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April 8, 2016

MEMORANDUM FOR: JOHN CONTI

ASSISTANT ADMINISTRATOR FOR ENERGY ANALYSIS

FROM: MINDI FARBER-DEANDA

ACTING TEAM LEAD

NATURAL GAS MARKETS TEAM

JOHN STAUB

TEAM LEAD

EXPLORATION AND PRODUCTION ANALYSIS TEAM

EXPLORATION AND PRODUCTION and NATURAL GAS

MARKETS TEAMS

SUBJECT: Second AEO2016 Oil and Gas Working Group Meeting Summary

(presented on February 29, 2016)

Attendees: Joseph Benneche (EIA)

Katie Dyl (EIA)

Terry Yen (EIA)

Danya Murali (EIA)

Laura Singer (EIA)

Faouzi Aloulou (EIA)

Dana Van Wagener (EIA)*

Troy Cook (EIA)*

Mindi Farber-DeAnda (EIA) 

John Staub (EIA)

Barbara Mariner-Volpe (EIA)

Kevin Easley (DOE)*

Taylor Malone (ARI)

Brett Murray (ARI)

Keith King (Moyes & Co)*

Doug Tierney (Encana)*

Gurcan Gulen (UT-Austin, BEG)*

Ben Schlesinger (BSA)*

Ken Ditzel (FTI Consulting)*

Richard Nehring*

Mike Lynch (SEER)*

Geoffrey Brand (API)*

Anas Alhajji (NGPTRS)*
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Beth Lau (CAPP)*

Katrina McLaughlin (RFF)*

Kara Callahan (OnLocation)*

Harry Vidas (ICF)*

Bob Hugman (ICF)*

Jack Weixel (PointLogic)*

Dave Schmalzer*

Jairam Gopal (Deloitte)*

Anthony Yuen (Citi Research)*

Kevin Massy (StatOil)*

Melissa Whitten (DayMark)*

Robert J Smith (DOE)*

Marshall Carolus (INTEK)*

Stuart Mueller*

*Attendance via WebEX

Presenters: Katie Dyl (NGTDM)

Dana Van Wagener (OGSM)

Presentation:

The Annual Energy Outlook 2016 (AEO2016) schedule started later and will result in a later 

publication than most years, target of June. The AEO2016 will have standard cases – Reference 

case, High/Low Oil Price cases, High/Low Macroeconomic Growth cases, and the High/Low Oil 

and Gas Resource/Technology cases – and a variety of other cases.

The presentation provided preliminary oil and natural gas production and price results for the

AEO2016 in the Oil and Gas Supply Module (OGSM) and the Natural Gas Transmission and 

Distribution Module (NGTDM), highlighting major changes compared to the AEO2015

Reference case.

For natural gas market modeling, the following were presented:

• Natural gas supply and delivered prices

• Natural gas consumption

• Pipeline imports/exports

• LNG exports

For oil and gas supply modeling, the following were presented:

• New approach to representing changes in Resources and Technology improvements

• Production of oil and natural gas across several scenarios by resource type, tight oil and 

shale gas plays

• Oil and natural gas price trends

• Liquids imports
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Questions and answers regarding the NGTDM:

1) What causes the dip in natural gas consumption in the electricity generation sector

around 2022? (slide 7)

EIA RESPONSE: Mainly renewables capacity growth. Natural gas prices are also 

rising in this time period.

2) Why don’t renewables appear to extend growth past 2022?

EIA RESPONSE: The tax credits are phased out or expire after this time period. So 

renewables continue to grow, just at a slower rate. Natural gas is also replacing coal 

after this time period, leading to its increase. 

3) Pipeline exports to Mexico being to decline around 2020. Is that because their 

production is increasing? (slide 9)

EIA RESPONSE: Yes. After 2020, U.S. exports to Mexico remain flat for several 

years, then begin to slowly decline due to new production in Mexico.

4) If shale gas resources are larger, will LNG capacity increase?

EIA RESPONSE: Potentially. When we have run our high oil and gas resource case 

previously we have seen more U.S. LNG liquefaction capacity built. LNG capacity 

increases are in response to the global natural gas price/world oil price relative to the 

price in the United States, which can be expected to be lower with more resources.

Questions and answers regarding the OGSM:

1) Does the future see rapid improvements in costs, EURs? Is it likely to have to rapid 

innovation near term, then slower further out?

EIA RESPOSNE: Timing of new technologies is difficult. We just want a simple 

assumption that will capture both the slow incremental improvement in industry 

practices and the rapid employment of future as yet unidentified technologies. 

2) Applying an S-curve to technology improvement would be more reasonable than 

linear improvement over time.

EIA RESPONSE: How should we choose the timing of the inflection point and 

slowdown in technology improvement? What about new future technologies that are 

not on the radar now? Technology advancement is expected to continue throughout 

the projection period without specifying the timing and contribution of specific 

technologies.

3) What vintage EUR’s are the basis for AEO2016?

EIA RESPONSE: We are using wells drilled in 2013, 2014 and 2015.

4) STAKEHOLDER COMMENT: Onshore and offshore costs are different.
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5) The good wells in the Middle Bakken probably have 3x the reasonable resource than 

the Three Forks. Are your projections too optimistic?

EIA RESPONSE: We have fit decline curves to all wells drilled in the Three Forks 

and use the mean EUR for each county. The Three Forks covers over 25 million acres 

and much of the area has little to no drilling. The EURs in undeveloped areas are 

based on the EURs of nearest developing counties but discounted as the distance from 

these counties increases.

6) Why is the Eagle Ford decreasing? Exhaustion of resources?

EIA RESPONSE: Only a few counties have productive wells. Drilling in the Eagle 

Ford is competing with drilling in other more production tight oil plays in Texas.

7) Have you reviewed/revised your resource assumptions for the Woodford?

EIA RESPONSE: We did update the Woodford resources. It’s difficult to judge 

where wells are going to go with the low prices- it’s hard to get drilling schedules 

consistent with the real world in the low price environment. 

8) Operator cash flow is a constraint on how much production can increase.

EIA RESPONSE: In general, cash flow impacts production and limits development in 

early years. We assume greater cash flow in later years.

9) Costs and facilities are important constraints.

EIA RESPONSE: Agreed. We represent development of resources as a function of 

the net present value of drilling in a play.

10) STAKEHOLDER COMMENT: Four years ago we wouldn’t have anticipated the 

amount of growth that could be sustained.

11) Is shale gas different from tight gas?

EIA REPONSE: Tight gas comes from tight sandstone carbonate plays. 

12) Tight sandstone gas peaked in 2008. Pinedale is backing out. Cotton Valley has 160 

acre spacing and can be drilled more closely.

EIA REPONSE: We assume that improvements in technology and industry practices 

in shale gas and tight oil formations will also be applied to tight gas resources.

13) Can you check the cumulative integral production from 2015-2040 to see how much 

resource is produced by 2040? Cannot produce at maximum rate beyond 70% of total 

recoverable resource.

EIA REPONSE: We have looked at the cumulative production through 2040 and 

have not exceeded a reasonable recovery rate where we have an estimate for oil or 

natural gas in-place.

14) Fluid physics interfering with recovery over time. For example in North Dakota the 

gas-to-oil ratio (GOR) has increased from 1,000 mcf/barrel to 1,400 mcf/barrel in 

recent years.
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EIA REPONSE: We assume flat gas-to-oil ratio over time.

15) How much larger is the Utica this AEO?

EIA REPONSE: We added roughly 100 Tcf additional resources to the Utica.