2014 Gas Outlook
Natural Gas Supply, Demand, Capacity and
Prices in the Pacific Northwest
Projections through October 2023
This report, compiled by the Northwest Gas Association (NWGA) and
its members, provides a consensus industry perspective of the Pacific
Northwest’s current and projected natural gas supply, demand, prices
and delivery capabilities through 2023. The Pacific Northwest in this case
includes British Columbia (BC) and the U.S. states of Washington, Oregon and
Idaho. Additional information, including white papers on specific natural gas
topics, can be found at www.nwga.org.
N W G A
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G A S
O U T L O O K
1
What’s New
From scarcity to abundance, the transformation of North
America’s energy landscape is remarkable. Our ability to extract
The Pacific Northwest, ideally positioned between
two prolific natural gas producing areas, is already
that can power our economy
reaping the benefits of this profuse gas supply.
with less of the carbon pollution
Manufacturers and other large natural gas consumers
that causes climate change.”
are considering locating or expanding in the region,
– President Barack Obama, 2014
Because of energy resources derived from shale,
spurred by access to low-cost supply. Likewise,
State of the Union Address
North America now has the potential to realize
regional electrical utilities are taking advantage of this
hydrocarbons (e.g., oil, natural gas, propane, butane, etc.) from
shale rock formations deep underground is creating supplyside shocks that reverberate across global energy markets.
its long-sought goal of energy independence.
economical, cleaner-burning fuel, proposing natural
In the meantime, projected long-term low
gas-fired plants as one means to reduce greenhouse
prices of these resources are attracting
gas emissions and achieve environmental objectives.
capital and infrastructure for a U.S.-based
The long-range affordability of natural gas continues
industrial renaissance and spurring
to drive this shift in thinking about the role of natural
investment in rapidly developing natural
gas in our region’s environment and economy. While
gas transportation options. At the same
prices are higher than a year ago, natural gas remains
time, energy-related greenhouse
gas emissions in the U.S. have been reduced
to a level not seen in more than a decade, in part
because of increased substitution of natural gas for
coal in power generation.1
an energy value especially when compared to its
price levels of just five years ago and to the current
price of substitute fuels. Then, expectations were that
natural gas prices would range between $7 and $10
per thousand cubic feet (Mcf ), or dekatherm (Dth)2,
U.S. EIA, Monthly Energy Review - U.S. Carbon Dioxide Emissions from Energy Consumption, November 2013
An Mcf is a volumetric measure. A Dth is a measure of energy content representing one million British Thermal Units (Btu). While the energy content of a Mcf varies according to a variety of factors,
it is roughly equivalent to a Dth (typically 0.95 to 1.05 Dth per Mcf ). For this study, volumetric measures (thousand, million and billion cubic feet; Mcf, MMcf, Bcf ) are used interchangeably with energy
measures (dekatherm, thousand dekatherm, million dekatherm; Dth, MDth, MMDth).
1
2
N W G A
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G A S
“[Natural gas is] the bridge fuel
O U T L O O K
“Since 2000, the oil and gas sector
has spent more on low and
zero-carbon technologies than
the federal government and all
other industries combined. Since
1990, the industry has invested
more than $250 billion toward
improving the environmental
performance of its products,
facilities and operations.”
– Jack Gerard, CEO, American
Petroleum Institute, 2014 State of
American Energy
2
and would only increase over time. Today, the U.S. Energy
coal-fired power generation (i.e. Boardman, Centralia) with
North America’s new reality of affordable,
Information Administration (EIA) projects that the average
natural gas.
abundant natural gas requires new thinking
Another new element, added to the Infrastructure
and visionary policies. Many existing natural
section, is a comparison and brief analysis of the preferred
gas regulations were developed during a time
represent a modest uptick across most sectors, reflecting
resource acquisition strategies dictated by the respective
when natural gas was perceived to be scarce
generally better economic conditions (see 2014 Regional
integrated resource plans (IRP) of each NWGA member
and market fundamentals were different than
Economic Outlook, on p. 12). Industrial demand appears to
company. Assembling and locating this information centrally
be perking up while gas use for generating electricity shows
in the Outlook study will help to inform the respective
Policymakers, local communities, natural
the most rapid growth rate among the sectors. Interestingly,
NWGA member company planning processes and other
gas utilities and customers must collaborate
while growth rates are the same or higher than in the 2013
stakeholders.
to facilitate the creation of new markets
annual price of natural gas won’t exceed $7 before 2035.
