Natural Gas Module
- Authors and Contact Information:
- General Description:
- Focus of Analyses:
- Limitations of Analyses:
- Technologies of Interest to DOE:
- Overview of Methodology:
- Major Assumptions:
- PDS (Portfolio Decision Support) Inputs:
- Stochastic Inputs:
- Key Inputs from other SEDS modules:
- Key Outputs to other SEDS modules:
- Other Information:
Authors and Contact Information:
- Donald Remson, National Energy Technology Laboratory:(412-386-5379), donald.remson@…
This module is a single-region representation of the U.S. natural gas supply. The module provides a reasonable estimate of annual average sector prices in ($/Joule) for natural gas given a level of demand specified in Watts for the same sectors. The natural gas market is broken up into four sectors; residential, commercial, industrial, and electricity generation. The module uses separate algorithms to determine price/supply relationships for domestic natural gas, LNG imports, and methane hydrates. The sector demand is provided to the natural gas module by other SEDS modules.
Focus of Analyses:
The effect of demand on the price of natural gas is the primary focus of this module. The relationship of demand to price for natural gas is basically pre-defined by an input set of year specific price vs. supply curves. The price elasticity determined by these curves is modified by the operation of the proposed Alaskan natural gas pipeline, development of methane hydrates, and development of re-gasification plants for handling LNG imports.
Limitations of Analyses:
Regional, sector, and seasonal effects cannot be evaluated because the model is based on an annual nationwide value of average wellhead price. Sector prices are determined simply by multiplying the forecast wellhead price by a constant value determined by historical data. A primary limitation of the model is its inability to handle resource development and depletion. The basic price vs. supply curves are fixed at the beginning of the simulation and are not affected by the SEDS projection of demand as the simulation progresses. In reality, a high demand will spur development which increases the future supply available at a given price. Later on this high production rate will potentially bring about an earlier depletion of the resource. A low demand for natural gas will discourage drilling and lessen the ability to immediately respond to a future higher demand.
Technologies of Interest to DOE:
A component of the natural gas supply which is of special interest to DOE is the methane hydrates resource. DOE is responsible for a major portion of the funding currently allocated towards Methane Hydrates R&D. DOE is also responsible for managing projects in unconventional gas recovery as well as ultra-deep offshore gas recovery. These projects are funded by royalty collections and were mandated by Section 999 of the 2005 Energy policy act.
Overview of Methodology:
For a given timestep, the first step of the model is to read in the four natural gas sector demands from SEDS and aggregate them into a single value of dry natural gas demand. This demand is then converted into an equivalent volume of wet gas by multiplying by the factor of 1.13 which accounts for historical rates of liquid losses in wet gas conversion as well as the quantity of gas required to operate the pipeline. This value of demand is associated with an average natural gas wellhead price by performing a table lookup in an aggregated table of price vs. supply.
The aggregated price vs. supply table is created by combining three separate tables of price vs. supply which were generated by the domestic natural gas sub module, the methane hydrates sub module, and the LNG imports sub module. This average natural gas wellhead price is then converted to $/joule and converted to year 2000 dollars. It is then converted to average sector prices using multipliers of 2.3, 1.86, 1.24, and 1.15 for the residential, commercial, industrial, and electric utility sectors respectively. These multipliers were based on averages for 6 recent years of monthly data provided by EIA.
The domestic natural gas sub module is responsible for generating a range of price vs. supply data for each model timestep. The data is derived from three sets of time dependent price supply curves which were created as input to a 2007 version of Markal used by DOE for performing benefits analysis. The three sets of curves were for Alaska natural gas, Canadian imports, and domestic natural gas. The data was provided in 5 year increments from 2005 to 2050 and in 18 steps. This module consists of routines to combine the Canadian and Alaskan (consistent with the completion date of the ANGTS pipeline which is in itself a stochastic variable) price supply data to the data for the domestic natural gas production. Linear interpolation is used to create a variable which contains price data for 900 supply data points for each timestep of the simulation.
