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August 12, 2013

MEMORANDUM FOR: JOHN CONTI

ASSISTANT ADMINISTRATOR FOR ENERGY ANALYSIS

FROM: ANGELINA LAROSE

TEAM LEAD

NATURAL GAS MARKETS TEAM

JOHN STAUB

TEAM LEAD

EXPLORATION AND PRODUCTION ANALYSIS TEAM

EXPLORATION AND PRODUCTION and NATURAL GAS

MARKETS TEAMS

SUBJECT: First AEO2014 Oil and Gas Working Group Meeting Summary

(presented on July 25, 2013)

Attendees: Anas Alhajji (NGP)*

Samuel Andrus (IHS)*

Emil Attanasi (USGS)*

Andre Barbe (Rice University)

David J. Barden (self)

Joseph Benneche (EIA)

Terry Boss (Global Energy Group)*

Geoffrey Brand (API)*

Phil Budzik (EIA)

Ron Charpentier (USGS)*

Troy Cook (EIA)*

Yelena Dandurova (SAIC)*

Joseph DiPietro (NETL)*

Michelle Foss (Univ. of Texas, Houston)*

Phani Gadde (Wood Mackenzie)*

Ron Gecan (CBO)

Matthew Gilstrap (INTEK)

Paul Holtberg (EIA)

Ozge Kaplan (EPA)*

Robert King (EIA)

Steven Koptis (Douglas-Westwood)*

Angelina Larose (EIA)

Geoffrey Lyon (DOE)
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Phyllis Martin (Phyllis Martin Energy)

Shashank Mohan (Rhodium Group)*

Stuart Mueller (CAPP)*

Chris Nichols (self)*

Olayinka Ogunsola (DOE)

OnLocation* 

Bill Pepper (ICF)*

Jack Perrin (EIA)

Gavin Pickenpaugh (NETL)*

Suryan Rajan (IHS)*

Donald Remson (NETL)*

Darryl Rogers (IHS)*

Deborah Rogers (Energy Policy Forum)*

Michael Schaal (EIA)

Ben Schlesinger (BSA)

David Shin (API)*

Michael Scott (EIA)

John Staub (EIA)

John Steelman (NRDC)*

Doug Tierney (EnCana)*

Peri Ulrey (NGSA)

Dana Van Wagener (EIA)

Anthony Yuen (Citigroup)*

Charles Zelek (NETL)

*Attendance via WebEX

Presenters: Joseph Benneche (NGTDM)

Dana Van Wagener (OGSM, EUR)

Phil Budzik (Alaska, CO2 EOR)

Michael Scott (Drilling Costs)

Presentation:

The presentation provided an overview of the primary assumption changes under consideration 

for AEO2014 in the Oil and Gas Supply Module (OGSM) and the Natural Gas Transmission and 

Distribution Module (NGTDM).

For natural gas modeling the following were presented:

• Benchmarking natural gas prices to average regional historical hub prices 

• Endogenously setting U.S. natural gas exports to Canada

• Assumption reassessments for Mexico natural gas consumption and production

• Assumption reevaluations of U.S. and Canada LNG exports

• Distributor tariffs and Canada supply equations reestimates

• Addition of natural gas use by trains and ships in NEMS
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For oil and gas supply modeling the following were presented:

• Update of USGS assessments of North Slope shale oil technically recoverable resources

(TRR)

• Perspective of North Slope shale oil activities to-date and production constraints

• Lower 48 offshore leasing availability and offshore deepwater projects

• Update of Outer Continental Shelf (OCS) undiscovered TRR

• CO2 Enhanced Oil Recovery (CO2 EOR) projects and availability assumptions

• Electricity Market Module (EMM) CO2 supply interface with the Oil and Gas Supply 

module (OGSM)

• Onshore Lower 48 dry shale gas and tight oil production

• Modified drilling cost equations

• Estimated Ultimate Recovery (EUR) from continuous plays

• Guarding against conservative biases (blind spots)

• County-level EUR analysis

• Side cases and Issues and Focus articles for AEO2014

• Modeling oil and gas tax legislation changes

Questions and answers regarding the NGTDM:

1) Are you modeling natural gas use in trains and trucks as cited by Administrator 

Sieminski this morning?

EIA response: Yes, for AEO2014, EIA will add a representation of train and ship use 

of natural gas; we previously have included trucks and cars.

