www.eia.gov

Joe Benneche

July 31, 2012, Washington, DC

Major assumption changes for AEO2013

Oil and Gas Working Group

Natural Gas Transmission and 

Distribution Module

DRAFT WORKING GROUP PRESENTATION 

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Overview

2

Joe Benneche, 

Washington, DC, July 31, 2012

• Replace regional natural gas wellhead price projections with 

regional spot price projections

• Pricing of natural gas vehicles fuels (CNG and LNG)

• Methodology for modeling exports of LNG

• Assumptions on charges related to LNG exports of domestic gas

• Other miscellaneous 

DRAFT WORKING GROUP PRESENTATION 

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Regional natural gas spot pricing

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• EIA has collected wellhead prices via a voluntary survey by states

– the reported data were becoming more sparse

– the concept of a wellhead price was becoming less well understood

– EIA needed to address budget tightening issues

– the survey was discontinued

• For AEO2013 replacing regional wellhead prices with 

representative spot prices

– previous AEOs based on the wellhead price; Henry Hub price estimated equation

– the inherent assumption forward is that producers in a region effectively respond to the 

going spot price in their area, with potential accounting for transportation differences

– selected candidate spot price(s) in each region and compared against wellhead prices

– align reasonably well, will fill in “missing” spot history with wellhead prices.

– potential impact on historical industrial prices

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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9

3

2

14

6

16

17

13

12

5

4

8

7

11

10 15

Supply regions in the NGTDM with 

representative spot prices

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Sumas/

Stanfield

Algonquin 

citygate

Transco 

Zone 6

Chicago 

citygate NGPL 

Amarillo

Northern 

Natural 

Ventura

Transco 

Zone 4 Tetco M2

Transco 

Zone 4

Henry

Hub

NGPL Midcon

Waha

Opal

FGT 

Zone 3

El Paso 

Permian

 El Paso 

Non Bondad

 Malin

 SoCal

 Border

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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Natural gas wellhead versus spot prices by NGTDM/OGSM region

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0

2

4

6

8

10

19941998200220062010199419982002200620101994199820022006201019941998200220062010

Wellhead

Spot

nominal dollars per MMBtu Shown from most to least production level

0

2

4

6

8

10

19941998200220062010199419982002200620101994199820022006201019941998200220062010

Wellhead

Spot

12 9 10 11

16 6 4 2

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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Natural gas wellhead versus spot prices by NGTDM/OGSM region (cont)

6

0

2

4

6

8

10

19941998200220062010199419982002200620101994199820022006201019941998200220062010

Wellhead

Spot

nominal dollars per Mcf Shown from most to least production level

0

2

4

6

8

10

19941998200220062010199419982002200620101994199820022006201019941998200220062010

Wellhead

Spot

15 3 8 17

5 13 14

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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Pricing of natural gas for vehicles

7

Joe Benneche, 

Washington, DC, July 31, 2012

• Had distinguished by fleet and retail, now also by CNG and LNG

• Reexamined assumptions for setting NGV fuel prices using following 

assumptions:

– A refueling facility will be used at a “reasonable” level if it is added

– Refueling capability will be added to existing stations

– Prices charged will reflect the cost of service (i.e., no economic rent)

– Estimated price markups will stay constant over time in real terms.

– Motor fuels (excise) taxes will stay constant over time in nominal terms

• Natural gas price to CNG station based on “vehicle fuel” prices

• Natural gas price to liquefaction facilities same as electric generators.

