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August 07, 2012

MEMORANDUM FOR: JOHN CONTI

ASSISTANT ADMINISTRATOR FOR ENERGY 

ANALYSIS

 ANGELINA LAROSE

TEAM LEADER

NATURAL GAS MARKETS TEAM

JOHN STAUB

TEAM LEADER

EXPLORATION AND PRODUCTION TEAM

FROM: EXPLORATION AND PRODUCTION and NATURAL GAS 

MARKETS TEAMS

SUBJECT: First AEO2013 Oil and Gas Working Group Meeting Summary 

(presented on 07-31-2012)

Attendees:

Anas Alhajji (NGPTRS) via WEBEX

Sara Banaszak (ExxonMobil) via WEBEX

Stephen Beck (PFC Energy) via WEBEX

Sandeep Bhakhri (EOG Resources) via WEBEX

Kara Callahan (OnLocation, Inc.) via WEBEX

Evelyn Dale via WEBEX

Aloulou Fawzi (EIA) via WEBEX

Michelle Foss (Univ of Texas, Houston) via WEBEX

Tim Grant via WEBEX

Gurcan Gulen (Univ of Texas, Austin) via WEBEX

Bob Hugman (ICFI) via WEBEX

Eric Kuhle via WEBEX

Beth Lau (CAPP) via WEBEX

Carol Lenox (EPA) via WEBEX

David Schmalzer (cox.net) via WEBEX

Charlie Sheppard (EOG Resources) via WEBEX

Peter Balash (NETL) via WEBEX

Joseph Dipietro (NETL) via WEBEX

Ken Kern (NETL) via WEBEX

Gavin Pickenpaugh (NETL) via WEBEX

Charles Zelek (NETL) via WEBEX

Justine Barden (EIA)

Joe Benneche (EIA)
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Geoffrey Brand (API)

Philip Budzik (EIA)

David Daniels (EIA)

Cory Gill (Goldwyn Global Strategies)

Ehsan Khan (FE)

Angelina LaRose (EIA)

Taylor Malone (adv-res)

Phyllis Martin (Self)

Moses McCall (EIA Intern)

Chetha Phang (EIA)

John Pyrdol (FE)

Jeff Quigley (EVA)

David Shin (API)

John Staub (EIA)

Peri Ulrey (NGSA)

Dana Van Wagener (EIA)

Jose Villar (EIA)

Presenters: Phil Budzik, Dana Van Wagener, Joe Benneche

Presentation: The presentation provided an overview of the primary assumption changes under 

consideration for AEO2013 in the Oil and Gas Supply Module (OGSM) and the Natural Gas 

Transmission and Distribution Module (NGTDM). For offshore oil and gas supply modeling

the following was presented: the schedule for new leasing in currently restricted areas, key 

assumptions on deepwater projects already discovered, and technically recoverable resources by 

region. For enhanced oil recovery (EOR) modeling the following assumptions were presented: 

the level of recoverable EOR resources by recovery method and price, CO2 availability by source 

type, and the location of current and potential CO2 EOR projects. The majority of the discussion 

was on the setting of and values to be used for the estimated ultimate recovery levels for 

continuous plays. For the NGTDM the discussion topics included: the move from basing the 

model on wellhead prices to spot prices, the new set of assumptions for pricing natural gas for 

vehicles, and the modeling and assumptions related to endogenously representing LNG exports 

of domestically produced natural gas. We mentioned that we are on a much reduced schedule 

this year and did not propose additional runs or Issues and Focus articles, but still asked for 

suggestions. Most of the non-clarifying questions and comments follow, with a summary of our 

responses:

Questions and answers regarding the OGSM:

1) What are you projecting different this year for oil production in Alaska, particularly 

offshore?

EIA response: There is no change from AEO2012 because there has been no new 

information regarding the oil and gas resource potential of offshore Alaska. However, 

if Shell were to discover a large oil field under the gas at the Berger prospect, then EIA 
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would re-evaluate the prospects for finding larger offshore Alaska oil fields than are 

currently represented in the model.

2) For tight oil and shale gas well decline rates, are you spot checking with producers or 

looking at actual data?

EIA response: EIA analyzes actual production data on a well-by-well basis. However, 

wells with less than 6 data points are eliminated from the analysis because the shape of 

the decline curve over the long-term cannot be specified with any certainty with only a 

few data points.

3) How are you dealing with lags in reporting of production data? 

EIA response: For shale gas production we use Lippman Consulting’s analysis to 

estimate dry shale gas production for key plays in the United States and for the total 

U.S. For all other oil and natural gas production at the well level we rely on data 

gathered by HPDI Inc and state governments. State governments vary in the timeliness 

of the data that they provide to the public. Because there is nothing EIA can do 

regarding the State reporting delays, all EIA can do is ensure that it is using the latest 

data that has been made available to the public by the States.

4) How are lease condensates and Associated Dissolved (AD) natural gas accounted for?

