U.S. Energy Information Administration Independent Statistics & Analysis www.eia.gov

Assumptions and Expectations for 

Annual Energy Outlook 2014: 

Oil and Gas Working Group

AEO2014 Oil and Gas Supply Working Group Meeting

Office of Petroleum, Gas, and Biofuels Analysis

July 25, 2013 | Washington, DC

http://www.eia.gov/forecasts/aeo/workinggroup/

WORKING GROUP PRESENTATION FOR DISCUSSION PURPOSES

DO NOT QUOTE OR CITE AS RESULTS ARE SUBJECT TO CHANGE
Introduction/Background

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 2

• Working group (history, purpose)

• National Energy Modeling System (NEMS)

– Annual Energy Outlook

– Requested service reports

– Assumptions/Documentation

– Model code and data input files

• Natural gas, petroleum, and biofuels modules

– Oil and Gas Supply Module (OGSM)

– Natural Gas Transmission and Distribution Module (NGTDM)

– Liquid Fuels Market Module (LFMM)

• Formerly Petroleum Market Module (PMM)

• Discussed in earlier working group
Primary data flows between oil and gas 

modules of NEMS

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 3

NGTDM OGSM LFMM

Lower 48 natural gas 

wellhead prices

Natural gas plant 

liquid prices

Domestic crude oil 

production

Natural gas plant liquid

production

Realized lower 48 

natural gas production

Lower 48

Associated-dissolved 

natural gas production

Expected lower 48 

Non-associated

natural gas production

Domestic crude oil 

wellhead prices
Assumptions

Natural Gas Transmission and 

Distribution Module (NGTDM)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 4
Overview

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 5

• Benchmark model to average regional historical hub prices

• Endogenously set exports from U.S. to Canada

• Reassess assumptions related to consumption and 

production in Mexico, and therefore exports to Mexico from 

the United States

• Reevaluate assumptions related to LNG exports out of U.S. 

and Canada

• Reestimate distributor tariffs and Canada supply equations

• Natural gas used in trains and ships is now included in NEMS
Regional natural gas pricing

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 6

• Previously the NGTDM was effectively benchmarked at the 

wellhead and city gate level

• With the pending discontinuation of the reporting of historical 

wellhead prices, for AEO2013 regional wellhead prices were 

replaced with representative spot prices less gathering charge

• For AEO2014, wellhead prices will be set as a netback from the 

regional hub price and hub prices will be benchmarked to 

representative historical spot prices

• While residential and commercial prices will still see a distributor 

markup off of the citygate price, industrial and electric generator 

prices will be marked up off of the regional hub price
Canada

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 7

• Exports from eastern U.S. to Canada, which had been set 

exogenously, now set endogenously based on relative prices. 

Expect volumes in same range (1.4 Tcf by 2040 in AEO2013).

• Eastern Canada production still exogenous, based on 

assumptions about offshore projects

• Western Canada production --update with new data, reestimate

• For AEO2013, LNG exports endogenous, draw from W. Canada 

market and based on W. Canada price, limited to 800 Bcf/y.

• For AEO2014, set exogenously consistent with IEO2013, 

assumed to draw from stranded resources (i.e., no influence W. 

Canada price)
Eastern Canada natural gas production, exogenous projection

8

billion cubic feet

0

50

100

150

200

250

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040

AEO2013

AEO2014

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Eastern Canada natural gas production, exogenous projection

9

trillion cubic feet

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change

0

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

1.8

2015 2020 2025 2030 2035 2040

AEO2013

IEO2013
Mexico

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 10

• Expect exports to Mexico from the U.S. to be higher in AEO2014 

compared to AEO2013, largely due to lower LNG imports into 

Mexico. Will depend on timing of infrastructure to support.

• Consumption set exogenously based on IEO2013 levels, higher 

towards the end of the forecast (in 2040, 6.0 Tcf in AEO2013 versus 

6.5 Tcf in IEO2013).

• While production is set endogenously it is based on IEO2013 

projections. If anything, will be slightly lower than IEO2013 levels.
IEO2013 Mexico natural gas consumption and production

AEO2013 net pipeline imports to Mexico from U.S.

