WORKING GROUP PRESENTATION FOR DISCUSSION PURPOSES ONLY.

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May 31, 2018

MEMORANDUM FOR: Ian Mead

Assistant Administrator for Energy Analysis

FROM: John Staub

Director, Petroleum, Natural Gas, and Biofuels Analysis

Subject: Summary of Natural Gas Working Group Meeting held on

May 23, 2018

This memorandum provides an overview of the presentation given during the first Annual Energy 

Oultook 2019 (AEO2019) Natural Gas Working Group meeting and a summary of the resulting 

discussions that took place. The presentation slides are available in a separate document.

Background

Katie Dyl, EIA’s lead natural gas markets modeler, led the working group. 

She explained to participants that EIA was holding the first working group meeting earlier in the 

development cycle than in the past in to discuss the results in the recently released AEO2018 and solicit 

stakeholder feedback for consideration in future modeling efforts. Additionally, the first working group 

meeting provides an opportunity to identify issues or topics that might be better addressed through

smaller, targeted working group discussions.

AEO2019 will be a short AEO cycle and will include the 6 core side cases (High/Low Macro, High/Low Oil 

Price, High/Low Oil and Gas Resource and Technology cases), along with the Reference case.

The meeting began with EIA staff presenting an overview of the updates that were included in AEO2018, 

including the new Natural Gas Markets Module (NGMM). Highlights includes specific results (e.g., 

selected regional flows, regional supply price differentials), which may imply the NGMM may be 

underestimating natural gas flows from the Northeast down to the Gulf Coast, and where future 

modeling efforts should be focused.

Model updates (AEO2019)

The following updates are being considered for AEO2019:

• Improvements to the variable tariff curves (the unit cost as a function of capacity utilization) to 

align regional flows and supply prices with recent history

• Improvements with convergence between NGMM and EMM (in collaboration with the 

electricity modelers)

• Strengthening NGMM’s benchmarking to new STEO forecasts

• The inclusion of historical calibration of NGMM results (a part of the post-AEO 2019 plan)

Not all of these update may be incorporated into AEO2019 because it is a short cycle, but a concerted 

effort is being made to improve this model based on what was learned when it was introduced during 

the last modeling cycle.
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Discussion

The first set of questions were related to how NGMM was structured and operated. Afterwards, the 

discussion focused on AEO2018 results and future modeling efforts. Finally, a few questions were asked 

about EIA’s related publications.

NGMM

Staff clarified that the NGMM was written in AIMMS, not GAMS, and that all future new models will be 

using AIMMS because of its ease of use and ability for staff to learn the interface relatively quickly. It 

was also asked whether NGMM solves each month one at a time. Staff indicated that all months in a 

given year are solved simultaneously and independently of one another.

When asked to explain how storage is considered in the NGMM, staff explained that storage is

endogenous in the model, fixed to the historical annual average. This assumption is well justified since

NEMS is focused on producing long-term annual projections, not short-term, monthy results for 

publication. This means, as one stakeholder pointed out, that supply is the “balancing” quantity in the 

NGMM, not storage as often happens in the marketplace. Storage injections and withdrawals are each 

represented by their own nodes, and balance out to zero in any given year.

Regarding capacity expansion, staff explained that NGMM determines capacity expansion endogenously 

using the extension of the variable tariff curves (representing the additional cost required to build a 

pipeline) and consumption ~15% in excess of the historical average to represent a peak January and 

August month. If the utilization of existing capacity surpasses 100%, that additional volume is added 

into the total for a given year starting in November.

When asked if the NGMM can stop or not consider capacity expansion for a given transportation arc 

(i.e., into New England), EIA indicated that yes, the price associated with the utilization on the tariff 

curve can be adjusted to make the cost too high to ever be reasonably economic.

Modelers were then asked about the upper portion of the tariff curve. In particular, there was a

concern that the variable tariff curve represents a variable cost below 100% utilization and a fixed 

capital cost above 100% utilization. EIA responded that this was not really a concern, especially as a first 

order approximation for the costs. There may be other ways to incorporate capacity expansion than 

this, but this way seems to work well. It was also pointed out that the curves should not be thought of 

as a variable cost, but as a basis differential representing a willingness to pay above the variable cost as 

capacity becomes constrained. The modelers were simply representing whether the demand is there 

for more capacity, not the capital costs associated with it.

Results (AEO2018)

Most of the questions during this discussion centered around natural gas trade. In response to a 

question related to where LNG export capacity was being built in the model endogenously after 2020, 

staff indicated that all additional LNG export capacity built beyond what is under construction is in the 

Gulf Coast. The only other option (by assumption) is to build capacity in Alaska. However this capacity 

does not come online since the project development lags behind others currently in advanced planning 

stages. Current constraints in the model do not allow for LNG exports out of the west coast (i.e., Jordan 

Cove in Oregon) as the prices seem too high for any likely expansion due, in part, to the additional 
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infrastructure required and its distance from low-cost U.S. supply. This choice can be amended, 

however, as the NGMM is flexible enough to include additional options for LNG export capacity sites. 

Any LNG out of Western Canada is exogenous as we use results from IEO 2017 to inform Canadian LNG 

export capacity.

