a horizontal well in any of the six DEP ta-
bles.6 We identified which of these wells had been spud by evaluating the following criteria in
stepwise order:
1. Was the well in the DEP’s Act 13 table?
2. Was the well in the DEP’s spuds table?
3. Was the well coded in the DEP’s production table as producing gas or with a
comment indicating it had been spud?7
4. Was the well coded in the DEP’s wastes table as having produced waste?8
5. Was the well flagged in the DEP’s compliance table as drilling commenced or
drilling completed?9
At each step, we flagged as spud any wells in our master table that met one of these criteria but
that were not previously identified as spud. These procedures resulted in the identification of
6,430 spud unconventional wells. The original DEP reports along with our SQL code and result-
ing tables are available for download in the Online Supplement accompanying this article.
Once this table was assembled, it was a simple matter to compare it against the DEP’s
Act 13 report. Upon doing so, we found considerable discrepancies. Specifically, we found that
for the period 2002–11, a total of 1,524 spud unconventional gas wells were omitted from the
DEP’s Act 13 report. As shown in Table 3, this included 386 spud wells from the DEP’s spuds
table not included in its Act 13 report, another 934 spud wells from its production table, 120
spud wells from its wastes table, and 84 spud wells from its compliance table. Of these omitted
wells, 1,330 wells (87.3%) were coded by the DEP as horizontal, whereas the rest were vertical.
10. 10
The areal distribution of these omitted spuds is shown in Figure 2. As one check on validity of
this estimate, we compared our results with those obtained using data assembled and distributed
by the Carnegie Museum of Natural History (2012). Despite using a different vintage of data and
following different procedures, it reported 6,503 unconventional wells as permitted, drilled, or
producing through the end of 2011, a total within approximately 1% of our estimate.
-- INSERT TABLE 3 AND FIGURE 2 ABOUT HERE --
Phase 2: The DEP Omitted 13,800 to 23,600 “Early” Unconventional Spuds
The second phase of our analysis picks up where the DEP’s Act 13 report leaves off.
Specifically, we sought to ascertain whether the lack of reported early unconventional gas wells
spud prior to 2002 was also due to DEP omissions or whether in fact no such wells had been
spud in Pennsylvania before 2002. We first searched scholarly databases for narrative histories of
natural gas development in Pennsylvania, especially unconventional formations below the Elk
Sandstone. This bottom-up analysis revealed numerous examples of unconventional gas well
spuds prior to 2002. For instance, we uncovered several hundred early examples of gas wells
spud in the Rhinestreet Shale (Kirr et al., 1986), the Marcellus Formation (Patchen et al., 1984),
and the Cabot Head Shale (Harper and Cozart, 1988), among others, all of which are unconven-
tional formations under Act 13. Given this evidence, we shifted our attention to a top-down as-
sessment of possible missing records for these earlier years. Ultimately, we were able to assem-
ble two different data sets, which together provide partial coverage of this earlier period.
We used data from the Pennsylvania Bureau of Topographic and Geological Survey
(hereafter, Bureau). Created in 1919, the Bureau became part of the Pennsylvania Department of
Conservation and Natural Resources (DCNR) in 1995, where it still performs many of the func-
tions for which it was originally responsible. However, its oil and gas management responsibili-
11. 11
ties were transferred to the DEP when that agency was created in 1995. Prior to this governmen-
tal reorganization, from 1950 to 1993, the Bureau published a series of Bulletins and Progress
Reports that provide information on oil and gas well development in Pennsylvania through the
end of 1991.10 In these publications, the Bureau categorized wells that penetrated the top of the
Tully Limestone or its equivalent as deep on a stratigraphic basis, regardless of their actual verti-
cal depth. Expressed in terms of Act 13, the Bureau’s deep wells correspond with formations 4–
12 in Table 1. As noted earlier, because there is no way to reach the Tully Limestone without
spudding an unconventional formation, every deep well ever drilled qualifies as a spud uncon-
ventional gas well under spud interpretation 2.
Accordingly, we tabulated the drilling records published in the Bureau’s reports.11 The
earliest reported deep well was drilled in 1888 and the last Progress Report issued by the Bureau
covered deep wells completed through 1991. Overall, the Bureau reported that, through 1991, a
cumulative total of 9,759 deep wells were completed in Pennsylvania. A spreadsheet of these
data is available in the Online Supplement accompanying our article. Moreover, according to the
Bureau, significantly more unconventional wells were likely spud during this period. For in-
stance, in 1967 the Bureau wrote, “The total represents only the wells reported. A considerable
number of completed wells were not reported” (Lytle et al., 1967, p. 5). Underreporting was ap-
parently a long-standing problem. “In 1981 Pennsylvania oil and gas well drillers reported 3,554
well completions. . . . As in previous years, the number of wells reported was probably half the
number actually drilled (an estimated 7,000 to 8,000 wells)” (Harper, 1982, p. 12; see also
Patchen et al., 1981). Thus, according to the Bureau’s own commentaries, through 1991 on the
order of 19,600 or more unconventional gas wells were likely spud in formations 4–12.