11

trillion cubic feet

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change

-1

0

1

2

3

4

5

6

7

1990 1995 2000 2005 2010 2015 2020 2025 2030 2035 2040

Consumption

Production

Cons. minus Prod.

Net pipe imports
LNG exports of domestically produced gas

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 12

• Minimum export levels set based on assessment of high 

likelihood of project going forward given reported project status.

– Plan to set minimums consistent with four trains at the Sabine Pass facility

• Model assesses 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 Europe and Asia versus the estimated market price in the 

two areas.

• Each project will consist of two 200 Bcf/y trains, with a limit of 

one (?) train built in the lower 48 states 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.
Charges and assumptions related to LNG 

exports for AEO2013

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 13

(2010$/MMBtu) S. Atlantic W.S. Cntl WA/OR Alaska

Liquefaction and Pipe Fee 3.30 3.00 4.10 7.00

Shipping to Europe 0.98 1.28 3.86 3.65

Shipping to Asia 2.63 2.55 1.15 0.90

Regasification 0.10 0.10 0.10 0.10

Fuel charge (percent) 15 15 15 15

Nonfuel markup to Europe 4.38 4.38 8.06 10.75

Nonfuel markup to Asia 6.03 5.65 5.35 8.00

 Risk 0.00 0.00 0.00 0.00

Maximum exports (Bcf) 9999 9999 9999 800

Earliest start year 2019 2018 2019 2023
U.S. natural gas imports and exports, AEO2013

14

trillion cubic feet

-4

-2

0

2

4

6

8

10

2010 2020 2030 2040

-4

-2

0

2

4

6

8

10

2010 2020 2030 2040

Reference case High resource case

Exports to 

Mexico

Exports to 

Canada

Lower 48 states 

LNG exports

Alaska LNG 

exports

Imports from 

Canada

LNG imports

bcf/day

27.4

21.9

16.4

11.0

5.5

-5.5

-11.0

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Contacts

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 15

Natural Gas Transmission and Distribution Module

joseph.benneche@eia.gov

International natural gas projections | justine.barden@eia.gov

General oil and gas questions | angelina.larose@eia.gov
Assumptions

Oil and Gas Supply Module (OGSM)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 16
Overview

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 17

• Introduction/background

• Oil and natural gas supply assumptions

– Alaska

– Offshore

– CO2 EOR

– Drilling cost equations

– Lower 48 continuous plays

• county level evaluation

• Side cases/Issues in focus

– pending tax change legislation

– high resources; same as last AEO?
Goals for AEO2014

18

• Streamline I/O system for historical data by transitioning from 

Fortran to SAS

• Reporting of NGPL technically recoverable resources

• New drilling cost equations

• Tight oil and shale gas EURs at county level, improves granularity

• Improved interfaces with LFMM and EMM

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Challenges/issues

19

• Data no longer available for historical updates

– Wells completed (IHS & EIA)

– Lease equipment & operating costs (EIA)

– Drilling costs (JAS)

– What’s next?

• DI database play name aliases and type (LP, SH) designations

– Definition consistent with monthly generated production charts

– Clean up play names in additional tight and shale plays

• Nehring reservoir database 2007 version

– API gravity, Sulfur, Depth, temperature, maturity, porosity, CO2 content, NGPL factor

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Alaska

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 20
Alaska North Slope shale oil production 

potential

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 21

• U.S. Geological Survey assessment (February 2012)

• Activities to-date

• Constraints to the development of shale oil resources

• North Slope wellhead oil prices

• Conclusions
U.S. Geological Survey assessments of North Slope and Bakken

shale oil technically recoverable resources (TRR)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 22

Shale 

formation

Mean value 

potential 

production area

(million acres)