2) Are you able to track large (unregulated) contracts (1 year contracts)?

EIA response: EIA recognizes that a large portion of natural gas is sold through longterm contracts. However, marginal prices drive the marginal demand that is used in 

the NEMS, a supply/demand equilibrium model.

3) What is the amount of gas sold through contracts?

EIA response: EIA doesn't track the amount of natural gas sold through long-term 

contracts. 

4) Is the EIA change in modeling Canadian LNG exports correct? (EIA question)

Working group attendee response: EIA’s treatment of Canadian natural gas is 

correct, including its treatment of LNG and stranded Canadian gas.

5) As recently written in the paper, how do you deal with international competition, i.e. 

Siberian gas to China.

EIA response: LNG build decisions are not necessary made from a holistic world 

natural gas market viewpoint. Builds will depend on representative Asian and 

European natural gas prices, as compared to a FOB U.S. LNG price. The EIA 

representative Asian and European price model includes production, the size of the 

global LNG market and regional production/consumption.
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6) How does EIA model LNG international competition?

EIA response: Both international supply and demand estimates, as well as, costs 

differentials are needed to model international LNG changes. For AEO2014, EIA is 

updating data for its profile of world LNG based on recent LNG investments and 

decisions by major producing and consuming nations, as well as with data from EIA’s 

recent International Energy Outlook supply and demand projections.

7) At what natural gas price does exporting LNG from U.S. LNG export terminals 

become uneconomical?

EIA response: EIA assumes that when a project is built, it will run at capacity for the 

projection period. EIA does not assume a price point that would prohibit exports from 

a facility that has been built in the model. Natural gas prices are just one input 

variable needed to estimate domestic LNG export investments. LNG exports are

modeled based on economics over the cost recovery period of the project.

Working Group response: Unless the market implodes, once a facility is built, it will 

be running at capacity.

8) How are LNG facilities modeled?

EIA response: Last year, LNG facilities builds were modeled endogenously. For 

AEO2013, North American LNG facility builds were also limited to one per year. 

For AEO2014, EIA is relaxing this constraint for build rates, allowing Alaska and 

Canada to operate as separate entities. Additionally, this year, EIA will also assume 

trains 3 and 4 of Sabine Pass will be built based on contracts in place. Additionally, 

EIA will exogenously set Canadian LNG export terminals based on the IEO 

projections.

9) How will prices of international LNG be modeled?

EIA response: EIA models representative European and Asian natural gas prices that 

change in relation to the oil price as more “flexible” LNG enters the market. NEMS, 

although it is mainly domestic, represents these international prices. EIA is in the 

process of enhancing its international model to provide more dynamic world cases for 

consideration.

10) Is all the gas (going for LNG) dry or is it about 20% ethane?

EIA response: The implicit model assumption is that we are only exporting dry gas 

as LNG as we are really only modeling the domestic market for dry natural gas within 

the Natural Gas Transmission and Distribution Module. While we are estimating the 

levels and value to the producers of natural gas plant liquids within the upstream 

model, the processing and marketing of the component products is handled separately 

within NEMS and therefore as a distinctly separate market from dry natural gas. 
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Questions and answers regarding the OGSM:

1) How are crude oil prices determined?

EIA RESPONSE: Domestic oil prices are estimated based on a supply/demand 

equilibrium, and are linked to the three exogenously estimated global oil price paths.

2) How does the model treat the non-homogeneities of world oil prices?

EIA response: The model uses a reduced representation of world oil prices to account 

for crude type and location. The level of detail is determined by the model's ability to 

mimic the market dynamics to world oil price differences.

3) Is there an effort to change the Reserve Report survey form to obtain county-level 

data such as in North Dakota?

EIA response: No changes to the EIA 23 survey. However, EIA is in the process of 

increasing the fidelity of production data to better estimate the potential of the play. 

Currently, the model characterizes plays within a state into just 3 EURs - the top 

15%, the bottom 15% and the 70% middle. For AEO2014 we plan to use 1 EUR for 

each county of a play.

4) Is there a published analysis showing the relationship of oil-in-place to technically 

recoverable? 

EIA Response: EIA has published several oil estimate articles and reports such as the 

recent publication "Technically Recoverable Shale Oil and Shale Gas Resources: An 

Assessment of 137 Shale Formations in 41 Countries Outside the United States"

summarized at http://www.eia.gov/analysis/studies/worldshalegas/.