The demand growth projections in this 2014 Outlook
Outlook, actual volumes projected for the residential and
Finally, gas companies utilize a number of assumptions
they are today.
and demand for this increasingly important
to help understand their resource requirements and plan
fuel source. We all stand to gain if we make
their systems accordingly. Identifying extreme but plausible
investments and update our policies now to
Study. To better capture anticipated but not-yet-planned-for
weather conditions is a critical part of satisfying their
realize the full potential of a natural gas-
regional demand, the Demand section includes a couple
obligation to serve core customers (residential, commercial
fueled future.
of reasonable future demand scenarios. The first is a more
and firm industrial consumers). Appendix B provides a matrix
For more information, visit www.
aggressive regional response by existing and new industrial
summarizing some of the key planning assumptions of the
fuelingthefuture.org.
consumers to lower and more stable natural gas prices. The
region’s natural gas utilities.
generation sectors are lower.
Readers will notice a few new features in this Outlook
second scenario examines the effect of replacing existing
N W G A
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G A S
O U T L O O K
3
Executive Summary
Based on analysis of our members’ data, we have arrived at a reasonable projection
of what the natural gas market may look like in the Pacific Northwest over the next 10
years. Here are our key conclusions and some of the issues we are following closely.
Supply
Prices
Demand
Key Conclusions
Key Variables
Key Conclusions
Key Variables
Key Conclusions
t 5IFFOPSNJUZPG/PSUI
America’s natural
gas resource, made
available by extracting
hydrocarbons from
shale rock formations
deep underground, is
fundamentally changing
the energy landscape.
t 5IFEFWFMPQNFOUPGOFX
or improved production
technologies and
techniques.
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rebounded in 2013 but
continue to reflect an
abundance of North
American natural gas.
t 8IFUIFSGVUVSFSFHVMBUJPOT
add to the cost of
production or limit access
to reserves.
t 8IJMFHSPXUISBUFTJOUIF t 5IFBEFRVBDZPGOBUVSBM
Pacific Northwest over this
gas infrastructure to
forecast period remain
support regional growth
about the same as in the
opportunities.
2013 Outlook, annual
t 5IFNBHOJUVEFBOEOBUVSF
volumes start lower.
of the growing use of
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natural gas for generating
showing signs of life in the
electricity to serve growth,
region with higher loads
balance the system and
and a faster rate of growth
transition from coal.
than projected in the 2013 t 5IFQPTTJCJMJUZPGOFX
Outlook.
industrial loads (including
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continues to exceed
expectations despite
lower natural gas prices,
reallocation of capital
and concerns over shale
production techniques.
t 1BDJmD/PSUIXFTUOBUVSBM
gas consumers benefit
from their proximity to the
prolific Western Canadian
Sedimentary Basin (WCSB)
and U.S. Rocky Mountain
(Rockies) natural gasproducing regions.
N W G A
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G A S
t 5IFFõFDUPGDPNNPEJUZ
prices on investments
in exploration and
production (E&P),
and hence on future
production.
t 5IFJNQBDUFOWJSPONFOUBM
concerns may have on
natural gas production.
t -PDBMBOEOBUJPOBM
legislation affecting
production/extraction
processes.
O U T L O O K
t .PTUMPOHUFSNQSJDF
forecasts have declined
significantly since 2008
when large volumes of
natural gas from shale
began to affect the
market.
t 1BDJmD/PSUIXFTU
consumers benefit from
less price competition
with eastern markets as
the flow dynamics of
natural gas shift from
traditional producing
regions to geographically
diverse shale plays.
t 5IFQPUFOUJBMFõFDUPGOFX
and improved production
technologies.
t 5IFQBDFPGBEPQUJPO
of natural gas for power
generation, industrial and
transportation uses.
t 5IFQBDFPGFDPOPNJD
growth.
t 5IFQSJDFJNQBDUTPG
changing natural gas flows
across North America.
t 5IFFõFDUPGQJQFMJOFBOE
storage constraints on
regional pricing.
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North American natural
gas exports to premium
overseas markets.