Mean estimated 

Oil + NGPL TRR

(million barrels)

Mean estimated

ultimate recovery for 

“sweet spot” wells

(thousand barrels 

per well)

Shublik 6.6 475 61

Brookian 17.4 471 43

Kingak 6.8 29 43

Bakken (only) 11.3 3,890 250 to 430

Sources: U.S. Geological Survey, AK North Slope - Fact Sheet 2012-3013 & Bakken – Fact Sheet 2013-3013
Alaska North Slope shale oil:

activities to-date

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 23

• Great Bear Petroleum

– leased ~500,000 acres in the shale oil “window” from the State in Oct. 2010

– formed JV with Halliburton in Nov. 2011 to test shale “proof-of-concept”

– JV drilled 2 wells and extracted rock cores in late 2012

– in April 2013, said more time was needed to analyze the shale rock cores

– no new company statements since April 2013...lack of good news to release?

• Royale Energy

– purchased 56 State leases in December 2011 auction

– formed JV with unnamed company in April 2013 to pay for initial shale test wells

– no new company statements since April 2013

Source: Petroleum News, Anchorage, Alaska
Alaska North Slope shale oil:

constraints to production

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 24

• Natural gas - shale oil production requires associated natural 

gas to provide reservoir-drive through gas expansion. Absent 

a market for North Slope natural gas, the co-production of 

natural gas imposes a re-injection cost, rather than being a 

revenue source, as it is in the lower-48.

• Drilling costs – North Slope shale well drilling and completion 

costs could be 2 times or more expensive than that 

experienced in the lower-48.

• Environmental – the construction of North Slope gravel roads 

and drilling pads is expensive due to permafrost conditions. 

Opposition to an extensive network of roads, drilling pads, 

gathering pipelines, and processing plants is expected.
Alaska North Slope shale oil:

wellhead oil prices

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 25

• In 2012, the average North Slope first purchase oil price was 

$94.52 per barrel.

• In 2012, Brent crude oil averaged $111.63 per barrel, 

indicating that North Slope crude oil was selling at a $17.11 

per barrel discount due to pipeline and marine transportation 

charges.

• If North Slope oil production continues to decline, thereby 

causing pipeline transportation rates to increase, then North 

Slope shale oil wellhead revenues per barrel would decline 

over time, if world oil prices stayed constant.

Source: U.S. Energy Information Administration 
Alaska North Slope shale oil:

conclusions

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 26

• Development of Alaska North Slope shale oil production is 

not expected prior to 2040 due to:

- low expected shale oil well recovery rates,

- high drilling, completion, and infrastructure costs,

- discounted wellhead oil prices, 

- natural gas and frack water disposal costs, and

- expected opposition by environmental groups.
Lower 48 Offshore

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 27
Lower 48 offshore leasing availability 

(no changes)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 28

AEO2013 AEO2014

North Atlantic none None

Mid Atlantic 2018 2018

South Atlantic 2018 2018

Northern & Central California none none

Southern California 2023 2023

Eastern GOM 2022 2022
Lower 48 offshore deepwater projects

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 29

* Currently producing

BOEM 

Field 

Name Nickname

Water 

Depth

Field 

Size 

(MMBoe)

Discovery 

Year

Start Year 

of 

Production

BOEM 

Field 

Name Nickname

Water 

Depth

Field Size 

(MMBoe)

