MEMORANDUM

TO: Brian D’Amico, EPA/EAD Lisa Biddle, EPA/EAD

FROM: Meghan Camp , ERG Brent Ruminski, ERG

DATE: 20 April 201 2

SUBJECT: Notes for Shale Gas Industry Meeting Held on 29 February 2012

On 29 February 2012 , EPA held a meeting with members of the oil and gas industry and

discuss ed economic and engineering topics f or the S hale Gas Extraction (SGE) rulemaking. The

main d iscussion topics included shale gas e conomics and e nginee ring.

Attachment 1 lists all of the meeting participant s

. The names of organizations participating on the call included:

• QEP Resources , Inc. (QEP) ;

• Apache Corporation (Apache);

• Anadarko Petroleum Company (Anadarko) ;

• American Petroleum Institute (API) ;

• American Natural Gas Alliance (ANGA) ;

• U

. S

. EPA;

• Abt Associates (Abt) ;

• Westat ; and

• Eastern Research Group, Inc (ERG)

.

Shale Gas Economics ( Sarah Banaszak, ANGA)

Sarah Banaszak, a representative from the American Natu ral Gas Alliance (ANGA) , led

the first d iscussion on economics , which covered historic gas prices, projected gas prices, and the long

- and short

- term factors that affect gas prices

. Attachment 3 provides slides that Ms. Banaszak presented for this discussion

.

Historic Gas Prices

Ms. Banaszak described overall trends in oil and gas prices. Until 2009, oil and gas prices tracked closely with each other . This was because the U.S. imported a majority of its oil and gas from other countries. However, since 2009 , a major increase in domestic gas pro duction from shale and tight sands formations has caused gas prices to decrease while oil prices continue toPage 2 of 15 rise. Th e increase in domestic gas production results from advancement s in hydraulic fracturing and horizontal drilling technologies

. Ms. Banaszak described these trends as long

- term factors of natural gas prices. In general, long

- term factors occur when industry moves from one technology to another or from one type of basin to another. Ms. Banaszak also pointed to a short

- term divergence in oil and gas prices during 2005 and 2006, which was the result of hurricanes disrupting Gulf of Mexico natural gas supplies.

Projected Gas Prices

Ms. Banaszak presented a chart from the EIA preli mi nary 2012 outcome, which shows the historic and projected U.S. dr y gas production from resources including shale gas, tight gas, coalbed methane, and other onshore and offshore resources. The chart shows the expansion of shale gas production starting around 2005. The projections predict that shale gas and tight gas

will account for 70 percent of the U.S. natural gas supply by 2035. Mark Himmelstein pointed out that CBM production has decreased by 2 percent since 2010, and stated that he expects CBM production to continue to decline.

Ms. Banaszak described how the increase in shale and tight gas supply impacted the EIA

outlook s between 2005 and 201 1

. The 2005 projections show the U.S. as a net importer of LNG and natural gas at an increasing rate. The 2011 projections show the U.S. as a net importe r of LNG and natural gas at a decreasing rate. Ms. Banaszak stated that the prediction is that the U.S. will become an exporter of LNG and potentially an exporter of natural gas. The U.S. exports natural gas via pipeline to Mexico and receives natural gas via pipeline from Canada. T he net natural gas imports are around 10 to 15 percent. On the LNG side, the U.S. currently operates six or seven LNG terminals around the country and exports LNG from Alaska. LNG imports can come from Trinidad, Tobago, West Afri ca, Nigeria, Angola, the Middle East, Qatar, and some Asian cargos.

Ms. Banaszak compared natural gas price forecasts from EIA 2011

, ICF , and IHS

. The EIA 2011 and ICF projections show shale gas prices grad ually increasing from $4.38/MMBt u in

2010 to arou nd $5 .00/MMBtu in 2020 and $7.00/MMBt u by 2035. Ms. Banaszak explained that the gradual price increases are due to inflation and increasing natural gas demand. The ICF model assumed higher natural gas demand in the power sector than the EIA model; however, the ICF price forecast for 2035 ($7.15/MMB t u) was slightly lower than the EIA 2035 price forecast ($7.21 /MMBtu ). The HIS price view with constrained shale gas production predicted $15.00/MMBtu by 2035.