Key Variables
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exports) due to sustained
could significantly affect
lower natural gas
demand during the
commodity costs.
forecast period. This
t 5IFTJHOJmDBOUSFHJPOBM
Outlook explores two
growth potential for natural
plausible scenarios: some
gas as a transportation fuel
replacement of regional
in a variety of applications.
coal-fired generation with
t 5IFJNQBDUPGGVUVSF
natural gas and accelerated
energy policies on
industrial demand.
demand, particularly GHG
legislation.
(See the Demand chapter for discussion of two scenarios
exploring the impact of these variables.)
4
Capacity
Key Conclusions
Putting the Pieces Together
Key Variables
t 5IFFYJTUJOHTZTUFNPGOBUVSBMHBT
t 8IFOXIFSFBOEIPXNVDIOBUVSBMHBT
pipelines and storage facilities has
will be needed for generation to meet
reliably served the load requirements
growing base load power demand and
of the region for decades and is
peaking capacity to support intermittent
sufficient to meet today’s needs.
renewable sources of generation.
t "EEJUJPOBMDBQBDJUZJTMJLFMZUPCF
t *NQBDUTPGUIFSFHJPOTDIBOHJOH
required within the forecast horizon
load profile on existing natural gas
to serve new demand for natural gas,
infrastructure. For example, the generation
particularly on a peak (design) day.
facilities planned to replace coal-fired
Industrial and generation demand
power and new industrial facilities could
above the expected case will
require significant capacity. Where existing
amplify and accelerate the need for
pipelines are underutilized, their load
incremental capacity.
factors would increase. As annual load
factors and peaking requirements increase,
t 3FHJPOBMQJQFMJOFBOETUPSBHF
expansion will be needed.
expansions have been undertaken
to maintain or enhance system
reliability in response to increases in
base load and peak day demand.
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of future capacity expansions or
additions, and utilization of existing
infrastructure, will depend on the
changing nature of regional natural
gas demand.
t 8IFUIFSFYJTUJOHSFHVMBUPSZIVSEMFTBSF
eased to allow construction of new or
expanded infrastructure in a timely manner
to address capacity shortfalls. Projects can
take multiple years to develop, making
foresight imperative.
t 5IFJNQBDUPOSFHJPOBMJOGSBTUSVDUVSFBOE
gas flows if one or more West Coast LNG
export terminals are built.
The profusion of natural gas and an expectation that its price will remain affordable over
time is creating opportunities for incremental natural gas use across North America. The
Pacific Northwest is well situated to take advantage of this low-cost abundance to address
a number of objectives, including economic growth, reducing air pollution and improving
public health.
Faced with modest growth prospects, regional gas utilities are looking at creative
ways to expand uses for this relatively clean-burning resource. A variety of projects are
under consideration or being developed, especially in the transportation sector. Regional
policymakers are also beginning to ask how the benefits of natural gas might be extended to
currently unserved communities or expanded within constrained areas.
Finally, how the current infrastructure is utilized or expanded remains an open question.
The only certainty is that the existing system will need to be augmented at some point to
accommodate additional and potentially more variable demand. The market will determine
the type and timing of infrastructure projects as new capacity users emerge.
Houses of Tomorrow
are more energy efficient,
use all natural gas
appliances and have direct
access to natural gas.
Clothes Dryer
4.4 Dth/yr
in full-fuelcycle energy
consumption
Cooking Equipment
Natural gas unit
3.8 Dth/yr in fullfuel-cycle energy
consumption
N W G A
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G A S
O U T L O O K
5
2014 GAS OUTLOOK –
A Closer Look
Supply
From scarcity to abundance, the scope
and scale of the North American natural gas
resource continues to astonish observers.
Key Conclusions
t 5IFFOPSNJUZPG/PSUI"NFSJDBTOBUVSBMHBTSFTPVSDFNBEFBWBJMBCMFCZFYUSBDUJOH
Geographically spread across North
hydrocarbons from shale rock formations deep underground, is fundamentally changing America (Figure S1), shale rock formations
the energy landscape.
located several thousand feet below the
surface of the earth are the source of
t /BUVSBMHBTQSPEVDUJPODPOUJOVFTUPFYDFFEFYQFDUBUJPOTEFTQJUFMPXFSOBUVSBMHBT
hydrocarbons like oil, natural gas and natural
prices, reallocation of capital and concerns over shale production techniques.
gas liquids. Essentially petrified mud, the
t 1BDJmD/PSUIXFTUOBUVSBMHBTDPOTVNFSTCFOFmUGSPNUIFJSQSPYJNJUZUPUIFQSPMJmD
low permeability of shale rock prevents
Western Canadian Sedimentary Basin (WCSB) and U.S. Rocky Mountain (Rockies) natural
hydrocarbons from readily flowing using
gas-producing regions.
traditional production methods.
