Estimating the Impact of the Atlantic Sunrise Project
on Natural Gas Consumers
Final Report
Andrew Kleit
Chiara Lo Prete
Seth Blumsack
Nongchao Guo
Kyungjin Yoo
John and Willie Leone Family Department of Energy and Mineral Engineering
The Pennsylvania State University
January 13, 2015
Acknowledgement: This report is an account of work sponsored by Williams Partners L.P.
(“Williams”). The study’s authors acknowledge that Williams provided financial support for the
analysis contained herein.
Contact author:
ank1@psu.edu.
Andrew N. Kleit, Professor of Energy and Environmental Economics,
EXECUTIVE SUMMARY
New production of natural gas in the Marcellus region of Pennsylvania has created
tremendous opportunities to benefit consumers of natural gas in the United States. Unfortunately,
the ability of this new production to create benefits is limited by the scarcity of pipeline capacity
out of the Marcellus region. To address this issue, Williams’ wholly owned subsidiary,
Transcontinental Gas Pipe Line Company, LLC (“Transco”), has proposed to expand its pipeline
through the Atlantic Sunrise project.
We seek to understand the market impact of the Atlantic Sunrise expansion by estimating
the changes in equilibrium prices, demand and supply along the Transco pipeline that would
result after the completion of the project. In this report, we construct a model assessing the
impact of Atlantic Sunrise on flows, injections, withdrawals and natural gas prices along the
Transco mainline from Alabama to New Jersey, using data from 2012 to the middle of 2014. In
turn, this will provide insights on how this project will impact natural gas consumers on the
eastern seaboard of the United States.
The Atlantic Sunrise project would affect operation of the Transco pipeline system in two
ways. First, it would permit additional deliveries from the Marcellus to markets on the Transco
system. Second, it would afford more flexibility to the Transco system, with the ability to
accommodate flow reversals in response to market conditions. In particular, the Atlantic Sunrise
project will allow gas to flow southward from the Pennsylvania-Maryland-New Jersey Region
into Virginia and further]south.
1
We have modeled the market impact of the Atlantic Sunrise project on flows and prices
across the Transco system, focusing on the impact in three geographic areas: PennsylvaniaMaryland-New Jersey; Virginia, North Carolina and South Carolina; and Alabama and Georgia.
Over the 30-month period examined in our study, we estimate that consumers served by Transco
from Alabama to New Jersey would have enjoyed about $2.6 billion in total benefits because of
the Atlantic Sunrise expansion. These benefits accrue due to lower prices and the opportunity for
additional natural gas consumption (which is itself partially a consequence of lower prices).
While we estimate that consumers would greatly benefit overall from Atlantic Sunrise, we wish
to emphasize some specific aspects of our findings.
First, the benefits to consumers are not uniform over time and will vary greatly with
system conditions. As Table 5.6 shows, more than 60% of the estimated benefits of Atlantic
Sunrise in our period of study would have accrued in January 2014 alone, because of the high
level of gas demand associated with the polar vortex in that month. This finding in particular
needs to be projected forward with care. Consumer benefits during the wintertime will generally
be higher than in other seasons because of increased heating demand, but we estimate that these
benefits would be roughly six to twenty times larger during very cold winters than during normal
winters. If wintertime natural gas demand rises (due to cold weather, increased demand from
power plants or other factors), this will magnify the consumer benefits of Atlantic Sunrise.
Similarly, if very cold winters become relatively uncommon, the consumer benefits of Atlantic
Sunrise will be correspondingly smaller over time.
Second, the benefits to consumers are not uniform over geographic areas. Consumers
from Alabama to Virginia would be the recipients of additional Marcellus gas flowing south due
to Atlantic Sunrise, and would nearly always benefit from the pipeline expansion project.
Because of the location of the constraints on the Transco system, we estimate that Virginia-North
Carolina-South Carolina customers would benefit nearly three times as much as AlabamaGeorgia customers. Pennsylvania-New Jersey-Maryland customers exhibit the highest benefits
overall (across our 30-month estimation period), but will also be harmed during certain periods
when exports from this region to Virginia cause prices north of Virginia to increase. These price
increases, however, are far smaller than the price decreases that would occur due to Atlantic
Sunrise during severe winter periods.
2
I.
Introduction
New production of natural gas in the Marcellus region of Pennsylvania has created
tremendous opportunities to benefit consumers of natural gas in the United States. Unfortunately,
the ability of this new production to create benefits is limited by the scarcity of pipeline capacity
out of the Marcellus region. To address this issue, Williams has proposed to expand its Transco
pipeline through the Atlantic Sunrise project.
We seek to understand the market impact of the Atlantic Sunrise expansion by estimating
the changes in equilibrium prices, demand and supply along the Transco pipeline that would
result after the completion of the project. In this report, we construct a model assessing the
impact of Atlantic Sunrise on flows, injections, withdrawals and natural gas prices along the
Transco mainline from Alabama to New Jersey, using data from 2012 to the middle of 2014. In
turn, this will provide insights on how this project will impact natural gas consumers on the
eastern seaboard of the United States.
In Section II of this report we describe the challenges posed by new sources of natural
gas and how the Atlantic Sunrise project helps address those challenges. Section III presents our
basic model, which includes arbitrage conditions, demand and supply elasticities, and the
different equilibrium prices and flows at various points on the Transco system that can result
from the Atlantic Sunrise expansion. Section IV examines the relevant flows and prices on four
different days, one from each season, had Atlantic Sunrise been operational on those days.
Section V presents the benefits Atlantic Sunrise would have had on natural gas consumers on the
Atlantic seaboard from 2012 to the middle of 2014. Section VI contains our conclusions.
II.
The Atlantic Sunrise Project
A. The Challenge of New Sources of Natural Gas
In 1990, 52 percent of electricity in the U.S. was produced from coal and 12 percent from
natural gas. By 2013, the share of coal had decreased to 39 percent, while that of natural gas had
increased to 28 percent.1 There are two main reasons for this change. First, the use of natural gas
as an input for electric power generation provides significant environmental benefits: in addition
to about half of coal’s greenhouse gas emissions per unit of energy, natural gas has significantly
lower traditional air pollutant emissions (nitrogen oxides and sulfur dioxides) than coal. Natural
gas demand in the electricity sector is expected to further increase in the future, partly due to
tightening environmental restrictions on the use of coal for power generation.2 The use of natural
gas as a transportation fuel has also been on the rise over the past ten years, though it still
remains a negligible fraction of U.S. total consumption.3
1
U.S. Energy Information Administration, http://www.eia.gov/electricity/data.cfm#generation.
In June 2014, the Environmental Protection Agency proposed Clean Air Act rules to reduce
carbon emission from fossil-fueled U.S. power plants by 30% by 2030, relative to their 2005
level. See http://www2.epa.gov/carbon-pollution-standards/what-epa-doing.
3
U.S. Energy Information Administration,
http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm.
2
3
Second, the new supply of natural gas has lowered natural gas prices in the U.S. Figure
2.1 shows the price of natural gas in the United States from 1998 to 2012. Starting in 1998, the
price of gas rose from near $2 per million BTU (MMBtu) to $8 in 2008. After that time,
however, the price of natural gas fell rapidly, with wellhead prices falling below $3 per MMBtu
in 2012. One of the most important reasons for this is the new production of gas from
“unconventional” sources.
Figure 2.1 U.S. Natural Gas Wellhead Price (1998-2012)
Source: EIA (2014), http://www.eia.gov/naturalgas/data.cfm#prices
There are three types of unconventional gas: tight gas trapped underground in
impermeable rock formations, shale gas from shale source rock, and coal bed methane (CBM)
from coal source rock. This unconventional gas has been developed vigorously since the mid2000s thanks to the widespread use of hydraulic fracturing and horizontal drilling. (See, for
example, Hefner (2014).) Hydraulic fracturing involves the injection of water, sand and other
chemicals at high pressures to fracture hydrocarbon-bearing formations, releasing oil and gas.
Horizontal drilling enables the recovery of larger hydrocarbon volumes with a smaller surface
footprint, enabling higher recovery in hard-to-reach areas or locations where obtaining surface
rights is prohibitive.4
4
See Energy Information Administration , “The Geology of Natural Gas Resources,” 2014,
http://www.eia.gov/todayinenergy/detail.cfm?id=110.
4
In terms of unconventional gas basins, there are seven major shale gas and/or oil
production areas: Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian, and Utica
(Figure 2.2). These regions made up the growth in U.S. natural gas production during 2011-13.5
Figure 2.2 U.S. Lower 48 States Shale Plays
Source: EIA (2011), http://www.eia.gov/oil_gas/rpd/shale_gas.pdf
Figure 2.2 depicts the major basins for U.S. unconventional energy production. In the
early days of shale gas development, the Barnett shale in Texas was the largest producer of shale
gas with over 4 million MMBtu per day. Since 2012, the Marcellus formation has yielded major
new gas supplies in the U.S. Mid-Atlantic region. In 2013, the Marcellus produced 9.2 million
MMBtu per day, contributing 13 percent of total U.S. natural gas supply.6
The Marcellus Shale formation underlies significant portions of Pennsylvania, West
Virginia, New York, eastern Ohio and other parts of eastern North America. It can be found
Energy Information Administration, “Drilling Productivity Report,” August 2014,
http://www.eia.gov/petroleum/drilling/archive/dpr_aug14.pdf.
6
See
http://stateimpact.npr.org/pennsylvania/2014/02/19/pennsylvania-shale-productioncontinued-to-grow-in-2013/.
5
5
beneath about 60 percent of Pennsylvania’s total land mass, occurring as deep as 9,000 feet
below ground surface.7 (See Figure 2.3.)
A few thousand feet below the Marcellus underlying Ohio, Pennsylvania, West Virginia,
New York, and Quebec, there exists another organic-rich rock unit named Utica shale.8 Currently,
the Utica Shale is receiving attention with a fast growth rate in energy production. It produced an
estimated 1.3 million MMBtu per day in September 2014. In addition, the Utica play has a
greater percentage of production from more profitable petroleum resources than the Marcellus.9
Figure 2.3 Depth of Marcellus Shale Base
Source: Penn State Marcellus Center for Outreach and Research,
http://www.marcellus.psu.edu/images/Marcellus_Depth.gif
More than 90 percent of the natural gas consumed in the U.S. is produced domestically.10
For decades, the focal point of natural gas production has been the U.S. Gulf Coast region.
Natural gas transmission pipelines were designed and built to accommodate one-directional gas
flow from the Gulf Coast area to the high-demand energy markets in the U.S. Southeast and
7
Penn State Marcellus Center for Outreach and Research, MCOR, 2014,
http://www.marcellus.psu.edu/resources/maps.php.
8
“Utica Shale,” Geology News and Information, 2014, http://geology.com/articles/utica-shale/.
9
“Drilling Productivity Report,” Energy Information Administration, Aug 2014,
http://www.eia.gov/petroleum/drilling/pdf/dpr-full.pdf).
10
See http://naturalgas.org/business/supply/ and International Energy Agency, 2013.