Long

- term Factors of G as P rices

Ms. Banaszak shifted the discussion to the long

- term factors that affect current gas prices and price outlooks. The EIA and other outlook models require many long

- term assumptions and it is important to understand what the model assumes before comparing results from two

diffe rent models. One major long

- term factor is investments to support indust ry growth ( 2012 EIA projects $5.7 billion per year through 2025 )

. Pipeline investments have been $8 billion over the last 3 out of 4 years. Some other long

- term drivers of gas prices on a large scale include:

• Oil price s;

• Technology development;

• Economic growth;Page 3 of 15 • Storage; and

• Electricity growth and demand.

Short

- term Factors of G as P rices and Risk

O n the project level, several risk factors affect natural gas prices. These risk factors are the same factors that comp anies consider when deciding whether to develop a project :

• D rilling a well will not always be successful. Sometimes the well production will be significantly less than expected or the composition of the gas itself will be

diff erent than expected 1

.

• C onnection of pipelines is critical for economical transportation of products. Delays in pipeline construction can prevent projects from becoming economical

.

• P ermit acquisition delays may push the well’s peak production to a lower ma rket when prices are lower.

• U nseasonably warm weather will put downward pressure on prices due to the lack

of demand.

Because all of these factors vary by play, basin, state, and time it is very difficult for companies to define a single minimal return of investment for all projects. Mr. Himmelstein suggested that EPA should assume this number on a basin or lower level. He also described how

p rojects on federal lands would have higher risk due to more stringent regulations. A general rule

of thumb is that c ompanies will always move assets (e.g . drilling rigs ) to projects with less risk. For example, Pioneer, who is the biggest producer in the Raton Basin, recently moved all of their rigs to Texas and Louisiana. In addition, smaller companies will have lower minimal return of investment for projects compared to larger companies

.
Current Structure of the Shale Gas Industry

Several speakers provided statistics on the profile of the U.S. gas extraction industry in

t erms of company sizes . It was unclear if these numbers were specific to the shale gas industry or the gas industry as a whole.

• Ninety to 98 percent of the companies with interest in shale gas extraction are larger corporations.

• Independent producers (i.e ., not companies like Exxon mobile or Shell) drill 70 percent of wells

.

• Independent producers produce 82 percent of natural gas.

• Sixty percent or more of the independent producers are pass

- through entities (e.g.
LLPs, LLCs, or INCs).

• Shale gas wells are m ore costly than CBM wells. Therefore, shale gas producing companies are larger than CBM producing companies.

• Most gas production is done on private land, and companies are starting to produce more liquid

- rich gas. Budgets are moving toward oil.

1 Wellhead gas is composed of methane, carbon dioxide, hydrogen sulfide, and other gases. The composition affects the cost for gas processing and may be difficult to predict.Page 4 of 15 • Many smalle r companies that started production in the Marcellus have been bought by larger corporations. In addition, some foreign companies are starting to buy the American company wells.

Shale Gas Engineering

The second part of the discussion covered engineering pr actices of shale gas extraction

. S peakers from two organizations led this part of the discussion : George King of Apache Corporation (Apache) discussed hydraulic fracturing and Rebecca Thingelstad of Anadarko Petroleum Company (Anadarko) discussed wastewate r handling.

Hydraulic Fracturing ( George King, Apache)

George King, a representative from the Apache Corporation , led the first discussion held on shale gas engineering . In general, Mr. King discussed technical details of hydraulic fracturing. Mr. King has 40 years of experience in hydraulic fracturin g. Mr. King broke down the production of oil and gas into drilling (well construction) and fracturing. Fracturing begins when the operator hauls equipment and materials on site and ends when the operator is sel ling gas . The majority of Mr. King’s discussion focused on drilling and fracturing.

Apache Projects

To describe the benefits of using horizontal wells

, Mr. King provided some background

on Apache’s shale gas project in the Horn River Basin, British Columb ia Canada. Table 1 shows infrastructure requirements to drain 6,000 acres of gas play (9 square miles) in the Horn River using hor izontal wells and vertical well s. Attachment 2 provides an image of a well pad in the Horn River Basin using horizontal wells.

Table 1

. Infrastructure Requirements for Horizontal and Vertical

Wells

Component Horizontal Wells Vertical Wells

Gas Play Drained (acres) 6,000 6,000

Wells 12 75

Well Pads 1 8

Total Surface Footprint (Acres) 6 150

Oil/Gas Pipelines (miles) 4 30

Trucking Miles (miles) 36,000 (or 1,400 with water pipeline) 45,000Page 5 of 15 Fresh Water Monitoring Zone Size (Acres) 8 6,000

Mr. King also described the closed loop fracturing technique that Apache uses in the

Horn River Basin. For fresh water, Apache pays between $2.12 per barrel in the summertime and over $3 per barrel in the wintertime due to freezing problems. Once Apache implemented the closed loop fracturing process, the fresh water price decreased to $0.72 per barrel. Mr. King described the closed loop process in terms of a typical scenario in the Horn River basin of

Canada.