Discovery 

Year

Start Year 

of 

Production

WR250 Cascade 8143 372 2002 2012* DC048 Dalmatian 5876 89 2008 2015

GC683 Caesar 4457 45 2006 2012* DC004 Axe 5822 89 2010 2015

GC726 West Tonga 4674 372 2007 2012* GB605 Winter 3400 45 2009 2015

MC241 MC241 2427 45 1987 2012* GC432 Samurai 3400 89 2009 2015

MC292 Raton South 3400 12 2008 2012* GC468 Pony 3497 372 2006 2015

LL400 Cheyenne East 9200 12 2011 2012* MC771 Kodiak 4986 182 2008 2015

MC199 Mandy 2478 182 2010 2012* GB427 Cardamom Deep 2720 182 2010 2015

MC562 Isabela 6535 45 2007 2012* MC762 Deimos South 3122 2010 2015

MC563 Santa Cruz 6515 2009 2012* MC792 West Boreas 3112 2004 2015

MC519 Santiago 6500 2011 2012* GC955 Mission Deep 7300 182 1999 2016

GB293 Pyrenees 2100 89 2009 2012* KC102 Tiber 4132 691 2009 2016

WR469 Chinook 8831 372 2003 2012* KC292 Kaskida 5860 691 2006 2016

GC299 Clipper 3452 45 2005 2012* MC984 Vito 4038 182 2009 2016

GC490 Wide Berth 3700 89 2009 2012* WR508 Stones 9556 89 2005 2016

MC751 Goose 1624 45 2003 2012* MC948 Gunflint/Freedom 6095 691 2008 2016

GB463 Bushwood 2700 89 2009 2013 GC859 Heidelberg 5000 182 2009 2016

GB506 Danny II 2800 2012 2013 WR052 Shenandoah 5750 182 2009 2017

GC512 Knotty Head 3557 372 2005 2013 KC872 Buckskin 6920 182 2009 2018

GB782 Entrada 4690 372 2000 2014 LL370 Diamond 9975 45 2008 2018

WR029 Big Foot 5235 182 2005 2014 WR627 Julia 7087 89 2007 2018

KC875 Lucius 7168 182 2009 2014 KC736 Moccasin 6759 2011 2018

MC725 Tubular Bells 4334 89 2003 2014 DC353 Vicksburg 7457 372 2007 2019

WR678 St. Malo 7036 372 2003 2014 MC392 Appomattox 7217 691 2009 2019

WR759 Jack 6963 372 2004 2014 WR848 Hal 7657 45 2008 2019

AC856 Gotcha/Great White West 7844 2006 2014 DC004 Dalmatian N 5831 89 2010 2020

KC964 Hadrian South 7586 182 2009 2014 KC919 Hadrian North 7000 372 2010 2020
OCS undiscovered technically recoverable 

resources (mean estimates) – minor changes

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 30

Region BOEM 2006 Assessment BOEM 2011 Assessment

Oil (Bbo) Natural Gas (tcf) BOE (Bbo) Oil (Bbo) Natural Gas (tcf) BOE (Bbo)

Alaska 26.61 132.06 50.11 26.61 131.45 50.00

Atlantic 3.82 36.99 10.40 3.30 31.28 8.87

 North 1.91 17.99 5.12 1.35 9.87 3.11

 Mid 1.50 15.13 4.19 1.42 19.36 4.87

 South 0.41 3.86 1.10 0.53 2.04 0.89

Gulf of Mexico 44.92 232.54 86.30 48.40 219.46 87.45

 Western 10.70 66.25 22.49 12.38 69.45 24.74

 Eastern 3.88 21.51 7.71 5.07 16.08 7.93

 Central 30.32 144.77 56.08 30.93 133.90 54.76

Pacific 10.53 18.29 13.79 10.20 16.10 13.07

 WA/OR 0.40 2.28 0.81 0.40 2.28 0.81

 Northern CA 2.08 3.58 2.71 2.08 3.58 2.71

 Central CA 2.31 2.41 2.74 2.40 2.49 2.84

 Southern CA 5.74 10.03 7.52 5.32 7.76 6.70

Total U.S. OCS 85.88 419.88 160.60 88.59 398.37 159.49

backup
CO2 EOR

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 31
Potential and current CO2 EOR projects

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 32

Category Field Count

Active (as of Jan. 1, 2012) 120

Planned (including ROZ) 11

Candidates 2,229 

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Existing Oil Fields

Planned Oil Fields

Candidate Oil Fields
CO2 availability assumptions

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 33

Source Type

Infrastructure

Development

(years)

