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Meeting Summary

Topic: Meeting with XTO Energy, Inc. about Unconventional Oil and Gas

Meeting Date: 18 July 2012

Participants: Lisa Biddle, Erik Helm, Brian D’Amico, Ahmar Siddiqui, Tom Born, 

Pooja Parikh (EPA)

Meghan Camp, Brent Ruminski (ERG)

Robert M. Nolan (ExxonMobil)

Joe Cardenas, Paul Krishna (XTO Energy)

On 18 July 2012, the U.S. Environmental Protection Agency (EPA) held a meeting with 

XTO Energy Resources, Inc. (XTO) to discuss their operations in unconventional oil and gas. 

Discussion topics included:

 XTO’s Current Production Activity;

 Project Development;

 Well Completion and Production; and

 General Cost Information.

Attachment 1 lists the meeting participants. Attachment 2 provides a summary of costs that XTO 

provided during the meeting.

XTO’s Current Production Activity

XTO is an oil and gas producer based in Fort Worth, Texas. In 2010, they became a 

subsidiary to ExxonMobil Corporation. Ownership of the drilling and production assets is held 

by ExxonMobil. In 2011, XTO drilled approximately 800 wells in unconventional formations, 

including shale oil, shale gas, and tight gas. XTO expects to drill [CBI redacted] to [CBI 

redacted] wells in 2012. According to DrillingInfo, Inc’s HPDI database, XTO was active in the 

following unconventional formations as of December 2011:

 Shale oil (Avalon & Bone Spring, Bakken,1 Barnett, Eagle Ford, Woodford);

 Shale gas (Marellus,2 Bakken, Barnett, Eagle Ford, Fayetteville, Haynesville, 

Woodford); and

 Tight gas (Cotton Valley, Dakota, Mesaverde).

 

1

The Energy Information Administration (EIA) classifies the Bakken as a mixture of shale and tight sandstone.

2 As of December 31, 2011, XTO operated 46 Marcellus shale gas wells in Pennsylvania. In the Marcellus, XTO 

currently has four active rigs and one hydraulic fracturing crew that cover Pennsylvania, Ohio, and West Virginia.
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XTO stated that the Barnett is their most developed shale play and they are no longer 

leasing new property there. In the Marcellus, XTO is currently running four drilling rigs and one 

hydraulic fracturing crew. XTO is also beginning development in the Utica shale, which 

underlies the Marcellus shale formation. Figure 1 shows all XTO’s Marcellus wells in 

Pennsylvania.

3 Through 2011, XTO operated 47 wells in northern and southwestern counties of 

Pennsylvania.

Source: EPA’s GeoPlatform mapping tool.

Figure 1. XTO’s Active Shale Gas Wells in Pennsylvania in 2011

Project Development

XTO provided information on the project development process. The following 

subsections outline this information in the general order they occur.

Obtaining a Lease

Operators lease land for mineral rights in quantities called “units”. A typical unit is 640 

acres of contiguous properties. Some states, including Pennsylvania, require operators to obtain 

all 640 acres of mineral rights before the operator can begin construction. In states such as Texas, 

New York, and Oklahoma, if a particular operator owns 65 percent of the leases in the unit, they 

can begin construction as long as the remaining acres are leased by another operator. When this 

occurs, it leads to the other operators, who have leases on the 640 acres, terminating their lease 

because they will never be allowed to drill. In a situation where all of the acres are not leased, an 

 

3

PA DEP updated through December 31, 2011. 

XTO Active Marcellus Shale Gas Wells in 

Southwestern Pennsylvania

• 29 horizontal wells

• West Moreland, Indiana, Armstrong, and 

Clarion Counties

XTO Active Marcellus Shale Gas 

Wells in Northern Pennsylvania

• 14 horizontal wells

• 4 vertical wells

• Lycoming, Columbia, and Clinton 

Counties

New York

Maryland Ohio

Pennsylvania
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operator can establish the right to drill on a unit through a process called “force pulling.” This 

occurs when certain acreage within a unit is not leased, the operator may file for “pooling” which 

will pull the un-leased acreage into the existing lease agreement for that unit.