12. 12
Whereas the Bureau’s reports provided aggregate data on selected deep wells, the Appa-
lachian Basin Tight Gas Reservoirs Project (AB Project) compiled well-level data related to six
specific formations in Pennsylvania and West Virginia (Behling et al., 2008). Funded largely by
the US Department of Energy, the Bureau was a primary contractor on the AB Project. We ob-
tained the database of Pennsylvania wells from the AB Project and based our analysis on 10,906
wells completed in the Medina Group during the period 1901–2007.
The Medina is composed of “sandstones, siltstones and shales” and “requires hydraulic
fracturing in order to achieve commercial production” (Kimmel and Fulton, 1983, p. 1). Specifi-
cally, as shown in Table 1, the Medina includes the Cabot Head Shale, an unconventional for-
mation under Act 13 (Carter, 2007).12 Because the AB Project’s data were largely derived from
(and thus potentially overlap with) the Bureau of Topographic and Geological Survey’s records,
we only used data from 1992 onward, the year after the Bureau’s reporting ended. Using this
cutoff left 4,038 Medina wells completed between 1992 and early 2007. Using spud interpreta-
tion 3, each of these wells owes fees under Act 13.
Summary of Findings
Taken together, our analyses suggest that the DEP’s Act 13 report minimally omitted
some 15,300 unconventional gas well spuds.13 This total includes over 1,500 recently spud Mar-
cellus wells, nearly 9,800 deep wells spud through 1991 (including Medina wells spud during
this period), and over 4,000 Medina wells spud from 1992 through early 2007. As shown in Ta-
ble 4, these wells have been drilled throughout Pennsylvania. Of note, we were able to identify
each of these wells by name, number, and location.
-- INSERT TABLE 4 ABOUT HERE --
13. 13
Additionally, our analysis suggests that the actual number of spud wells probably in-
cludes as many as 25,100 unconventional gas wells—all the above wells, plus an additional
9,800 deep wells considered “missing” from the Bureau’s records. Moreover, as described in the
“Limitations” section below, our analysis covers only 962 (52%) of the 1,848 formation-years
during which unconventional wells were potentially spud in Pennsylvania, suggesting that the
number of unconventional wells omitted from the DEP’s Act 13 report could be significantly
higher. Although we recognize that significant efforts may be required to identify the names,
numbers, and locations of these latter wells, at no point do these circumstances relieve the DEP
of its reporting requirements under Act 13.
Estimated Financial Consequences of the DEP’s Omissions
So far, we have focused primarily on fee assessment, but Act 13 also specifies require-
ments for the duration and collection of fees. Under Act 13, it is the DEP’s responsibility to re-
port spud unconventional wells to the PUC, whereas the PUC is responsible for fee collection.
Specifically, Act 13 grants the PUC “authority to make all inquiries and determinations neces-
sary to calculate and collect the fee, administrative charges or assessments imposed under this
chapter, including, if applicable, interest and penalties” (58 Pa.C.S. §2307). But, in the absence
of accurate information from the DEP, the PUC cannot collect these fees. What revenue short-
falls could result from the DEP’s omissions?
According to Act 13, fees are due for 15 years in the case of horizontal wells and 10
years in the case of vertical wells [58 Pa.C.S. §2302(b)]. Additionally, if after 10 years a well is
restimulated, fees are due for another 15 or 10 years, respectively [58 Pa.C.S. §2302(d)]. Once a
well is spud, there are only two ways for a well operator to avoid liability for these fees: nonpro-
duction and plugging. If within two years after paying the initial fee a spud unconventional well
14. 14
is incapable of producing more than 90,000 cubic feet of gas per day during any month, then the
fee shall be suspended [58 Pa.C.S. §2302(b.1)]. In this case, fees are due for a minimum of three
calendar years (PA PUC, 2012a). After spudding, an operator may also certify that a well has
ceased production and has been plugged according to regulations established by the DEP [58
Pa.C.S. §2302(e); 3220], at which point fees would cease in the year following plugging certifi-
cation. Of note, at no point does Act 13 exempt so-called inactive wells from fees (58 Pa.C.S.
§3214). Stated plainly, the wells subject to fees are spud wells, unconventional wells, vertical
wells, capped wells, and restimulated wells (PA PUC, 2012b, p. 3).