• Hydraulically fracturing a horizontal well requires 12 million gallons of makeup

water.

• A local salt water w ell will provide 90 percent of this makeup water (this water is not usable as potable water)

.

• Fresh water makes up the addition al 10 percent of makeup water.

• When the operator recovers water after fracturing, they send it back down the salt

water well.

Mr . King noted that this technique is more economical than traditional methods but is not commonly used. Currently, Apache is looking at potential closed loop fracturing projects in the Eagle Ford and Barnett shale plays of Texas. In these areas, third parti es drill water wells to supply fresh water for municipalities. However, some water wells are unsuccessful and result in the production of salt water. Apache is working on a n arrangement with the companies that drill these wells where Apache would purchase this salt water. Apache is also working on deals with local municipalities using the concentrated brine waste stream from reverse osmosis units in their fracturing operations.

Well Construction

Mr. King related the well casing to as a pressure vessel, whi ch must keep high

- pressure fluids contained early in its life and keep out salt water in the later stages of its life. W ell casing usually includes 3 to 5 barriers of steel and cement. Well casing regulations use d to be flexible

but states have done a thor ough job on strengthening them. For example, e arly operators in the

Marcellus did not enclose the annular space around the well with cement. This is especially critical when the surrounding rock is methane rich (e.g., shales and coal beds )

. Through years o f experience and research, Mr. King found that w hen operators make this mistake (less than 1 percent of wells he has researched) there is a one

- to

- one correlation to elevated methane in surrounding water aquifers

. Attachment 2 shows a slide from Mr. King’s website that illustrates proper well construction.

Hydraulic Fracturing of Conventional and Unconventional Wells

Hydraulic fracturing in unconventional formations requires 50 to 60 percent of the hydraulic press ure required to fracture conventional formations due to the direction the fractures

occur. In vertical wells , “planer” fracturing o ccurs, which are in the direction out of the sides of the well. In these fractures, the force must overcome tectonic pressure s. In horizontal wells , thePage 6 of 15 fractures occur up and down and with less tectonic pressure. In addition, unconventional formations contain more natural fractures. As a result, unconventional wells can have up to 10 to 100 million square feet of contact area, which is much higher than conventionally fractured

wells.

The differences in conventional and unconventional hydraulic fracturing fluids and

wastewater include :

• Conventional wells require less fracturing fluid but a higher percentage will return

as flowback or produced water;

• Conventional wells require less chemicals overall and there is more potential for the use of greener chemical ;

• Conventional wells may require m ore polymer crosslink chemicals; and

• Wastewater from conventional wells will have low er concentration of trace pollutants.

Hydraulic Fracturing of Shale Gas and Tight Sands

According to Mr. King, hydraulic fracturing in tight sands and shale is very similar. However, a few minor differences include:

• T ight sands fracturing fluids may requir e more clay control additives than shale fracturing fluids

.

• Tight sands fracturing fluids may not need the same viscosity as shale fracturing

fluids.

Hydraulic Fracturing Process Description

Operators typically develop a new unconventional field by drilli ng vertical wells in order

to find productive areas . After the productive areas are located, they focus on drilling horizontal

wells. Horizontal wells are fractured in multiple stages. Typical horizontal wells require 8 to 10 stages; however, some wells may require up to 14 or 16 stages. In terms of refracturing completed wells, operators typically refracture less than 5 percent of wells per year. It would not be beneficial to refracture a well in 3 years. Operators are more likely to go back to convention al wells that have already been producing (but not fractured) and fracture them to enhance production.

Fracturing Fluid

Operators’ criteria for makeup water quality have shifted over the last few years. Historically

, most operators required that all makeup water be fresh water (approximately 500 mg/L TDS)

. The current criteria for m akeup water is between 30,000 to 50,000 mg/L TDS but up to 70,000 mg/L is possible due to advancement s in friction reducers and other chemical

a dditives. Iron is also a critical pollutant that must be less than 10 mg/L to prevent downhole scaling.

Mr. King described how service provide rs typically add all chemicals possibl e to a fluid

to “cover their base s.” However, a good way for operators to r educe cost is to look intoPage 7 of 15 eliminating unnecessary chemicals. He said it is possible to save on the order $30,000 to $100,000 2 per hydraulic fracture by eliminating the use of unnecessary chemical additives. Attachment 2 provides a slide from Mr. King’s we bsite that shows common additives that are require versus generally unnecessary additives.