DRAFT WORKING GROUP PRESENTATION 

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Assumptions in setting NGV fuel markup

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CNG CNG LNG LNG

Fleet retail fleet retail

Retail Markup after dry gas pipeline delivery, 

 with no excise tax (2010$/dge) 0.80 0.93 1.39 1.58

 Capacity (dge/day) 1600 1100 4000 4000

 Usage (percent of capacity) 80 60 80 60

 Capital cost (million 2010$) 0.8 0.5 1.0 1.0

 Capital recovery (years) 5 10 5 10

 Weighted Average cost of capital (rate) 0.10 0.15 0.10 0.15

 Operating cost (2010$/dge) 0.34 0.51 0.41 0.59

 Charge for liquefying and delivering LNG (2010$/dge) -- -- 0.75 0.75

Federal excise tax (nominal$/dge) 0.21 0.21 0.42 0.42

State excise tax (nominal$/dge) 0.15 0.15 0.24 0.24

Fuel loss for liquefying and delivering LNG (% of input) -- -- 10 10

Fuel loss at station (% of input volumes) 0.5 0.5 1.0 2.0

-------------------------------------------------------

Source: U.S. Energy Information Administration, U.S. Tax Code and State Tax Codes. 

Note: dge is diesel-gallon equivalent

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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Basic approach for modeling LNG exports of 

domestically produced gas in AEO2013

9

Joe Benneche, 

Washington, DC, July 31, 2012

• Minimum export levels set based on assessment of high likelihood of 

project going forward given reported project status.

– Plan to set minimums at export levels assumed for AEO2012 (up to 2.2 Bcf/d in U.S.)

• Model will assess the economic viability of a project based on a 20-

year net present value assessment of the difference between the fully 

loaded price for natural gas from the U.S. as delivered to the NBP 

and/or Japan versus the estimated market price in the two areas.

• Each project will consist of two 0.5 Bcf/d trains, with a limit of one 

train built in North America in a given forecast year.

• If a liquefaction facility is built by the model, it will be assumed that 

it is used to full operating capacity thereafter.

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Estimated market price of natural gas in Europe

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MarketPriceUK = CUK + (αUK * IRAC) - (βUK * flexible LNG/OECD Europe consumption)

IRAC = Imported refinery acquisition cost

Flexible LNG = estimate of world LNG not tied to strict contract terms of delivery

Flexible LNG / OECD Europe consumption = indicator of whether the European market is 

generally tight or loose, thus driving the market price higher or lower.

Projection of OECD Europe consumption from IEO 2011. Flexible LNG based on IEO2011 

with analyst judgment. 

Some percentage of volumes of U.S. exports will be added to flexible LNG and result in 

lower Europe price

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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Estimated market price of natural gas in Japan

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MarketPriceJP = CJP + (αJP * IRAC) – [βJP * (flexible LNG+China prod)/Asia consumption]

IRAC = Imported refinery acquisition cost

Flexible LNG = estimate of world LNG not tied to strict contract terms of delivery

Asia consumption = consumption in Japan, China, and South Korea

(Flexible LNG +China production)/ Asia consumption = indicator of whether the Asian 

market is generally tight or loose, thus driving the market price higher or lower.

Projection of Asia consumption and China production from IEO 2011. Flexible LNG based 

on IEO2011 with analyst judgment. 

Some percentage of volumes of U.S. exports will be added to flexible LNG and result in 

lower Japan price

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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Assumed transportation, liquefaction, shipping, 

and regasification markups from N. America

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(2010$/MMBtu) Gulf Northeast Northwest Alaska

Transport from regional supply source 0.20 0.30 0.60 3.15

Liquefaction charge 3.00 3.00 4.20 3.70

 % increase for fuel for liquefaction 8% 8% 8% 8%

Shipping to UK 1.40 1.00 4.40 4.50

Shipping to Japan 3.10 3.75 1.20 1.00

Regasification 0.10 0.10 0.10 0.10

Nonfuel markup to UK 4.70 4.40 9.30 11.45

Nonfuel markup to Japan 6.40 7.15 6.10 7.95

 Risk?

Joe Benneche, 

Washington, DC, July 31, 2012

DRAFT WORKING GROUP PRESENTATION 

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Other discussion items

13 Joe Benneche, 

Washington, DC, July 31, 2012

• Other NGTDM changes

– Historical updates

– Change in industrial prices

– Increased exports to Canada

• AEO2013 schedule streamlined

• Potentially reduce extra side cases – Suggestions?

• Any comments on AEO2012 results?

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