All wells spud prior to 2012 are considered spud in 2011 and owe fees of $50,000 and
$10,000, respectively, depending on whether they are horizontal or vertical (58 Pa.C.S. §2302;
PA PUC, 2012b, p. 5). We have documented over 1,300 omitted spud horizontal Marcellus
wells, which collectively owe $65 million in unconventional gas well fees. Another 14,000 omit-
ted Marcellus, deep, and Medina wells (assumed to be vertical) owe $140 million in fees.14 Left
uncorrected, these omissions represent at least $205 million in lost revenues in 2012 (see Table
5). Of note, these fees are distinct from and additional to the $211 million in fees that have been
estimated based on the DEP’s Act 13 report (Detrow, 2012c). In other words, if properly
implemented, Act 13 will provide state, county, and municipal governments with nearly twice
the 2012 revenue previously estimated.15
-- INSERT TABLE 5 ABOUT HERE --
Unless these wells are certified as plugged, the fees are due for a minimum of three cal-
endar years (58 Pa.C.S. §2302; PA PUC, 2012a), implying a $431–$636 million omission by the
DEP (see Table 5). Assuming well lives of 15 and 10 years for horizontal and vertical wells, re-
spectively, the cumulative cost of the omissions could total $0.75–$1.27 billion over time. Addi-
15. 15
tionally, our analyses suggest that the actual number of spud wells probably includes as many as
25,100 unconventional gas wells. Assuming these additional missing wells are all vertical, these
omissions represent another $98 million in unconventional gas well fees (see Table 5). In sum,
owing to the DEP’s omissions, the state, county, and municipal governments designated by Act
13 could forfeit fees of $205–$303 million in 2012, and unless these wells are plugged or inca-
pable of sufficient production, up to $0.75–$1.85 billion over their expected lives.16
DISCUSSION
The emergence of environmental and sustainability concerns frequently generates de-
mands for increased disclosure and reporting (Etzion and Ferraro, 2010; Gallagher and Song,
2011). In the case of the DEP, it appears that managing the disclosure and reporting required by
Act 13 has resulted in potentially widespread and systemic omissions. Moving forward, if the
DEP is to meet the requirements of Act 13, a more robust approach will be needed. As with un-
conventional gas drilling and exploration more generally, the problem implicates “three spatial
dimensions and time” (Mooney, 2011, p. 82).
Surmounting Pennsylvania’s Legacy of Oil and Gas Information Management Problems
Unfortunately, information management appears to be a long-standing problem within
the DEP and its predecessor agencies. In 1980, the Bureau reported it was working on a two-year
project to compile, standardize, and computerize 27,000 deep well records: “Determining the
historical data has presented numerous problems. Some of the information has been lost with
time, whereas other information is confused because different workers have used different
names, dates and geographic localities” (Piotrowski, 1980, p. 35).17
Six years later, the Bureau reported that it had again “begun the process of computerizing
its well record files” (Harper, 1986, p. 38), by then numbering more than 100,000 wells. In 1993,
the Bureau launched a third “multiyear project to compile an electronic information system
16. 16
based on all the oil and gas data on file in hardcopy format” (Cozart and Harper, 1993, p. 33).
This project—the Wells Information System—continues to this day, though under the auspices
of the DCNR and not the DEP as one might expect. Despite these multiple attempts at computer-
ization over a 30-year period, the status of at least 184,000 wells in Pennsylvania remains “un-
known” (PA DEP, 2000).
In addition to these documented issues, other data management problems appear to have
gone largely undetected. In the process of analyzing the DEP’s wastes reports, we noticed there
were only four records for all of 2007, compared with some 15,000 records in 2006 and 25,000
records in 2008. What happened in 2007? After asking the DEP for an explanation, we were told
“we had a system crash and lost most of our 2007 waste reports” (personal communication,
2012), suggesting that the DEP had neglected to perform routine backups, a common data man-
agement practice. Others have documented numerous missing permit and spud records, as well
as inconsistent Marcellus designations (Hamill, 2012; Whitacre and Wenzel, 2011).
Although our study did not attempt to identify the mechanisms that may be responsible
for the DEP’s inability to build and maintain an accurate database of drilling activity, prior or-
ganizational research suggests several plausible explanations. Most sinister is the possibility of
regulatory capture (Levine and Forrence, 1990), wherein governmental agencies succumb to
narrow special interests, straying from the goal of serving their intended public constituencies.
