Photo by Pat Sullivan/AP https://www.houstonchronicle.com/news/houston-texas/houston/article/Fracking-research-hits-roadblock-with-Texas-law-6812820.php
Kyle Ferrar, MPH

California regulators need to protect groundwater from oil and gas waste this time around

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By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

California’s 2nd Largest Waste Stream

Every year the oil and gas industry in California generates billions of gallons of wastewater, also known as produced water. According to a study by the California Council on Science and Technology, in 2013, more than 3 billion barrels of produced water were extracted along with some 0.2 billion barrels of oil across the state. This wastewater is usually contaminated with a mixture of heavy metals, hydrocarbons, naturally occurring radioactive materials, and high levels of salts. Yet, contaminated wastewater from oil-field operations is exempt from the hazardous waste regulations enforced by the Resource Conservation and Recovery Act (RCRA).

Operators are, therefore, not required to measure or report the chemistry of this wastewater. Even with these unknowns, it is legally re-injected back into groundwater aquifers for disposal. Once an aquifer is contaminated it can be extremely difficult, if not impossible, to clean up again. Particularly in California, where water resources are already stretched thin, underground injection of oil and gas wastewater is a major environmental and economic concern.

Regulatory Deficiency

Under the Underground Injection Control program, wastewater is supposed to be injected only into geologic formations that don’t contain usable groundwater. However, a loophole in the Safe Drinking Water Act allows oil and gas companies to apply for what’s called an aquifer exemption, which allows them to inject wastewater into aquifers that potentially hold high-quality drinking water. To learn more about aquifer exemptions, see FracTracker’s summary, here.

The California department responsible for managing these aquifer exemption permits – the Division of Oil, Gas, and Geothermal Resources (DOGGR) – has for decades failed in its regulatory capacity. In 2015, for example, DOGGR admitted that at least 2,553 wells had been permitted to inject oil and gas waste into non-exempt aquifers – aquifers that could be used for drinking water. Independent audits of DOGGR showed decades of poor record-keeping, lax oversight, and in some cases, outright defiance of the law – showing the cozy relationship between regulators and the oil and gas industry. While 176 wells (those that were injecting into the cleanest drinking water) were initially shut down, most of the rest of the 2,377 permits were allowed to continue injecting into disputed wells through the following two years of the regulatory process.

The injection wells targeted by the Environmental Protection Agency (EPA), including those that were shut down, are shown in the map below (Figure 1).

Figure 1. Map of EPA-targeted Class II Injection Wells


View map fullscreen | How FracTracker maps work | Map Data (CSV): Aquifer Exemptions, Class II Wells

The timeline of all this is just as concerning. The State of California has known about these problems since 2011, when the EPA audited California’s underground injection program and identified substantial deficiencies in its program, including failure to protect some potential underground sources of drinking water, a one-size-fits-all geologic review, and inadequate and under-qualified staffing for carrying out inspections. In 2014, the Governor’s office requested that the California EPA perform an independent review of the program. EPA subsequently made a specific remediation plan and timeline for DOGGR, and in March of 2015 the State finalized a Corrective Action Plan, to be completed by February 2017.

Scientific Review of CA Oil and Gas Activities

Meanwhile, in 2013, the California Senate passed SB-4, which set a framework for regulating hydraulic fracturing in California. Part of the bill required an independent scientific study to be conducted on oil and gas well stimulation, including acid well stimulation and hydraulic fracturing. The California Council on Science and Technology organized and led the study, in collaboration with the Lawrence Berkeley National Laboratories, which combined original technical data analyses and a review of relevant literature, all of which was extensively peer-reviewed. The report argues that both direct and indirect impacts of fracking must be accounted for, and that major deficiencies and inconsistencies in data remained which made research difficult. They also recommended that DOGGR improve and modernize their record keeping to be more transparent.

Figure 2. Depths of groundwater total dissolved solids (a common measure of groundwater quality) in five oil fields in the Los Angeles Basin. Blue and aqua colors represent protected groundwater; the heavy black horizontal line indicates the shallowest hydraulically fractured well in each field. In three of the five wells (Inglewood, Whittier, and Wilmington), fracking and wastewater injection takes place directly adjacent to, or within, protected groundwater.

Figure 2*. Depths of groundwater total dissolved solids (a common measure of groundwater quality) in five oil fields in the Los Angeles Basin. Blue and aqua colors represent protected groundwater; the heavy black horizontal line indicates the shallowest hydraulically fractured well in each field. In three of the five wells (Inglewood, Whittier, and Wilmington), fracking and wastewater injection takes place directly adjacent to, or within, protected groundwater.

A major component of the SB-4 report covered California’s Class II injection program. Researchers analyzed the depths of groundwater aquifers protected by the Safe Drinking Water Act, and found that injection and hydraulic fracturing activity was occurring within the same or neighboring geological zones as protected drinking water (Figure 2*).

*Reproduced from California Council on Science and Technology: An Independent Scientific Assessment of Well Stimulation in California Vol. 3.

More Exemptions to be Granted

Now, EPA is re-granting exemptions again. Six aquifer exemptions have been granted, and more are on the docket to be considered. In this second time around, it is imperative that regulatory agencies be more diligent in their oversight of this permitting process to protect groundwater resources. At the same time, the 2015 California bill SB 83 mandates the appointment of an independent review panel to evaluate the Underground Injection Control Program and to make recommendations on how to improve the effectiveness of the program. This process is currently in the works and a panel has been assembled, and FracTracker Alliance will be working to provide data, maps and analyses for this panel.

Stay tuned for more to come on which aquifers are being exempted, why, and what steps are being taken to protect groundwater in California.

Feature image by Pat Sullivan/AP

Matt Kelso, BA

Report: Potential Impacts of Unconventional Oil and Gas on the Delaware River Basin

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Report: Potential Impacts of Unconventional Oil and Gas on the Delaware River Basin

White Paper (PDF)
FracTracker Alliance

Mariner East 2: More Spills & Sinkholes Too?

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The Mariner East 2 (ME2) pipeline, currently being built by Sunoco Pipeline (Energy Transfer Partners), is a massive 350-mile long pipeline that, if completed, will carry 275,000 barrels of propane, ethane, butane, and other hydrocarbons per day from the shale gas fields of Western Pennsylvania to a petrochemical export terminal located on the Delaware River.

ME2 has faced numerous challenges from concerned citizens since Sunoco first announced plans for the project in 2014. Fights over taking private property by eminent domain, eyebrow raising permit approvals with known technical deficiencies, as well as nearly a hundred drilling mud spills — inadvertent returns (IRs) — at horizontal directional drilling (HDD) sites have occurred since work began in 2017.

This article and the accompanying map brings us up-to-date on the number, location, and status of ME2’s HDD spills. We also summarize the growing list of violations and settlements related to these events. Finally, we highlight the most recent concerns related to ME2’s construction: sinkholes emerging along the pipeline’s path in karst geological formations.