6
Northeast. One of the largest of these pipelines, Transco, ships gas from the Gulf Coast to New
York City. Transco is designed to deliver up to 11.2 million MMBtu per day of natural gas on a
firm basis, and is crucial to maintaining natural gas supplies to distribution companies, industry
and power plants. Bottlenecks on the Transco system have traditionally occurred during the
winter, due to excess demand relative to available firm capacity.
As noted above, over the past ten years the widespread use of horizontal drilling and
hydraulic fracturing has allowed access to major natural gas deposits captured in shale
formations in the Northeastern U.S. In particular, the Marcellus Shale formation in the northern
Appalachian basin, in large part below the state of Pennsylvania, is rich in natural gas resources.
Despite the existence of significant resources in close proximity to strong areas of natural gas
demand in Southeastern and Northeastern states, natural gas pipeline capacity from Pennsylvania
is severely constrained. This lack of pipeline capacity, in Pennsylvania and several other regions
in the country, limits the potential economic gains from the extraction of unconventional gas.
(See Joskow, 2013.)
The lack of sufficient pipeline infrastructure has also induced price separation between
Pennsylvania and the surrounding states. 11 The impacts of gas transmission constraints were felt
particularly hard in the winter of 2014, when prices in surrounding states surpassed
$100/MMBtu, while gas prices in Pennsylvania remained at less than one-tenth these levels. (See
Figure 2.4 below.) In turn, low prices in Pennsylvania have economically constrained the
completion of new Marcellus wells. Delivery constraints from limited transmission capacity also
contributed to electric reliability issues during the “polar vortex” period in the Mid-Atlantic
during January 2014.12 There are reports that only about half of the Marcellus wells being drilled
in Pennsylvania are being completed. These economic constraints are particularly acute in the
Northern Tier region of Pennsylvania, which produces primarily dry gas.13
11
See, for example, Energy Information Administration, “Some Appalachian natural gas spot
prices are well below the Henry Hub national benchmark, October 15, 2014,
http://www.eia.gov/todayinenergy/detail.cfm?id=18391.
PJM Interconnection, LLC. “Analysis of Operational Events and Market Impacts During the
January 2014 Cold Weather Events,” May 8, 2014. Available online at
http://www.pjm.com/~/media/documents/reports/20140509-analysis-of-operational-events-andmarket-impacts-during-the-jan-2014-cold-weather-events.ashx.
13 See Andrew Maykuth, “Natural-gas prices force down number of Marcellus drilling rigs,”
Philadelphia
Inquirer,
July
2,
2012,
http://articles.philly.com/2012-0708/business/32589447_1_natural-gas-prices-drilling-natural-gas. “Dry gas” is in contrast to “wet”
gas, which is extracted with a variety of valuable associated products besides natural gas.
12
7
Figure 2.4
Natural Gas Prices per MMBtu on January 22, 2014
Source: http://atlanticsun.wpengine.com/
B. Addressing the Challenge: The Atlantic Sunrise Project
On the Transco system, bottlenecks have historically occurred in three different areas.
First, the Leidy Line from the Marcellus region eastward into New Jersey is typically constrained,
limiting flows of gas out of Pennsylvania. Indeed, the operations data we have reviewed indicate
that this line is almost always constrained. Second, Transco currently restricts southward flow
south of Transco Station 195 (located near the borders of Pennsylvania, Maryland and Delaware).
During the summer this can be an important constraint, due to increased power generation
demand to support air-conditioning load in mid-Atlantic states. We thus observe that during the
summer, natural gas prices can often be greater south of station 195 than north of 195. Finally,
there is often a bottleneck on the Transco system east of station 90 in Alabama, which precludes
more gas from flowing northward, and causes prices to rise at points north and east of
Alabama.14
The first two of these constraints in particular have contributed to gas supplies (both
conventional and unconventional) being “stranded” in Pennsylvania, because transportation
capacity is insufficient for much of that gas to reach customers outside of Pennsylvania. The
stranding of gas supplies reduces production incentives and in extreme cases (such as the polar
vortex) can have cascading impacts on other infrastructures, such as the electricity grid.
14
Historic data on flow constraints on the Transco system can be found at:
http://www.1line.williams.com/Transco/index.html.
8
To overcome pipeline capacity constraints and help relieve Pennsylvania’s stranded gas
problem, Williams has proposed the Atlantic Sunrise project. The project goal is to expand and
reverse the flow on part of the Transco pipeline, thus relieving the southbound bottleneck at
Station 195. Atlantic Sunrise includes three components, presented in Figure 2.5:
1) The installation of two greenfield pipelines, the Central Penn Line North (55.79 miles
of 30-inch pipe from compressor station 517 to Susquehanna County) and the Central
Penn Line South (120.98 miles of 42-inch pipe from compressor station 517 to
Lancaster county, above station 195). The new lines will connect the Marcellus shale
region to the Transco mainline near Station 195 in southeastern Pennsylvania. The
Central Penn Line will provide 1.7 million MMBtu/day of additional natural gas
transportation capacity to markets in the Mid-Atlantic and Southeast of the U.S. The
increased system capacity associated with this expansion has already been allocated
to market participants via contracts that are typically 20 years in duration.
2) The expansion of existing capacity of the Transco Leidy Line in the Marcellus region,
running across the northern tier of Pennsylvania,
3) Pipeline replacements, construction of new compressor facilities, facility
modifications and upgrading in five states, at various points on the Transco mainline.
These additions and modifications will allow gas to flow bi-directionally on the main
line. In particular, it is expected that the pipeline flow will often be reversed south of
Station 195, allowing Marcellus gas to be supplied to customers in the Mid-Atlantic
and Southeastern states. In turn, this will reduce the price of natural gas in these
regions.
Field surveys for the Atlantic Sunrise project began in Spring 2014. Williams is also
seeking federal and state approval for the expansion. Compressor and pipeline construction is
expected to start in 2016, while the project is scheduled for completion by the third quarter of
2017. The analysis in this report focuses on how the Atlantic Sunrise expansion would impact
natural gas prices along the Transco mainline – this corresponds to estimating the market impact
of the second and third elements of the Atlantic Sunrise project.
9
Figure 2.5. Atlantic Sunrise Project
Source: Williams, http://atlanticsunriseexpansion.com/
C. Other natural gas pipeline expansion projects to the East Coast and MidAtlantic regions
Some of Williams’ competitors have also proposed (or are currently developing) pipeline
projects to alleviate capacity constraints in the Marcellus production area. Our focus in this
section is on proposed expansions carrying natural gas from Pennsylvania to markets along the
East Coast and in the Mid-Atlantic region of the U.S.
Owned by Columbia Pipeline Group (CPG), Columbia Gas Transmission is a major
interstate natural gas system in the Northeast, and extends to the Midwest and Southeast regions.
It consists of nearly 12,000 miles of transmission pipeline and can deliver up to 9.4 million
MMBtu per day of natural gas. Its East Side Expansion project 15 involves upgrading and
expansion of existing pipeline and compression facilities on the east side of the Columbia Gas
Transmission line in Pennsylvania, to transport Marcellus shale gas to the Northeast and Mid-
15
Columbia Pipeline Group, https://www.columbiapipelinegroup.com/current-projects/east-sideexpansion-project
10
Atlantic markets. Pending regulatory approval, construction should begin in early 2015; the
expansion is expected to be in service by the end of 2015.16
Spectra Energy owns and operates the Texas Eastern Transmission line, which runs for
about 9,000 miles from the Gulf Coast to the Northeast, and can transport up to 8.5 million
MMBtu per day of natural gas. The Texas Eastern Appalachia to Market 2014 (TEAM 2014)
Project plans to expand existing capacity on the Texas Eastern Transmission line by
approximately 600,000 MMBtu per day, via the addition of new lines (“looping”) and the
installation of new compressor units. The project was authorized by FERC in February 2014, is
currently under construction and is expected at this writing17 to be in service in November 2014.
Texas Eastern has also conducted an “open season” to solicit interest in the Access South project,
delivering up to 320,000 MMBtu/day from the Appalachian region to markets in the Southeast
by the end of 2017. Moreover, Spectra has recently announced plans to build a new underground
pipeline, the Spectra Energy Pipeline project, carrying up to 1 million MMBtu per day of
incremental capacity from Pennsylvania to the Mid and South Atlantic regions by the end of
2018.18
Tennessee Gas Pipeline (TGP), a subsidiary of Kinder Morgan Energy Partners, is a
13,900-mile line shipping natural gas from the Gulf Coast area to the Northeast. Through its
Rose Lake Project,19 TGP plans to expand the capacity of its 300 Line from the Appalachian and
Marcellus region to the northeastern U.S. by about 230,000 MMBtu per day. The project
received FERC approval in September 2013 and should be brought into service by November
2014. TGP has also proposed the Niagara Expansion project20 to transport additional natural gas
16
In addition to the East Side Expansion project, CPG has proposed a West Side Expansion
project, consisting of two components. The Gulf Bi-Direction project, which was completed
earlier this year, included modifications and upgrades on the Columbia Gulf Transmission
(another CPG company) to transport up to 540,000 MMBtu per day from Leach, Kentucky to
Rayne, Louisiana. Moreover, the Smithfield III project will build new compressor stations on the
west side of the Columbia Gas Transmission line, enabling 440,000 MMBtu per day to flow
from Pennsylvania and West Virginia to Leach, Kentucky. The project received FERC approval
in December 2013 and is anticipated to be in service by the end of 2014.
17
See http://www.spectraenergy.com/Operations/New-Projects-and-Our-Process/New-Projectsin-US/Texas-Eastern-Appalachia-to-Market-2014-TEAM-2014/, accessed November 19, 2014.
18
Spectra
Energy,
http://www.spectraenergy.com/Operations/New-Projects-and-OurProcess/New-Projects-in-US/Texas-Eastern-Appalachia-to-Market-2014-TEAM-2014/. Spectra
Energy is considering expansions of its Algonquin Gas Transmission system (crossing New
England, New York and New Jersey for about 1,000 miles and a capacity of up to 2.6 million
MMBtu per day) through the Algonquin Incremental Market (AIM) project and the Atlantic
Bridge project. Once additional natural gas supplies from the Appalachian basin reach the states
of New York and New Jersey, the two proposed expansions would allow gas to flow northward,
satisfying demand in New England and Maritime provinces. The AIM Project is under regulatory
review, while the Atlantic Bridge Project is in the early evaluation stages.
19
Kinder Morgan, http://www.kindermorgan.com/content/docs/FERC%20application.pdf.
20
Kinder Morgan, http://www.kindermorgan.com/business/gas_pipelines/east/Niagara/.
11
volumes from Pennsylvania to the Niagara region in northern New York. If approved, full
operation is scheduled at the time of this writing for November 2015.21
III.
Economic Modeling of the Atlantic Sunrise Expansion
A. Arbitrage in the Presence of Constrained Pipeline Flows
This section describes the economic model that we use to estimate the impact of the
Atlantic Sunrise project on supply-demand balance along various points of the Transco system.
While the process of price determination in natural gas markets is complex, the market itself is
sufficiently mature that we can exploit two economic principles in the development of our model.