Lease payments vary due to many factors including region, shale play, acreage position, 

company, etc. Often, a lease includes two types of payments to the mineral rights owner. These 

payments include:

 Upfront bonus per acre—This is a onetime payment made to the mineral rights 

owner. Currently, upfront bonuses in the Barnett are approximately [CBI 

redacted] per acre but once were as high as [CBI redacted] per acre. In the 

Marcellus, upfront bonuses are currently around [CBI redacted] per acre. These 

costs vary with market demand and shale play.

 Royalty—This is a continuous payment paid to the mineral rights owner 

calculated as a percentage of revenue. The baseline percentage is 16 percent. In 

some areas it can be as high as 25 percent. 

Exploration

Exploration may occur before or after they actually obtain a lease depending on the 

specific circumstances. Using geological data (e.g., formation depth, formation thickness, 

formation slope, permeability, porosity), XTO targets the formation that is most favorable to 

produce; XTO uses three exploration methods including:

 Offset production data— analysis of existing production data from nearby wells. 

 Existing data logs from drilling— analysis of data logs from drilling existing 

wells.

 Seismic— using specially equipped trucks that send and receive sound waves 

through the ground. Special service providers convert the received sound waves 

into 2D or 3D images of the formation. This service costs between [CBI redacted] 

and [CBI redacted] for several square miles.

Well Pad Construction and Drilling

After XTO obtains a lease and targets the most favorable area for production, they begin 

well pad site selection and construction. For site selection, they consider the following site 

specific qualities: 

 Location relative to mineral lease—The site should allow the wells to drain the 

largest possible portion of the lease. In addition, the location of the site should 

allow the horizontal legs to be drilled perpendicular to the maximum stress of the 

formation. 

 Flat land—The site must have the ability to be excavated into a flat well pad at a 

reasonable cost. Land that is already relatively flat and stable may reduce 

construction costs.
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 Accessibility—The operator considers access to roads and natural gas pipeline. 

The cheapest and most direct road access may not be possible if land owners are 

not willing to make agreements for passage over their property.

 Freshwater —Freshwater availability is more important in regions where surface 

water supplies are limited, such as the Barnett and Bakken. In places where 

surface water supplies are abundant, like the Marcellus, freshwater availability is 

not as important of a consideration for site selection.

When the desired site is selected, XTO may need to obtain surface use agreements for 

road access and well pad construction if they are not included in the lease agreement. Typically, 

the mineral rights owner is the same person as the surface owner, but sometimes they are 

different. In these cases, operators must negotiate a separate agreement with the land owner 

before construction.

The total cost for XTO to establish a surface lease agreement is approximately [CBI 

redacted] to [CBI redacted]. Excavation costs (including earth moving equipment, grading, 

environmental impact management, etc.) range between [CBI redacted] and [CBI redacted]. 

These costs are higher in regions with hilly terrain. XTO constructs each well pad on three to 

four acres and designs them to hold 12 to 16 wells (minimum is six). 

After constructing the well pad, XTO will typically drill and complete two wells. Vertical 

depth and horizontal leg length vary by formation. In the Marcellus, most wells are between 

6,500 to 7,000 feet deep with 2,000 to 5,000 foot laterals. After these wells successfully produce 

gas, XTO drills out the additional wells (typically six total) when logistics are favorable (e.g., 

pipeline capacity, drilling rig availability, gas prices, lease requirements). XTO explained that 

the length of time between completion of the first two wells and the remaining wells is hard to 

predict but estimated it may be between five and 10 years. This process is called delineation.

When asked if companies will ever use the same vertical portion of the well for more 

than one lateral, XTO explained that there is a drilling process for “multilaterals.” In a 

multilateral well, the operator drills on vertical bore and then drills multiple horizontal bores in 

different directions. XTO explained that they do not drill multilateral wells because the process 

is mechanically complex and has no history of reliability. 