Map of ME2 Updated HDDs, IRs & Karst

The map below shows an updated visual of ME2’s IRs, as of the DEP’s latest tally on March 1, 2018. Included on this map are HDDs where DEP ordered Sunoco reevaluate construction sites to prevent additional spills. Also identified on this map are locations where Sunoco was ordered to notify landowners in close proximity to certain HDDs prior to additional drilling. Finally, the below map illustrates how sinkholes are not a problem unique to one site of construction but are, in fact, common to many areas along ME2’s route. These topics are discussed in greater depth below.

Open the map full-screen to view additional layers not available in the embedded version below.

View Map Fullscreen | How FracTracker Maps Work

HDDs & Inadvertent Returns – Redux

In July 2017, the PA Environmental Hearing Board granted a two week halt to ME2’s HDD operations. The temporary injunction was in response to petitions from the Clean Air Council, Mountain Watershed Association, and the Delaware Riverkeeper Network following IRs­­ at more than 60 sites that contaminated dozens of private drinking water wells, as well as nearby streams and wetlands. FracTracker first wrote about these issues in this prior article.

HDD IR in Washington County
(image: Observer-Reporter)

Despite these issues, and despite Sunoco being cited for 33 violations, ME2 was allowed to proceed under an August 7th agreement that stated Sunoco must reevaluate their HDD plans to minimize additional spills. These studies were to include re-examining the site’s geology and conducting seismic surveys. Sites for reevaluation were selected based on factors such as proximity water supplies, nearby streams and wetlands, problematic geologic conditions, and if an IR had occurred at that site previously. Of ME2’s 230 HDDs, 64 were ordered for reevaluation — 22 of these were selected due to prior IRs occurring at the site.

The DEP mandated that Sunoco’s reevaluation studies be put out for public comment. A table of which HDD studies are currently out for comment can be found here. DEP’s settlement also required Sunoco to notify landowners in proximity to certain HDDs prior to commencing construction due to elevated risks. Of the 64 HDD sites under review, Sunoco must notify 17 residents within 450ft of an HDD site, and 22 residents within 150ft of other sites. The HDD reevaluation sites are shown on the FracTracker map above. Below is an illustration of one site where Sunoco is required to notify landowners within 450ft.

HDDs for reevaluation with 450ft notification zone

One issue residents have raised with these notifications is that Sunoco is allowed to offer landowners the option to connect their homes to a water buffalo during drilling as an alternative to using their groundwater well. The catch is that, if their well does become contaminated, they would also waive their right to have Sunoco drill them a new replacement well.

“Egregious Violations”

In January 2018, the DEP again suspended ME2’s construction, this time indefinitely revoking their permits, due to even more IRs. DEP also cited Sunoco for “egregious and willful” permit violations —mainly executing HDDs at sites where they had no permission to do so. The DEP noted of their decision that, “a permit suspension is one of the most significant penalties DEP can levy.”

Nevertheless, Sunoco was again allowed to resume construction on February 8, 2018, after paying a $12.6 million fine. The DEP press release accompanying the decision assured the public that, “Sunoco has demonstrated that it has taken steps to ensure the company will conduct the remaining pipeline construction activities in accordance with the law and permit conditions, and will be allowed to resume.”

Sunoco advertisement in the Harrisburg Patriot-News

A few weeks later, Sunoco ran a full-page advertisement in the Harrisburg Patriot-News, shown above, lauding their safety record. Among other notables, the piece boasts, “State and federal regulators spent more than 100 inspection days during 2017 on the Mariner East project, more inspection days than on any other pipeline in Pennsylvania.” Critics have noted that the inordinate number of inspections are due to the comedy of errors associated with ME2’s construction.

Karst Formations & Sinkholes

Which brings us to the current ME2 debacle. Last week, the PA Public Utility Commission (PUC) ordered a temporary shutdown of Mariner East 1 (ME1), another natural gas liquids pipeline owned by Sunoco/ETP. ME1 was built in the 1930s and its right-of-way is being used for most of ME2’s route across the state. This latest construction setback comes in the wake of numerous sinkholes that emerged beginning in December along Lisa Drive in West Whitehead Township, a suburb of Philadelphia in Chester County.

The most recent of these sinkholes grew into a 20ft-deep, 15ft-wide chasm that exposed portions of ME1 and came within 10ft of a house. It is worth noting that, until only a few days ago, ME1 was an operational 8in pipeline with a potential impact radius (aka “blast zone”) of some 500ft. The PUC ordered that Sunoco must now run a line inspection on ME1 for a mile upstream and a mile downstream from the sinkhole sites along Lisa Drive, seen in the image below. Note the proximity of these sinkholes to Amtrak’s Keystone rail lines (connecting Pittsburgh to Philadelphia), under which ME2 also runs. The Federal Railway Administration only recently learned of the sink holes from a nearby resident.

ME2-related sinkholes along Lisa Drive
(Image: Eric Friedman)

The Lisa Drive sinkholes are being credited to Sunoco executing an HDD in an area known to have karst geological formations. Sunoco has been ordered by the PUC to conduct more geophysical testing and seismic analyses of the area because of this. Karst is often called the “Swiss cheese” of geology — notorious for caves, sinkholes, and underground rivers. As these geological formations change shape, pipelines can bend and settle over time, ultimately leading to potentially dangerous gas leakages or explosions. For instance, the 2015 Atex-1 pipeline explosion in Follansbee, WV, was ultimately determined by the Pipeline and Hazardous Materials Safety Administration (PHSA) as having been caused by ground settling. That explosion released some 24,000 barrels of ethane, burning more than five acres of surrounding land.

The US Geological Survey (USGS) maintains fairly detailed maps of rock formations for most states, including formations known to have karst. In PA, there are a number of “carbonate” rock families known for karst features and settlement issues: limestone and dolostone, and, to a lesser extent, shale. Meanwhile, the PA Department of Conservation and Natural Resources (DCNR) has maintained a record of karst “features” — sinkholes and surface depressions — documented since 1985. A great explanation of the different types of karst features can be found here.

Underestimating the Risks

What is concerning about the Lisa Drive sinkholes is that Sunoco had supposedly already conducted additional karst geological reviews of the area as part of the August DEP settlement, subsequently ranking a nearby HDD (#PA-CH-0219) as “low risk” for running into karst issues—despite knowing the HDD runs through a karst formation with sinkholes and surface depressions in the area. For the HDD that runs the length of Lisa Drive (#PA-CH-0256), the study rated its risk as “very low.” These two HDDs are shown below, along with the area of ME1 now under structural review.

Sunoco’s karst study did not account for the Lisa Drive HDD

The likely result of these inaccurate assessments led to two IRs at Lisa Drive, one in October and another in November 0f 2017. DEP’s writeup of these events note that the total volume of drilling muds spilled remains unknown because Sunoco didn’t report the incident. Then, only a month later, sinkholes emerged in the same locations. An image of the November HDD IR is shown below.