EIA response: Lease condensates are included with crude oil. AD gas (i.e. gas from oil 

wells) is included in the natural gas production. Likewise, liquids from wells classified 

as natural gas wells are put in the “natural gas plant liquids” category.

5) Are you distinguishing kerogen?

EIA response: Yes, “oil shale” that is produced from kerogen is treated separately in the 

model from “shale oil” which EIA refers to as “tight oil” because of the frequent 

confusion in names. We do not foresee any large-scale production of oil shale from

kerogen during the AEO time horizon because of the short payback period and high 

rates of return on tight oil wells, relative to the large investments, long time delays, and 

low rates of return associated with oil shale production from kerogen.

6) Do your EURs make a distinction between horizontal and vertical wells, how do you 

reflect what has been occurring? The different types shouldn’t be mixed. What is the 

mix of well types (vertical/horizontal/directional)?

EIA response: EIA analyses the vertical and horizontal well production data separately.

In modeling future year drilling activity, EIA assumes that the type of wells drilling in 

future will reflect the current mix of horizontal and vertical wells being drilled today.

7) Are you including proved shale gas in these numbers?

EIA response: Not in this presentation. The EIA proved oil and gas reserves report will 

be coming out soon. The EIA models will be updated to reflect the latest EIA oil and 

gas reserve volumes.

8) A lot of other people are showing a much higher TRR, how does your view differ, what 

is the justification?
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EIA response: EIA’s TRR estimates are based on existing well production profiles. 

TRR estimates give a context for the relative magnitude of the resource base, but there 

is a lot of uncertainty regarding these estimates. EIA’s TRR estimates will change as 

new well production data becomes available. In the AEO2012, EIA ran sensitivity 

cases to explore the impact of different resource sizes on future oil and gas production, 

consumption, and prices. EIA’s modeling efforts are primarily focused on the 

economics of producing oil and gas, which doesn’t focus on TRR per se, but rather on

well production curves and well drilling and completion costs. EIA’s ultimate 

responsibility in the Annual Energy Outlook is to project the equilibrium of production,

consumption, and prices. To do that, EIA models the competition between individual 

wells across all of the resource types and petroleum basins on a discounted cash flow 

basis.

9) If USGS does an assessment do you use it?

EIA response: When the USGS makes their continuous resource assessment data 

available, EIA uses as much of it as possible, including: the areal extent of the 

formation, well spacing, percent of the total area that has potential, etc. The primary 

obstacle has been that the USGS has not published much of its detailed assessment 

data. 

10) What well spacing do you use and how is it derived?

EIA response: Well spacing is specific to each formation and depends on information 

obtained directly from producer reports and presentations and from the USGS oil and 

gas resource assessments, when this data is available.

11) Have you incorporated the new information that has come out recently regarding the 

Bakken formation being potentially more gas prone?

EIA response: The large continuous formations are divided into subregions. The wells 

within each subregion are assigned an average oil-gas ratio, based on the average oilgas ratio determined for the existing wells producing within that region.

12) What made the Niobrara area TRR increase from last year’s AEO? Are you seeing 

lower EURs but higher TRRs in the Bakken and Niobrara?

EIA response: For the continuous formations, TRR estimates are primarily a function 

of the formation’s areal, well spacing, and well EUR. The change in the Niobrara’s 

TRR was largely due to expanding the areal extent of the Niobrara, which is found in 

many of the Rocky Mountain petroleum basins.

13) Do the Deep Bossier play well decline curves fall off rapidly?

EIA response: In the OGSM model, the Deep Bossier tight gas and the adjacent 

Haynesville gas shale play are treated as a single formation. Wells in both formations 

exhibit a rapid decline in gas production rates after high initial production rates. So an 

average well decline profile is used for the combined formations, which has a high 

initial production rate followed by a rapid decline.
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14) How are you incorporating the variations over time regarding well drilling and 

completion costs?

EIA response: Historically, changes in well drilling and completion costs have 

followed the changes in oil and gas prices. The OGSM model reflects this historical 

relationship, wherein the model’s well drilling and completion costs are both a function 

of oil and gas price levels and the well design (e.g., vertical depth, length of the 

horizontal lateral, and the number of fracturing stages). 

15) Are average EURs really representative?

EIA response: Average well EURs are representative of the existing wells within the 

each formation’s subregion. During the AEO2013 cycle, EIA will be examining the 

EUR variation within each continuous formation to better refine the number and areal 

extent of the subregions within each formation, so that regional variation in well EUR 

is better represented in OGSM.

16) Does using the total population of wells cause EURs to be artificially low (including 

dry holes)?

EIA response: Generally, using the total population of wells to derive EURs provides 

the best representation of what producers are likely to witness when drilling new wells. 

Dry-holes, however, are not explicitly represented within the model because they do 

not result in a production decline curve, and consequently, are not used in generating an 

average well production decline curve that is the basis for determining an average EUR.

17) It would be helpful to see a supply curve showing how much resource would be 

available at what cost.