Well Completion and Production

XTO provided information on the following fresh water and wastewater handling and 

management practices:

 Fresh Water Acquisition;

 Hydraulic Fracturing; and

 Wastewater Management Practices.
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Fresh Water Acquisition

XTO obtains fresh water for fracturing from a variety of sources including:

 Municipalities;

 Public surface waters (e.g., river); and

 Privately owned surface waters (e.g., pond). 

XTO provided a range of cost for freshwater acquisition. They have paid as little as [CBI 

redacted] per barrel for municipal water (e.g., City of Fort Worth) and as high as [CBI redacted] 

per barrel for privately owned surface waters. Similarly, XTO pays between [CBI redacted] and 

[CBI redacted] per barrel for public surface water supply. These prices vary based on the project 

location and proximity to the source of water. XTO will typically transport fresh water to 

centralized freshwater impoundments prior to fracturing. Impoundments cost approximately 

[CBI redacted] to [CBI redacted] and hold between 50,000 and 60,000 barrels. XTO attempts to 

locate impoundments to serve up to four to five wells. However, an impoundment may only 

serve one well in remote locations.

Each impoundment can hold approximately half of the total volume required for 

hydraulic fracturing (i.e., 50,000 to 60,000 barrels). Therefore, XTO must continuously refill the 

impoundment during the fracturing job. To minimize trucking costs, XTO uses temporary 10 

inch diameter aluminum piping as much as possible to transport fresh water from the source to 

the impoundment and from the impoundment to the well pad. They typically rent temporary 

piping from service providers. The use of temporary piping may require XTO to obtain addition 

surface use agreements from landowners. XTO estimated they spend approximately [CBI 

redacted] to [CBI redacted] for approximately one mile of temporary piping over a few weeks

(this includes the rental costs of pipes and pumps, as well as the cost of a service to lay the 

piping). A nominal fee is paid to the landowners whose property must be traversed by the 

temporary piping.

When piping is not possible, XTO trucks the fresh water. XTO typically contracts a third 

party trucking company in order to eliminate paying truckers by the hour. Trucking costs vary 

depending on the basin and distance between the source water, impoundment, and/or well site. 

Under a contract basis, XTO pays between [CBI redacted] to [CBI redacted] per barrel in the 

Barnett (assuming 10-15 miles) and between [CBI redacted] to [CBI redacted] per barrel in the 

Marcellus (assuming transport from Indiana, Pennsylvania to Youngstown, Ohio or 

approximately 100 miles). Each truck can hold approximately 130 barrels of freshwater and 100 

barrels of wastewater.

4

Hydraulic Fracturing

XTO provided general information on hydraulic fracturing of unconventional oil and gas 

wells. XTO fractures each well in eight to 10 stages at a rate of approximately two stages per 

day. The total cost to fracture a single stage with slick water is approximately [CBI redacted] 

 

4 When hauling wastewater, trucks can typically only hold 100 barrels of wastewater because wastewater is denser 

(weighs more per barrel) than freshwater. 
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(gel fractures, commonly performed in the Bakken shale play, cost approximately [CBI redacted] 

per stage). XTO explained that the total cost for fracturing varies by formation and suggested it 

is more expensive to fracture a Marcellus well than a Barnett well. Prior to fracturing each stage, 

XTO transports enough fresh water to complete the stage onto the well pad from the nearest 

freshwater impoundment via temporary piping or truck. XTO stores the fresh water in 500 barrel 

fracturing tanks on the well pad. These tanks cost XTO [CBI redacted] to [CBI redacted] per day 

per tank to rent in addition to [CBI redacted] in transportation costs to bring the tanks to and 

from the site. If the water is piped to the tanks from a water source or fresh water impoundment, 

XTO typically keeps 5 to 10 tanks onsite; if water is trucked to the site, XTO will maintain 40 to 

50 tanks on site (which is enough for one fracturing stage). At a rate of one to two stages per day, 

fracturing one well requires approximately one to one and a half weeks. 

XTO discussed water quality requirements for hydraulic fracturing. As the water is 

pumped to the site, some filtration occurs through meshes within the pipeline. When the water 

reaches the site, it is blended with scale inhibitor, an anti-microbial agent, and proppant. For 

slickwater fracturing in the Marcellus, XTO recommends TDS concentrations of 30,000 or less. 