Market

Acceptance

(years)

Ultimate Market

Acceptance

Maximum CO2

Volumes

(million tons)

Average Carbon 

Capture & 

Transportation 

(within Region) 

Cost

($/ton)

Ammonia Plants 2 10 100% 4.5 31

Natural Gas 

Processing 2 10 100% 10.9 27

Ethanol Plants 4 10 100% 18.4 33

Hydrogen Plants 4 10 100% 0.2 37

Refineries 4 10 100% 16.7 29

Cement Plants 7 10 100% 21.6 70

Fossil Fuel Plants Determined by the Electricity Market Module (EMM)

Coal-to-Liquids Determined by the Liquid Fuels Market Module (LFMM)
New EMM CO2 Supply Interface

34

• EMM determines cost of CO2 capture and transportation to 

potential CO2 EOR fields from new and existing electric 

power plants.

• OGSM producers see the delivered volume and wellhead 

cost of CO2 provided by power plants and determine whether 

to use that incremental CO2 supply based on the economics 

of EOR recovery for their field.

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Recoverable EOR/ASR resources

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 35

(Vertical & Horizontal) (Vertical & Horizontal)

-

5

10

15

20

25

30

35

40

45

CO2 EOR Steam Flood Polymer Infill Profile

Modification

billion barrels

Technical $50/Bbl $80/Bbl $125/Bbl

backup
Onshore Lower 48

36

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
U.S. dry shale gas production was 28.9 Bcf/d in June 2013.

8% growth over June 2012, 1% growth over May 2013

37

shale gas production (dry)

billion cubic feet per day

Sources: LCI Energy Insight gross withdrawal estimates as of June 2013 and converted to dry production 

estimates with EIA-calculated average gross-to-dry shrinkage factors by state and/or shale play. State 

abbreviations indicate primary state(s).

0

5

10

15

20

25

30

35

2000 2002 2004 2006 2008 2010 2012

Rest of US

Marcellus (PA and WV)

Haynesville (LA and TX)

Eagle Ford (TX)

Bakken (ND)

Woodford (OK)

Fayetteville (AR)

Barnett (TX)

Antrim (MI, IN, and OH)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
U.S. tight oil production was 2.4 mmbbl/d in March 2013.

46% growth over March 2012, 2% growth over Feb. 2013

38

tight oil production

million barrels of oil per day

Source: Drilling Info, and EIA, through March 2013. State abbreviations indicate primary state(s).

0.0

0.4

0.8

1.2

1.6

2.0

2.4

2.8

2000 2002 2004 2006 2008 2010 2012

Eagle Ford (TX)

Bakken (MT & ND)

Granite Wash (OK & TX)

Bonespring (TX Permian)

Wolfcamp (TX Permian)

Spraberry (TX Permian)

Niobrara-Codell (CO)

Woodford (OK)

Monterey (CA)*

Austin Chalk (LA & TX)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Drilling cost equations

39

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
$0 

$200 

$400 

$600 

$800 

$1,000 

$1,200 

$1,400 

$1,600 

0 4,000 8,000 12,000 16,000 20,000

Drilling depth (ft)

$0 

$2,000 

$4,000 

$6,000 

$8,000 

$10,000 

$12,000 

$14,000 

0 4,000 8,000 12,000 16,000 20,000

Drilling depth (ft)

Wide distribution in drilling costs

40

Drilling costs per well ($M) Drilling costs per foot ($/ft)

Drilling costs and drilling costs per foot vary more than 100% due to many 

factors (location, geology, experience, etc.)