First, if portions of Transco are unconstrained, we take advantage of the theory of
arbitrage. (See, for example, Kleit (2001)). The theory of arbitrage states that if a product moves
from Market A to Market B, and there is no shortage of transportation capacity between the two
markets, the price in Market A plus the costs of transportation from Market A to Market B will
equal the price in Market B. Thus, for example, assume that the price of natural gas in Market A
is $5.00 per unit (MMBtu), we observe that gas shipped is shipped from A to B, and that the
transportation cost from A to B is $0.30 per MMBtu. This implies that the price of gas in Market
B will be $5.30. The intuition behind the theory of arbitrage is that if the price of gas in Market B
rose above $5.30 per MMBtu, there would be profit opportunities in increasing shipments of gas
from Market A to Market B. The influx of new supplies to Market B would have a depressing
effect on prices in that market.
Second, if the pipeline is constrained (here, east of Station 90 in Alabama) we can
assume that the flow through Transco at that point is fixed. We note that because pipeline
operating conditions change from day to day, that fixed amount will vary. (See Ruff (2012)). In
our data, for example, we assume that the Transco system is constrained in Alabama by
observing price differentials between Station 90 and Zone 5 that are not consistent with the
theory of arbitrage. During periods where we observe constraints in the Transco system, we will
fix flows at the constrained point at the observed level for each day.
The Transco system is divided into zones for rate purposes. For the purposes of this
analysis, the Alabama and Georgia parts of Transco are in Zone 4; South Carolina, North
Carolina and Virginia are in Zone 5; Maryland and states to the northeast are in Zone 6 (See
Figure 3.1 below). The Federal Energy Regulatory Commission (FERC) regulates the
transmission rates between and within those zones. Station 195, which represents the southern
terminus of the Atlantic Sunrise expansion (i.e., where Atlantic Sunrise would connect with the
main Transco line), is on the western side of Zone 6.
21
In December 2013, TGP successfully completed an open season for an incremental 500,000
MMBtu per day on its system. The Utica Backhaul project, which began service on April 1,
transports natural gas from the Marcellus and Utica production areas to the U.S. Gulf Coast.
12
Figure 3.1. Transco Zones Map
Source: http://www.1line.williams.com/ebbCode/MapTranscoMain.jsp
Using the principle of arbitrage and our assumption that flows are fixed at observed
levels at constrained portions of the Transco system, we can describe a formal economic model
for price determination at various points along the Transco system. We will let Pj be the price in
Zone j after the beginning of operations on the Atlantic Sunrise expansion. Thus, P4, P5, P6 are
the prices in zones 4, 5, and 6 respectively. (P4 refers to prices in Zone 4 east of the potential
bottleneck at Station 90.) We observe pre-Atlantic Sunrise prices in Zone 5 and Zone 6. We also
observe prices at Station 90, which we denote P90.
FERC regulated transportation rates for firm transportation service typically consist of
two parts. The first is a reservation, or fixed, fee. The second charge is a usage fee, based on the
variable costs to provide the transportation service. In addition, shippers are subject to a charge
for fuel and line loss make-up -- a small percentage of the gas used in connection with the
compression necessary to move the gas. [Thus, in practice, the transportation costs one way
between zones will be slightly different than the transport costs the other way, depending on gas
costs in each zone. In our model, we will define Tjk to be the transportation cost from Zone j to
Zone k.
13
Let Q90,before equal the quantity flowing east out of Station 90 prior to Atlantic Sunrise
and Q90,after be the amount flowing east of Station 90 after Atlantic Sunrise. Let T45 be the
transport cost between zones 4 and 5, and T54 be the transport cost between Zone 5 and 4. Let T56
be the transport cost between zones 5 and 6, and T65 be the transport cost between Zone 6 and 5.
Let T195,5 be the transport cost between Station 195 and Zone 5. Let T195,6 be the cost of shipping
gas from Station 195 to any point in Zone 6. Let Q195,N equal the amount of gas flowing north
from Station 195, with Q195,S equal the southward flow, with Q195,S ≥0. (These terms refer to the
equilibrium amounts after Atlantic Sunrise goes into operation.)
We consider how the Atlantic Sunrise Expansion would affect equilibrium prices and
flows at three points on the Transco system:
1. The potential bottleneck east of Station 90;
2. The Zone 4/Zone 5 border (at Station 135, on the east side of the Georgia/South Carolina
border);
3. Station 195, the injection point for the Atlantic Sunrise project, on the western side of
Zone 6 in Maryland.
1.
Equilibrium Price and Flow East of Station 90
If the flow east of Station 90 is constrained after the Atlantic Sunrise project, our
assumption of fixed flows in the presence of constraints suggests that:
(1) Q90,before = Q90,after
In this case, the flow on the Transco is fixed. We note that allowable flows change from day to
day. We will set the post-Atlantic Sunrise flow equal to the pre-Atlantic Sunrise flow on the
relevant days in these circumstances. In the case of constrained flow east of station 90, we must
have the following relationship between prices at station 90 and in Zone 4:
(2) P90< P4
Because of the constraint east of Station 90, arbitrage is not possible between Station 90 and the
rest of Zone 4, and prices in the rest of Zone 4 are higher than at Station 90.
On the other hand, if the flow east of Station 90 is unconstrained, prices will be equal
across Zone 4, or:
(3) P90= P4
In this circumstance, the new flow from Station 195 will displace some or even all of the Station
90 flow, implying:
(4) Q90,before > Q90,after
14
Finally, there are circumstances where there is no null point on Transco east of Station 90.
In that case, the flow into Station 90 moves from east to west. If we define west-east flows with
positive numbers and east-west flows with negative numbers, we would thus have:
(5) Q90,after ≤0
For all other circumstance, the Station 90 flow goes from west to east.
2. Equilibrium Prices and Flows Across the Zone 4/Zone 5 Border
Three possibilities for flows across the border between Zones 4 and 5 exist:



Flows north and east from Zone 4 to Zone 5;
Flows south and west from Zone 5 to Zone 4;
No cross-border flows.
In the first case, gas flows north and east from Zone 4 to Zone 5. In this case, owners of
gas will be indifferent between selling their gas in Zone 4 and selling it in Zone 5. This implies:
(6) P4+ T45=P5
For example, assume that the price of gas in Zone 4 is $5.70 and the cost of transportation of gas
from Zone 4 to Zone 5 is $0.30, and that gas flows from Zone 4 to Zone 5. This implies that the
price of gas in Zone 5 will be $5.70+$0.30=$6.00.
In the second case, gas could flow south and west across the Zone 4/5 border. This
implies gas owners in Zone 5 are indifferent between selling in Zone 5, or paying the transport
cost and selling in Zone 4, or:
(7) P5+ T54=P4
The third circumstance is when no gas is shipped across the Zone 4/5 border. This
implies that owners of gas in Zone 4 would prefer to sell it in Zone 4, while owners of gas in
Zone 5 would prefer to sell the gas in Zone 5. In this case, the transportation costs are greater
than any price difference. Therefore, P4+T45>P5 (no shipments from Zone 4 to Zone 5) and
P5+T54>P4 (no shipments from Zone 5 to Zone 4). This implies:
(8) P4-T54<P5<P4+T45
For example, assume that the price in Zone 4 is $4.00, the price in Zone 5 is $4.10, and the
transport cost between zones is $0.30. In this case, gas owners prefer not to ship gas between the
two zones, and “autarky” (a state of no trade) exists between the zones.
15
3. Equilibrium Prices and Flows at Station 195
The impact of Atlantic Sunrise on flows at Station 195 is complex. We identify five
different possibilities in equilibrium:





Gas injected at Station 195 flows both north and south;
Gas injected at Station 195 flows northbound only, and additional flows from
Zone 5 to Zone 6 are facilitated by the pipeline expansion;
Gas injected at Station 195 flows northbound only, but no additional flows occur
from Zone 5 to Zone 6;
Gas injected at Station 195 flows southbound only, and additional flows from
Zone 6 to Zone 5 are facilitated by the pipeline expansion;
Gas injected at Station 195 flows southbound only, but no additional flows occur
from Zone 6 to Zone 5;
Each of these equilibria has specific conditions under which they will occur. These conditions
are described below for each of the five equilibria.
a. The Injected Gas Flows Both North and South
If gas injected at Station 195 goes both north and south, under the theory of arbitrage,
owners of natural gas injected at Station 195 should be indifferent between their gas going north
or south. This implies that the net return from northbound flow must be equal to the net return
from southbound flow. In addition, both northward and southward flows are possible from
Station 195.
(9)
(10)
P6 – T195,6 = P5 – T195,5
-1.7 million MMBtu≤ Q195,S ≤ 0≤ Q195,N ≤1.7 million MMBtu
For example, assume the price in Zone 5 is $6.00, the cost of transporting gas from Station 195
to Zone 5 is $0.20 per MMBtu, while the cost of transporting cost from Station 195 to Zone 6 is
$0.15. Moreover, assume that injected gas at Station 195 goes both north and south. Under the
arbitrage assumption, gas owners at Station 195 are indifferent between sending their gas north
to Zone 6, or South to Zone 5. Thus, the prevailing prices in Zones 5 and Zone 6 would need to
satisfy (9) above, or P6 - $0.15 = $6.00 - $0.20, implying that the price of gas in Zone 6 was
$5.95.
b. All of the Injected Gas Flows North
There are two scenarios here. Assume that all gas injected at Station 195 goes north, and
additional gas flows on Transco from Zone 5 to Zone 6. In this scenario, the price of gas in Zone
6 minus the transportation cost from Station 195 to Zone 6 will be greater than the price of gas in
Zone 5, net of the transportation cost from Station 195 to Zone 5.
(11)
P6 – T195,6 ≥P5 – T195,5
16
For example, if the price in Zone 6 is $5 and the two transport costs both equal $0.25, (11)
implies that the price in Zone 5 must be less than $5.
Assume now that gas from Zone 5 also flows into Zone 6, implying:
(12)
Q195,N >1.7 million MMBtu
Gas flowing north from Zone 5 to Zone 6 implies that owners of gas in Zone 5 are
indifferent between selling in Zone 5, or paying the transport cost and selling in Zone 6, or:
(13)
P5+ T56=P6
For example, assume that transport cost between Zone 5 and Zone 6 is $0.35 per unit. Given a
price in Zone 5 of $6.00, this implies the price in Zone 6 will be $6.35.
Alternatively, all of the gas from Station 195 flows north, but no gas from Zone 5 flows
into Zone 6. In this case, condition (11) still applies. However, the northward flow at Station
195 equals the injections from Atlantic Sunrise at 195, or:
(14)
Q195,N =1.7 million MMBtu
In addition, Zone 5 gas owners prefer not to send their gas to Zone 6, or:
(15)
P5+ T56>P6
In this case, we say that Zone 6 is in autarky with respect to Zone 5.
c. All of the Injected Gas at Station 195 Flows South
There are again two scenarios here. Assume that all of the gas injected at Station 195
goes south. This implies:
(16)
P6 – T195,6 ≤P5 – T195,5
and that the payoff to sending gas south is greater than the payoff to sending gas north.