XTO explained that water with high TDS concentrations (that is, salty water) can reduce the 

effectiveness of friction reducers which are usually hydrocarbon-based. XTO explained that they 

are more careful about water quality in formations that use gel-based fracturing fluids (e.g., 

Bakken). For gel-based fracturing fluids, fresh water TDS levels are desired (approximately 500 

mg/L) for make-up water.

XTO fractures each stage with 12,000 barrels of hydraulic fracturing fluid and 300,000 to 

400,000 pounds of proppant.

5 With eight to 10 stages per well, XTO may use four to five million 

gallons of hydraulic fracturing fluid and 2.4 to 4 million pounds of sand. A typical stage is 

approximately 500 feet of the horizontal leg. In the Marcellus, XTO is currently moving towards 

shortening the stage lengths to 280 to 300 feet to increase production, which will increase the 

total number of stages per well. However, XTO estimates that shorter stages will still require 

12,000 barrels of fracturing fluid, which may result in higher total volumes of hydraulic 

fracturing fluid per well. 

XTO estimated the flowback process lasts 30 to 60 days. During this period, XTO 

collects the flowback in five 500 barrel fracturing tanks. Because the flowback flow rate is 

relatively high, trucks must empty the fracturing tanks daily until the flow rate decreases. In most 

formations, approximately 40 percent of the injected fracturing fluid returns as flowback. After 

the flowback period, the wastewater is considered produced water and is routed to onsite above 

ground storage tanks. Table 1 provides approximate percentages of fracturing fluid that returns 

during flowback and produced water volume flow rates by formation. XTO believes the Barnett 

shale contains naturally occurring formation water directly above and below the shale layer. 

Although XTO has not been active in unconventional formations for more than 10 years, they

estimate the life of a well to be 20 to 30 years.

 

5 XTO’s proppant is a mixture of 20-40 and 40-70 sand. 
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Table 1. Wastewater Generation by Formation

Formation

Percent of Fracturing 

Volume Returned 

During Flowback (% )

Produced Water Flow Rate 

(barrels per day)

Marcellus 20 – 30 2 – 4

Barnett 40 30 – 40

Haynesville 20 – 30 2 – 4

Most other 

formations 40 7 – 10

When asked if an operator would ever hydraulically fracture two wells on the same pad at 

the same time, XTO explained that there are several fracturing techniques that involve 

simultaneous fracturing, but XTO does not use these techniques. These include:

 “Simulfracture”: Using this technique, two wells are fractured at the same time, 

which creates a pressure barrier between the wells and forces the fractures 

outward in separate directions.

 “Zipper fracture:” Using this technique, the operator alternately perfora tes and 

fractures well stages on two side-by-side wells. For example, the operator will 

perforate the first stage of Well B while fracturing the first stage of Well A. Next, 

the operator will fracture the first stage of Well B while perforating the second 

stage of Well A. This process continues in this pattern until all stages are 

complete, and causes the fractures to form in the space between the two wells.

Wastewater Management Practices

XTO provided information on their wastewater management practices for each 

unconventional formation in which they operate. During the flowback period, XTO collects the 

flowback in the same 500 barrel fracturing tanks that were used to store freshwater during the 

hydraulic fracturing process. As mentioned previously, XTO rents these tanks at a rate of 

approximately [CBI redacted] to [CBI redacted] per day. When the well switches to production 

mode, the produced water is collected and stored in above ground storage tanks at the well pad. 

Limitations on the capacity and number of above ground storage tanks varies by state, county, 

and sometimes by city due to differences in regulations. For example, the City of Forth Worth 

limits its sizes to 300 to 400 barrels per tank. In western Texas, XTO is able to use 3,000 barrel 

tanks if needed. XTO prefers to have 400 to 500 barrel tanks, which is permitted in the Marcellus 

Region.