That is why the production of
FIGURE S1. North American Shale Formations
hydrocarbons from shale was, until recently,
impractical and uneconomic. Traditional
production taps into more permeable
rock formations like sandstone into which
hydrocarbons migrated over millennia from
the shale formations situated below.
The innovative application and improved
efficiencies of decades-old production
technologies changed all that, making
it economically possible to unlock vast
reserves of natural gas, oil and other
hydrocarbons. Estimates of the total
available North American natural gas
resource have skyrocketed over the last
several years. In 2012, the U.S. Potential Gas
Committee (PGC) increased its estimate
of the total remaining U.S. gas resource by
more than 25 percent over its 2010 report
(Figure S2).3
FIGURE S2. Comparison of PGC Resource Estimates Since 1990
3,000
2,384
Trillion Cubic Feet
2,500
2,000
1,073
Shale resource not assessed separately
1,500
1,119
1,003
1,000
500
147
147
146
141
155
169
147
169
166
856
854
881
921
897
936
958
950
955
0
Traditional
Potential Gas Committee, Potential Supply of Natural Gas in the United States, April 2013. PGC is an independent, non-profit
organization that has been estimating U.S. natural gas reserves since the early 1960s.
3
N W G A
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G A S
O U T L O O K
~200
Coalbed
Shale
616
687
163
159
1,057
1,052
158
1,153
6
Canada’s National Energy Board (NEB)
upped its estimate of the remaining marketable Canadian natural gas resource from
424 trillion cubic feet (Tcf ) in 2011 to 1,093
Tcf in 2013, a staggering increase of more
than 250 percent.4 As a result, natural gas
from shale rock formations has changed
the conversation from one of limited and
declining supplies just a handful of years
ago, to one of abundance and opportunity
today. North American natural gas resources are now estimated to be sufficient for
many generations to come.
According to Navigant Consulting,
shale plays made up 6 percent of North
American natural gas supply in 2007, and
are expected to make up more than 60
percent of overall production by 2035
FIGURE S3. Shale Plays Dominate Future North American Gas Production
(Figure S3). U.S. natural gas production grew
more than 7 percent in 2011, the largest
year-over-year volume increase in history,
and almost 6 percent in 2012. A similar shift
from traditional to shale and tight sands gas
production is occurring in British Columbia
(BC).
Actual production of natural gas from
shale formations continues to exceed
expectations despite a soft market. It is
difficult to keep pace with the industry
as producers introduce new or enhanced
technologies and dial in the most effective
techniques for producing from each
particular field. Figure S4 illustrates this
difficulty by plotting recent forecasts of
natural gas production from shale against
actual production.
FIGURE S4. U.S. EIA Forecasts and Actual Shale Production
130
25.0000
Shale
Non-Shale
Net LNG Imports
110
20.0000
BCf/day
70
Bcfd
90
50
Tcf/year
15.0000
10.0000
30
5.0000
0.0000
-10
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
10
Actual
Shale
Non-Shale
Source: Navigant Consulting Inc.
4
2010 AEO
2012 AEO
2014 AEO (ER)
Net LNG Imports
Source: U.S. EIA
Forecast - Annual Energy Outlook (AEO)
Actual - Annual Natural Gas Gross Withdrawals and Production, Dec 2013
Canada National Energy Board, Canada’s Energy Future 2013, November 2013
N W G A
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G A S
O U T L O O K
7
In the Pacific Northwest, we are immediately adjacent to and supplied by two large
natural gas production areas (Figure S5).
The WCSB includes the Canadian provinces
of BC and Alberta, while the relevant Rockies producing states are Colorado, Utah
and Wyoming. The region typically receives
more than 50 percent of its gas from the
WCSB while the remainder comes from
the Rockies. The ability to source gas from
different areas gives regional consumers
purchasing options. Figure S6 illustrates the
proportion of gas sourced from each, which
typically depends on a combination of the
lowest commodity price along with available pipeline capacity.
Combined, these two production areas
produced an average of 25 billion cubic
feet per day (Bcf/d) in 20125, or 30 percent
of North America’s total natural gas supply.