Source: JAS 2007

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Average drilling costs per foot suggest three 

dominate cost drivers

41

$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

0 5,000 10,000 15,000 20,000

Northeast

Gulf Coast

Midcontinent

Southwest

Rocky Mountains

West Coast

$- 

$100 

$200 

$300 

$400 

$500 

$600 

$700 

0 5,000 10,000 15,000 20,000

Overhead

Drilling

Trouble

Drilling depth (ft) Drilling depth (ft)

Drilling costs ($ million) Drilling costs per foot ($/ft)

Drilling cost equations were revised to represent real-world cost drivers

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Drilling and completion cost equations

42

Old Equation : A + B*Depth + C*Depth2 + D*Depth3 (truncated 3rd Order Polynomial)

New Equation : A*exp(-b*Depth) + (C*Depth + D*Depth2) + E*exp(f*Depth)

Provides better representation of dominating cost drivers: economy of scale and learning for fixed costs 

(overhead, pre-spud, surface work) and deep well trouble (kicks, trips, lower ROPs, rig type switching)

fixed --------------- drilling -------------- trouble

$-

$1 

$2 

$3 

$4 

$5 

$6 

$7 

500 2,500 4,500 6,500 8,500 10,500 12,500 14,500

Trouble (Problems)

Variable (Drilling)

Fixed (Prespud & Overhead)

Drilling costs ($ million)

Drilling depth (ft)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Estimated Ultimate Recovery –

continuous plays

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 43
Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 44
Lower 48 states major tight gas plays

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 45
Estimated ultimate recovery (EUR) –

continuous plays

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 46

• USGS 2012-2013 updates

– Utica Shale, Appalachian Basin

– Bakken and Three Forks Formations, Williston Basin

• Play-level EURs are based on historical well performance

– Individual well performance analyzed (2008-2012)

– Hyperbolic decline 

where, 0 < b < 2 and 0< Di <1

– Converts to exponential decline when decline rate reaches Q ∞
AEO2013 documentation

http://www.eia.gov/forecasts/nemsdoc/ogsm/pdf/m063(2013).pdf

47

• Pages 182-184 “Appendix 

2.C: Decline curve analysis”

• Provides hyperbolic decline 

curve parameters for 

selected plays

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
AEO2013 assumptions

http://www.eia.gov/forecasts/aeo/assumptions/index.cfm

48

• pages 117-132

• Provides play level 

– well spacing, 

– areas, 

– EUR, and 

– TRR

• CO2 EOR parameters

• Offshore projects

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Guarding against conservative biases (blind spots)

49

• Develop fitting procedures that do not 

contain “built-in” biases (e.g. working up 

from zero)

• Limits of interpolation and extrapolation

• Historical over and under-estimating

0

5

10

15

20

25

30

35

40

45

50

missing data

I

H

G

F

E

D

C

B

A

0

100

200

300

400

0 2 4 6 8 10

0

2

4

6

8

10

1 2 3 4 5 6 7 8 9 101112131415161718

1500 

1700 

1900 

2100 

2300 

2500 

1994 1996 1998 2000 2002 2004 2006 2008 2010 

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
EUR analysis

50

• County-level review

– Step 1: Automated fitting routine

– Step 2: Spot check groups of wells

– Counties with few to no wells producing?

– Counties with wide range of EURs?

• Vintage

• Marcellus Example

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Oil and natural gas drilling in Pennsylvania

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 51
Oil and natural gas drilling in Bradford County, PA

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 52
PA Marcellus – 2008-2011 wells

(need minimum of 4 data points for EUR fits)

53

EUR 

 < 1 bcf

 1-1.99 bcf

 2-3.99 bcf

 4+ bcf

 

`

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
PA Marcellus – 2008 wells

54

EUR 

 < 1 bcf

 1-1.99 bcf

 2-3.99 bcf

 4+ bcf

 

`

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
PA Marcellus – 2009 wells

55

EUR 

 < 1 bcf

 1-1.99 bcf

 2-3.99 bcf

 4+ bcf

 

`

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
PA Marcellus – 2010 wells

56

EUR 

 < 1 bcf

 1-1.99 bcf

 2-3.99 bcf

 4+ bcf

 

`

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
PA Marcellus – 2011 wells

57

EUR 

 < 1 bcf

 1-1.99 bcf

 2-3.99 bcf

 4+ bcf

 