Another possibility is that the DEP exists in a state of permanent failure (Meyer and Zucker,
1989), wherein organizational members focus their attention and efforts primarily on organiza-
tional survival rather than organizational performance. A third possibility is that the DEP recog-
nizes the need for improved organizational performance, yet is unable to implement a robust
program of organizational learning (Argote, 1999; Argyris and Schön, 1978) that will enable it
17. 17
to fundamentally address the root causes underlying its data management problems. The extent
to which these mechanisms may be to blame is beyond the scope of our article, but may be fruit-
ful possibilities for the DEP and future research to consider.
Some Options for Building a Robust Well Information System
Although dealing with multiple relational and temporal complexities such as these can be
challenging (Garud and Gehman, 2012; Garud, Gehman, and Kumaraswamy, 2011), in the case
of the DEP and Act 13, it appears that many of these challenges could be addressed by building a
platform capable of bridging the legacies of the past and the needs of the future, while perform-
ing in the present. For instance, with a properly designed relational database (RDB) and geo-
graphic information system (GIS) (Belieu, Paque, and Simmers, 2001; Bonham-Carter, 1994;
National Research Council, 2012), the analysis required by Act 13 would be rather straightfor-
ward.
A first step in building such a system would be for the DEP to develop a RDB containing
permitted well locations, proposed drilling depths, and formations targeted, to name just a few
variables. These attributes are all required by the DEP’s Permit to Drill or Alter an Oil and Gas
Well (PA DEP, 2012c). Once these data were at hand, it would be a simple matter to import the
wells as geospatial data into an application such as ArcGIS. Then, together with spatial data rep-
resenting the depth to geological formations, the proposed drilling depth could be used to deter-
mine whether wells will penetrate unconventional formations (Mamoulis, 2012). Wells where
the depths of unconventional formations are less than the proposed drilling depths would be
flagged as unconventional and reported to the PUC when spud, as required by Act 13.
In developing such a system, the DEP could leverage a number of existing standards. For
instance, Federal Geographic Data Committee guidelines specify metadata standards relevant to
18. 18
GIS (Behling et al., 2008). Similarly, the PPDM Association publishes database standards specif-
ically designed to help the oil and gas industry manage well-related data (PPDM, 2012). PPDM
3.8, the latest version of its open standards data model, covers 53 subject areas, which include
various standards related to wells, geology, environment, health, and safety data, among others.
In sum, a RDB-GIS built on standards such as PPDM would allow the DEP to aggregate and
manage the various data associated with each well in a more comprehensive manner, thereby
enabling it to meet the requirements of Act 13.
Without an accurate diagnosis of the organizational issues underlying the DEP’s data
management difficulties, it is difficult for us to provide meaningful suggestions extending be-
yond this list of best practices. One arena, however, may help the DEP immensely, albeit indi-
rectly: improved governance. Ostrom (1990) has shown that governance mechanisms that in-
crease transparency and integrate data and preferences at multiple levels of a system are condu-
cive to maintaining the long-run integrity of public resources (i.e., a commons). Relatedly, other
research has shown that contentious, multi-stakeholder issues may be governed more effectively
through hybrid forums (Callon, Lascoumes, and Barthe, 2009). Enhanced public access to data
could serve not only to improve the quality and reliability of the DEP’s information systems, but
could lead to greater awareness of the extent of drilling in the state, as well as its positive and
negative consequences. Unfortunately, rather than taking such a distributed approach to govern-
ance, Act 13 centralizes authority, “largely eviscerating the possibility of constructive engage-
ment between state and local governments” (Rabe and Borick, 2012, p. 16).
Limitations
When interpreting our analysis and results, there are several limitations to keep in mind.
First, owing to data limitations, we were unable to evaluate the number of spud wells in numer-
19. 19
ous formations and years. As depicted in Figure 3, the extent of these limitations can be calculat-
ed as a grid of 12 formations multiplied by 154 years (1858–2011), or a total of 1,848 formation-
years. Data from the Bureau enabled us to estimate spuds in nine formations from 1888 to 1991,
or 936 formation-years. The AB Project provided spud estimates for a single formation—the
Medina Group—over a 16-year period. Finally, data from the DEP enabled us to estimate Mar-
cellus spuds from 2002 to 2011, or another 10 formation-years. In other words, the available data
covered only 962 (52%) of the 1,848 formation-years during which unconventional wells were
potentially spud in Pennsylvania. To the extent that additional unconventional gas wells were
spud in the 886 formation-years for which no data were available, our estimates may significant-
ly understate the true scope of the DEP’s omissions. For instance, in the mid-1980s, one operator
reportedly completed more than 100 Rhinestreet Shale penetrations (Kirr et al., 1986), all of
which are unconventional wells under Act 13, but none of which are included in our estimates,
owing to a lack of relevant publicly available data.