Given that all the injected gas flows south, it is also possible that Zone 6 gas would also
flow south. In this circumstance, we have that:
(17)
(18)
P6 + T65=P5
Q195,S <-1.7 million MMBtu
In this case, the Zone 6 price plus the cost of transport from Zone 6 to Zone 5 will equal the Zone
5 price.
17
Alternatively, no gas would flow south from Zone 6. This implies:
(19)
(20)
P6 + T65>P5
Q195,S =-1.7 million MMBtu
Once again, Zone 6 would be in autarky.
The possible equilibrium conditions that we found are summarized in Tables 3.1-3.3
below. (Numbers in the boxes refer to the relevant equilibrium/arbitrage condition. “NA”
indicates that the relevant circumstance did not arise in our simulations.)
18
Pipeline Previously Unconstrained East of Station 90 Scenarios
In all these scenarios
Conditions 3: P90= P4; and 4: Q90,before > Q90,after apply
Table 3.1
Station 195 gas flows either both North and South, or only North to Zone 6
Gas flows both South to Zone
5 and North to Zone 6
Gas flows from Zone 4 to
Zone 5
Gas flows from Zone 5 to
Zone 4 and the null point is in
Zone 4
Gas flows from Zone 5 to
Zone 4 and the null point is to
the southwest of Station 90
No gas flows between Zone 4
and Zone 5
6: P4+ T45=P5
9: P6 – T195,6 = P5 – T195,5
10:-1.7 million MMBtu≤
Q195,S≤0≤ Q195,N <1.7 million
MMBtu
7: P5+ T54=P4
9: P6 – T195,6 = P5 – T195,5
10:-1.7 million MMBtu≤
Q195,S≤0≤Q195,N <1.7 million
MMBtu
5: Q90,after <0
7: P5+ T54=P4
9: P6 – T195,6 = P5 – T195,5
10:-1.7 million MMBtu≤
Q195,S≤0≤ Q195,N <1.7 million
MMBtu
8: P4-T54<P5<P4+T45
9: P6 – T195,6 = P5 – T195,5
10:-1.7 million MMBtu≤
Q195,S≤0≤ Q195,N <1.7 million
MMBtu
19
Gas flows only North to Zone
6
6: P4+ T45=P5
11: P6 – T195,6 ≥P5 – T195,5.
Gas flows from Zone 5 to
Zone 6:
12: Q195,N >1.7 million
MMBtu
13: P5+ T56=P6
No gas flows from Zone 5 to
Zone 6:
14: Q195,N =1.7 million
MMBtu
15: P5+T56>P6
NA
NA
NA
Table 3.2
Station 195 gas flows only South to Zone 5
In all these scenarios
Condition 16: P6 – T195,6 ≤P5 – T195,5 applies
Gas flows from Zone 4 to
Zone 5
Gas flows from Zone 5 to
Zone 4 and the null point is in
Zone 4
Gas flows from Zone 5 to
Zone 4 and the null point is to
the southwest of Station 90
No gas flows between Zone 5
and Zone 4
Gas flows from Zone 6 to
Zone 5
6: P4+ T45=P5
17: P6 + T65=P5
18: Q195,S <-1.7 million
MMBtu
7: P5+ T54=P4
17: P6 + T65=P5
18: Q195,S <-1.7 million
MMBtu
5: Q90,after <0
7: P5+ T54=P4
17: P6 + T65=P5
18: Q195,S <-1.7 million
MMBtu
8: P4-T54<P5<P4+T45
17: P6 + T65=P5
18: Q195,S <-1.7 million
MMBtu
20
No gas flows from Zone 6 to
Zone 5
6: P4+ T45=P5
19: P6 + T65>P5
20: Q195,S =-1.7 million
MMBtu
7: P5+ T54=P4
19: P6 + T65>P5
20: Q195,S =-1.7 million
MMBtu
NA
8: P4-T54<P5<P4+T45
19: P6 + T65>P5
20: Q195,S =-1.7 million
MMBtu
Pipeline Previously Constrained East of Station 190 Scenarios
Table 3.3
Gas flows from Zone 4 to
Zone 5
Gas flows from Zone 4 to
Zone 5
Gas flows from Zone 4 to
Zone 5
Gas flows from Zone 4 to
Zone 5
Station 195 Scenario: gas flows North from Injection Point to
Zone 6; Gas flows from Zone 5 to Zone 6
Constraint remains after the
Constraint is eliminated after
injection at Station 195
the injection at Station 195
1: Q90,before = Q90,after
3: P90= P4
2: P90< P4
4: Q90,before > Q90,after
6: P4+ T45=P5
6: P4+ T45=P5
11: P6 – T195,6 ≥P5 – T195,5
11: P6 – T195,6 ≥P5 – T195,5
12: Q195,N >1.7 million
12: Q195,N >1.7 million
MMBtu
MMBtu
13: P5+T56=P6
13: P5+T56=P6
Station 195 Scenario: Gas flows South, no flow from Zone 6 to
Zone 5
Constraint remains after the
Constraint is eliminated after
injection at Station 195
the injection at Station 195
3: P90= P4
6: P4+T45=P5
16: P6 – T195,6 ≤P5 – T195,5
NA
19: P6+T65>P5
20: Q195,S =-1.7 million
MMBtu
Station 195 Scenario: Gas flows north from injection point to
Zone 6; No gas flows from Zone 5 to Zone 6
Constraint remains after
Constraint is eliminated after
the injection at Station 195
the injection at Station 195
1: Q90,before = Q90,after
3: P90= P4
2: P90< P4
4: Q90,before > Q90,after
6: P4+ T45=P5
6: P4+ T45=P5
11: P6-T195,6 ≥ P5-T195,5
11: P6-T195,6 ≥P5-T195,5
14: Q195,N =1.7 million
14: Q195,N =1.7 million
MMBtu
MMBtu
15: P5+T56>P6
15: P5+T56>P6
Station 195 Scenario: Gas flows from the injection point both
south to Zone 5 and north to Zone 6
Constraint remains after
Constraint is eliminated after
the injection at Station 195
the injection at Station 195
1: Q90,before = Q90,after
3: P90= P4
2: P90< P4
4: Q90,before > Q90,after
6: P4+ T45=P5
6: P4+ T45=P5
9: P6 – T195,6 = P5 – T195,5
9: P6 – T195,6 = P5 – T195,5
10:-1.7 million MMBtu≤
10:-1.7 million MMBtu≤
Q195,S≤0≤ Q195,N <1.7
Q195,S≤0≤ Q195,N <1.7
million MMBtu
million MMBtu
21
In all, there are 19 equilibrium scenarios described above. 22
We note that it is not directly possible to solve for which model applies. Rather, it is
necessary to assume which equilibrium applies, solve out the relevant parameters, and see if the
necessary conditions are met.
In our modeling, we have also been able to solve for the “null point” on Transco. The
null point is where the southward flows (from either Station 195 or the end of Transco in
northern New Jersey) meet the northward flow coming from Station 90. In some circumstances,
the null point is actually at or to the west of Station 90, as the flow across Zone 4 is westward,
rather than eastward. If all of the gas injected at Station 195 flows north and east, that implies
that the null point is in Zone 6.
B. The Supply and Demand Model
In this section we outline the conditions used to set supply equal to demand in all zones
after Atlantic Sunrise. Combined with the arbitrage conditions discussed above, these conditions
will allow us to model the economic impact of injecting 1.7 million MMBtu of natural gas per
day at Station 195.
We first assume that a perfectly elastic supply of gas is available at Station 90 at a
constant price. This infinite elasticity assumption is reasonable to the extent that gas sent through
the Transco at that point is a relatively small amount of the total gas produced in Southwestern
statesWe also assume that the price of gas in the Marcellus Region is always below that of the
price at Station 195 minus the costs of transport to Station 195 from central Pennsylvania. This is
because there is currently a great deal of stranded gas in the Marcellus, so much that even an
additional 1.7 million MMBtu per day will not fully alleviate the excess production problem.
𝐸𝐷
Demand at any withdrawal point takes the constant elasticity form, 𝑄𝑖𝐷 = 𝐴𝑖𝐷 𝑃𝑖 𝑖 ,
where 𝑄𝑖𝐷 is the withdrawal amount at point i, 𝑃𝑖 is the price of natural gas at this point, 𝐴𝑖𝐷 is a
point specific constant and 𝐸𝐷𝑖 is the elasticity of demand of point i. We categorize all the
withdrawal points into three categories: Local Distribution Companies (LDCs), Power Plants,
and Other Industry. LDCs consists of two types of customers: Residential and Commercial. The
Energy Information Administration (EIA)23 estimates short run U.S. natural gas price elasticities
for residential, commercial, industrial and electric power to be -0.042, -0.055, -0.269 and -0.138
respectively. The EIA reports that natural gas consumption by residential and commercial
22
In theory, there are many more potential equilibria possible than listed in the table above. The
equilibria listed here are the ones we found in our simulations.
23
EIA, “Reduced Form Energy Model Elasticities from EIA’s Regional Short-Term Energy
Model (RSTEM),” http://www.eia.gov/forecasts/steo/special/pdf/elasticities.pdf.
22
customers in 2013 was 4.941 trillion and 3.291 trillion cubic feet respectively.24 Using weighted
averaging, we calculate a price elasticity of demand for LDCs of -0.0472.
Each injection point has supply function from the sources listed in Table A-1 of 𝑄𝑖𝑆 =
where 𝑄𝑖𝑆 is the injection amount at each point, Pi is the price of natural gas at that
point, 𝐴𝑖𝑆 is a point specific constant and 𝐸𝑆𝑖 is the elasticity of supply, assumed to be equal to
0.76 (Ponce and Neumann, 2014).25 Based on the withdrawals and injections data, we calculate
the point specific demand and supply parameters 𝐴𝑖𝐷 and 𝐴𝑖𝑆 . A list of injection points is given in
Table A-1. A summary of the other suppliers in given in Table 3.4 below.
𝐸𝑆
𝐴𝑖𝑆 𝑃𝑖 𝑖 ,
Table 3.4
Summary of Other Suppliers on Transco
Zone
Number of Suppliers
Zone 4
Zone 5
Zone 6
1
4
25
Total Injections by
Zone (MMBtu)
on January 28, 2014
25,568
1,048,981
4,663,258
Arbitrage price differences between zones are governed by interruptible (IT) rates on
Transco. Between Zone 4 and Zone 5 the IT rate is 36 cents plus 1.28% of gas costs that day.
We will assume gas costs here imply the gas costs in the originating zone. To simplify our
calculations, we will assume gas costs are based on pre-Atlantic Sunrise prices. 26
From Zone 5 to Zone 6, the IT rate is 0.77% of gas costs plus 26 cents. From Zone 6 to
Zone 5, the current IT rate is 26 cents. Currently, there is no charge based on the cost of gas from
Zone 6 to Zone 5. However, we expect that one will be imposed by FERC, once gas starts
physically flowing south on Transco: we assume it will also be 0.77% of gas costs. Gas flowing
north from station 195 pays the Zone 6 intra-zonal rate, which is 14 cents. Gas flowing south
from station 195 pays the Zone 6 to Zone 5 rates, 0.77% of gas costs plus 26 cents.