As for where U.S. LNG exports ultimately go in the NGMM, these flows are not explicitly modeled. 

However, when determining the economic benefit of building additional capacity, two possible options

are modeled: Atlantic basin (i.e., Europe) and Pacific bain (i.e., Japan, South Korea, China). In the 

NGMM, LNG exports go to the Pacific as prices are higher and therefore offer a greater profit. LNG 

going to Mexico or South America is not currently included in the model. However, an exogenous LNG 

import level into Mexico based off of results from IEO 2017 is assumed.

There was also a question on how NGMM models Canadian supply, specifically shale gas development in 

western Canada. Unlike in the prior natural gas model, this is now handled by the Oil and Gas Supply 

Module (OGSM), which bases their results on NEB projections. However, the NGMM does solve for the 

spot price in western Canada, which is sent to OGSM as in input for determining future production. NEB 

projections show that most of the growth in natural gas production does come from shale gas, 

specifically the Montney formation.

Model updates

This discussion centered on two themes: the incremental attempts to improve historical calibration and 

improved convergence with the electricity market module.

While stakeholders were informed that a thorough historical calibration effort would not be possible in 

AEO2019, EIA intends to work on this the future. EIA also received a lot of good feedback about 

potential pitfalls and options. Stakeholders thought the improved regionality was a “great start,” and 

asked about any future plans to make certain states (i.e. Texas) even more granular. While increased 

regional granularity is something worth considering, it’s a difficult task because demand data is not 

available at that level, and it would require a significant effort to prepare the data to this level. 

Therefore, this is not a high priority improvement unless it becomes necessary for historical calibration. 

One stakeholder asked about how EIA was dealing with the issue of pipelines that purchase electricity 

for processing, compression, etc., while dealing with the calibration of natural gas used as pipeline fuel 

because electricity is increasingly used in leiu of natural gas to run these facilities. The response was 

that EIA is aware of the issue, and the Natural Gas Markets Team is trying to make modifications to 

existing EIA surveys in an attempt to collect more information on this issue.

With respect to convergence with Electricity Market Module (EMM), one participant pointed out that it 

could be a sensitivity issue, and the EMM may be jumping on penny changes. Monthly storage might be 

impacting this because the NGMM is generating too much price sensitivity to months with peak 

electricity use. Additionally, the historic storage pattern might overstate the demand. EIA could try a 

separate run where interactions with EMM are at an annual, not seasonal, level, letting it underestimate 

the price volatility. It may not get as much of a price swing which may be more reflective of the electric 

markets. Another participant suggested the alternate approach, interacting at a monthly level, but EIA 

modelers were not sure about the feasibility of this; it could also add to run time. 
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Toward the end of the meeting, the discussion went back to storage, where the idea rose that instead of 

making storage a historical average, or part of the QP, the model could look at demand changes and 

adjust storage values accordingly (thereby potentially mitigating price spikes). However, while this could 

work with residential and commercial sectors, there was still skepticism that this could work given the 

price sensitivity of the electric power sector.

EIA confirmed that a historical average injection and withdrawal pattern was used for each individual 

state and that it is kept constant across the projection and scenarios. Therefore, no more storage is 

built, even in the high resource case.

One stakeholder pointed out that this fixed storage could be exaggerating price swings, for example, 

local distribution centers (LDCs) needing additional storage, and that it might benefit the NGMM to look 

at changing storage by demand type and change. However, the difficulty of this was acknowledged 

given that it could depend on a lot of different factors (i.e. weather). But it might be worthwhile to look 

at electric load changes. Finally, the discussion closed with a comment that the electric power sector is 

a lot more important to balancing gas markets than might be acknowledged.

Additional issues

There were some general questions related to publication:

• The AEO2018 Assumptions document is available for the Natural Gas Market Module.

• NGMM documentation is in review and will be out as soon as it gets through that process. Katie 

Dyl offered to provide an early copy of this document for those that have an interest when it is 

through the first stage of review and edits.

• The documentation process, including the development of a “User’s Handbook,” is being 

discussed within EIA and may be available in a few years.

Attendees

Guests (in person)

Brian D. Lavoie DOE

Joe Benneche Former EIA

Pete Whitman FERC

Jose Benitez Energy Ventures Analysis

Registered Guests (WebEx/phone)

Ben Schlesinger BSA Energy

Amy Sweeney DOE

Brian D. Lavoie DOE

Yelena Dandurova Leidos

Matthew Hansen National Energy Board, Canada

Chris Doleman National Energy Board, Canada

Bill Pepper Consultant

Robert Schultz Leena Labs, Inc.
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Sauleh Siddiqui Johns Hopkins University

Felipe Feijoo Johns Hopkins University

Robert Gulliksen California Energy Commission

Niko Kydes OnLocation, Inc.

John Myer

Henan Xu Energy Ventures Analysis

Kevin Blaser Saginaw Chippewa Indian Tribe

EIA attendees (in person)

Katie Dyl (presenter)

Peter Gross

John Staub

Samantha Calkins

Ian Meade

Angelina LaRose

David Fritsch

EIA attendees (WebEx/phone)

Michael Cole

David Manowitz

Beth May

James Preciado 

Dana Van Wagener