Wastewater and Gas Production over Time

Mr. King described a typical wastewater production decline curve for hydraulically

fractured wells. After the shut in period, wastewater will flow an initial rate of 3 to 6 barrels per minute (equivalent to 4

, 300 to 8

, 600 bbl/day). Within 5 to 6 days, this flow rate will drop of f significantly. Within 2 to 6 weeks, 5 to 55 percent of the fracturing fluid will return as flowback (typically 40 to 50 percent in the Devonian and more like 5 to 10 percent in the Eagle Ford)

. Over the lifetime of a well, wastewater will only flow at a rate of 10 barrels per day. However, these numbers may vary by well and play.

Mr. King also described typical natural gas production decline curve for hydraulically

fractured wells. Over the first year, a well’s gas production will decrease by 45 percent alone followed by 20 percent decline over the second and third year. Over the remaining life of the

we ll, gas production will decrease at a rate of 4 percent per year. A productive well will produce 2 to 3 BCF of gas in its lifetime. Again, these numbers will vary by well and play. Mr. King noted that the 40 percent decline over the first year use to be 70 percent. This improvement is due to advancements in hydraulic fracturing. It is possible that shale well s may only produce for 10 years but the latest estimate is a 15 to 20 year lifespan. There is always a possibility a wells will last for a much longer period. Mr. King provided an example of a 150

- year

- old well in PA still producing oil today.

Wastewater Handling and Management ( Rebecca Thingelstad, Anadarko)

The second discussion of engineering practices of the shale gas industry focused on wastewater handling practices. Rebecca Thingelstad of Anadarko led this discussion

. Ms. Thingelstad mentioned that best practices vary from basin to basin , play to play, op erator to operator, and well to well. Throughout this d iscussion, the speakers provided several explanations for these variation s, including:

• Regulations vary by state and region;

• UIC disposal capacity varies by region; and

• New plays have less infrastructure in place for centralized management options.

Types of Wastes from Hydraulic Fracturing

Ms. Thinglestad began by describing the different types of waste streams found on oil and gas well sites. These include stormwater, drilling water, and wa stewater. Operators manage stormwater, drilling fluids, and wastewater separately. This discussion only includes management of wastewater. For the purpose of this discussion, w astewater is all water p roduced by the well after hydraulically fractur ing. This includes both the commonly used terms

2 Mr. King also described these savings as 3 to 10 percent of the total cost of f racturing.Page 8 of 15 “flowback” 3 and “produced” 4 water. T he meaning of flowback is actually a process and not the

water itself that immediately flows out of the well after fracturing.

Wastewater Handling

Wastewater is u sually stored in closed tanks or lined pits for a short period but t he

method used depends on regulations in the area

. In some cases, regulations may restrict the transportation of water. For example, federal regulations sometimes prohibit the transportation of

water fr om private land to federal land. U nless the operator intends to use the wastewater in additional fracturing, they will haul the wastewater off site quickly. The waste water is hauled offsite by truck or pipeline. According to Mr. King, pipelines can result in 7 0 percent reduced transportation costs. Operators may use t emporary pipelines on various landscapes and reuse them repeatedly

. Temporary piping is often made of polypropylene, which is available in 5,000

- foot long reels and does not include joints.

Wastewater Management

A large portion of the discussion focused on current trends of wastewater management in

the indu stry

. Representatives who spoke mentioned several wastewater management options including:

• Haul to CWT;

• Haul to POTW;

• Evaporation in impou ndments;

• Haul to UIC; and

• Reuse.

Craig Brown from QEP Resources Inc. (QEP) suggested that operators manage 90 to 9 8

perc ent of wastewater through underground injection and less than 1 percent through POTWs. However, he did not explain if this number is nat ionwide, specific to QEP, or specific to one basin or play

. No matter how the wastewater is managed (e.g.

, r euse, UIC, CWT, and POTW ) ; there are always contractual limitations (e.g., quality and quantity) . In addition, all current

wastewater management options require operators to comply with some local, state, or federal regulations

. Producers may hire subcontractors who special ize in wastewater management but this is more common for larger companies than for smaller companies.

Reuse

W hen possible

, oper ators will truck or pipe wastewater to another site for use in additional fracturing jobs. Previously, wastewater reuse was uncommon due to concerns that the high TDS levels would decrease the effectiveness of friction reducers and the fluid would require too much horsepower during fracturing. New chemicals now allow TDS concentrations to be as high as 70,000 mg/L making reuse more popular.