A November HDD IR at Lisa Drive
(Image: Eric Friedman)

It is important to note two additional things of Sunoco’s karst study, an except of which is seen in their map of the West Whiteland area below. First, Lisa Drive is just on the edge of a karst limestone formation. USGS data suggest the location is actually mica schist, but the USGS data is also only a rough estimate of different formations. This underscores why pipeline companies must be required to conduct detailed geotechnical analysis of all HDD sites at the onset of their projects.

The other notable aspect of Sunoco’s study is that it does not fully represent all rock formations known to have karst features. In Sunoco’s map, we see orange shading for limestone, but this does not include dolostone that underlies the many surface depressions and sinkholes surrounding West Whiteland. FracTracker’s map includes these formations for greater accuracy.

Sunoco’s karst study of the West Whiteland area

Takeaways

Interestingly, as Anya Litvak of the Pittsburgh Post-Gazette observed in her reporting on the Lisa Drive incident, Sunoco’s updated karst assessment ranked the entire route of the ME2 pipeline through the state as “low to very low” risk for potential issues. Furthermore, Sunoco has tried to downplay the Lisa Drive incident, stating that “all areas have been secured,” and that additional incidents are unlikely to occur.

But the overall relationship between Mariner East 2’s IRs, HDD sites, and known karst features tells a very different story than Sunoco’s about the potential risks of ME2. In addition to the concerns about new sinkholes near Lisa Drive, FracTracker found the following in our analysis:

  • 7 sinkholes and 386 surface depressions are within 1,500ft of a ME2 HDD site.
  • Of the 230 HDDs, 87 are located in carbonate rock areas (52 in limestone/dolostone, 35 in shale).
  • Of the 99 IRs, 39 have occurred in carbonate rock areas (23 in limestone/dolostone, 16 in shale).

In other words, nearly half of the IRs caused by ME2 HDDs were located in areas known to have karst formations. Worth noting is that an additional 15 occurred in sandstone formations, also known to cause settlement over time. The remaining IRs are split across nine other formation types.

Considering that the DEP’s current review of Sunoco’s ability to safely execute future HDDs are based on the same karst study that missed the Lisa Drive HDD and ranked nearby HDDs as a “low” risk, one can only assume that additional spills will occur. There are many more HDD sites yet to be drilled, and also not likely studied fully for potential karst risks. As illustrated by the continuing saga of spills, violations, and omissions, it is clear that Sunoco has not maintained a high standard of construction in building ME2 from the onset.

We thank Eric Friedman from the Middletown Coalition for Community Safety for supplying photos of the Lisa Drive site used in this article.

By Kirk Jalbert, FracTracker Alliance

Waiting on Answers - XTO incident image two weeks later
FracTracker Alliance

Waiting on Answers Weeks after a Well Explosion in Belmont County Ohio

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Mar 7 Update: The well has finally been capped.

On February 15, 2018, officials evacuated residents after XTO Energy’s Schnegg gas well near Captina Creek exploded in the Powhatan Point area of Belmont County, Ohio. More than two weeks later, the well’s subsequent blowout has yet to be capped, and people want to know why. Here is what we know based on various reports, our Ohio oil and gas map, and our own fly-by on March 5th.

March 19th Update: This is footage of the Powhatan Point XTO Well Pad Explosion Footage from Ohio State Highway Patrol’s helicopter camera the day after the incident:


Powhatan Point XTO well pad explosion footage from Ohio State Highway Patrol

Cause of the Explosion

The well pad hosts three wells, one large Utica formation well, and two smaller ones. XTO’s representative stated that the large Utica well was being brought into production when the explosion occurred. The shut-off valves for the other two wells were immediately triggered, but the explosion caused a crane to fall on one of those wells. The representative claims that no gas escaped that well or the unaffected well.

Observers reported hearing a natural gas hiss and rumbling, as well as seeing smoke. The Powhatan Point Fire Chief reported that originally there was no fire, but that one later developed on the well pad. To make matters worse, reports later indicated that responders are/were dealing with emergency flooding on site, as well.

As of today, the Utica well that initially exploded is still releasing raw gas.

Site of the Feb 15th explosion on the XTO pad

Map of drilling operations in southeast Ohio, with the Feb 15, 2018 explosion on XTO Energy’s Schnegg gas well pad marked with a star. View dynamic map

Public Health and Safety

No injuries were reported after the incident. First responders from all over the country are said to have been called in, though the mitigation team is not allowed to work at night for safety reasons.

The evacuation zone is for any non-responders within a 1-mile radius of the site, which is located on Cat’s Run Road near State Route 148. Thirty (30) homes were originally evacuated within the 1-mile zone according to news reports, but recently residents within the outer half-mile of the zone were cleared to return – though some have elected to stay away until the issue is resolved completely. As of March 1, four homes within ½ mile of the well pad remain off limits.

The EPA conducted a number of site assessments right after the incident, including air and water monitoring. See here and here for their initial reports from February 17th and 20th, respectively. (Many thanks to the Ohio Environmental Council for sharing those documents.)

Much of the site’s damaged equipment has been removed. Access roads to the pad have been reinforced. A bridge was recently delivered to be installed over Cats Run Creek, so as to create an additional entrance and exit from the site, speaking to the challenges faced in drilling in rural areas. A portion of the crane that fell on the adjacent wellhead has been removed, and workers are continuing their efforts in removing the rest of the crane.


The above video by Earthworks is optical gas imaging that makes visible what is normally invisible pollution from XTO’s Powhatan Point well disaster. The video was taken on March 3, 2018, almost 3 weeks after the accident that started the uncontrolled release. Learn more about Earthworks’ video and what FLIR videos show.

An early estimate for the rate of raw gas being released from this well is 100 million cubic feet/day – more than the daily rate of the infamous Aliso Canyon natural gas leak in 2015/16. Unfortunately, little public information has been provided about why the well has yet to be capped or how much gas has been released to date.

Bird’s Eye View

On February 26, a two-mile Temporary Flight Restriction (TFR) was enacted around the incident’s location. The TFR was supposed to lapse during the afternoon of March 5, however, due to complications at the site the TFR was extended to the evening of March 8. On March 5, we did a flyover outside of the temporary flight restriction zone, where we managed to capture a photo of the ongoing release through a valley cut. Many thanks to LightHawk and pilot Dave Warner for the lift.

Photo of the XTO Energy well site and its current emissions after the explosion two weeks ago. Many are still waiting on answers as to why the well has yet to be capped.

XTO Energy well site and ongoing emissions after the explosion over two weeks ago. Many are still waiting on answers as to why the well has yet to be capped. Photo by Ted Auch, FracTracker Alliance, March 5, 2018. Aerial support provided by LightHawk

Additional resources

Per the Wheeling Intelligencer – Any local residents who may have been impacted by this incident are encouraged to call XTO’s claims phone number at 855-351-6573 or visit XTO’s community response command center at the Powhatan Point Volunteer Fire Department, located at 104 Mellott St. or call the fire department at 740-312-5058.