-- INSERT FIGURE 3 ABOUT HERE --
Second, we were unable to independently verify the accuracy of the data we used. In
short, our conclusions are only as good as the data we have used, and in all cases we have been
essentially limited to data produced by the very agency we have endeavored to assess. However,
these data have been shown to suffer numerous problems (e.g., Harper, 1982; Whitacre and
Wenzel, 2011). As a result, our analysis may significantly underestimate the number of uncon-
ventional gas wells spud. Accordingly, the omitted spuds that we have documented may well be
the lower bound of the true number of omissions by the DEP, were such data available.
Third, as one anonymous reviewer pointed out, it is possible to use more or less stringent
criteria when determining whether a well was spud. Such choices would result in corresponding-
20. 20
ly higher or lower estimates of the number of spud unconventional wells. For example, we de-
termined the number of spud wells in part by using the DEP’s production and wastes reports, but
these reports are based on activities that take place after a well is completed. To the extent that
other wells were spud in unconventional formations, but not yet completed (and thus not report-
ed in the production or wastes tables), our count of spud unconventional wells may be artificially
low. Accordingly, we made every effort to interpret the DEP’s publicly available data sets ap-
propriately. Because the DEP provides few descriptions, codebooks, or metadata for its reports,
we consulted with the DEP to confirm our interpretation of its database codes on multiple occa-
sions, hardly an ideal situation. Ultimately, the number of wells omitted by the DEP depends on
interpretations of whether a given well meets the criteria required by Act 13, and such interpreta-
tions are themselves constrained by the quality of the underlying data.
Fourth, Act 13 suffers from several ambiguities. This is not entirely surprising, as laws
are “inherently flexible” (Thornton, Ocasio, and Lounsbury, 2012, p. 12) and subject to changing
interpretations (Edelman, Uggen, and Erlanger, 1999). Indeed, Act 13 confirms these observa-
tions. For instance, despite issuing a “final order” in May 2012 (PA PUC, 2012a), the PUC later
revised its interpretation of vertical well fees (PA PUC, 2012c; see also note 14). Other aspects
of Act 13 have been ruled unconstitutional and have been appealed to the Pennsylvania Supreme
Court (Detrow, 2012a,b). In addition to legal disputes that are still unfolding, other potential am-
biguities have yet to be considered. For instance, at no time does Act 13 define what qualifies as
a geologic shale formation, leaving the meaning of this phrase open to interpretation. In this arti-
cle, we interpreted the phrase quite narrowly, including only known organic rich shale lithofa-
cies, meaning shales that constitute distinct stratigraphic intervals capable of producing hydro-
carbons (Carter, 2007; Harper, 2008; Rushing, Newsham, and Blasingame, 2008). But Act 13
21. 21
imposes no requirement that unconventional formations be rich in organic materials. This is po-
tentially significant because throughout Pennsylvania the Elk Sandstone is immediately under-
lain by one of two formations (see Figure 1). The Brallier Formation is a “fine-grained, siliceous
shale” (Butts, 1918). In areas where the Brallier is nonexistent, the Angola Shale is present. In
other words, there is no way to penetrate below the Elk Sandstone without immediately spudding
shale. However, we did not count wells spud into these two shales as unconventional wells and
thus may have omitted a significant number of wells subject to Act 13.
Another definitional ambiguity relates to hydraulic fracturing, a phrase that Act 13 in-
vokes several times but never defines. For instance, an unconventional formation is defined in
part as an 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 for-
mation to the well bore” (58 Pa.C.S. §2301). But this mention proves to be a red herring, as Act
13 never conditions the assessment of fees on hydraulic fracturing, multilateral well bores, or
other formation exposure techniques. Indeed, no such techniques need be performed for a well to
be considered spud, as, by definition, such activities can occur only after spudding, if they ever
occur at all. Collectively, the four types of limitations described above suggest that while our
results provide ample evidence of reporting problems, our analysis should not be interpreted as a
definitive or comprehensive assessment of these problems.
Conclusion
Unconventional shale gas development has become widespread, bringing with it a grow-
ing number of concerns. Critical to untangling these many controversies is better information.
Twenty years ago, the Bureau wrote, “For 125 years oil and gas well drillers and producers have
22. 22
had a veritable free hand in Pennsylvania” (Harper and Cozart, 1992, p. 38). Act 13 of 2012 is
simply Pennsylvania’s latest effort to close this gap. Our analysis of the DEP’s Act 13 reporting
suggests that, unfortunately, this “veritable free hand” persists.