Table 1 summarizes XTO’s wastewater management practices on a formation basis. XTO 

manages the majority of their wastewater through reuse and underground injection. For 

underground injection, XTO estimated that they use 50 percent XTO-operated injection wells 

and 50 percent commercially-operated injection wells. In Texas, underground injection costs 

approximately [CBI redacted] per barrel for disposal and [CBI redacted] for trucking from the 

well pad to the injection well. 
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For reuse in slickwater fracturing fluids, XTO provided a general rule of thumb that 

hydraulic fracturing fluid should not contain more than 30,000 mg/L TDS after blending. Above 

30,000 mg/L, the effectiveness of friction reducer additives in the fracturing fluid is reduced.

Although current technology can allow friction reducers to be used with higher TDS 

concentrations than in the past, it also increases the cost for additives. Reuse in the Bakken6is 

also challenging because most wells are fractured using gel fracturing techniques, which require

fresh water. XTO also explained that they do not reuse wastewater from one formation type (e.g., 

shale gas) in another formation type (e.g., tight gas) because of chemical incompatibilities.

Table 2. XTO’s Nationwide Wastewater Management Practices

Formation or 

Basin Production Type General Wastewater Management Practices

Eagle Ford Shale oil and gas Mostly underground injection.

a

Haynesville Shale gas Mostly underground injection because reuse is 

not technically feasible due to high fracturing 

pressures.

Woodford Shale oil and gas Mostly underground injection.

Fayetteville Shale gas Reuse as much as possible due to limited 

underground injection.

Bakken Shale oil and gas b Mostly underground injection. Limited reuse 

because make up water for fracturing must be 

similar to fresh water. 

Pieance Tight gas Reuse as much as possible, then underground 

injection.

Marcellus Shale gas Reuse as much as possible, then underground 

injection.

Utica Shale oil and gas Reuse as much as possible, then underground 

injection.

a—XTO suggested that some companies reuse 100 percent of wastewater in the Eagle

Ford but XTO does not.

b—The Bakken produces both oil and gas. Some of the gas is flared and some is 

collected for production.

In the Marcellus, XTO estimated they currently reuse 55 percent of their wastewater in 

fracturing and truck 45 percent to Ohio underground injection wells. For the wastewater that 

XTO reuses, they use one of the following options:

 Direct reuse without any treatment;

 Reuse after onsite treatment at the well pad or at central field location; or 

 Reuse after treatment at a centralized waste treatment (CWT) facility.

 

6

The Energy Information Administration (EIA) classifies the Bakken as a mixture of shale and tight sandstone.
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For onsite treatment at the well pad or at central field locations, XTO uses third party treaters 

such as Waste Management of Pennsylvania (Waste Management)

7

and Bosque Disposal 

Systems, LLC (Bosque).

8 Onsite treatment technologies include filtration, electro coagulation, or 

ozone9depending on the wastewater quality. XTO estimated that this type of onsite treatment for 

reuse costs between [CBI redacted] and [CBI redacted] per barrel. 

Table 3 provides XTO’s 2011 Marcellus wastewater management practices in 

Pennsylvania as provided in the Pennsylvania Department of Environmental Protection (PA

DEP) Oil and Gas Reporting Database. The majority of the wastewater volume XTO reported 

sending to CWTs was treated by Waste Management. XTO clarified that Waste Management is a 

third party treater who offers electro coagulation for onsite treatment prior to reuse. Onsite 

treatment typically results in a solid or sludge waste stream that must be disposed of in a 

permitted landfill. XTO stated that in a typical day they will treat hundreds of barrels of 

flowback using electro coagulation and generate 200 to 300 barrels of sludge that must be 

disposed of.

Table 3. XTO's 2011 Marcellus Shale Wastewater 

Management in Pennsylvania

Management Practice

Percentage 

(% )

Volume 

(barrels)

Reuse a8 37,341

Centralized Waste Treatment 

(CWT)—Reuse 44 210,846

Underground Injection 48 232,406

Landfill <1 429

Total 100 481,022

a—XTO utilized CWTs that return treated wastewater to the operator for 

reuse in fracturing (e.g., Reserved Environmental Services, Inc.) and 

facilities that treat and discharge (e.g., Pennsylvania Brine). 

Source: PA DEP’s Oil and Gas Reporting Database.