Sources:

Aerial image of fracking activity in Marshall County, WV, next to the Ohio River on January 26th, 2018 from approximately 1,000 to 1,200 feet, courtesy of a partnership with SouthWings and pilot Dave Warner. The camera we used was a Nikon D5300. Photo by Ted Auch, FracTracker Alliance, January 2018
Ted Auch, PhD

Fracking’s Freshwater Supply and Demand in Eastern Ohio

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Water is the key ingredient in the hydraulic fracturing process, and its usage – in total and per well – is increasing at an exponential rate. Below, FracTracker takes a look at water withdrawal and use for fracking across 23 Eastern Ohio counties between 2010 and 2016.

Mapping Hydraulic Fracturing Freshwater Supply and Demand in Ohio

Below is a map of annual and cumulative water withdrawal volumes by the hydraulic fracturing industry across Ohio between 2010 and 2016. It displays 312 unique sites, as well as water usage per lateral. The digital map, which can be expanded fullscreen for more features, includes data up until May 2017 for 1,480 Ohio laterals (vertical wells can host more than one lateral well).


View map fullscreen | How FracTracker maps work

The primary take-home message from this analysis and the resulting map is that we can only account for approximately 73% of the industry’s more than 13-billion-gallon freshwater demand by considering withdrawals alone. Another source or sources must be supplying water for these hydraulic fracturing operations.

Hydraulic fracturing rig on the banks of the Ohio River in Marshall County, West Virginia, Winter 2018 (Flight provided by SouthWings)

When Leatra Harper at Freshwater Accountability Project and Thriving Earth Exchange and I brought up this issue with Ohio Division of Water Resources Water Inventory and Planning Program Manager, Michael Hallfrisch, the following correspondence took place on January 24, 2018:

Mr. Hallfrisch: “Where did the water usage per lateral data come from?  Does the water usage include reused/recycled water?  I know that many of the larger operators reuse a significant amount of their flow back because of the high cost of disposal in class II injection wells.”

FracTracker: “[We’]ve been looking at Class II disposal economics in several states and frankly the costs here in Ohio are quite cheap and many of the same players in Ohio operate in the other states [We]’ve looked at.  Granted they usually own their own Class II wells in those other states (i.e., OK, or CO) but the fact that they are “vertically integrated” still doesn’t excuse the fact that the cost of disposing of waste in Ohio is dirt cheap.  As for recycling that % was always a rounding error and last [we] checked the data it was going down by about 0.25-0.35% per year from an average of about 5.5-8.0%.  [We respectfully] doubt the recycling % would fill this 25% gap in where water is coming from.  This gap lends credence to what Lea and [FracTracker] hear time and again in counties like Belmont, Monroe, Noble etc with people telling us about frequent trenches being dug in 1st and 2nd order streams with operators topping off their demands in undocumented ways/means.  Apologies for coming down hard on this thing but we’ve been looking/mapping this thing since 2012 and increasingly frustrated with the gap in our basic understanding of flows/stocks of freshwater and waste cycling within Ohio and coming into the state from PA and WV.”

Consol Energy Wastewater Impoundment adjacent to a Hydraulically Fractured Well Pad in Belmont County, Ohio, Fall, 2017

Consol Energy Wastewater Impoundment adjacent to a Hydraulically Fractured Well Pad in Belmont County, Ohio, Fall, 2017

Consol Energy Wastewater Impoundment adjacent to a Hydraulically Fractured Well Pad in Belmont County, Ohio, Fall, 2016

Broader Implications

The fracking industry in Ohio uses roughly 10-14 million gallons per well, up from 4-5 million gallon demands in 2010, which means that freshwater demand for this industry is increasing 15% per year (Figures 1 and 2). (This rate is more than double the volumes cited in a recent publication by the American Chemical Society, by the way.) If such exponential growth in hydraulic fracturing’s freshwater demand in Appalachia continues, by 2022 each well in Ohio and West Virginia will likely require[1*] at least 43 million gallons of freshwater (Table 1).

Table 1. Projected annual average freshwater demand per well (gallons) for the hydraulic fracturing industry in Ohio and West Virginia based on a 15% increase per year.

Year Water Use Per Well (gallons)
Ohio West Virginia
2019 19,370,077 19,717,522
2020 23,658,666 23,938,971
2021 28,896,760 29,064,215
2022 35,294,582 35,286,756
2023 43,108,900 42,841,519

Water quantity and associated watershed security issues are both acute and chronic concerns at the local level, where fracking’s freshwater demands equal 14% of residential demands across Ohio. These quantities actually exceed 85% of residential demand in several Ohio counties (e.g., Carroll and Harrison), as well as West Virginia (e.g., Doddridge, Marshall, and Wetzel). Interestingly the dramatic uptick in Ohio freshwater demand that began at the end of 2013 coincides with a 50% decline in the price of oil and gas (Figure 3).  The implication here is that as the price of gas and oil drops and/or unproductive wells are drilled at an unacceptable rate, the industry uses more freshwater and sand to ensure acceptable financial returns on investments.

Figures 1-3

Ave. per-well freshwater demand by the hydraulic fracturing industry from Q3-2010 to Q4-2016 2017 in OH

Ave. per-well freshwater demand by the hydraulic fracturing industry from Q3-2010 to Q4-2016 2017 in WV

Average Monthly Price of Brent Crude and WTI Oil ($ Per Barrel)

Note: Data from U.S. Energy Information Administration (EIA) Petroleum & Other Liquids Overview

Total Water Used

To date, the fracking industry has taken on average 90 million gallons of freshwater per county out of Ohio’s underlying watersheds, resulting in the production of 9.6 million gallons of brine waste that cannot be reintroduced into waterways. This massive waste stream is destined for one of Ohio’s Class II Injection wells, but the industry spends less than 1.25% of available capital on water demand(s) and waste disposal. All of this means that the current incentive (cost) to become more efficient is too low. Sellers of water to the industry like the Muskingum Watershed Conservancy District, which we’ve chronicled frequently in the past[2], have actually dropped their price for every 1,000 gallons of water – from roughly $9 to now just $4-6 – for the fracking industry in recent years.

Gulfport Energy’s Barnesville Reservoir freshwater withdrawal pumping station, Belmont County, Ohio, Summer, 2017

Gulfport Energy’s Seneca Lake Reservoir freshwater withdrawal pump in Belmont County, Ohio, Fall, 2015

Gulfport Energy’s Barnesville Reservoir freshwater withdrawal pumping station, Belmont County, Ohio, Spring, 2017

Freshwater Impoundment adjacent to a Hydraulically Fractured Well Pad in Belmont County, Ohio, Fall, 2017

Hydraulic fracturing’s demand is becoming an increasingly larger component of total water withdrawals in Ohio, as other industries, agriculture, and mining become more efficient. Oil and gas wells drilled at the perimeter of the Utica Shale are utilizing 1.25 to 2.5 times more water than those that are staged in the shale “Sweet Spots.” Furthermore, the rise in permitting of so called “Super Laterals” would render all of our water utilization projections null and void. Laterals are the horizontal wells that extend out underground from the vertical well. Most well pads are home to multiple laterals in the range of 4-7 laterals per pad across Ohio and West Virginia.