FIGURE S5. Supply Regions Serving the Pacific Northwest
FIGURE S6. Annual Supply Diversity in the Pacific Northwest
Horn River
Shale Gas Cordova
Embayment
100%
9%
9%
8%
9%
9%
8%
9%
9%
8%
7%
A L B E RT A
Montney
Tight Gas
Fort St. John
$8.00
80%
Western Canadian
Sedimentary Basin
Percentage
70%
B R I T I S H
C O L U M B I A
Duvernay
37%
36%
46%
41%
48%
51%
43%
38%
37%
$5.00
$4.00
0%
Kingsgate
O R E G O N
Big Horn
I D A H O
Boise
Klamath
Falls
Malin
31%
34%
40%
44%
42%
$3.00
$2.00
10%
8%
8%
9%
10%
10%
10%
8%
10%
2003
2004
2005
2006
2007
2008
2009
2010
2011
Alberta
Domestic
British Columbia
Storage
14%
2012
18%
2013
$1.00
$0.00
Alberta/Stanfield Prices
Rockies/Opal Prices
British Columbia/Sumas Prices
WY O M I N G
Pocatello
Salt Lake City
N E V A D A
Wind River
DenverJulesburg
Uinta
Piceance
U T A H
Paradox
G A S
Powder
River
Green
Overthrust River
C A L I F O R N I A
2 0 1 4
33%
35%
M O NT A N A
Bend
N W G A
Bakken
NWGA MEMBER Pipelines
Other Pipelines
Natural Gas Supply Basins
Spokane
Portland
Medford
43%
46%
10%
W A S H I N GT O N
Wenatchee
44%
40%
20%
Calgary
$7.00
$6.00
48%
50%
30%
Vancouver
Sumas
Victoria
34%
60%
40%
Seattle
$9.00
8%
90%
Fort Nelson
ALASKA
a growth pattern in the latter years as
new markets open up and commodity
prices improve. More specifically, currently
declining production of conventional
reserves in Alberta will be offset by
expanding shale and tight sands
production in the large Montney and Horn
River plays in northeast BC and continued
development of shale in the U.S. Rockies
(Figures S7 and S8).
Prices
Liard
Put this into perspective, the Northwest
uses a little more than 3 Bcf/d on average
through the winter months (November
through March), although that number can
go significantly higher when the weather
becomes unusually cold.
Production from these two areas is
expected to be about 26 Bcf/d by 2023.
Production in both regions will decline
slightly in the near future before resuming
O U T L O O K
C O L O R A D O
5
Statistics Canada, Table 131-0001 – Annual Supply and Disposition of Natural Gas, 2012; U.S. EIA, Natural Gas Production by State (CO, UT, WY),
December 2012
8
FIGURE S7. WCSB Production Forecast6
Key Natural Gas Supply Variables
18
The natural gas supply picture is a rosy one today and is expected to remain that way for
the foreseeable future. NWGA members are monitoring a number of evolving issues that
could affect supplies, including:
16
14
t 5IFEFWFMPQNFOUPGOFXPSJNQSPWFEQSPEVDUJPOUFDIOPMPHJFTBOEUFDIOJRVFT
Bcf/day
12
t 5IFFõFDUPGDPNNPEJUZQSJDFTPOJOWFTUNFOUTJOFYQMPSBUJPOBOEQSPEVDUJPO&1
BOE
hence on future production.
10
t 5IFJNQBDUFOWJSPONFOUBMDPODFSOTNBZIBWFPOOBUVSBMHBTQSPEVDUJPO
8
t -PDBMBOEOBUJPOBMMFHJTMBUJPOBõFDUJOHQSPEVDUJPOFYUSBDUJPOQSPDFTTFT
6
4
BC contribution to total WCSB production
2
0
WCSB Low
WCSB High
WCSB Reference Case
BC Reference Case
FIGURE S8. U.S. Rockies Production Forecast7
16
EIA adjusted to exclude San Juan, Raton, Paradox, and Williston Basins
14
Gas Production (Bcf/day)
12
10
8
6
Production Growth 2013 to 2023 = 2.9 Bcf/d
4
2
0
2010
2011
2012
2013
Kinder Morgan Forecast
Kinder Morgan Low
2014
2015
2016
2017
2018
2019
2020
EIA 2013 AEO – Adjusted to Wellhead
Kinder Morgan High
2021
2022
2023
Canada National Energy Board, Canada’s Energy Future 2013, November, 2013
Kinder Morgan, 2013 Rockies Production Forecast, September 2013
6
7
N W G A
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G A S
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9
BC Gas Supply Outlook
It’s long been known that BC is a major natural
gas supplier, but a report released in 2013 turned gas
resource estimates upside down. It’s not that past
projections were overstating things – rather, that they
were grossly conservative. The joint federal-provincial
government study (by the National Energy Board, BC Oil
and Gas Commission, the Alberta energy regulator and
the BC Ministry of Natural Gas Development), released
in November 2013, more than doubles the estimated
amount of unconventional gas resources in BC.