Our intention in this article has not been to determine the exact number of unconventional
gas well spuds in Pennsylvania, but to assess the extent to which the DEP has fulfilled its Act 13
reporting requirements. Though clearly more than 4,906 unconventional gas wells were spud by
the end of 2011, determining the true number of such wells remains the DEP’s responsibility. In
this regard, we hope that our analysis may prompt the DEP to reconsider its statutory require-
ments more carefully. Until these omissions are corrected, the many state, county, and municipal
stakeholders impacted by unconventional gas well drilling will not be compensated for the im-
pacts of unconventional gas wells as required by Act 13.
23. 23
ACKNOWLEDGMENTS
This research was initiated while the first author was a doctoral candidate at the Smeal College
of Business, Pennsylvania State University. The authors gratefully acknowledge the financial
support of the Social Sciences and Humanities Research Council of Canada (SSHRC Award
410-2009-1259). We owe a special thank-you to John Wenzel and James Whitacre of the Pow-
dermill Nature Reserve at the Carnegie Museum of Natural History for their helpful suggestions
and encouragement during the article’s development and revisions. We thank Mary Behling of
the West Virginia Geological and Economic Survey for assistance related to the Appalachian
Basin Tight Gas Reservoirs Project, an information technology specialist at the Pennsylvania
Department of Environmental Protection for clarifying its oil and gas reports on several occa-
sions, and an assistant counsel in the Department’s Bureau of Regulatory Counsel for summariz-
ing the regulatory basis of its well permitting authority. We thank the journal and special issue
editors and two anonymous reviewers for their input on our original paper. Separate from Envi-
ronmental Practice’s review process, in May 2012 we offered both the Pennsylvania Department
of Environmental Protection and the Pennsylvania Public Utility Commission an opportunity to
review our findings, but neither agency offered any comments.
NOTES
1. Many assume the Marcellus Formation is a recent discovery, but “in reality, the Marcellus has
been a known gas reservoir for more than 75 years” (Harper, 2008, p. 2).
2. Although a complete comparison of state oil and gas taxes is beyond the scope of our article,
Kunce and Morgan (2005) compared severance, property and corporate taxes in eight major oil
and gas–producing states from 1970 to 1997. More recently, Rabe and Borick (2012, p. 13) con-
cluded that Act 13 imposes “an effective tax rate of between 1 and 2 percent during the initial
years of fee operation,” with marked declines in later years, a level “substantially below the ef-
fective tax rate of all other state oil and gas producers.” By comparison, Texas imposes a 7.5%
severance tax, representing some 10% of total state revenues (Kunce and Morgan, 2005; Rabe
and Borick, 2012).
3. After the tremendous success of the gas well in nearby Fredonia, New York, numerous gas
wells had been drilled along the shores of Lake Erie by 1858. Drake’s famous oil well followed
closely behind in 1859.
4. This nomenclature was not necessarily operant historically. For instance, the Medina Group
(Carter, 2007) was known as the Albion Formation until as late as 1995 (Ryder, 2004). As a re-
sult, the analysis must also consider alternative designations for these same formations.
5. Passed in July 1937, P.L. 2772 required “certain records of oil and gas wells drilled in the
Commonwealth showing the location of the same and the geologic formations encountered there-
in.” This law was superseded by Act 359 of 1961, the Oil and Gas Conservation Law. According
to the DEP (personal communication, 2012), its current authority to require well permits rests on
Act 223 of 1984, the Oil and Gas Act (58 Pa.C.S. §3211).
24. 24
6. We identified a total of 185 wells that were coded as horizontal in one or more of the DEP’s
reports, but not coded as Marcellus or unconventional in any of its reports. Upon encountering
this potential anomaly, we sent a file containing all 185 wells to the DEP. After reviewing the
file, a DEP information technology specialist confirmed that these wells were all unconventional,
despite being omitted from its Act 13 report (personal communication, 2012).
7. The DEP’s production report contains a “comment” field. For many wells, no comments were
provided. In other instances, operators provided one of the following comments: (a) currently
being drilled; (b) drilling finished, well not yet completed; (c) transferred this well; (d) plugged
well; (e) regulatory inactive well; (f) well shut-in; (g) sold this well; and (h) abandoned well.
According to the DEP (personal communication, 2012), any well containing one of these com-
ments has been spud, as these activities are only possible after spudding.
8. According to the DEP (personal communication, 2012), the only way for a well to produce
wastes is for it to have been spud. Indeed, until spudding no well exists to generate wastes.
9. From our master table of unconventional wells, we identified 432 unique wells associated with
a total of 974 inspection records. Using a codebook provided by the DEP (personal communica-
tion, 2012), we manually reviewed all 974 records. We coded 133 inspections (13.7%) associat-
ed with 84 unique wells (19.4%) as spud.