5) What is the level of production well information EIA is using to project future 

production? 

EIA response: EIA use publicly available drilling databases, company surveys and 

evaluates the well performance by vintage, county level, changes in well length and 

number of frac stages.

6) Has EIA written a white paper on EUR analysis?

EIA response: The Annual Energy Outlook 2012 included two “Issues and Focus” 

articles on EUR analysis (http://www.eia.gov/forecasts/aeo/pdf/0383(2012).pdf).

7) EIA question: EIA is considering moving away from distinguishing between "shale

gas" versus “tight gas” labeling for low permeability plays because many low 

permeability plays are a mix of rock types. The important feature of the play is the 

production method which indicates the permeability.

Stakeholder response: No problems raised.

8) How is EIA handling the uncertainties of the 3-D shape of the formations and the 

physical boundary in estimating technically recovery oil?

EIA response: EIA attempts to remove as much uncertainty as possible in the drilling 

information as it relates to defined formations. This includes the uncertainty in the 
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boundaries of the adjacent/overlying formations. For example, the Bakken-Three 

Forks is often labeled as merely "Bakken" rather than separating out the Three Forks 

formation.

9) Are people drilling horizontally into deeper layers?

EIA response: Yes and no. Drilling strategies vary as drilling knowledge is gained

for a play. It's about moving to the most profitable layers. Some drilling plays evolve 

into deeper drilling, while others move into shallower ones. We see testing of the 

Three Forks benches, but industry is at early stage.

10) How does EIA put out its modeling assumptions and get discussions going?

EIA response: EIA publishes its assumptions annually at 

http://www.eia.gov/forecasts/aeo/assumptions/, where it splits out the information by 

each NEMS module. For the oil and gas assumptions, we hold two working group 

meetings and we reach out to the oil and gas industry and discuss these assumptions 

with the companies involved. EIA recognizes the need to maintain confidentiality 

and understands the limits of the companies' comments. All discussions are tied to 

well productivity. For example, the Buda formation, which underlies the Eagle Ford

formation, has a just few scattered wells. And in the Monterey formation, estimates 

based on the oil-in-place method have not materialized. The evolving understanding

is that the oil may have moved out of the Monterey due to faulting.

11) The independent oil companies are driving the shale and tight oil drilling. Are there 

enough driven producers to keep it going?

EIA response: EIA continues to monitor exploration and production drilling activity 

and investigates the trends in terms of activity, cost, and annual production. If the 

industry continues to have success, it is expected that the industry will grow as 

market opportunities dictate. Single no single well is guaranteed to produce 

economically, the drilling decision is an educated one, based on a monetized 

assessment of risk versus reward. For example, an operator in the Bakken drilled two

wells, one went horizontally to the west of the surface location and produced at 1000 

barrels of oil per day (bopd), while the other went horizontally to the east and 

produced less than 100 bopd. The maturity of the play will include both the use of 

tighter well spacing in known "sweet spots" and the expansion of exploration and 

production into less productive areas.

12) How does EIA estimate the near-term future of these plays?

EIA response: Near-term forecasts are informed by drilling activity trends, drilling 

efficiency trends, backcasting using near-term exploration and production history and

analyst knowledge of play activity.

13) Is there a side case for the Bakken?

EIA response: There are side cases on resource assumptions that include EUR and 

well spacing changes to the Bakken and all of the other low permeability plays.
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14) When will you know if production will drop due to a decline of drilling?

EIA response: In 2008 as gas prices dropped, drilling counts started to head down.

Total decreases in oil and gas production will occur when the economics of the 

investment result in insufficient drilling to replace the net production declines of 

existing wells. Those economic conditions are affected by the geology, technology, 

and economy. EIA monitors all three of these factors and adjusts the model to reflect 

measured changes.

15) Why are the EURs of wells in Bradford County, PA better than those in SW 

Pennsylvania?

EIA response: It depends if you are looking at just gas or both gas and liquids. 

Current production data from these two areas are used to estimate the well EURs. As 

time passes, these estimates will improve as more production data is provided and the 

EURs will change over time, perhaps showing different comparative performances.

16) Does EIA see a big overall production difference over time?

