Natural Gas Transmission and Distribution Module
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The NEMS Natural Gas Transmission and Distribution Module (NGTDM) derives
domestic natural gas production, wellhead and border prices, end-use prices,
and flows of natural gas through the regional interstate network, for both
a peak (December through March) and off peak period during each projection
year. These are derived by solving for the market equilibrium across the
three main components of the natural gas market: the supply component,
the demand component, and the transmission and distribution network that
links them. Natural gas flow patterns are a function of the pattern in
the previous year, coupled with the relative prices of the supply options
available to bring gas to market centers within each of the NGTDM regions
(Figure 8). The major assumptions used within the NGTDM are grouped into
five general categories. They relate to (1) structural components of the
model, (2) capacity expansion and pricing of transmission and distribution
services, (3) Arctic pipelines, and (4) imports and exports. A complete
listing of NGTDM assumptions and in-depth methodology descriptions are
presented in Model Documentation: Natural Gas Transmission and Distribution
Model of the National Energy Modeling System, Model Documentation 2008, DOE/EIA-M062(2008) (Washington, DC, 2008).
Key Assumptions
Structural Components
The primary and secondary region-to-region flows represented in the model
are shown in Figure 8. Primary flows are determined, along with nonassociated
gas production levels, as the model equilibrates supply and demand. Associated-dissolved
gas production is determined in the Oil and Gas Supply Module (OGSM).
Secondary flows are established before the equilibration process and are
generally set exogenously. Liquefied natural gas (LNG) imports are also
not directly part of the equilibration process, but are set at the beginning
of each NEMS iteration in response to the price from the previous iteration.
Flows and production levels are determined for each season, linked by
seasonal storage. When required, annual quantities (e.g., consumption
levels) are split into peak and offpeak values based on historical averages.
When multiple regions are contained in a Census Division, regional end-use
consumption levels are approximated using historical average shares. Pipeline
and storage capacity are added as warranted by the relative volumes and
prices. Regional pipeline fuel and lease and plant fuel consumption are
established by applying an historically based factor to the flow of gas
through a region and the production in a region, respectively. Prices
within the network, including at the borders and the wellhead, are largely
determined during the equilibration process. Delivered prices for each
sector are set by adding an endogenously estimated markup (generally a
distributor tariff) to the regional representative citygate price. Supply
curves and electric generator gas consumption are provided by other NEMS
modules for subregions of the NGTDM regions, reflective of how their internal
regions overlap with the NGTDM regions.
Capacity Expansion and Pricing of Transmission and Distribution Services
For the first 2 projection years, announced pipeline and storage capacity
expansions (that are deemed highly likely to occur) are used to establish
limits on flows and seasonal storage in the model. Subsequently, pipeline
and storage capacity is added when increases in consumption, coupled with
an anticipated price increase, warrant such additions (i.e., flow is allowed
to exceed current capacity if the demand still exists given an assumed
increased tariff). Once it is determined that an expansion will occur,
the associated capital costs are applied in the revenue requirement calculations
in future years. Capital costs are assumed based on average costs of recent
comparable expansions for compressors, looping, and new pipeline.
It is assumed that pipeline and local distribution companies build and
subscribe to a portfolio of interstate pipeline and storage capacity to
serve a region-specific colder-than-normal winter demand level, currently
set at 30 percent above the daily average. Maximum pipeline capacity utilization
in the peak period is set at 99 percent. In the off-peak period, the maximum
is assumed to vary between 75 and 99 percent of the design capacity. The
overall level and profile of consumption, as well as the availability and
price of supplies, generally cause realized pipeline utilization levels
to be lower than the maximum.
Pricing of Services
While transportation tariffs for interstate pipeline services are initially
based on a regulated cost-of-service calculation, an adjustment to the
tariffs is applied which is dependent on the realized utilization rate,
to reflect a market-based differential. Transportation rates for interstate
pipeline services (both between NGTDM regions and within a region) are
calculated assuming that the costs of new pipeline capacity will be rolled
into the existing rate base.
Delivered prices by sector and season are derived by adding a markup to
the average regional market price of natural gas in both peak and off-peak
periods. (Prices are reported on an annual basis and represent quantity-weighted
averages of the two seasons.) These markups include the cost of service
provided by intraregional interstate pipelines, intrastate pipelines, and
local distributors. The intrastate tariffs are accounted for endogenously
through historical model benchmarking. Distributor tariffs represent the
difference between the regional delivered and citygate price, independent
of whether or not a customer class typically purchases gas through a local
distributor.