These laterals, which can reach up to 21,000 feet or almost 4 miles, demand as much as 87 million gallons of freshwater each.

Even accounting for the fact that the super laterals are 17-21,000 feet in length – vs. an average of 7,452 feet – such water demand would dwarf current demands and their associated pressures on watershed security and/or resilience; typically, Ohio’s hydraulically fractured laterals require 970-1,080 gallons of freshwater per lateral foot (GPLF), but super laterals would need an astounding 4,470 GLPF.

Conclusions and Next Steps

The map above illustrates the acute pressures being put upon watersheds and public water supplies in the name of “energy independence.” Yet, Ohio regulators and county officials aren’t putting any pressure on the high volume hydraulic fracturing (HVHF) industry to use less water and produce less waste. We can’t determine exactly how water demand will change in the future. The problem is not going away, however, especially as climate change results in more volatile year-to-year fluctuations in temperature and precipitation. This means that freshwater that was/is viewed as a surplus “commodity” will become more valuable and hopefully priced accordingly.

Furthermore, the Appalachian Ohio landscape is undergoing dramatic transformations at the hands of the coal and more recently the HVHF industry with strip-mines, cracking plants, cryogenic facilities, compressor stations, gas gathering lines – and more – becoming ubiquitous.

Freshwater Impoundment and Hydraulically Fractured Well Pad in Wetzel County, West Virginia, Winter, 2018

Freshwater Impoundment and Hydraulically Fractured Well Pad in Wetzel County, West Virginia, Winter, 2018

Forest clearing in prepration for hydraulic fracturing well pad establishment, Belmont County, Ohio, Spring, 2017

Freshwater Impoundment, hydraulically fractured well pad, and access road in Noble County, Ohio, Spring, 2016

We are seeing significant acreage of deciduous forests, cropland, or pasture that once covered the region replaced with the types of impervious surfaces and/or “clean fill” soil that has come to dominate HVHF landscapes in other states like North Dakota, Texas, and Oklahoma.

This landscape change in concert with climate change will mean that the region will not be able to receive, processes, and store water as effectively as it has in the past.

It is too late to accurately and/or more holistically price the HVHF’s current and past water demand in Ohio, however, such holistic pricing would do wonders for how the industry uses freshwater in the future. After all, for an industry that believes so devotedly in the laws of supply and demand, one would think they could get on board with applying such laws to their #1 resource demand in Appalachia. The water the HVHF industry uses is permanently removed from the hydrological cycle. Now is the time to act to prevent long term impacts on Ohio’s freshwater quantity and quality.

Relevant Data

  • Ohio hydraulic fracturing lateral freshwater demand by individual well between 2010 and the end of 2016. Download
  • Ohio hydraulic fracturing lateral freshwater withdrawals by site between 2010 and the end of 2016. Download

Endnotes

  1. *Certainty, with respect to this change in freshwater demand, is in the range of 86-90% assuming the exponential functions we fit to the Ohio and West Virginia data persist for the foreseeable future. Downing, Bob, 2014, “Ohio Drillers’ Growing Use of Fresh Water Concerns Environmental Activists”, March 19th, Akron, Ohio
  2. Downing, Bob, 2014, “Group Reacts to Muskingum Watershed Leasing Deal with Antero”, April 22nd, Akron, Ohio

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

Ted Auch, PhD

Appalachian Ohio: Where Coal Mining, Fracking, and National Politics Converge

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The head of Murray Energy Corporation, Robert Murray, is very close to the highest office in the land. Such an association demands a close look at the landscape from which this corporation and its founder arouse.

Belmont County, Ohio’s most famous tycoon Robert Murray has established a close relationship with the Trump administration. This connection dates back to his $300,000 contribution to Trump’s inauguration. The intimacy of this relationship has been given new weight recently when it was revealed that a hug between Mr. Murray and the Department of Energy’s Secretary Rick Perry preceded a meeting where Mr. Murray presented the administration with a memo outlining a 16-point plan for removing some of the burdensome regulations put in place by Mr. Murray’s least favorite person former President Barack Obama.

Among the few consistent themes from this most inconsistent of presidents has been a fondness for coal and steel, where brawny men do essential work and are threatened not by shifting economics, but by greenies and weenies who want to shut them down. Mr Trump and Mr Murray both want environmental rules rolled back—Mr Murray because it would be good for his bottom line, and Mr Trump because a second consistent aim of his presidency is to reverse anything done by Barack Obama. It is doubtful whether policy shifts alone could revive coal mining, but the attempt to do so says much about how vested interests operate in this administration… Mr Trump played a hard-nosed businessman on TV, but Mr Murray is the real thing. – The Economist, 2018

Not only has Mr. Murray succeeded in capturing the hearts and minds of the Trump administration, he has demanded that his $300,000 contribution get his longtime Oklahoman lawyer, and former aide to the senate’s chief climate skeptic James M. Inhofe of Oklahoma, the #2 spot behind Scott Pruitt at the EPA. Mr. Murray is so powerful that he managed to get Perry & Co. to fire the photographer that took the photo of the tender moment between Messrs. Perry and Murray.

Awkwardness aside, these situations could reasonably lead one to conclude that Perry and Pruitt are competing for Murray’s favor in the event they choose to run for higher office and need a patron with deep pockets. Mr. Murray would be in a real pickle if they both chose to run for the highest office in the land, with two fawning candidates potentially offering to one-up the other in terms of incentives and/or regulatory carve outs for Mr. Murray’s beloved King Coal.

Rick Perry and Robert Murray Embrace

The cover of Upton Sinclair’s “King Coal”

Belmont County

Once the heart of Ohio Coal Country, Belmont Co. is now a major player on the hydraulic fracturing landscape, as well.

Given the growing influence of Mr. Murray and the coal industry writ large we thought it was time to do a deep dive into how Mr. Murray’s Appalachian Ohio home county of Belmont and surrounding counties have been altered by coal mining. We were also interested in how the coal industry has come to interact with the hydraulic fracturing industry, which has drilled 542 Utica wells in Belmont County alone since March 2012. These wells amount to 20% of all fracked wells in Ohio as of January 2018. The rate at which Utica wells are being permitted in Belmont County is actually increasing by about 1.5 to 2 permits per month or 5.5 to 7.8 times the statewide average (Figure 1).

Belmont County also happens to be the “all-time leader in coal production in Ohio” having produced 825 million tons since 1816 (ODNR, 2005). All of this means that the Ohio county that produces the most coal is also now The Buckeye State’s most actively drilled county.