EIA response: Supply curves are a static representation of what is a very dynamic 

situation. Drilling and completion costs change not only due changes in technology

and management practices, but also reflect a specific oil and gas price level. Another 

conundrum associated with such curves is the co-production of oil, gas, and NGL, and 

the assignment of drilling and completion costs to each product. This is a critical issue 

because oil, gas, and NGL are frequently co-produced by a well. Although a supply 

curve might be interesting, it could also be misleading due to the numerous 

assumptions that are required to generate such a curve.

18) With such low EURs, could it reflect the many nonperformers and should it? Some of 

these seem to be too low to be economic.

EIA response: Within continuous formations, neighboring well production rates can 

vary by as much as a factor of three. Studies of Barnett gas wells indicate that at gas 

prices of around $7/MMBtu as many as 20% of the wells might have been unprofitable. 

Even so, the unprofitable wells will be produced so long as their revenues exceed 

operating costs; consequently, few such wells are plugged and abandoned early. 

Producers drill new wells based on an expected average EUR knowing that if they drill 

a large enough number of wells over time they will realize recovery rates that are 

consistent with the average EUR.
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19) Does drilling to hold leases lead to too many dry holes or nonperforming wells and 

push down EURs? Do producers abandon marginal acreage and return back to sweet 

spots? How would that be captured? 

EIA response: Drilling to hold leases should not significantly affect the average well 

EUR. If a producer drills leasehold acreage that proves to be unproductive and 

unprofitable, the producer has no financial incentive to drill many wells in that acreage. 

In contrast, producers have a large financial incentive to drill the greatest number of 

wells where they expect to realize the highest production rates and profits. 

Consequently, it would be expected that only a small proportion of the total wells 

drilled in a formation would be deliberately drilled in unproductive and unprofitable 

acreage and this small proportion would have a correspondingly small impact on the

average EUR.

20) Good idea to be more explicit about assumptions that are erring on the conservative 

side. What is the benefit of being conservative?

EIA response: EIA’s methodology of determining average well EURs is based on 

existing well production performance. As such, this methodology neither under 

estimates nor over estimates a formation’s productive potential, based on what is 

known today. Although these estimates might be viewed in the future as being 

conservative due to future improvements in technology and management practices, it 

would be inappropriate to assume a more optimistic approach to estimating well EURs 

and formation TRRs that might not be realized in the future.

21) In a future workshop, the group would like to see how model makes the linkage to 

profitability. How does the model pull in prices and costs? At what point do 

technically recoverable resources become economic? 

EIA response: The EIA energy models are fully documented and that documentation is 

available on the EIA website for those parties who are interested in better 

understanding the interrelationship between oil and gas resources, their production 

costs, and the development of new productive capacity.

22) Where do side case topics come from? Congress? Suggest something on relationships 

between natural gas and NGL volumes across plays, as well as infrastructure issues 

(gas and NGL).

EIA response: Generally, the EIA performs side cases on those attributes of the model 

that have the greatest uncertainty (e.g., continuous oil and gas resources) or the greatest 

potential impact. Some side cases are performed with respect to proposed changes in 

Federal law, policy, and regulation that have not been enacted.

Questions and answers regarding the NGTDM:

1) Is EIA modeling the situational relationships of natural gas vehicles and natural gas 

stations? For example, is EIA modeling designated natural gas transportation corridors, 

such as the Texas Clean Energy Triangle?

EIA response: Neither fueling infrastructure nor “transportation corridors” are explicitly 

modeled in NGTDM. In NGTDM, costs associated with fueling infrastructure are 
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included in the retail markup of the natural gas vehicle fuel price. EIA bases this markup 

off the capacity, utilization, capital costs and operating costs for an “average” station. 

2) Although EIA’s equation for estimating the market price of natural gas in Europe and 

Japan seems to be “on the right track” and “a good idea”, the most critical factor in that 

equation seems to be the flexible LNG. For your estimated natural gas market price for 

Europe and Asia, where are you getting the flexible LNG data?

EIA response: EIA is reviewing publicly available information regarding LNG contract 

ending dates, as well as analyzing industry reports on the levels of flexible LNG 

historically/currently traded. EIA will consider these factors and use analyst judgment. 

3) Particularly in the European market, seasonality plays an important role in market prices. 

For your estimated natural gas market price for Europe and Asia, are you looking at those 

markets on monthly or annual basis? 

EIA response: In the statistical analysis that helped define the equation, EIA used 

monthly data. However, in the NGTDM model, the equation will be run based on annual 

data.

4) For the assumed LNG transportation rates, are you factoring in the cost of the Suez Canal 

toll for your rates from the Northeast United States to Japan?

EIA response: EIA’s estimated LNG transportation costs take into consideration the Suez 

Canal toll, as well as the added travel costs if a tanker did not pass through the Canal.

5) Have we considered adjusting are Mexican exports, which could grow substantially?

EIA response: EIA was not planning on making any significant changes to our basic 

modeling approach and assumptions for Mexican exports for AEO2013, but we’ll take a 

closer look.