Transportation rates are summarized in Table 3.5 below, assuming a market cost of
$4.00/MMBtu.
24
http://www.eia.gov/dnav/ng/ng_cons_sum_dcu_nus_a.htm.
We note that this is likely to be a very high number for elasticity of supply. This estimate is
taken from well-head production of natural gas, not pipeline supply. In practice, the elasticity of
supply from many pipelines may well be zero, as they may also be capacity constrained.
Because the lower the elasticity of supply the greater the price effects of Atlantic Sunrise, this
assumption serves to reduce our estimates of the actual consumer benefits of the expansion
project.
26
http://www.1line.williams.com/Transco/files/Tariff/TranscoTariff.pdf.
25
23
Table 3.5
Interruptible Transportation Rates
assuming a gas price of $4.00/MMBtu
To
From
Zone 4
Zone 5
Station 195
Station 195
Zone 5
Zone 6
Zone 6
Zone 5
Fixed
Fee/MMBtu
$0.36
$0.26
$0.14
$0.26
Percent of Gas
Costs
1.28%
0.77%
0%
0.77%
Total Rate/
MMBtu
$0.411
$0.291
$0.14
$0.291
We have two sets of data. The first is composed of flows, injections and withdrawals
along Transco from January 1, 2012 to June 27, 2014. The second includes price data supplied
by Williams. We have prices at Station 90 (“Transco-85”), Zone 5 (“non-WGL Transco Z5,”
near the Virginia/North Carolina border) and Zone 6 (“TETCO-M3,” near Philadelphia).
Our model allows us to calculate the change in consumer surplus as a result of the
Atlantic Sunrise project. This represents both the saving consumers receive through lower gas
prices and the benefits they gain because they purchase more gas, since prices are lower.
Given a demand function of the constant elasticity form, the change in consumer surplus
at a point i is expressed by the following formula:
(21)
A
iD
ΔConsumer Surplus𝑖 = 1−ED
∗ (𝑃i 𝐴1−ED − 𝑃i B1−ED )
where PiA is the zonal price before Atlantic Sunrise project, and PiB is the price after Atlantic
Sunrise project.
We calculate the change in consumer surplus at each milepost. We use the withdrawals at
each “out of system” milepost, injections at each “into system” milepost and the price before the
Atlantic Sunrise project to calculate the constants A at each milepost. Using equation (21), we
obtain the change in consumer surplus at each milepost.
There are some important caveats here. First, it is a distinct possibility that there are some
days that consumer surplus will decline in Zone 6. This is because there are days where gas is
significantly less expensive in Zone 6 than Zone 5, and, without Atlantic Sunrise, this gas cannot
flow south. Allowing a southward flow on Transco relieves the underlying bottleneck and allows
gas to flow from Zone 6 to Zone 5, potentially resulting in higher prices in Zone 6.
Second, in the data we often observe uneconomic flows of gas between zones. For
example, on July 28, 2013, the price in Zone 4 is $3.54, the Zone 5 price is $3.61, the
transportation cost from Zone 4 to Zone 5 is $0.41, and yet there are substantial flows of gas
from Zone 4 to Zone 5. We assume that these uneconomic flows are the result of difficulties of
renegotiating long-term contracts between parties. Our model assumes that these uneconomic
flows will not continue following the construction of Atlantic Sunrise. In reality, these
24
uneconomic transactions may continue but there is no way to predict the extent to which they
will do so.
We take three modeling steps to address this issue. These steps are both conservative in
nature (i.e., lower our estimates of consumer benefit) and consistent with the economic modeling
assumptions. First, in circumstances where the resulting change in Zone 5 consumer surplus is
negative, we set the change in consumer surplus to zero. We note that there is no economic
reason to believe that the Atlantic Sunrise project would cause Zone 5 prices to rise (since
Atlantic Sunrise would, in effect, increase supply deliverability into Zone 5). This assumption
serves to reduce our estimate of consumer benefits on days where the Zone 5 price would have
declined, because the decline is from an uneconomically low level.
Second, on days where there are no shipments for gas from Zone 6 to Zone 5, and the
estimated consumer surplus change in Zone 6 is negative, we set the change in Zone 6 consumer
surplus to zero. Again, there is no reason to believe in these circumstances that Zone 6 consumer
surplus would decline, because all gas sales in Zone 6 would effectively serve customers within
Zone 6.
Finally, on days where we estimate that Atlantic Sunrise would induce shipments of gas
from Zone 6 to Zone 5, we allow estimated consumer surplus in Zone 6 to decline. On these
days, there are economic reasons to believe Zone 6 prices would rise, since buyers in Zone 5
would be willing to pay higher prices for gas supplied from Zone 6 than gas supplied from Zone
5. Again, this makes our estimates of the total consumer gains from Atlantic Sunrise
conservative, as we do not take into account any adjustments for uneconomic flows.
In addition, there are days where our model estimates that gas would have flowed into
Station 90. These supplies serve to displace shipments of gas eastward from Texas and Louisiana,
and result in additional supplies going to other (non-Transco) markets. We do not estimate the
benefits of these shipments to customers in other markets, but it is worth noting that the benefits
of additional gas transportation infrastructure would not be limited to markets served directly by
Transco.
IV.
Illustration of the Impacts of Atlantic Sunrise on Five Different Days
To illustrate how our economic model can be used to estimate the market impacts of the
Atlantic Sunrise expansion, we choose five days in different seasons (February 11, 2013, July 28,
2013, October 28 2013, January 28, 2014 and April 28, 2014) and solve for the market
equilibrium (injections, withdrawals and prices in each zone), given the establishment of the
Atlantic Sunrise project. These days represent different demand/supply balances along the
Transco system, and thus allow us to describe the market impacts of Atlantic Sunrise under
various system conditions.
25
1. February 11, 2013
On this day, there was no constraint at Station 90. Prior to Atlantic Sunrise, in the Zone
4 price was $3.28,27 the Zone 5 price was $3.64, and the Zone 6 price was $4.02. Gas flows
from Zone 4 to Zone 5 were uneconomic. We assume that, in equilibrium, 1.7 million MMBtu
injected at Station 195 only flows north, and there is additional gas flowing from Zone 5 to Zone
6. Moreover, gas is flowing from Zone 4 to Zone 5.
The market situation prior to Atlantic Sunrise suggests that in equilibrium, gas would
flow from Zone 4 to Zone 5, and from Zone 5 to Zone 6. Assuming a perfectly elastic supply at
Station 90 at a price of $3.28, this implies that the gas price in Zone 4 will also equal $3.28. Our
assumptions imply that 𝑃5 − 𝑃4 = 𝑇4,5 , and 𝑃6 − 𝑃5 = 𝑇5,6 . Solving these two conditions, given
the intra-zonal transportation costs, we obtain:
𝑃4 = $3.28
𝑃5 = $3.69
𝑃6 = $3.97
The consumer surplus change for February 11, 2013 by zone would have been:
ΔCS4 = $0, ΔCS5 = −$91,525, ΔCS6 = $222,233
Zone 4 consumer surplus does not change, as the price in Zone 4 is still equal to the Station 90
price. The modelled price in Zone 5 increases due to the elimination of uneconomic gas flows.
Even though this is a useful assumption in our model, the uneconomic flow are likely to continue
in reality (which would benefit consumers; however, these uneconomic flows are not a
consequence of Atlantic Sunrise). Therefore, we adjust the change of consumer surplus in Zone 5
to $0. Prices in Zone 6 decline, as lower cost Marcellus gas now supplies Zone 6, determining an
increase in consumer surplus in this zone. This implies that the total increase in consumer surplus
across the three zones for this day would have been about $0.22 million.
27
This and other price information comes from LCI Data Services
26
Table 4.1 Comparison of Flows
Before and After Atlantic Sunrise, February 11, 2013 (MMBtu)
Area
Flow
Before
Flow After
Flow
Change
Station 90
4,042,102
2,373,789
-1,668,313
Station 135
3,181,293
1,512,980
-1,668,313
1,861,731
1,907,915
46,184
0
0
0
Station 195
North Flow
Station 195
South Flow
Table 4.1 and 4.2 compare the flows, prices, withdrawals and injections before and after
the Atlantic Sunrise project for this day. Flows with a positive sign are northbound, while flows
with a negative sign are southbound. On this day, the Atlantic Sunrise project would have
reduced flows across Station 90 by almost the full amount of the injections at Station 195. Prices
in Zone 6 decline by about four and a half cents due to the additional less expensive flows from
Station 195.
Table 4.2 Comparison of Withdrawals, Injections and Prices
Before and After Atlantic Sunrise, February 11, 2013
Area
Zone
4
Zone
5
Zone
6
Withdrawals
Before,
After,
Change
(MMBtu)
885,422
885,422
0
2,031,763
2,024,281
-7,482
4,784,839
4,805,378
20,539
Injections
Prices
Before,
Before,
After,
After,
Change
Change
(MMBtu) ($/MMBtu)
24,613
3.284
24,613
3.284
0
0
712,201
3.6388
719,216
3.6860
7,015
0.0472
2,923,108
4.0204
2,897,463
3.9741
-25,645
-0.0463
27
2. July 28, 2013
On this day, there was no constraint at Station 90 prior to Atlantic Sunrise. Prices in Zone
4 were $3.54, while the Zone 5 price was $3.61. Given a transportation cost of $0.41 from Zone
4 to Zone 5, it was uneconomic for gas to flow from Zone 4 to Zone 5, since the price in Zone 5
was lower than the price in Zone 4, plus the relevant transport cost. Nevertheless, we observe gas
flows from Zone 4 to 5. Similarly, gas flowed from Zone 5 to Zone 6, even though the Zone 6
price ($3.36) was lower than the Zone 5 price plus the transportation cost from Zone 5 to Zone 6
($0.29).
Here we assume that, in equilibrium, the 1.7 million MMBtu injected at Station 195
flows both north and south. There is no trading between Zone 4 and Zone 5 (and therefore, the
null point is on the Georgia-South Carolina border between Zones 4 and 5).
Assuming a perfectly elastic supply at Station 90 at a price of $3.54, this implies that the
gas price in Zone 4 will also equal $3.54. We have two equations for solving prices in Zone 5
and Zone 6. First, under the assumption that gas injected at Station 195 goes both north and
south, we have 𝑃6 − 𝑇195,6 = 𝑃5 − 𝑇195,5. Second, total injections in Zones 5 and 6 are equal to
total withdrawals in the two zones. Solving the above two conditions, we obtain the new
equilibrium prices:
𝑃4 = $3.54
𝑃5 = $3.15
𝑃6 = $3.00
We then check to see if the result satisfies the autarky condition (i.e., there is no trade
between Zone 4 and 5). Gas is shipped from Zone 5 to Zone 4 if P5 + T5,4 ≤ P4. Gas is shipped
from Zone 4 to Zone 5 if P5 – T4,5 ≥ P4. This implies that if P4 – T5,4 < P5 < P4 + T4,5, there is
no trade between Zone 4 and 5.
𝑃4 − 𝑇5,4 = $(3.54 − 0.40) = $3.14
𝑃4 + 𝑇4,5 = $(3.54 + 0.41) = $3.95
𝑃5 = $3.15 is within this region. Thus, our result satisfies the autarky condition between Zones 4
and 5 on that day.