This radical change in estimates of the provincial
gas supply is the result of gas producers applying new
technology to develop unconventional gas economically.
Enormous volumes in northeast BC are now dominating
the energy supply portfolio. Specifically, there are large
volumes of shale gas in the Horn River Basin, the Liard
Basin, and the Cordova Embayment, and tight gas in the
Montney Formation.
Similar to the shale gas and tight gas surge in other
producing areas of North America, such as the Marcellus
in Pennsylvania and the Eagle Ford in Texas, BC’s gas
production and resource estimates have experienced
growth over the last few years.
8
Gas in place means estimated quantities of natural gas that exist in a reservoir including both
recoverable and unrecoverable volumes given existing production technologies. The data in
this sidebar relate to BC only.
N W G A
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G A S
O U T L O O K
Before 2009, unconventional gas in North America was
not established commercially and gas supply estimates
were limited to conventional gas resources. In BC, it was
estimated less than 20 Tcf was in place. Now, with the
inclusion of shale gas and tight gas, BC has more than
2,700 Tcf of estimated gas in place.8
Estimates of unconventional gas will continue to
change as new wells are developed and technology
advances. Current production from most unconventional
gas reservoirs only covers a portion of the entire reservoir
and there is risk when applying these results over broader
areas. However, as geologic understanding evolves and
new technologies are made available, new resources
become economic. For example, from 2009 to 2012 the
Montney Formation was estimated to contain 410 Tcf
gas in place. Now, based on the research done in 2013,
the estimate is over 1,900 Tcf gas in place. That places the
Montney play among the top natural gas basins in the
world.
– Prepared by Brian Morse, Gas Supply Manager – Spectra
Energy Transmission
10
2014 GAS OUTLOOK -
A Closer Look
Natural Gas Prices
Natural gas prices fell to their lowest
levels in more than a decade in early 2012.
gas at the Henry Hub averaged almost $9
per Dth (Figure P1).
Key Conclusions
This reflected both high supply and low
demand due to a warmer than normal
winter that year. According to the EIA, the
spot price of natural gas rebounded in
2013, averaging $3.73 per Dth at the Henry
Hub9 compared to $2.75 in 2012. Current
commodity prices demonstrate a continuing
surplus of natural gas supply across North
America, in stark contrast to the period
preceding the advent of the enormous shale
resource. In 2008, the spot price of natural
In addition, the price the market is
currently paying for future deliveries of
natural gas (futures) and short-term price
forecasts indicate that the supply surplus is
expected to continue for a few years (Figure
P2). Because utilities pass through (without
markup) the costs of purchasing natural gas,
Pacific Northwest consumers have saved
hundreds of millions of dollars since 2008.
Most longer term forecasts project
prices to average between $4 and $7/Dth
t 4QPUBOEGVUVSFTQSJDFTSFCPVOEFEJOCVUDPOUJOVFUPSFnFDUBOBCVOEBODFPG
North American natural gas.
t .PTUMPOHUFSNQSJDFGPSFDBTUTIBWFEFDMJOFETJHOJmDBOUMZTJODFXIFOMBSHF
volumes of natural gas from shale began to affect the market.
t 1BDJmD/PSUIXFTUDPOTVNFSTCFOFmUGSPNMFTTQSJDFDPNQFUJUJPOXJUIFBTUFSO
markets as the flow dynamics of natural gas shift from traditional producing regions
to geographically diverse shale plays.