10. Through 1966, the Bureau reported on wells completed during the preceding year. Starting in
1967, it reported on well completion records received, regardless of when drilled. See Progress
Report 177 (Kelley et al., 1969).
11. Our analysis is based on Bulletins M31, M39, and M49, and Progress Reports for 1960–91.
12. An anonymous reviewer objected, agreeing that while the Medina Formation qualifies as an
unconventional formation under the meaning of Act 13, such wells should not be considered
liable for fees because the Cabot Head Shale is not highly productive. In its efforts to avoid im-
posing a severance tax, however, Act 13 imposed fees without regard to production (Rabe and
Borick, 2012). Under 58 Pa.C.S. §2302, spudding is all that is required.
13. As one check on the credibility of this estimate, consider data available from TGS (2012), a
provider of “geoscientific data products and services to the oil and gas industry.” TGS has “iden-
tified over 270,000 wells within the Marcellus trend” and “over 18,500 wells with known Mar-
cellus penetrations.”
14. After our article was accepted for publication, the PUC reconsidered its treatment of vertical
wells. For a discussion of the potential impact of this ruling on the estimated financial conse-
quences of the DEP’s omissions, please see the Addendum in the Online Supplement.
15. Act 13 uses a complex formula to allocate impact fees, with nearly 20 pages of legislative
text required to outline the distribution among state, county, and municipal governments (58
Pa.C.S. §2313; see also PA PUC, 2012b; Rabe and Borick, 2012). For 2012, the first $23 million
in fees is earmarked for various state programs, such as the Pennsylvania Fish and Boat Com-
25. 25
mission, the State Fire Commissioner, and the Natural Gas Energy Development Agency (58
Pa.C.S. §2313; see also PA PUC, 2012b). These off-the-top earmarks fluctuate based on inflation
and other factors specified in Act 13. Of the remaining fees, 60% is allocated to counties and
municipalities, again based on a rather involved calculus, and 40% is allocated to the Marcellus
Legacy Fund. To be eligible to receive funds, Act 13 required counties to adopt uniform zoning
laws prohibiting their ability to zone and regulate oil and gas drilling, and restricted how counties
and municipalities could use the funds they receive. However, in a July 2012 ruling, Pennsylva-
nia’s Commonwealth Court voided 58 Pa.C.S. §3304; 3215(b)(4), ruling that Act 13’s zoning
restrictions “unconstitutionally bar local governments from their right to separate industrial ac-
tivity from residential neighborhoods” (Detrow, 2012a). Seeking expedited review, attorneys
representing the PUC and the DEP have since filed an appeal with the Pennsylvania Supreme
Court. In the meantime, the rest of Act 13 remains in force.
16. Our estimates are based on data that provide only partial coverage of the formations and
years over which unconventional wells were potentially spud. Here we can only speculate, but if
the ratio of omitted wells is similar, these omissions could represent an additional $250 million
in 2012 fees.
17. Thirty years later, problems with inconsistent reporting persist (e.g., see PA DEP, 2011a).
26. 26
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33. 33
FIGURE 1
Figure 1. Devonian age subsurface rock correlation diagram (adapted with permission from
Carter, 2007).
34. 34
FIGURE 2
Figure 2. Map of omitted recent unconventional gas wells spud in Pennsylvania through De-
cember 31, 2011.
35. 35
FIGURE 3
Figure 3. Summary of data limitations. This figure is drawn to scale (i.e., the total area of cells
for which data are available is 962 formation-years vs. 886 for the cells for which no data were
available). a: Department of Environmental Protection data available for Marcellus wells from
2002 to 2011. b: Bureau of Topographic and Geological Survey data available for selected deep
wells from 1888 to 1991. c: Appalachian Basin Tight Gas Reservoirs Project data available for
Medina wells from 1992 to 2007.
36. 36
TABLE 1. SHALE FORMATIONS BELOW THE ELK SANDSTONE
System (age) Formation or group (shale)
Devonian (360 Ma) West Falls (Rhinestreet)
Sonyea (Middlesex)
Genesee (Burket; Geneseo)
Marcellus (Marcellus)
Bois-Blanc (Needmore)
Helderberg (Mandata)
Silurian (405 Ma) Salina (Camillus; E; C; Willis Creek)
Clinton (Rochester; Rose Hill)
Medina (Cabot Head)
Ordovician (430 Ma) Queenston (Queenston; Juniata)
Reedsville (Reedsville)
Utica (Utica; Antes)
Source: Adapted from Carter (2007). “Ma” is mega-annum, or a mil-
lion years.