The distribution tariffs are projected using econometrically estimated
equations, primarily in response to changes in consumption levels. An
assumed differential is used to divide the industrial price into one for
noncore customers (refineries and industrial boiler users) and one for
core customers who have less alternative fuel options.
The vehicle natural gas (VNG) sector is divided into fleet and non-fleet
vehicles. In general, the distributor tariffs for natural gas to vehicles
are set to EIA’s Natural Gas Annual historical end-use prices minus citygate
prices plus Federal and State VNG taxes (held constant in nominal dollars)
plus an assumed dispensing cost. Dispensing costs are assumed to be $3.93
and $2.29 (2007 dollars per mcf) for non-fleet and fleet vehicles, respectively.
Pipelines from Arctic Areas into Alberta
The outlook for natural gas production from the North Slope of Alaska is
affected strongly by the unique circumstances regarding its transport to
market. Unlike virtually all other identified deposits of natural gas in
the United States, North Slope gas lacks a means of economic transport
to major commercial markets. The lack of viable marketing potential at
present has led to the use of Prudhoe Bay gas to maximize crude oil recovery
in that field. Recent high natural gas prices seemingly raised the potential
economic viability of such a project, although expected costs have increased
as well. The primary assumptions associated with estimating the cost of
North Slope Alaskan gas in Alberta, as well as for MacKenzie Delta gas
into Alberta, are shown in Table 10.1. A calculation is performed to estimate
a regulated, levelized, tariff for each pipeline. Additional items are
added to account for the wellhead price, treatment costs, pipeline fuel
costs, and a risk premium to reflect the potential impact on the market
price once the pipeline comes on line.
To assess the market value of Alaskan and Mackenzie Valley gas against
the lower-48 market, a price differential of $0.70 (2007 dollars per Mcf)
is assumed between the price in Alberta and the average lower 48 price.
The resulting cost of Alaska gas, relative to the lower 48 wellhead price,
is approximately $5.65 (2007 dollars per Mcf), with some variation across
the projection due to changes in gross domestic product. Construction of
an Alaska-to-Alberta pipeline is projected to commence if the assumed total
costs for Alaska gas in the lower 48 States exceeds the average lower 48
gas price in each of the previous 2 years, on average over the previous
5 years (with greater weight applied to more recent years), and as expected
to average over the next 3 years. An adjustment is made if prices were
declining over the previous 5 years. Once the assumed 4-year construction
period is complete, expansion can occur if the price exceeds the initial
trigger price by $6.44 (2007 dollars per Mcf). Supplies to fill an expanded
pipeline are assumed to require new gas wells. When the Alaska to Alberta
pipeline is built in the model, additional pipeline capacity is added to
bring the gas across the border into the United States. For accounting
purposes, the model assumes that all of the Alaska gas will be consumed
in the United States and that sufficient economical supplies are available
at the North Slope to fill the pipeline over the depreciation period.
Natural gas production from the MacKenzie Delta is assumed to be sufficient
to fill a pipeline over the projection period should one be built connecting
the area to markets in the south. The basic methodology used to represent
the decision to build a MacKenzie pipeline is similar to the process used
for an Alaska-to-lower 48 pipeline, using the primary assumed parameters
listed in Table 10.1. One exception is that wellhead costs are assumed
to change across the projection period with estimated changes to drilling
costs for the lower 48 States.
Supplemental Natural Gas
The projection for supplemental gas supply is identified for three separate
categories: pipeline quality synthetic natural gas (SNG) from coal or
coal-to-gas (CTG), SNG from liquids, and other supplemental supplies (propane-air,
coke oven gas, refinery gas, biomass air, air injected for Btu stabilization,
and manufactured gas commingled and distributed with natural gas). The
third category, other supplemental supplies, are held at a constant level
of 10.3 billion cubic feet per year throughout the projection because this
level is consistent with historical data and it is not believed to change
significantly in the context of a reference case. SNG from liquid hydrocarbons
in Hawaii is assumed to continue over the projection at the average historical
level of 2.7 billion cubic feet per year. SNG production from coal at
the currently operating Great Plains Coal Gasification Plant is also assumed
to continue through the projection period at an average historical level
of 51.4 billion cubic feet per year. It is assumed that additional CTG
facilities will be built if and when natural gas prices are high enough
to make them economic. One CTG facility is assumed capable of processing
6,040 tons of bituminous coal per day, with a production capacity of 0.1
Bcf per day of synthetic fuel and approximately 100 megawatts of capacity
for electricity cogeneration sold to the grid. A CTG facility of this
size is assumed to cost over $1.05 billion in initial capital investment
(2007 dollars). CTG facilities are assumed to be built near existing coal
mines. All NGTDM regions are considered potential locations for CTG facilities
except for New England. Synthetic gas products from CTG facilities are
assumed to be competitive when natural gas prices rise above the cost of
CTG production (adjusted for credits from the sale of cogenerated electricity).