Utica Wells Permits in Belmont County, Ohio Q1-2012 to Q1-2018

Figure 1. Monthly and cumulative hydraulically fractured wells in Belmont County, Ohio between Q1-2012 and Q1-2018

Photos of coal mining operations in Belmont County, OH. Flyovers courtesy of SouthWings:

Ohio Valley Coal Co. Underground “Powhatan No. 6” Mine and Slurry Pond (39.911606, -80.98456)

Ohio Valley Coal Co. Underground “Powhatan No. 6” Mine and Slurry Pond (39.911606, -80.98456)

American Energy Corp. Underground “Century” Mine and Mine Spoil Pile (39.895921, -81.02129)

American Energy Corp. Underground “Century” Mine and Mine Spoil Pile (39.895921, -81.02129)

An End to Coal

However, the days of coal’s dominance – and easily mineable coal – in Ohio appear to be coming to an end.

Per mine, Ohio’s mines produce about 30% of the national average and 43% of the state averages (Figure 2). Ohio’s mines only produce about 10% of what the mega Western mines produce on a per-mine basis, and much less than states like New Mexico and Texas, as well.

Even with automation, the barriers to a return of coal in Appalachia are formidable given that most of the easily recoverable coal has already been mined. Additionally, the landscape is more formidable and not as conducive to the large strip-mine and dragline operations of  the Powder River Basin, which produce roughly 8.5 million tons of coal per mine, compared to an average of 330,000 tons per mine in Appalachia. (Figure 2).

Coal Production by State (Thousand Tons, 2016)

Figure 2. Total coal produced across the twenty-five coal producing states, the Appalachian region, Western Basins (2016, tons, Data Courtesy of Energy Information Administration (EIA) State Profile and Energy Estimates)

Mapping Coal and Fracking

The below map depicts parcels owned by coal mining companies in the Ohio counties of Belmont, Noble, Guernsey, and Muskingum, as well as previously mined and/or potential parcels based on owner and proximity to existing mines.

We also incorporated production data (2001 to 2016) for 116 surface and strip coal mines in these and surrounding counties, natural gas pipelines, hydraulically fractured laterals, and Class II Salt Water Disposal (SWD) injection wells as of January 2018.

There are few areas in the United States where underground coal mining and fracking are taking place simultaneously and on top of each other. What could possibly go wrong when injecting massive amounts of fracking waste at high pressures into the geology below, while simultaneously pumping billions of gallons of water into hydraulically fractured laterals and mining coal at similar depths?

In the coming months and years we will be monitoring Belmont County, Ohio as an unfortunate case-study in determining the answer to such a unique question.

At the present time:

  • Murray Energy, its subsidiaries, and other coal companies own approximately 15% of Belmont County.
  • Coal companies and their associated real-estate firms and subsidiaries have mined or own approximately 5,615 square miles across the Noble, Belmont, Guernsey, and Muskingum counties.
  • The 116 mines in this map have mined an average of 3.22 million tons of coal since 2001 and more than 373 million tons in total. Mr. Murray’s mines account for 50% of this amount, producing nearly 15 times more coal per mine than the other 112 mines.

Collectively, these mines have contributed 1.09 billion tons of CO2 and CH4+N2O in CO2 equivalents to atmospheric climate change, or 68 million tons per year (MTPY). This volume is equivalent to the annual emissions of nearly 60 million Americans or 19% of the population.

Murray’s mines alone have contributed enough greenhouse gases (CO2+CH4+N2O) to account for the emissions of 9.2% of the US population since 2001. Each Murray mine is belching out 8.41 million tons of greenhouse gases per year or roughly equivalent to the emissions of 463,489 Americans.


View map fullscreen | How FracTracker maps work

Relevant data for this map can be found at the end of this article.

Broader Implications

Robert Murray’s influence and mining impacts extend well beyond Appalachian Ohio.

Mr. Murray’s is the primary owner of 157 mines and associated facilities1 across eleven states – and five of the six major Lower 48 coal provinces – from Utah and North Dakota to Alabama, Georgia, and Florida (Figure 3). Mr. Murray likes to highlight his sage purchases of prime medium and high volatility bituminous coal real-estate over the years on his company’s website. However, nowhere in his corporate overview does he mention his most notorious mine: the abandoned and sealed underground Crandal Canyon Mine, Emery County, Utah. It was at this mine on August 6, 2007 that a collapse trapped six miners and resulted in their deaths, along with the deaths of three rescue workers. Mr. Murray told the BBC that he had had an emotional breakdown and hadn’t deserted anyone living in a little trailer adjacent to the mine’s entrance every day following the collapse. Furthermore, Mr. Murray blames such events on subsidiaries like Grenwal Resources Inc., which happens to be the owner of record for the Crandal Canyon Mine and is one of thirty-three unique subsidiaries owned by Mr. Murray (data download).

US Coal Mines and Mines Owned by Robert Murray

Figure 3. US Coal Mines by type and Mines Owned by Robert Murray highlighted in turquoise

Table 1. Robert Murray coal mine ownership by mine status

Status Number of Mines
Abandoned 68
Abandoned and Sealed 62
Active 12
Non-Producing 10
Temporarily Idled 5
Total 157

The Politics of Energy

Robert Murray and his fellow fossil fuel energy brethren’s bet on Trump paid off, with Trump winning 99% of the vote in congressional districts where coal mines exist (Figure 4). Such a performance bested the previous GOP candidates of McCain and Romney even though they had achieved an impressive 96% of the vote. Interestingly, Trump did nearly as well in congressional districts dominated by wind farms and ethanol refineries where more than 87% of the electorate was white.

Percent of Energy Infrastructure in Congressional Districts that went for GOP Presidential Candidates in 2016, 2012, and 2008

Figure 4. Presidential election results for GOP candidates in voting districts where various forms of energy are produced and/or processed, 2016, 2012, and 2008

Trump & Co. promised these districts that his administration would breathe life into the fossil fuel industry. True, Trump, Pruitt, Perry, and Interior Secretary Ryan Zinke are greasing the skids for the industry’s revival. In terms of annual production, however, it is far from certain that such moves will translate into the types of boost in employment promised by Trump during the 2016 campaign. Even if production does return, executives like Murray admit that the advent of efficiencies and extraction technologies means that the industry is mining more coal per miner than ever before:

“Trump has consistently pledged to restore mining jobs, but many of those jobs were lost to technology rather than regulation and to competition from natural gas and renewables, which makes it unlikely that he can do much to significantly grow the number of jobs in the industry,” said Murray. “I suggested that he temper his expectations. Those are my exact words,” said Murray. “He can’t bring them back.” – The Guardian, March 27, 2017

Conclusions and Next Steps

It remains to be seen how the coal mining and fracking industry’s battle for supremacy will play out from a socioeconomic, health, environmental, and regulatory perspective. While many people understand that coal jobs aren’t coming back, we shouldn’t doubt the will of the Trump administration and friends like Robert Murray to make sure that profits can still be extracted from Appalachia.