The consumer surplus change for July 28, 2013 by zone would have been:
ΔCS4 = $0, ΔCS5 = $678,878, ΔCS6 = $1,278,248
Therefore, the total increase in consumer surplus across all three zones for this day would have
been about $1.96 million. Zone 4 consumer surplus does not change, as the price in Zone 4 is
still equal to the Station 90 price. Prices in Zone 5 and 6 decline as lower cost Marcellus gas now
supplies both zones, at a lower price than the gas that previously came from Station 90.
28
Table 4.3 Comparison of Flows
Before and After Atlantic Sunrise, July 28, 2013 (MMBtu)
Area
Flow
Before
Flow After
Flow
Change
Station 90
2,076,968
874,730
-1,202,238
Station 135
1,202,238
0
-1,202,238
132,087
530,082
397,995
0
-1,169,918
Station 195
North Flow
Station 195
South Flow
-1,169,918
Table 4.3 compares the flows before and after the Atlantic Sunrise project for this day.
Note that before Atlantic Sunrise 1.2 MMBtu flowed northward across Station 135 (on the east
side of the Georgia-South Carolina boarder), even though net-of-transportation prices were lower
in Zone 5 than in Zone 4.
As a result of Atlantic Sunrise, 1.7 million MMBtu are injected at Station 195. This
results in a decrease in flow east of Station 90 by 1.2 MMBtu, and a drop in injections from other
suppliers of 0.32 million BTU along Transco. The net increase in injections is 0.18 million
MMBtu, resulting in price declines of $0.46 per MMBtu in Zone 5 and $0.36 cents per MMBtu
in Zone 6, as illustrated below in Table 4.4. The larger decline in the Zone 5 price is due to the
southward bottleneck at Station 195 being relieved. Of the gas injected at Station 195, 1.17
million MMBtu flows south, while 530,000 MMBtu flows north.
29
Table 4.4 Comparison of Withdrawals, Injections and Prices
Before and After Atlantic Sunrise, July 28, 2013
Area
Zone
4
Zone
5
Zone
6
Withdrawals
Before,
After,
Change
(MMBtu)
884,982
884,982
0
1,526,769
1,581,503
54,734
3,536,160
3,656,586
120,426
Injections
Prices
Before,
Before,
After,
After,
Change
Change
(MMBtu) ($/MMBtu)
10,252
3.542
10,252
3.542
0
0
456,618
3.609
411,585
3.149
-45,033
-0.461
3,404,073
3.358
3,126,504
3.003
-277,569
-0.356
3. October 28, 2013
Similarly to the case above, on October 28, 2013 there is no constraint at Station 90 prior
to Atlantic Sunrise. The Zone 4 price was $3.67, the Zone 5 price was $3.79, while the Zone 6
price was $3.71. Once again, there were uneconomic flows from Zone 4 to Zone 5 (since the
Zone 5 price is lower than the Zone 4 price, plus the transportation cost from Zone 4 to Zone 5,
$0.41), and from Zone 5 to Zone 6 (since the Zone 6 price is lower than the Zone 5 price, plus
the transportation cost from Zone 5 to Zone 6, $0.29).
In this scenario, we solve for the autarky solution where there is no trade across the Zone
4/5 border. We also assume that gas injected at Station 195 goes both north and south. Two
equations determine the equilibrium prices in Zone 5 and Zone 6. The first equation comes from
the arbitrage assumption that the sellers of gas injected at Station 195 are indifferent between
their gas going north or south. This implies that the Zone 5 price, minus the transportation cost
from Station 195 to Zone 5, should be equal to the Zone 6 price, minus the transportation cost
from Station 195 to Zone 6. Therefore, 𝑃6 − 𝑇195,6 = 𝑃5 − 𝑇195,5.
The second equation comes from equating total injections to total withdrawals for Zone 5
and Zone 6, with no gas crossing the Zone 4/Zone 5 border. Solving the two equations, we get:
𝑃4 = $3.67
𝑃5 = $3.91
𝑃6 = $3.76
We then need to check if these results satisfy the autarky condition (i.e., there is no trade
between Zone 4 and 5). As noted for the case of July 28, 2013, gas is shipped from Zone 5 to
30
Zone 4 if P5 + T5,4 ≤ P4. Gas is shipped from Zone 4 to Zone 5 if P5 – T4,5 ≥ P4. This implies
that if P4 - T5,4 < P5 < P4 + T4,5, there is no trade between Zone 4 and 5. For October 28, 2013,
we have that:
𝑃4 − 𝑇5,4 = $(3.67 − 0.41) = $3.26
𝑃4 + 𝑇4,5 = $(3.67 + 0.41) = $4.08
Since 𝑃5 = $3.91 is within this region, we have thus verified that there no trading occurs
between Zones 4 and 5. In turn, this implies the null point is on the Georgia-South Carolina
border, similarly to the July 28, 2013 case. Moreover, there is no trading between Zone 5 and
Zone 6.
The estimated surplus change for October 28, 2013 from our model is:
ΔCS4 = $0, ΔCS5 = −$190,293, ΔCS6 = −$205,895
The estimated overall impact on consumer surplus implied by our model is a decrease by
$396,188 for this day. The reason is that gas was previously flowing into Zone 5 (and 6), even
though the price of gas in Zone 4 was higher than the price in Zone 5, net of transportation. This
result, occurring before the Atlantic Sunrise project is constructed, is now eliminated by the
arbitrage condition we impose in our calculation. Because this result is an artifact of our model,
we set the change in consumer surplus equal to 0 for this day. This is an underestimate of the
impact on consumer surplus of the Atlantic Sunrise project on this day.
Table 4.5 and 4.6 summarizes the flows at each compressor station and the injections,
withdrawals and prices in each zone after the Atlantic Sunrise project for this day.
31
Table 4.5 Comparison of Flows
Before and After Atlantic Sunrise, October 28, 2013 (MMBtu)
Area
Flow
Before
Flow After
Flow
Change
Station 90
2,625,261
847,583
-1,777,678
Station 135
1,777,678
0
-1,777,678
474,966
419,504
-55,462
0
-1,280,496
Station 195
North Flow
Station 195
South Flow
-1,280,496
Table 4.6 Comparison of Withdrawals, Injections and Prices
Before and After Atlantic Sunrise, October 28, 2013
Area
Zone
4
Zone
5
Zone
6
Withdrawals
Before,
After,
Change
(MMBtu)
858,440
858,440
0
1,634,033
1,619,859
-14,174
4,186,554
4,168,517
-18,037
Injections
Prices
Before,
Before,
After,
After,
Change
Change
(MMBtu) ($/MMBtu)
10,857
3.670
10,857
3.670
0
0
331,321
3.785
339,362
3.907
8,041
0.121
3,711,588
3.710
3,749,013
3.758
37,425
0.048
Table 4.5 presents the impact of the Atlantic Sunrise project on natural gas flows.
Besides the 1.7 million MMBtu injection at Station 195, injections from other pipelines increase
by 0.045 million MMBtu (Table 4.6). Flows eastward from Station 90, however, decrease by
1.778 million (Table 4.5). The net result is an increase in price of $0.12 in Zone 5 and $0.05 in
Zone 6, as shown in Table 4.6.
32
4. January 28, 2014
In this case, the Transco pipeline is constrained at Station 90 prior to Atlantic Sunrise, as
the prices in Zone 5 and 6 are significantly higher than the reported Zone 4 price. This is the
circumstance where we expect the bulk of the welfare gains from the Atlantic Sunrise project to
occur. Prices in Zones 4, 5 and 6 were $93.13, $93.56 and $79.85, respectively, prior to the
construction of Atlantic Sunrise.
Our assumptions are that the 1.7 million MMBtu injected at Station 195 flows both north
and south, and gas flows across the Zone 4/5 border. We also assume that Station 90 will remain
congested after the additional gas is put into the system.
We have three equations for obtaining the equilibrium prices in Zone 4, Zone 5 and Zone
6. The first two equations come from our arbitrage assumption: prices in zones that are
connected by uncongested pipelines should differ by the cost of transportation. Therefore,
𝑃6 − 𝑇195,6 = 𝑃5 − 𝑇195,5 and 𝑃5 − 𝑃4 = 𝑇4,5 . The last equation follows from setting total
withdrawals equal to total injections in the three zones, given that flows downstream of Station
90 remain constant.
Solving for the three equations, in equilibrium yields the new zonal prices:
𝑃4 = $67.55
𝑃5 = $67.99
𝑃6 = $67.25
For this scenario, we present in detail our calculation of the null point. To determine the
null point, we calculated the demand and supply at various mileposts on Transco south of Station
195. Going southward from Station 195, we calculated the southward flow. When the flow turns
negative, we have isolated the null point, as shown in Table 4.7. Our calculation shows that the
null point would be at MP 1413.01, Station 165, the South Virginia Lateral in Virginia. See
Figure 4.1.
33
Table 4.7
Calculation of Null Point on January 28, 2014
Meter Station Name
(South to North)
Martinsville
Danville
Brockway Glass
Chatham
Compressor Station 165
South Virginia Lateral
Altavista
Brookneal
Lynchburg
Compressor Station 170
Virginia Fibre
Mainline
Milepost
1389.25
1393.33
1403.56
1409.26
1412.99
1413.01
1425.71
1440.03
1451.48
1457
1466.39
Flow
(MMBtu)
141,359
129,241
106,516
104,278
103,076
Null Point
-93,668
-96,514
-96,876
-120,918
-120,918
Figure 4.1 Estimated Null Point on January 28, 2014
Null Point: Station 165, South Virginia Lateral
Source: Williams
34
The consumer surplus change for January 28, 2014 would be:
ΔCS4 = $37,263,863, ΔCS5 = $98,894,271, ΔCS6 = $67,198,480
Overall, consumer surplus would have increased by about $203 million for this day because of
Atlantic Sunrise.
Table 4.8 summarizes the flows at four compressor station after the Atlantic Sunrise
project for this day. Table 4.9 compares the prices, withdrawals and injections before and after
the Atlantic Sunrise project for this day.
Table 4.8 Comparison of Flows
Before and After Atlantic Sunrise, January 28, 2014 (MMBtu)
Area
Flow
Before
Flow After
Flow
Change
Station 90
4,250,131
4,250,131
0
Station 135
2,884,727
2,737,184
-147,543
48,066
994,323
946,257
0
-705,677
-705,677
Station 195
North Flow
Station 195
South Flow
Table 4.9 Comparison of Withdrawals, Injections and Prices
Before and After Atlantic Sunrise, January 28, 2014
Withdrawals Injections
Prices
Before,
Before,
Before,
Area
After,
After,
After,
Change
Change
Change
(MMBtu)
(MMBtu) ($/MMBtu)
1,390,972
25,568
93.129
Zone
1,532,979
20,032
67.553
4
142,007
-5,536
-25.576
3,885,642 1,048,981
93.56
Zone
4,265,804
822,943
67.986
5
380,162
-226,038
-25.576
5,182,529 5,134,463
79.846
Zone
5,500,782 4,506,459
67.251
6
318,253
-628,004
-12.595
35
As the Station 90 flows remains constrained, flows at that point remain at 4.25 million
units. 994,000 of the Station 195 injection flows north, while the remainder of the 1.7 million
MMBtu injection flows south. Prices fall by $25.58 in Zone 5, and by $12.59 in Zone 6.