It is assumed that CTG facilities will not be built before 2012.
Natural Gas Imports and Exports
U.S. natural gas trade with Mexico is determined endogenously based on
various assumptions about the natural gas market in Mexico. U.S. natural
gas exports from the United States to Canada are set exogenously in NEMS
starting at 534 billion cubic feet per year in 2008 and increasing to 739
tcf by 2030. Canadian production and U.S. import flows from Canada are
determined endogenously within the model.
Growth rates for consumption in Mexico are set exogenously based on projections
from the International Energy Outlook 2008 and are provided in Table 10.2,
along with initially assumed growth rates for production in Mexico from
the same source. Adjustments are made endogenously within the model to
reflect a response to price fluctuations within the market. Domestic production
is assumed to be supplemented by LNG from receiving terminals constructed
on both the east and west coasts of Mexico. The difference between production
plus LNG imports and consumption in any year is assumed to be either imported
from, or exported to, United States.
Canadian consumption and production in Eastern Canada are set exogenously
in the model and are shown in Table 10.3. Production in the Western Canadian
Sedimentary Basin (WCSB) is calculated endogenously to the model using
annual supply curves based on beginning-of-year proved reserves and an
estimated production-to-reserve ratio. Reserve additions are set equal
to the product of successful natural gas wells and a finding rate (both
based on an econometric estimation). The initial coalbed methane, shale
gas, and conventional WCSB economically recoverable resource base estimates
assumed in the model for the beginning of 2004 are 70 trillion cubic feet,
30 trillion cubic feet (starting in 2010), and 92 trillion cubic feet,
respectively.1 Potential production from tight formations was approximated
by increasing the conventional resource level by 1.5 percent annually.
Production from coalbed and shale sources is established based on an assumed
production path which varies in response to the level of remaining resources
and the solution price in the previous projection year. To approximate
the impact of the average increase in the Alberta royalty rate, starting
in 2009 the price drivers (i.e., the price realize by producers) on western
Canada supply in the model were assumed to be 5 percent less than they
would have been otherwise.
Annual U.S. exports of liquefied natural gas (LNG) to Japan are assumed
to decrease from 2007 levels of 44 billion cubic feet per year through
March of 2011, when the export license expires, and cease thereafter. LNG
imports to the United States are determined endogenously within the model.
For the most part, LNG imports are set endogenously in the model based on Atlantic/Pacific and peak/off-peak supply curves derived from model results generated by EIA’s International Natural Gas Model (INGM).Prices from the previous model iteration are used to establish the total level of North American imports in the peak or off-peak and in the Atlantic or Pacific.First assumed LNG imports which are consumed in Mexico 2 are subtracted (presuming the volumes are sufficient) and the remaining levels are allocated to the model regions based on last year’s import levels, the available regasification capacity, and the relative prices. Regasification capacity is limited to facilities currently in existence and those already under construction and is fully sufficient to accommodate import levels projected by the model.
Legislation and Regulations
The methodology for setting reservation fees for transportation services is initially based on a regulated rate calculation, but is ultimately consistent with FERC’s alternative ratemaking and capacity release position in that it allows some flexibility in the rates pipelines ultimately charge. The methodology is market-based in that rates for transportation services will respond positively to increased demand for services while rates will decline (reflecting discounts to retain customers) should the demand for services decline.
A number of legislative actions have been taken to provide a more favorable environment for the introduction of new liquefied natural gas (LNG) regasification facilities in the United States. In December 2002 under the Hackberry Decision, FERC terminated open access requirements for new onshore LNG terminals,placing them on an equal footing with offshore terminals regulated under provisions of the Maritime Security Act of 2002. The Maritime Security Act, signed into law in November 2002, also amended the Deepwater Port Act of 1974 to include offshore natural gas facilities, transferring jurisdiction for these facilities from the FERC to the Maritime Administration and the U.S.Coast Guard. The result should be to streamline the permitting process and relax regulator requirements. More recently an EPACT2005 provision clarified the role of the FERC as the final decision making body on issues concerning onshore LNG facilities. While none of these legislative/regulatory actions is explicitly represented in the modeling framework,these provisions are indirectly reflected in selected model parameters.