Will the fracking industry and coal barons agree to get along, or will they wage a war on multiple fronts to marginalize the other side? Will this be another natural resource conflagration? If so, how will the people – and species like the “near-threatened” Hellbender Salamander (Cryptobranchus alleganiensis) or the region’s recovering Bald Eagle (Haliaeetus leucocephalus) population that live in the disputed Appalachian communities respond? How will their already stressed day-to-day existence be affected? To this point, the fossil fuel industry has managed to blame everyone but itself for the tepid to non-existent job growth in their sectors.

Bald Eagle flying above Murray Energy’s Powhatan No. 6 Mine, Belmont County, Ohio. Photo by Ted Auch

Bald Eagle and nest adjacent to Murray Energy’s Powhatan No. 6 Mine, Belmont County, Ohio. Photo by Ted Auch

The Appalachian landscape has been deeply scarred and fragmented by coal mining, and now it is experiencing a new colonizing force in the form of the hydraulic fracturing industry. When Appalachia realizes that automation, globalization, and natural gas, are the key drivers to the downfall of coal, will they bring fire, brimstone, and pitchforks to the doorstep of Murray Energy of the fracking companies? Or is Appalachia’s future merely that of an extraction colony?

Oh Say, did you see him; it was early this morning.
He passed by your houses on his way to the coal.
He was tall, he was slender, and his dark eyes so tender
His occupation was mining, West Virginia his home
It was just before noon, I was feeding the children,
Ben Moseley came running to give us the news.
Number eight was all flooded, many men were in danger
And we don’t know their number, but we fear they’re all doomed.
– “West Virginia Mine Disaster” © Jean Ritchie, Geordie Music Publishing

By Ted Auch, Great Lakes Program Coordinator, FracTracker Alliance

Endnote

  1. Murray is listed as the owner of 45 coal mining facilities, 35 surface mines, and 77 underground mines according to data compiled from the Department of Labor

Download Relevant Data (Zip Files)

High Impact Areas and Donut Holes - Variability in PA's Unconventional O&G Industry map
Matt Kelso, BA

High Impact Areas and Donut Holes – A Look at Unconventional O&G Activity in PA

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FracTracker Alliance has been mapping the impacts of unconventional oil and gas (O&G) drilling activity in Pennsylvania since 2010, and the Pennsylvania Shale Viewer is our most complete map to show the impacts of the industry.

While it can rightly be said that the development of the Marcellus Shale and other unconventional formations have affected half the state since 2005, this analysis takes a look at high impact areas, as well as a closer look at areas that have been avoided so far.

Explore the Story Map

High Impact Areas and Donut Holes
Variability in PA’s Unconventional Oil and Gas Industry


By Matt Kelso, Manager of Data and Technology, FracTracker Alliance

http://www.bakersfield.com/news/arvin-looks-to-impose-more-regulations-on-oil-gas-operators/article_2beb26d6-cbdc-11e7-ba1a-4b0ac35a0fa8.html
Kyle Ferrar, MPH

Arvin, CA – a City in the Most Drilled County in the Country – files for a Setback Ordinance

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The City of Arvin, with a population of about 20,000, is located in Kern County, California just 15 miles southeast of Bakersfield. Nicknamed ‘The Garden in the Sun,’ Arvin is moving forward with establishing new regulations that would limit oil and gas development within the city limits.

Setback Map

The new ordinance proposes setback distances for sensitive sites including hospitals and schools, as well as residentially and commercially zoned parcels. The proposal establishes a 300-foot buffer for new development and 600’ for new operations.

In the map below, FracTracker Alliance has mapped out the zoning districts in Arvin and mapped the reach of the buffers around those districts. The areas where oil and gas well permits will be blocked by the ordinance are shown in green, labeled “Buffered Protected Zones.” The “Unprotected Zones” will still allow oil and gas permits for new development.

There are currently 13 producing oil and gas wells within the city limits of Arvin, 11 of them are located in the protected zones. Those within the protected zones are operated by Sun Mountain Oil and Gas and Petro Capital Resources. They were all drilled prior to 1980, and are shown in the map below.

Map 1. Arvin, CA Proposed setback ordinance

View map fullscreen | How FracTracker maps work

Information on the public hearings and proposals can be found in the Arvin city website, where the city posts public notices. As of January 24, 2018, these are the current documents related to the proposed ordinance that you will find on the webpage:

Earlier Proposals in Arvin

The proposed 2017 setback ordinance is in response to a previously proposed 2016 ordinance that would allow Kern County to fast track permits for oil and gas activities without environmental review or any public notice for the next 20 years. This could mean 72,000 new wells without review, in an area that already possesses the worst air quality in the country. Communities of color would of course be disproportionately impacted by such policy. In Kern County, the large percentage of Latinx residents suffer the impacts of oil drilling and fracking operations near their homes schools and public spaces.

In December of 2016, Committee for a Better Arvin, Committee for a Better Shafter, and Greenfield Walking Group, represented by Center for Race, Poverty and the Environment, sued Kern County. The lawsuit was filed in coordination with EarthJustice, Sierra Club, Natural Resources Defense Council, and the Center for Biological Diversity.

The Importance of Local Rule

Self-determination by local rule is fundamental of United States democracy, but is often derailed by corporate industry interests by the way of state pre-emption. There is a general understanding that local governments are able to institute policies that protect the interests of their constituents, as long as they do not conflict with the laws of the state or federal government. Typically, local municipalities are able to pass laws that are more constrictive than regional, state, and the federal government.

Unfortunately, when it comes to environmental health regulations, states commonly institute policies that preserve the rights of extractive industries to access mineral resources. In such cases, the state law “pre-empts” the ability of local municipalities to regulate. Local laws can be considered the mandate of the people, rather than the influence of outside interest on representatives. Therefore, when it comes to land use and issues of environmental health, local self-determination must be preserved so that communities are empowered in their decision making to best protect the health of their citizens.

For more on local policies that regulate oil and gas operations in California, see FracTracker’s pieces, Local Actions in California, as well as What Does Los Angeles Mean for Local Bans?

By Kyle Ferrar, Western Program Coordinator, FracTracker Alliance

Feature image by: Henry A. Barrios / The Californian

Falcon Public EIA Project feature image
FracTracker Alliance

Wingspan of the Falcon Pipeline

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A Public EIA of Shell’s Ethane Cracker Pipeline

Pittsburgh, Pennsylvania – Jan. 29 – FracTracker Alliance has released a detailed environmental impact assessment (EIA), including digital maps, of the Falcon Ethane Pipeline being built to feed Shell Appalachia’s ethylene cracker plant in Beaver County, PA.

FracTracker’s Falcon Public EIA Project offers a rich series of interactive maps and articles detailing the Falcon’s proposed route through PA, WV, and OH, likely impacts to waterways, potential blast zones, ecological footprint, proximity to hazardous industrial areas, and more.