The methane hydrates model uses a pair of dynamic loops to first go from region and price based estimates of remaining economically recoverable gas to proven reserves and second from proven reserves to annual production. The module uses a finding rate multiplier to determine proven reserves based on remaining economically recoverable gas. Likewise the remaining economically recoverable gas is determined by subtracting the new proved reserves from the value of economically recoverable gas. This circular dependency is accounted for by using a dynamic loop and lagging one of the variables. Production is calculated using a Production to Reserves (PR) ratio. The cyclic dependency between reserves and production is also handled using a dynamic loop and lagging one of the variables. The resulting production is stored in a variable containing price and supply information for each timestep of the simulation.
The LNG module adds re-gasification capacity in line with increasing natural gas demand. Capacity available at any timestep is determined by initial capacity, planned utilization, average plant capacity, plant approval rate, and time to permit and build facility. LNG production is determined by capacity utilization of the available capacity. This capacity utilization increases or decreases at a fixed rate depending on whether or not natural gas LNG demand exists. The capacity utilization is subject to maximum and minimum bounds. A floor price represents the minimum price at which LNG imports will be added to the supply curve. The resulting production is stored in a variable containing price and supply information for each timestep of the simulation.
The current version of the Natural Gas Supply module is dependent on a set of price-supply vs. time data used as input to a MARKAL model used by DOE for benefits analysis. These curves originated from a set of assumptions applied to the AEO2007 reference case forecast. Work is currently ongoing to develop a better approach for modeling the price-supply relationship for domestic natural gas production. Specifically we are working on development of a method for generating price supply curves which would be more conducive to a stochastic analysis. The input MARKAL price supply curves are used for domestic production, Alaskan production, and Canadian imports.
The methane hydrates model relies on an input table of economically recoverable resource vs. price for the hydrate regions. This data will be obtained from a methane hydrates benefits module which is currently under development at this time. Regional values of hydrates finding rates, starting year of development, and reserves to production ratios will be provided by expert judgment. Likewise, the LNG module will require expert judgment in assigning inputs such as re-gasification plant capacities, approval rates, build times, utilization rates and limits. Residential, Commercial, Industrial, and Electric Generation prices are determined by multiplying the average well head price by 2.3, 1.86, 1.24, and 1.15 respectively.
PDS (Portfolio Decision Support) Inputs:
At the present time there are no plans for including PDS inputs in the Natural Gas Supply module, although it may be possible to incorporate various levels of economically recoverable methane hydrates resource as a result of various levels of government sponsored R&D.
The Natural Gas supply module has numerous stochastic inputs, especially in the methane hydrate and LNG modules. The following is a list of the stochastic variables currently incorporated in the module.
- Natural Gas Price Uncertainty Factor
- Year in which ANGTS Pipeline Opens
- Alaska Hydrates Reserves Multiplier
- Year in which Alaska Hydrates Development Begins
- Alaska Hydrates Finding Rate
- Alaska Hydrates Reserves to Production Ratio
- Offshore Hydrates Reserves Multiplier
- Year in which Offshore Hydrates Development Begins
- Offshore Hydrates Finding Rate
- Offshore Hydrates Reserves to Production Ratio
- Maximum New LNG Re-gasification Capacity
- Planned Re-gasification Capacity Utilization
- Re-gasification Average Plant Capacity
- Re-gasification Plant Approval Rate
- Re-gasification Permitting and Building Lag Time
- Re-gasification Initial Capacity Utilization
- Re-gasification Maximum Capacity Utilization
- Re-gasification Minimum Capacity Utilization
- Annual Utilization Rate Adjustment
- LNG Floor Price
Key Inputs from other SEDS modules:
- Residential Sector Natural Gas Demand (Watts)
- Commercial Sector Natural Gas Demand (Watts)
- Industrial Sector Natural Gas Demand (Watts)
- Electricity Generation Sector Natural Gas Demand (Watts)
Key Outputs to other SEDS modules:
- Residential Sector Natural Gas Price ($/J)
- Commercial Sector Natural Gas Price ($/J)
- Industrial Sector Natural Gas Price ($/J)
- Electricity Generation Sector Natural Gas Price ($/J)
Not available at this time