5. April 28, 2014
On this day, there was no constraint at Station 90 prior to Atlantic Sunrise. The Zone 5
price of $4.74 was only slightly above the Zone 4 price of $4.66. There were observed flows
from Zone 4 to Zone 5. Zone 6 prices, at $3.76, are actually well below the Zone 5 price. Despite
this, 166,587 MMBtu flowed from Zone 5 to Zone 6.
Observe that the price in Zone 6 was lower than the price in Zone 5. We assume that in
equilibrium, after Atlantic Sunrise becomes operational, the 1.7 million MMBtu injected at
Station 195 only flows south. We also assume that gas flows from Zone 6 to Zone 5, thus
implying that consumer surplus will fall in Zone 6.
We have two equations for obtaining the equilibrium prices in Zone 5 and Zone 6. Both
of these two equations result from our arbitrage assumption: prices in zones that are connected
by uncongested pipeline should differ by the cost of transportation, with gas flowing south from
Zone 6 to Zone 5 to Zone 4. Therefore, we have 𝑃5 − 𝑃6 = 𝑇6,5 and 𝑃4 − 𝑃5 = 𝑇5,4 .
Given our assumption that the price in Zone 4 remains at $4.66, we have:
𝑃4 = $4.66
𝑃5 = $4.24
𝑃6 = $3.95
Note that the Zone 5 price is now lower than the Zone 4 price. Our calculation shows that the
null point would be at MP 1107.33, Center Power Plant in Georgia, which will receive gas from
both northward and southward flows.
The change in consumer surplus for April 28, 2014 would be:
ΔCS4 = $0, ΔCS5 = $817,240, ΔCS6 = −$806,155
Here the decline in consumer surplus for Zone 6 is partly due to the export of approximately
93,000 MMBtu from Zone 6 to Zone 5. To be conservative, we count the entire change in
consumer surplus here as negative. Total gains in consumer surplus for this day are therefore
approximately $11,000.
As a result of the Atlantic Sunrise project, the flow across Station 90 is reduced from 2.27
million MMBtu to 439,000 MMBtu. The flow at Station 135 reverses direction, with 439,000
units flowing south and west, rather than almost 1.4 million units flowing north and east. All of
the input from Station 195 flows south. Zone 5 prices decline, as less expensive gas from the
36
Marcellus flows into the region. Tables 4.10 and 4.11 summarize the impacts of Atlantic Sunrise
on this day.
Table 4.10 Comparison of Flows
Before and After Atlantic Sunrise, April 28, 2014 (MMBtu)
Area
Flow
Before
Flow After
Flow
Change
Station 90
2,271,379
439,347
-1,832,032
Station 135
1,392,589
-439,443
-1,832,032
166,587
0
-166,587
0
-1,753,494
-1,753,494
Station 195
North Flow
Station 195
South Flow
Table 4.11 Comparison of Withdrawals, Injections and Prices
Before and After Atlantic Sunrise, April 28, 2014
Area
Zone
4
Zone
5
Zone
6
Withdrawals
Before,
After,
Change
(MMBtu)
896,850
896,850
0
1,674,605
1,725,833
51,228
4,268,173
4,204,901
-63,272
Injections
Prices
Before,
Before,
After,
After,
Change
Change
(MMBtu) ($/MMBtu)
18,060
4.661
18,060
4.661
0
0
448,603
4.746
411,782
4.240
-36,821
-0.506
4,101,586
3.761
4,258,395
3.951
156,809
0.190
In total, 1.7 million MMBtu are injected at Station 195. Station 90 eastward flows decline
by 1.83 million MMBtu. Prices in Zone 5, however, decline by $0.51. The reason for this is the
removal of the southward bottleneck at Station 195. As a result, gas flows south from Zone 6
into Zone 5. Injections in Zone 6 increase by 0.16 million, as the Zone 6 price rises by $0.19. A
small amount of gas, 93,000 units, flows south from Zone 6 into Zone 5.
37
Table 4.12 summarizes the projected impacts of the Atlantic Sunrise project across the
five days presented in this section.
Table 4.12
Summary Across the Five Examined Days
Date
Equilibrium
Characteristics
February
11, 2013
Station 195 gas flows
north.
No flow constraint at
Station 90.
Gas flows from Zone 4
to Zone 5, and from
Zone 5 to Zone 6.
Station 195 gas flows
both north and south.
No flow constraint at
Station 90.
Gas does not flow
across the Zone 4/5
border.
Station 195 gas flows
both north and south.
No flow constraint at
Station 90.
July 28,
2013
October 28,
2013
January 28,
2014
April 28,
2014
Station 195 gas flows
both north and south.
Flow constraint at
Station 90.
Gas flows north across
Zone 4/5 border.
Station 195 gas flows
south
No flow constraint at
Station 90.
Gas flows from Zone 6
to Zone 5.
Gas flows south across
Zone 4/5 border.
Old
Prices,
$/MMBtu
(Zone 4,
Zone 5,
Zone 6)
3.28
3.64
4.02
New
Prices
$/MMBtu
(Zone 4,
Zone 5,
Zone 6)
3.28
3.69
3.97
ΔCS, $K
(Zone 4,
Zone 5,
Zone 6,
Total)
Zone 4/5
Border
3.54
3.61
3.36
3.54
3.15
3.00
0
679
1,278
1,957
Zone 4/5
border
3.67
3.79
3.71
3.67
3.91
3.76
0
0
0
0
MP 1413.01
in Virginia,
Zone 5
93.13
93.56
79.85
67.55
67.99
67.25
37,264
98,894
67,199
203,357
MP
1107.33,
Center
Power Plant
in Georgia,
Zone 4
4.66
4.74
3.76
4.66
4.24
3.95
0
817
-806
11
Null Point
Zone 6
38
0
0
222
222
V.
Analysis of Impact of Atlantic Sunrise
Results from Section IV suggest that during periods of relatively moderate natural gas
demand in the Mid-Atlantic region (i.e. all periods other than the January, 2014 modeled day),
the impacts of Atlantic Sunrise on consumer surplus are relatively modest. The benefits to
consumers during the most constrained periods, however, are substantial, with modeled prices
falling by around 30% relative to prices that actually prevailed during the January day modeled.
Our five specific days modeled in the previous section serve to illustrate the conditions under
which benefits to consumers would be large. It also allows us to identify conditions under which
Atlantic Sunrise would yield small price increases in Zone 6.
In this section we present results from a more comprehensive analysis of Atlantic Sunrise,
covering a period of more than two and a half years (906 days). We identify a larger number of
possible market outcomes (equilibrium flows and prices) than in our previous examples, and are
able to characterize the economic location of the null point for each day.
A. Scenario Analysis
Tables 5.1 through 5.3 display the number of each type of equilibria our modeling
obtained, based on whether the pipeline east of Station 90 was constrained, where the gas
injected at Station 195 would flow to, and what type of flows would occur between Zones 4 and
5. We found 19 different scenarios in our simulation exercise.
Out of a total of 906 days modeled, 796 (88.0%) were unconstrained east of Station 190
prior to the Atlantic Sunrise expansion. Of these, the model found that after Atlantic Sunrise 658
days had gas flowing both north and south from the injection point at Station 195. 443 (48.89%
of the total of 906 days) would have had gas at Station 195 flowing both north and south, as well
as gas flowing north from Zone 4 to Zone 5. 40 of these days, however, would have gas flowing
south across the Zone 4/5 border, with an additional scenario find that the null point would have
been actually southwest of Station 90. 174 days would have had an equilibrium where no gas
flowed across the Zone 4/5 border. A relatively small number of days, 64, would have had
natural gas flowing solely north from Station 195, where the line in Alabama was unconstrained.
There are 74 days where the line east of Station 90 was previously unconstrained and in
which the gas from Station 195 would have flowed only south. In a total of 61 of those days the
gas would have flown southward past the Georgia-South Carolina line. Out of those 61, in 26
days the null point would have been to the south and west of Station 90.
Only 110 days were constrained east of Station 90 prior to the modeling of the Atlantic
Sunrise project. Of these, 36 days remained unconstrained after the introduction of natural gas
injections at Station 195.
39
Pipeline Previously Unconstrained East of Station 90 Scenarios
Table 5.1
Station 195 gas flows either both North and South, or only North to Zone 6
Gas flows both South to Zone Gas flows only North to Zone
5 and North to Zone 6
6
Gas flows from Zone 5 to
Gas flows from Zone 4 to
Zone 6: 6 (0.66%)
443 (48.89%)
Zone 5
No gas flows from Zone 5 to
Zone 6: 58 (6.39%)
Gas flows from Zone 5 to
Zone 4 and the null point is in
40 (4.41%)
0 (0.0%)
Zone 4
Gas flows from Zone 5 to
Zone 4 and the null point is to
1 (0.11%)
0 (0.0%)
the southwest of Station 90
No gas flows between Zone 4
174 (19.20%)
0 (0.0%)
and Zone 5
Table 5.2
Station 195 gas flows only South to Zone 5
Gas flows from Zone 6 to
No gas flows from Zone 6 to
Zone 5
Zone 5
Gas flows from Zone 4 to
4 (0.44%)
4 (0.44%)
Zone 5
Gas flows from Zone 5 to
Zone 4 and the null point is in
24 (2.64%)
8 (0.88%)
Zone 4
Gas flows from Zone 5 to
Zone 4 and the null point is to
26 (2. 86%)
0 (0%)
the south of Station 90
No gas flows between Zone 5
7 (0.77%)
1 (0.11%)
and Zone 4
40
Pipeline Previous Constrained East of Station 190 Scenarios
Table 5.3
Station 195 Scenario: gas flows North from Injection Point to
Zone 6; Gas flows from Zone 5 to Zone 6
Constraint remains after the
Constraint is eliminated after
injection at Station 195
the injection at Station 195
Gas flows from Zone 4 to
Zone 5
26 (2.86%)
28 (3.08%)
Station 195 Scenario: Gas flows South, no flow from Zone 6 to
Zone 5
Gas flows from Zone 4 to
Zone 5
0
3 (0.33%)
Station 195 Scenario: Gas flows north from injection point to
Zone 6; No gas flows from Zone 5 to Zone 6
Gas flows from Zone 4 to
Zone 5
1 (0.11%)
16 (1.76%)
Station 195 Scenario: Gas flows from the injection point both
south to Zone 5 and north to Zone 6
Gas flows from Zone 4 to
Zone 5
9 (0.99%)
27 (2.97%)
Table 5.4 summarizes the geographic distribution of economic null points with the
operation of Atlantic Sunrise during the modeled time period. We estimate that Station 195
would have been the null point slightly over three quarters of the time.