Given the issues associated with Mariner East 2 – a PA-based natural gas liquids pipeline whose history has been fraught with citations, public scrutiny is a crucial facet of pipeline construction. The Falcon Public EIA Project represents the first time that public stakeholders have been given such a significant amount of time and detail to investigate a proposed pipeline, including access to specific location information. Public comments are being accepted by the PA Department of Environmental Protection on the Falcon’s permit until February 20th.

“Companies are generally not required to publicly disclose GIS data when applying for permits,” remarked Kirk Jalbert, project lead and Manager of Community Based Research and Engagement at FracTracker. “While concerned citizens can stitch together paper maps provided by companies in their applications, that process can be complex and very labor intensive.”

With FracTracker’s project, however, digital maps and figures are front and center.

Early access to what is being proposed for the Falcon pipeline will enable nearby communities to better understand how its construction and the associated ethane cracker facility, which will produce 1 million tons of ethylene annually for making plastics, will affect their lives. Upon analyzing the data, FracTracker uncovered a number of particularly noteworthy statistics, for example:

  • There are 97.5 miles of pipeline proposed to be built through 22 townships in 3 states.
  • 2,000 properties have been surveyed; 765 easements executed.
  • Falcon will intersect 319 streams and 174 wetlands, with hundreds more proximate to work areas.
  • 550 family residences, 20 businesses, 240 groundwater wells, 12 public parks, 5 schools, 6 daycare centers, and 16 emergency response centers are within potential risk areas.
  • Learn more

“Extreme levels of risk and injustice are commonplace in petrochemical pipeline siting, as well as in where their contents come from and how they get used. This project provides context for the importance of reducing these impacts, both for curtailing environmentally unfriendly plastics as well as for moving away from fossil fuel dependencies,” said Brook Lenker, Executive Director of FracTracker.

The Falcon Public EIA Project is meant to expand public dialogue about what should be included in EIAs and how they should apply to petrochemical pipelines. The project also serves as a model for how regulatory agencies can be more transparent with data when engaging the public. This is especially important in the case of the Falcon pipeline, which will be exempt from Federal Energy Regulatory Commission (FERC) scrutiny and, therefore, not be subject to a full environmental impact assessment.

Explore the Falcon Public EIA Project
FracTracker Alliance

Pipeline Regulations & Impact Assessments, a Primer

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Part of the Falcon Public EIA Project

Pipelines are categorized by what they carry — natural gas, oil, or natural gas liquids (NGLs) — and where they go — interstate or intrastate. The regulatory system is complicated. This primer is a quick guide to the agencies that may be involved in Falcon’s permit reviews.

Regulating Pipelines

The siting of natural gas pipelines crossing state or country boundaries is regulated by the Federal Energy Regulatory Commission (FERC). Meanwhile, determination of the location of natural gas routes that do not cross such boundaries are not jurisdictional to FERC, instead determined by the owner pipeline company. Hazardous liquids and NGL pipelines are not regulated for siting by FERC regardless of their location and destination. However, FERC does have authority over determining rates and terms of service in these cases. The U.S. Army Corps of Engineers gets involved when pipelines cross navigable waters such as large rivers and state Environmental Protection Agencies.

Pipeline design, operation, and safety regulations are established by the Pipeline and Hazardous Materials Safety Administration (PHMSA), but these regulations may vary state-by-state as long as minimal federal standards are met by the pipeline project. Notably, PHMSA’s oversight of safety issues does not determine where a pipeline is constructed as this is regulated by the different agencies mentioned above – nor are PHMSA’s safety considerations reviewed simultaneously in siting determinations done by other agencies.

An excerpt from the U.S. Army Corps’ EIS of the Atlantic Sunrise pipeline

These federal agencies are required by the National Environmental Policy Act (NEPA) to prepare an Environmental Impact Statement (EIS) investigating how the pipeline pertains to things like the Clean Water Act, the Endangered Species Act, the National Historic Preservation Act, as well as state and local laws. The image above, for instance, is a caption from the Army Corp’s assessment of the Atlantic Sunrise, a natural gas pipeline.

An EIS is based on surveying and background research conducted by the company proposing the project, then submitted to agencies as an Environmental Impact Assessment (EIA). An EIS can exceed hundreds of pages and can go through many drafts as companies are asked to refine their EIA in order to qualify for approval.

An excerpt from the PA DEP’s review of water crossings for the Mariner East 2 pipeline

Pipeline proposals are also evaluated by state and local agencies. In Pennsylvania, for instance, the PA DEP is responsible for assessing how to minimize pipeline impacts. The DEP’s mission is to protect Pennsylvania’s air, land and water from pollution and to provide for the health and safety of its citizens through a cleaner environment. The PA Fish and Boat Commission oversees the avoidance or relocation of protected species. Local township zoning codes can also apply, such as to where facilities are sited near zoned residential areas or drinking reservoirs, but these can be overruled by decisions made at the federal level, especially when eminent domain is granted to the project.

Regulating the Falcon

For the Falcon pipeline, an interstate pipeline that will transport ethane (an NGL), FERC will likely have authority over determining rates and terms of service, but not siting. Construction permitting will be left state agencies and PHMSA will retain its federal authority with the Pennsylvania Public Utilities Commission (PUC) acting as PHMSA’s state agent to ensure the project complies with federal safety standards and to investigate violations. The Army Corps will almost certainly be involved given that the Falcon will cross the Ohio River. As far as we know, the Falcon will not have eminent domain status because it supplies a private facility and, thus, does not qualify as a public utility project.

Questioning Impact Assessments

The contents of EIAs vary, but are generally organized along the lines of the thematic categories that we have created for assessing the Falcon data, as seen above. However, there is also much that EISs fail to adequately address. The Army Corp’s assessment of the Atlantic Sunrise is a good example. The final EIS resulting from the operators EIA includes considerations for socioeconomic impacts, such effects on employment and environmental justice, as seen in the excerpt below. But potential negative impact in these areas are not necessarily linked to laws requiring special accommodations. For instance, federal regulations mandate achieving environmental justice by “identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects” of projects subject to NEPA’s EIS requirement. However, there are no laws that outline thresholds of unacceptable impact that would disallow a project to proceed.

An excerpt from the Atlantic Sunrise EIS addressing environmental justice concerns

Furthermore, the narratives of EIAs are almost always written by the companies proposing the project, using sources of data that better support their claims of minimal or positive impact. This is again seen in the Atlantic Sunrise EIS, where several studies are cited on how pipelines have no affect on property values or mortgages, with no mention of other studies that contradict such findings. Other factors that may be important when considering pipeline projects, such as concerns for sustainability, climate change, or a community’s social well-being, are noticeably absent.

Complicating matters, some pipeline operators have been successful in skirting comprehensive EIAs. This was seen in the case of the Mariner East 2 pipeline. Despite being the largest pipeline project in Pennsylvania’s history, a NEPA review was never conducted for ME2.

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By Kirk Jalbert, FracTracker Alliance