FIGURE P1. Spot Price of Natural Gas at Henry Hub
FIGURE P2. EIA Short Term Price Forecast and NYMEX Futures Contract Prices
$14.00
$6.00
$12.00
$5.00
$10.00
$8.00
$/Dth
$/Dth
$4.00
$3.00
$6.00
NYMEX Gas Futures (2/13/14)
Dec-2015
Nov-2015
Oct-2015
Sep-2015
Jul-2015
Aug-2015
Jun-2015
May-2015
Apr-2015
Mar-2015
Jan-2015
Feb-2015
Dec-2014
Nov-2014
Oct-2014
Sep-2014
Jul-2014
Aug-2014
Jun-2014
May-2014
Apr-2014
Mar-2014
Jan-2014
Jan-2014
Jul-2013
Oct-2013
Jan-2013
Apr-2013
Jul-2012
Oct-2012
Apr-2012
Jan-2012
Jul-2011
Oct-2011
Apr-2011
Jan-2011
Jul-2010
Oct-2010
Apr-2010
Jan-2010
Jul-2009
Oct-2009
Apr-2009
Jan-2009
Jul-2008
$-
Oct-2008
$0.00
Apr-2008
$1.00
Jan-2008
$2.00
Feb-2014
$2.00
$4.00
EIA Short Term Energy Outlook (2/11/14)
9
The Henry Hub in Louisiana is the pricing point for natural gas futures on the New York Mercantile Exchange (NYMEX). Settlement
prices there are used as benchmarks for the entire North American natural gas market.
N W G A
2 0 1 4
G A S
O U T L O O K
11
through 2023 (2012$). Even factoring in a
growing economy, prices are not expected
to rise substantially in the next decade due
to the abundance of natural gas described
earlier (Figure P3).
Price-lowering volumes are but one
effect of shale gas. North American shale
plays are also geographically dispersed
across the continent. Because some of
the shale plays are also close to large
markets (e.g., Marcellus in Pennsylvania
and New York), there is less demand from
those regions for the resources the Pacific
Northwest depends upon. In addition,
the price risks associated with weatherrelated supply disruptions in more distant
and clustered conventional sources are
mitigated (e.g., hurricanes in the Gulf Coast
region).
Given continuing abundance of North American supply, consumers are likely to
benefit from relatively low natural gas prices for the foreseeable future. NWGA members
are tracking a number of market dynamics that could influence natural gas prices going
forward:
t 8IFUIFSGVUVSFSFHVMBUJPOTBEEUPUIFDPTUPGQSPEVDUJPOPSMJNJUBDDFTTUPSFTFSWFT
t 5IFFõFDUPGOFXBOEJNQSPWFEQSPEVDUJPOUFDIOPMPHJFT
t 5IFQBDFPGBEPQUJPOPGOBUVSBMHBTGPSQPXFSHFOFSBUJPOJOEVTUSJBMBOEUSBOTQPSUBUJPO
uses.
t 5IFQBDFPGFDPOPNJDHSPXUI
FIGURE P3. Long-Term Natural Gas Price Forecasts
t 5IFQSJDFJNQBDUTPGDIBOHJOHOBUVSBMHBTnPXTBDSPTT/PSUI"NFSJDB
$10.00
$9.00
t 5IFFõFDUPGQJQFMJOFBOETUPSBHFDPOTUSBJOUTPOSFHJPOBMQSJDJOH
$8.00
t #FOFmUTBOEDPTUTPG/PSUI"NFSJDBOOBUVSBMHBTFYQPSUTUPQSFNJVNPWFSTFBTNBSLFUT
$7.00
2012$/Dth
Key Natural Gas Price Variables
FORECAST
$6.00
$5.00
$4.00
$3.00
$2.00
Historic HH Spot Price
EIA 2014 AEO (ER) HH Forecast
N W G A
2 0 1 4
G A S
O U T L O O K
NWPCC AECO Forecast
NWPCC Sumas Forecast
NW Power & Conservation Council HH Forecast
2035
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
$0.00
2008
$1.00
12
Regional Economic Outlook for 2014
With U.S. and Canadian Gross Domestic Product
(GDP) growth crawling in around 2 percent for 2013,
North America can again bid “adieu” to another year
of unmemorable growth. As a result, inflation in both
countries has been lower than expected and allowed both
central banks to continue with accommodative monetary
policies. In turn, this allowed the U.S. housing recovery
to gain momentum. For 2014, most published forecasts
show GDP growth in both countries will be in the 2.4 - 2.8
percent range, with inflation in the 1 - 2 percent range.
U.S. GDP growth is predicted to be somewhat faster than
Canada’s.