EIA response: No, production appears to continue provided the economics are 

favorable. We have not identified any step change due to technology or resource 

discoveries.

17) Do you see any proxies for estimating field production?

EIA response: We do look for proxies to improve our estimating capabilities. 

Currently, we are switching to county-level modeling where we may see production 

changes more quickly.

18) Any evidence of restimulation of wells?

EIA response: Yes, we have seen restimulation of wells, which appear to mostly 

recover oil sooner, increasing the net present value of the well.

19) Is EIA modeling deep Bypassed Residual Zone and its effect on CO2 demand?

EIA response: Although a potential resource, at this time, too little is known about 

Residual Zone Oil to permit its modeling in OGSM.

20) How is CO2 Enhance Oil Recovery (EOR) analysis coordinated between EIA, NETL 

and other groups?

EIA response: There is ongoing interaction with group in and outside of the 

government on CO2 EOR. EIA proposed organizing a workshop in September or 

October, which would bring in outside speakers (such as NETL, USGS, industry) and 

facilitate a discussion of the potential of industrial and electric power generation 

capture of CO2, and the amount of additional oil that could be produced.

21) Does Alaska versus Lower 48 well costs depend on productivity?

EIA response: Productivity, prices and costs determine the return on investment. The 

oil and gas project must also be risk rated to effectively determine its 

competitiveness.
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22) What is the distance of the Great Bear tight oil well test area from TAPS?

EIA response: One well is off the Dalton highway, the play ranges up to 

approximately 100 miles from the Dalton Highway on both sides.

23) EIA made a great case for zero oil from the Alaska shale by 2040. Is the shale on 

state land?

EIA response: Yes, to date, all the Alaskan shale leases granted are on state land.

24) What coordination is done with BOEM on technically recoverable resource estimates 

used in NEMS?

EIA Response: BOEM provides EIA with the underlying field-size distribution for 

their resource assessment. EIA subtracts the number of fields that have been 

discovered since the latest assessment data cutoff (the BOEM 2011 assessment used 

data as of 1/1/2009). Also, the list of announced discoveries is provided to the 

BOEM for comment.

25) When will you update your estimates?

EIA response: TRRs will be updated by the end of August 2013. CO2 numbers have

not been updated. However, EMM and the CO2 environmental role has been 

incorporated into NEMS to provide additional industrial CO2 for EOR if cost 

effective.

26) Why are drilling costs modeled on American Petroleum Institute’s (API) 2007 Joint 

Association Survey (JAS) data? 

EIA response: More recent JAS data appear to represent less of the industry, cost 

more and API has altered their product to make it less useful from a modeling 

perspective. The 2007 drilling cost data, while not ideal, is the most comprehensive 

we have and is sufficient to develop cost terms that reflect the dominant cost drivers 

to drilling oil and gas wells.

27) Does this cost equation make sense in light of the wide cost variations in the data?

EIA response: Yes, the cost equation is an estimate of the drilling and completion 

cost by location, depth, and well type. The model uses the drilling cost, along with 

other well costs, to rank order the net present value of the investment in all potential 

wells. This method enables total drilling activity to be estimated by region and year. 

The new equation merely aligns the cost terms to real world cost drivers. A statistical 

approach would not provide a "better" cost estimate for the model. The rank ordering 

of the potential wells creates the distribution of wells needed to emulate drilling 

decisions. The model is attempting to emulate a market behavior not estimate the 

cost of a particular project.

28) Is EIA doing the same for offshore drilling costs?

EIA response: We will not change the drilling cost equation for the offshore in 

AEO2014.
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29) Is the drilling cost problem variability?

EIA response: The model is not trying to model the variability of costs but the 

behavior of the industry in determining where, when and how much to drill. There is 

no added value to modeling D&C cost variability since the variability of other cost 

components not available such as the variability in the costing of risk among different

drilling companies. EIA does run sensitivity cases based on cost.

30) Do you see a change in costs due to rig activity?

EIA response: We analyze the rig activity effect and only see correlation when rig 

counts start approaching historical highs. We are also assessing rig type switching 

effects on drilling cost. Historically, the dominant well cost indicator is oil price. 

Other cost drivers include technology adoption and learning.

31) What about marginal wells cost credit?

EIA response: There are two enhanced oil recovery credits: one sunset at $30 per 

barrel, and the other is the 45Q gas enhanced oil to cover CCS cost.