Table 5.4
Null Point Summary
Location of Null Points
Station 90
Zone 4
Zone 4/5 Border
Zone 5
Both Station 195 and Zone 4
Both Station 195 and Zone 4/5
border
Both Station 195 and Zone 5
Both Station 195 and Station 90
Zone 6
41
Number Percentage
28
3.1%
32
3.5%
8
0.9%
9
1.0%
40
4.4%
174
19.2%
479
1
135
52.9%
0.1%
14.9%
B. Welfare Analysis
We calculate the impact of Atlantic Sunrise on consumer surplus across Zones 4, 5 and 6
for the period January 1, 2012 to June 27, 2014, or two and a half years. Table 5.5 summarizes
our results by month across the three zones.
There are about $46 million in gains for consumers estimated for January, 2012, largely
from reducing or eliminating the bottleneck east of Station 90. (In our model, Zone 4 gains only
come about by reducing or eliminating the bottleneck problem in Alabama.) For most of the rest
of the year, however, we estimate no gains in the relevant zones from the Atlantic Sunrise project.
What is occurring there is that the new injection of gas is simply serving to displace gas that was
flowing east of Station 90. In theory, that should have resulted in relatively small consumer
gains in Zone 6. Those gains in our model, however, were offset by the assumed cessation of
uneconomic flows of gas to Zone 6.
In January and February 2013, there were about $183 million worth of gains to
consumers from reducing or eliminating the Station 90 bottleneck. From June to October that
year there are about $212 million worth of consumer gains, as the new injection of gas either
results in exports from Zone 5 to Zone 4, or results in lower Zone 5 price such that imports from
Zone 4 were eliminated.
The largest gains from Atlantic Sunrise arise from extreme periods such as the polar
vortex of January 2014. Consumer gains from January to March 2014 were estimated to be
about $2.1 billion, with $1.6 billion occurring in January of that year. There are additional gains
on the order of $59 million later that year, as there were days where shipments from Zone 4 to
Zone 5 would have been eliminated, or gas would have flown from Zone 5 to Zone 4.
From April to June of 2014 the price of gas in Zone 4 was extremely low (often below
$3/MMBtu). In these circumstances, the Atlantic Sunrise project would have permitted low cost
Zone 6 gas to be transported to Zone 5. Thus, prices rise and consumer surplus falls in Zone 6 on
those days.
Table 5.5
Impact of Atlantic Sunrise on Consumer Surplus by Month
($000)
Month
Jan-12
Feb-12
Mar-12
Apr-12
May-12
Jun-12
ΔConsumer ΔConsumer ΔConsumer
Total
Surplus
Surplus
Surplus
ΔConsumer
Zone 4
Zone 5
Zone 6
Surplus
$4,769
$10,529
$30,768
$46,067
$1,987
$4,118
$6,529
$12,634
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$0
$253
$253
42
Jul-12
Aug-12
Sep-12
Oct-12
Nov-12
Dec-12
Jan-13
Feb-13
Mar-13
Apr-13
May-13
Jun-13
Jul-13
Aug-13
Sep-13
Oct-13
Nov-13
Dec-13
Jan-14
Feb-14
Mar-14
Apr-14
May-14
Jun-14
Total
$0
$0
$0
$0
$446
$2,608
$14,864
$5,434
$226
$0
$0
$0
$0
$0
$0
$0
$6,334
$8,958
$314,306
$27,662
$31,771
$0
$0
$0
$419,365
$0
$0
$66
$0
$998
$5,415
$35,146
$12,470
$463
$0
$1,654
$9,766
$8,422
$15,355
$17,595
$15,479
$18,762
$22,051
$752,464
$58,104
$80,735
$12,466
$25,310
$23,956
$1,131,324
$124
$14
$627
$290
$3,995
$8,347
$90,182
$25,838
$3,925
$434
$6,611
$25,866
$20,029
$31,674
$39,069
$29,219
$5,150
$39,495
$583,864
$181,535
$120,391
$3,296
-$41,314
-$67,901
$1,148,310
$124
$14
$693
$290
$5,439
$16,370
$140,192
$43,742
$4,614
$434
$8,265
$35,632
$28,451
$47,029
$56,664
$44,697
$30,247
$70,504
$1,650,634
$267,301
$232,897
$15,762
-$16,004
-$43,945
$2,699,000
Table 5.6 summarizes some of the results of Table 5.5. Slightly over 61 percent of
consumer gains would have occurred in the cold month of January 2014. A relatively small
amount of gains, on the order of $81 million, would have occurred in 2012, while a $510 million
increase in consumer surplus would have happened in 2013. The bulk of the gains, $2.1 billion,
would have occurred in the first half of 2014.
43
Table 5.6
Summaries of Impact of Atlantic Sunrise on Consumer Surplus ($000)
Month
% from January 2014
Total from 2012
Total from 2013
Total from first six months of
2014
Total from January 2012 to June
2014
ΔConsumer ΔConsumer ΔConsumer
Surplus
Surplus
Surplus
Zone 4
Zone 5
Zone 6
74.95%
66.51%
50.85%
$9,810
$21,126
$50,947
$35,816
$157,163
$317,492
Total
ΔConsumer
Surplus
61.16%
$81,884
$510,471
$373,739
$953,035
$779,871
$2,106,645
$419,365
$1,131,324
$1,148,310
$2,699,000
We note that our results serve to underestimate the positive benefits of Atlantic Sunrise
for two reasons. First, we have assumed elasticities of supply for connecting pipelines that
appears rather high, due to a lack of empirical evidence on the question. A high elasticity of
supply for connecting pipelines means a higher substitution away from supplying the Transco
line when Atlantic Sunrise comes into operation, and hence higher implied prices for consumers.
Second, our model assumes away uneconomic flows. We have found a number of instances
where gas will flow, say from Zone 4 to Zone 5, even though the price of gas in Zone 5 is less
than the price of gas in Zone 4 plus the relevant transport costs. This serves in our modeling to
reduce the supply of gas to Zones 5 and 6, partially (or some days, more than outweighing) the
impact of Atlantic Sunrise on prices in Zones 5 and 6.
VI.
Conclusion
The Atlantic Sunrise project would affect operation of the Transco pipeline system in two
ways. First, it would permit additional deliveries from the Marcellus to the Transco system.
Second, it would afford more flexibility in the Transco system, with the ability to engineer flow
reversals in response to market conditions. We have modeled the market impact of the Atlantic
Sunrise project on flows and prices across the Transco system, focusing on the impact in Zones 4,
5 and 6.
Our modeling approach involved comparing prevailing market conditions during the
period January 1, 2012 to June 27, 2014 with a simulated market that incorporated the additional
system capacity from Atlantic Sunrise. Over this 30-month period, we estimate that consumers in
Zones 4, 5 and 6 would have enjoyed about $2.6 billion in total benefits because of the Atlantic
Sunrise expansion. These benefits would have accrued due to lower prices and the opportunity
for additional natural gas consumption (which is itself partially a consequence of lower prices).
While we estimate that consumers would benefit overall from the Atlantic Sunrise, we
wish to emphasize some specific aspects of our findings.
44
First, the benefits to consumers are not uniform over time and will vary greatly with
system conditions. As Table 5.6 shows, more than 60% of the estimated benefits of Atlantic
Sunrise would have accrued in January 2014 alone, because of the high level of gas demand
associated with the polar vortex. This finding in particular needs to be projected forward with
care. Consumer benefits during the wintertime will generally be higher than in other seasons
because of increased heating demand, but we estimate that these benefits would be roughly six to
twenty times larger during very cold winters than during normal winters. If very cold winters
become relatively uncommon, the consumer benefits of Atlantic Sunrise will be correspondingly
smaller over time. Similarly, if wintertime natural gas demand rises (due to cold weather,
increased demand from power plants or other factors), this will greatly the consumer benefits of
Atlantic Sunrise.
Second, the benefits to consumers are not uniform over space. Consumers in Zones 4 and
5, which would be the recipients of additional Marcellus gas flowing south due to Atlantic
Sunrise, would nearly always benefit from the pipeline expansion project. Because of the
location of the constraints at Stations 90 and 195, we estimate that Zone 5 customers would
benefit nearly three times as much as Zone 4 customers. Zone 6 customers exhibit the highest
benefits overall (across our 30-month estimation period), but will also be harmed during certain
periods when exports form Zone 6 to Zone 5 cause prices in Zone 6 to increase. These price
increases in Zone 6 occur only during these export periods, and are orders of magnitude smaller
than the price declines in other zones (and price declines during Zone 6 during periods when no
exports occur) that can be expected during cold winter days once the Atlantic Sunrise project
becomes operational.
Third, predictions of how Atlantic Sunrise will affect market outcomes are sensitive to a
number of factors. Our model uses standard economic logic to identify likely market outcomes
under a variety of conditions, but the nature of the equilibrium is very sensitive to prevailing
system conditions, particularly regarding constraints at Station 90.
References
Hefner, Robert A., III, “The United States of Gas: Why the Shale Revolution Could Have
Happened Only in America,” Foreign Affairs, May-June 2014, 93:3, 9-14.
Joskow, Paul L., “Natural Gas: From Shortages to Abundance in the United States”, American
Economic Review, 2013, 103:3, 338-43.
Kleit, Andrew N., “Defining Electricity Markets: An Arbitrage Approach”, Resource and Energy
Economics, 2001, 23, 259-270.
Ponce, Micaela, and Anne Neumann, “Elasticities of Supply for the US Natural Gas Market”,
2014, http://www.diw.de/documents/publikationen/73/diw_01.c.441773.de/dp1372.pdf (German
Institute for Economic Research).
Ruff, Larry, "Rethinking Gas Markets - and Capacity", Economics of Energy and Environmental
45
Policy, 2012, 1:3, 1-13.
46
Appendix
Table A-1
Existing Suppliers on the Transco pipeline Northeast of Station 90
Before Atlantic Sunrise on January 28, 2014
Zone
Milepost
Supplier
Injections
(MMBtu)
Total
Injections by
Zone (MMBtu)
on January 28,
2014
ZONE
4
890.510
Black Warrior Basin (AL)
25,568
25,568
1356.970
ZONE
5
1384.860
1519.910
1575.780
1678.740
1784.640
ZONE
6
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1789.550
1808.180
1825.700
1825.730
1826.390
Pine Needle Lng Plant Outlet
(NC)
Cascade Creek
Boswells Tavern (VA)
Nokesville
Lower Chanceford (PA)
Lambertville Oakford Receipt
(NJ)
Carverton (PA)
Puddlefield
Chapin
Marc I Exchange
Barto
Quaker State
Miller Hill
Liberty Drive
Guinter
Canoe Run
Tombs Run
Breon
Bull Run Vista 2
Rattlesnake
Grugan 2
Dry Run
Leidy Transport
Leidy Storage
Wharton Storage
Linden Oakford (NJ)
Boil Off East Rutherford #2
Sta. 240 Regeneration Gas
Rivervale
47
363,363
357,113
255,538
72,967
831,781
1,048,981
75,631
69,972
601,438
520,050
287,552
113,204
24,221
213,157
243,134
188,981
97,654
283,300
220,196
77,219
1,154
92,449
11,079
181,277
45,852
165,069
96,975
341
11,541
210,031
4,663,258