37. 37
TABLE 2. SUMMARY OF THE ACT 13 REPORT FROM THE PENNSYLVANIA DEPARTMENT OF
ENVIRONMENTAL PROTECTION (PA DEP)
Formation 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Totals
Burket 1 5 6
Geneseo 1 1
Mandata 1 1
Marcellus 1 2 1 6 34 107 324 815 1,613 1,984 4,887
Rhinestreet 1 2 1 4
Utica 7 7
Totalsa 1 2 1 6 34 107 325 816 1,616 1,998 4,906
Source: This table is based on an analysis of the DEP’s Act 13 report as generated on March 1, 2012, at 9:45 a.m.
(PA DEP, 2012d). Please see the accompanying text for a complete description.
a
Spud dates were available for 4,718 of the 4,906 wells in the DEP’s Act 13 report. On average, these wells were
spud 67 days after their last permit date. Accordingly, we imputed spud dates for 187 wells by using this formula:
spud date = last permit date + 67 days. One well had no reported permit or spud date, so we arbitrarily assigned it to
2011. These decisions are inconsequential to our analysis as all wells spud prior to the passage of Act 13 are consid-
ered spud in 2011.
38. 38
TABLE 3. COMPARISON OF THE OIL AND GAS REPORTS FROM THE
PENNSYLVANIA DEPARTMENT OF ENVIRONMENTAL PROTECTION (PA DEP)
THROUGH 2011
DEP’s DEP’s
Unconventional Act 13 oil & gas
spud wells report reports
From Act 13 report 4,906 4,906
From spuds table — 386
From production table — 934
From wastes table — 120
From compliance table — 84
Total spud wells 4,906 6,430
Sources: This table is based on an analysis of publicly avail-
able DEP reports (Act 13, permits, spuds, production,
wastes, and compliance) and covers the period through De-
cember 31, 2011. The reports were imported into a
Structured Query Language (SQL) database and American
Petroleum Institute (API) well numbers were used as unique
identifiers. Please see the accompanying text for a complete
description.
40. 40
Sullivan 1 67 4 72
Susquehanna 21 91 4 116
Tioga 12 42 232 286
Venango 722 544 1,266
Union 3 3
Warren 2 10 820 388 1,220
Washington 17 63 17 97
Wayne 1 1 6 8
Westmoreland 7 34 114 155
Wyoming 1 78 3 82
York 3 3
Totals 194 1,330 9,759 4,038 15,321
Note: Please see the accompanying text for a complete description.
a
Based on our analysis of the Pennsylvania Department of Environmental Protection’s
publicly available Act 13, permits, spuds, production, wastes, and compliance reports
through December 31, 2011.
b
Based on our analysis of well records published by the Bureau of Topographic and Geo-
logical Survey covering 1888–1991 (the date range for which these data are available).
See Bureau Bulletins M31, M39, and M49, and Progress Reports for 1960–91.
c
Based on our analysis of Medina well records compiled by the Appalachian Basin Tight
Gas Reservoirs Project for the period from 1992 to early 2007 (the date range for which
these data are available and do not overlap with the Bureau’s deep well data).
41. 41
TABLE 5. ESTIMATED FINANCIAL CONSEQUENCES OF OMITTED WELLS
Cumulative Cumulative
fees, if wells fees, if wells
Minimal fees, nonproductive unplugged for
Wells included due in 2012 within 2 yearsa 10 or 15 yearsb
c
Known wells ~$205 million ~$431–636 ~$0.75–$1.27
~1,300 horizontal wells @ $50,000 million billion
~14,000 vertical wells @ $10,000
Probable wellsd ~$303 million ~$636–939 ~$1.09–$1.85
All of the above, plus ~9,800 vertical million billion
wells @ $10,000
Note: Please see accompanying text for a complete description of all estimates, the Online
Supplement for detailed calculations, and note 14 for a discussion of the PUC’s revised treat-
ment of vertical wells.
a
Assumes that within two years after paying the initial fee all wells are incapable of producing
more than 90,000 cubic feet of gas per day (90 mcfpd), resulting in the suspension of subse-
quent fees.
b
Assumes that all wells are not incapable of producing 90 mcfpd within 2 years after paying
the initial fee and are not plugged for 15 years in the case of horizontal wells and 10 years in
the case of vertical wells.
c
Based on our analysis of data from the Pennsylvania Department of Environmental Protection,
the Bureau of Topographic and Geologic Survey and the Appalachian Basin Tight Gas Reser-
voirs Project. These wells can be identified by name, number, and location.
d
Based on our analysis of the above data sources and the assumption that data from the Bureau
underreported the number of deep wells spud during 1888–1991 by a factor of 2.