`

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change
Marcellus Basin – 2008-2011 wells

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 58

bcf/well

Number 

of wells

Average 

EUR

minimum

maximum

25th percentile

mean

median

75th percentile
Marcellus Basin – 2008-2011 wells (con’t)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 59

bcf/well

Number 

of wells

Average 

EUR

minimum

maximum

25th percentile

mean

median

75th percentile
Marcellus Basin – 2008-2011 wells (con’t)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 60

bcf/well

Number 

of wells

Average 

EUR

minimum

maximum

25th percentile

mean

median

75th percentile
Marcellus Basin – 2008-2011 wells (con’t)

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 61

bcf/well

Number 

of wells

Average 

EUR

minimum

maximum

25th percentile

mean

median

75th percentile
Marcellus Basin – Bradford County

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 62

bcf/well

Number 

of wells

Average 

EUR

minimum

maximum

25th percentile

mean

median

75th percentile
Marcellus Basin – Susquehana County

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 63

bcf/well

minimum

maximum

25th percentile

mean

median

75th percentile

Number 

of wells

Average 

EUR
Marcellus Basin – Tioga County

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 64

bcf/well

minimum

maximum

25th percentile

mean

median

75th percentile

Number 

of wells

Average 

EUR
Marcellus Basin – Greene County

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 65

bcf/well

minimum

maximum

25th percentile

mean

median

75th percentile

Number 

of wells

Average 

EUR
Marcellus Basin – Washington County

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 66

bcf/well

minimum

maximum

25th percentile

mean

median

75th percentile

Number 

of wells

Average 

EUR
Side cases

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 67
Side cases and Issues and Focus articles

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 68

• Planned AEO2014 Side Cases

– High/low world oil price

– High/low macroeconomic growth

– High/low tight/shale oil and gas resources

• Potential AEO2014 Side Cases

– Proposed tax legislation

• AEO2014 Issues and Focus?
Pending oil and gas tax legislation

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 69

• Federal royalty rates

– Repeal of EPACT 2005 royalty relief

– Royalty rate changes from 12.5% to 18.75%

• Tax relief

– Repeal the enhanced oil recovery credit

– Repeal the credit for oil and natural gas produced from marginal wells

– Repeal the deduction for tertiary injectants

– Repeal expensing of IDCs

– Repeal percentage depletion for oil and natural gas wells
U.S. tight oil production leads growth in domestic production

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 70

0

2

4

6

8

10

1990 2000 2010 2020 2030 2040

0

2

4

6

8

10

1990 2000 2010 2020 2030 2040

Source: EIA, Annual Energy Outlook 2013 and Short-Term Energy Outlook, July 2013 end of year values.

Alaska

Tight oil

Other lower 48 states onshore

Lower 48 states offshore

STEO July 2013 U.S. crude oil projection

History 2011 Projections History 2011 Projections

Alaska

Tight oil

Other lower 48 states onshore

Lower 48 states offshore

Reference case High resource case

million barrels per day
Contacts

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 71

Lower 48 oil and gas supply

dana.vanwagener@eia.gov

troy.cook@eia.gov

michael.scott@eia.gov

jack.perrin@eia.gov

Alaska & CO2 EOR oil supply | philip.budzik@eia.gov

Offshore oil and gas supply | samuel.gorgen@eia.gov

General oil and gas questions | john.staub@eia.gov
For more information

Office of Petroleum, Gas, and Biofuels Analysis Working Group Presentation for Discussion Purposes 

Washington, DC, July 25, 2013 DO NOT QUOTE OR CITE as results are subject to change 72

U.S. Energy Information Administration home page | www.eia.gov

Short-Term Energy Outlook | www.eia.gov/steo

Annual Energy Outlook | www.eia.gov/aeo

International Energy Outlook | www.eia.gov/ieo

Monthly Energy Review | www.eia.gov/mer

Today in Energy | www.eia.gov/todayinenergy