3 Flowback is commonly referred to as the wastewater that flows immediately after hydraulic fracturing takes place until the well begins producing gas. This fluid usually resembles the fracturing fluid used to fracture the well.

4 Produced water is commonly referred to as the wastewater that flows after flowback water for the remaining life of the well. This fluid usually resembles the formation waterPage 9 of 15 Craig Brown from QEP Resources provided an example of how operators in the Pinedale area of southwest Wyoming pipe was tewater directly to a reverse osmosis facility

. All wastewater is transferred via pipeline to a third party recycler

. The third party recycler treats

waste w ater and returns it to the operator to u se in addition al fracturing jobs. Wastewater that is

not of sufficient quality is treated and discharged under a WY NPDES permit into the upper

Green River Basin

. QEP and Anadarko did not provide details on the recycler contract.

Treatment

Operators may decide to treat wa stewater for reuse or disposal but the ultimate decision always comes back to economics. In parts of Wyoming, it is more economic for operators to

bui ld gathering pipelines to pipe wastewater to CWTs for treatment because large volumes of wastewater can be managed increasing the econom i es of scale

. However, a newly developed play will not have that kind of infrastructure in place resulting in less attractive economics for

centralized treatment.

According to Mr. King, treatment of wastewater to reduce certain ions will start at $3 per

ba rrel. More intense treatment such as evaporation and condensation may cost between $12 and $15 per barrel (not including transportation or solids disposal ). In Texas, operators pay between $1.5 and $2.0 per barrel for UIC disposal, which makes economic sen se. On the other hand, operators in the Marcellus will not have access to as many UIC disposal wells and treatment options may be more economical.Page 10 of 15 Attachment 1: List of Meeting Participants

Name Affiliation

Rob Wood U.S. EPA, Acting Director of EAD

January Mat us zko U.S. EPA, Branch Chief

Erik Helm U.S. EPA, SGE Economist

Tom Borne U.S. EPA, CBM EA

Jan Pickerel U.S. EPA, Pretreatment Program

Kim Petro U.S. EPA, Pretreatment Program

James C ovington U.S. EPA, CBM Economist

Marla Smith U.S. EPA, CBM Lead

Brian D’Amico U.S. EPA, SGE Lead

Lisa Biddle U.S. EPA, SGE Engineer

Ahmar S iddiqui U.S. EPA, CBM Engineer

Cuc Schroeder U.S. EPA, SGE Statistician

Maria Gomez

- Taylor U.S. EPA

Richard Mark Unknown

Jil l Dean U.S. EPA , OGWDW

Lee Full er IPPA

Stephanie Meadows API

Jason Smith API

Sarah Banaszak ANGA , Chief Economist

Amy Farrell ANGA

Mar c Himmelstein CBM lobbyist

Rebecca Thingelsta d Anadarko

George King Apache

Craig Brown QEP

Matt Kellog g IPPA

Jan Gil breath U.S. EPA, OP

Richard Witt U.S. EPA, OGC

Telephone Participants :

Brian S c h u mac h er U.S. EPA , ORD

Chris Impelliteri U.S. EPA , ORD

David Marke r Westat

Erik Edgar Abt

Mike Fisher AbtPage 11 of 15 Attachment 1: List of Meeting Participants

Name Affiliation

Tatiana Melnikova Abt

Betsy Bicknell ERG

Meghan Camp ERG

Brent Ruminski ERGPage 12 of 15 Attachment 2 : George King Slides

Figure 1

. P roper well casing e xample

Source: George King’s Website 5

5 Available online at: http://gekengineering.com/Downloads/Free_Downloads/Avoiding_Shale_Investment_Pitfalls_Pitfalls_23_January_ 2012.pdfPage 13 of 15 Table 1

. Common versus U ncommon Chemical Additives

Source: George King’s Website 6

6 Available online at: http://gekengineering.com/Downloads/Free_Downloads/A_Guide_to_Chemicals_in_Fracturing_10_Aug_2010.pdfPage 14 of 15 Figure 2 . Horn River Basin 6 acre well pad draining 5,000 acres

.
Source: George King’s Website 7

7 Available online at: http://gekengineering.com/Downloads/Free_Downloads/Alternate_Water_Sources_for_Fracturing_17_Jan_2012.pd

fPage 15 of 15 Attachment 3 : American Natural Gas Alliance (ANGA) Presentation