General Cost Information

XTO provided additional cost information. Attachment 2 summarizes all cost information 

XTO provided. For accounting purposes, XTO classifies costs at the well level into completion 

(i.e., capital) and production (i.e., operating) costs. XTO estimated that a “hurdle rate” or 

minimal rate of return on investment at the well or project level is [CBI redacted]. XTO 

estimated that operating (i.e., wastewater management) costs are approximately [CBI redacted] 

to [CBI redacted] per thousand cubic feet (MCF). This estimate represents a nationwide range. 

 

7 According to Waste Management’s website, the company recently acquired Heartland Technology Partners (HTP), 

a company that offers mobile evaporation/condensation treatment units. More information about HTP is available at: 

http://www.heartlandtechnologypartners.com/.

8 According to Bosque’s website, they are active in the Permian Basin and Barnett, Eagle Ford, Fayetteville, and 

Bakken shale plays. More information about Bosque is available at: http://www.bosquesystems.com/index-2.html.

9 Ozone wastewater treatment oxidizes pollutants in wastewater so they can be filtered.
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XTO also estimated that the Pennsylvania POTWs they sent wastewater to in the past charged 

approximately [CBI redacted] to [CBI redacted] per barrel. 
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Attachment 1

Table A-1. List of Meeting Participants

Name Affiliation Phone Email

Joe Cardenas XTO Energy 817-885-1225 Joe_Cardenas@xtoenergy.com

Robert M. Nolan ExxonMobil 202-862-2003 Robert.m.nolan@exxonmobile.com

Paul Krishna XTO Energy 817-885-1171 Paul_krishna@xtoenergy.com

Lisa Biddle US EPA 202-566-0350 Biddle.Lisa@epamail.epa.gov

Erik Helm US EPA 202-566-1049 Helm.Erik@epa.gov

Brian D’Amico US EPA 202-566-1069 Damico.Brian@epa.gov

Ahmar Siddiqui US EPA 202-566-1044 Siddiqui.ahmar@Epa.gov

Tom Born US EPA 202-566-1001 Born.thomas@Epa.gov

Pooja Parikh US EPA 202-564-0839 Parikh.pooja@Epa.gov

Meghan Camp ERG 703-633-1684 meghan.camp@erg.com

Brent Ruminski ERG 703-633-1701 brent.ruminski@erg.com
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ATTACHMENT 2

Table A-2. Summary of Costs Provided by XTO

Process Cost Notes

Well Construction and Development

Well pad construction [CBI redacted] Includes excavation.

Hydraulic fracturing (one stage) [CBI redacted] Cost to hydraulically fracture a single 

stage.

Freshwater Acquisition 

Municipal [CBI redacted] This price is from the City of Fort Worth, 

TX.

Private property [CBI redacted]

Freshwater and Wastewater Storage

Freshwater impoundment [CBI redacted] Hold between 50,000 and 60,000 barrels.

Fresh Water and Flowback Storage [CBI redacted] Rental cost for 500 barrel fracturing 

tanks.

Temporary piping (10 inch 

aluminum) [CBI redacted] Total cost to rent temporary piping for a fracturing job over a few weeks.

Wastewater Treatment

Onsite treatment for reuse [CBI redacted]

This treatment includes filtration, electro 

coagulation, or ozone. It includes 

bacteria, TSS, and select ion removal.

UIC in TX [CBI redacted]

Total cost for trucking and disposal of 

wastewater in Texas underground 

injection wells.

UIC in Ohio [CBI redacted]

Total cost for trucking and disposal of 

Pennsylvania wastewater in Ohio 

injection wells.

Treatment at a POTW [CBI redacted]

Other General Costs

Return on investment [CBI redacted] XTO estimated the “hurdle rate” for 

projects. 

Operating cost [CBI redacted]

This is the operating cost at the project 

level. This includes costs for staffing and 

man hours for maintenance.

Trucking [CBI redacted]

Each truck holds 130 barrels of fresh 

water and 100 barrels of wastewater.

This cost represents short trips such as 

from the producing well to underground 

injection well in Texas, which is usually 

2 or 3 miles.