Section 116 of the Military Construction Appropriations and Emergency Hurricane Supplemental Appropriations Act, 2004 (H.R.4837) gives the Secretary of Energy the authority to issue Federal loan guarantees for an Alaska natural gas transportation project, including the Canadian portion, that would carry natural gas from northern Alaska, through the Canadian border south of 68 degrees north latitude, into Canada,and to the lower 48 States. This authority would expire 2 years after the final certificate of public convenience and necessity is issued. In aggregate the loan guarantee would not exceed: (1) 80 percent of total capital costs (including interest during construction); (2) $18 billion dollars (indexed for inflation at the time of enactment); or (3) a term of 30 years. The Act also promotes streamlined permitting and environmental review, an expedited court review process, and protection of rights-of-way for the pipeline. The assumed costs of borrowing money for the pipeline was reduced to reflect the decreased risk as a result of the loan guarantee.
Section 706 of the American Jobs Creation Act of 2004 (H.R.4520) provided a 7-year cost-of-investment recovery period for the Alaska natural gas pipeline, as opposed to the previously allowed 15-year recovery period, for tax purposes. The provision is effective for property placed in service after 2013 (or treated as such) and is assumed to have minimal impact on the decision to build the pipeline.
Section 707 of the American Jobs Creation Act extended the 15-percent tax credit previously applied to costs related to enhanced oil recovery to construction costs for a gas treatment plant that supplies natural gas to a 2 trillion Btu per day pipeline, lies in Northern Alaska, and produces carbon dioxide for injection into hydrocarbon-bearing geological formations. A gas treatment plan on the North Slope that feeds gas into an Alaska pipeline to Canada is expected to satisfy this requirement. The provision is effective for costs incurred after 2004. The impact of this tax credit is assumed to be factored into the cost estimates filed by the participating companies.
In 2005,Section 1113 of the Safe, Accountable, Flexible, Efficient Transportation Equity Act:A Legacy for Users (SAFETEA-LU) raised the federal motor fuels tax for compressed natural gas vehicles (CNG) from 48.54 cents per Mcf to 18.3 cents per gasoline gallon equivalent (or about $1.46 per Mcf), all in nominal dollars. The same section also allows for a motor fuels excise tax credit of $0.50 per gasoline gallon equivalent to the seller through September 30, 2009. The tax rate assumed in the model was changed accordingly and assumed constant in nominal terms throughout the projection.
Section 312 of the Energy Policy Act of 2005 authorizes the Federal Energy Regulatory Commission (FERC) to allow natural gas storage facilities to charge market-based rates if it was believed that they would not exert market power. Storage rates are allowed to vary in the model from regulation-based rates, depending on market conditions.
Natural Gas Transmission and Distribution Alternative Cases
High and Low Liquefied Natural Gas Import Cases
Reference case assumptions regarding LNG imports to the U.S. reflect expectations of increasing global demand and non-competitive domestic natural gas prices relative to higher world LNG prices.
In the high LNG supply case, LNG imports to the U.S. are exogenously projected to increase over reference case levels to determine the potential impact of additional LNG imports on the U.S.natural gas market. LNG imports are set by multiplying the reference case import levels by a factor which starts at 1.0, increases linearly between 2010 and 2030, and results in an LNG import level 5 times the reference case level by 2030. LNG imports in the high LNG case reach a level that approaches the projected regasification capacity in the United States in the reference case.
In the low LNG supply case, LNG imports to the U.S.are projected to remain constant at 2009 LNG import levels from the reference case.
No Alaska North Slope Natural Gas Pipeline Case
The construction of a natural gas pipeline from the North Slope of Alaska (ANS)to the lower 48 states has been a matter of uncertainty for a number of years amidst increasing capital cost estimates and political and business concerns existing between the state government and North Slope producers.In prior AEO projections, the earliest start year for ANS pipeline transmission has generally been pushed back as these issues delay construction of the pipeline.In the AEO2009 reference case, it is projected that the ANS pipeline will begin transporting natural to the lower 48 states beginning in 2020, the earliest assumed start year.
In the No Alaska North Slope pipeline case, it is assumed that the ANS pipeline will not be built over the projection period. This results in slightly higher imports and increased domestic production.
Natural Gas Transmission and Distribution Module Notes |