However, there are hurdles to reaching the upper end
of this GDP forecast range. First, the European economic
recovery is fairly weak and could be undermined by
another debt crisis, and China is experiencing a growth
slowdown while transitioning to a new generation of
political leaders. Weak growth in Europe and China would
drag on North American export growth in 2014.
Second, U.S. and Canadian households are fiscally
constrained. U.S. households continue to experience slow
income growth, and Canadian household debt continues
to be at historically high levels. In the U.S., public sector
spending is also constrained by high debt levels and
national politics.
Finally, there are growing signals that the Federal
Reserve will reduce some asset purchases in 2014, which
will increase long-term U.S. interest rates. Given that U.S.
and Canadian interest rates tend to rise and fall together,
this will also put upward pressure on Canada’s long-term
rates. This could slow real estate and investment activity in
both countries.
Regionally, U.S. growth in the Pacific Northwest
will continue to be stronger in the urban areas around
Portland, Seattle and Boise. Following 2013, employment
growth in Idaho, Washington, and Oregon will continue
to track U.S. growth, which will probably be in the 1.5 - 1.8
percent range in 2014.
Due to a significant slowdown in the goods producing
sector, employment growth in BC will likely end 2013 near
zero, significantly below national growth, which will be
around 1.4 percent. The weak employment growth reflects
weak growth in new construction, consumer spending
and exports. Still, 4Q 2013 data for BC shows a rebound in
exports and manufacturing, suggesting that BC will see
stronger employment growth in 2014.
Sources: Bank of Canada, B.C. Stats, Bloomberg.com, Canada Mortgage and Housing
Corporation, Scotiabank, Statistics Canada, RBC, T.D. Economics, The Economist, U.S.
Bureau of Labor Statistics, U.S. Federal Reserve.
– Prepared by Grant D. Forsyth, Chief Economist – Avista Corp.
N W G A
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O U T L O O K
13
2014 GAS OUTLOOK -
A Closer Look
Regional Natural Gas Demand
Key Conclusions
t 8IJMFHSPXUISBUFTJOUIF1BDJmD/PSUIXFTUPWFSUIJTGPSFDBTUQFSJPESFNBJOBCPVUUIF
same as in the 2013 Outlook, annual volumes start lower.
t 5IFJOEVTUSJBMTFDUPSJTTIPXJOHTJHOTPGMJGFJOUIFSFHJPOXJUIIJHIFSMPBETBOEBGBTUFS
rate of growth than projected in the 2013 Outlook.
t "OVNCFSPGWBSJBCMFTDPVMETJHOJmDBOUMZBõFDUEFNBOEEVSJOHUIFGPSFDBTUQFSJPE
This Outlook explores two plausible scenarios: some replacement of regional coal-fired
generation with natural gas and accelerated industrial demand.
TABLE D1. Projected Regional Demand Growth through 2023
Total
Residential
Commercial
Industrial
Generation
Low
Annual Rate Cumulative
0.9%
8.7%
0.7%
6.7%
0.4%
3.9%
0.7%
6.5%
1.9%
18.6%
Expected
High
Annual Rate Cumulative Annual Rate Cumulative
1.5%
14.2%
2.2%
21.7%
0.9%
8.8%
1.1%
10.5%
0.8%
7.6%
1.2%
10.9%
0.9%
8.3%
1.0%
9.8%
3.3%
34.0%
5.0%
55.3%
According to the EIA, U.S. natural gas
consumption is expected to average a
record high 71.2 Bcf/d in 2013, an increase
of 1.5 Bcf/d (2.1%) from the previous year. In
2014, projected natural gas consumption is
expected to fall by 1.6 Bcf/d (2.2%) because
of the forecast 4.6% decline in heating
degree days and lower natural gas use by
the electric power sector. In 2015, natural
gas consumption is expected to rise again
by 1.4 Bcf/d with growth in use by the
industrial and electric power sectors.
Moderate economic growth continues
across the Pacific Northwest, affecting
projections for the demand of natural
gas across every sector (see the Regional
Economic Outlook sidebar preceding this
section). Natural gas consumption in the
Pacific Northwest is expected to grow
an average of 1.5 percent per year for a
total volume increase of 14.2 percent (114
million Dth) over the next 10 years (Table
D1). While the growth rate is generally
consistent with last year’s Outlook,
expected annual loads average about 1
percent lower than last year’s Outlook
and almost 17 percent lower than the
pre-recession 2008 Outlook. Much of the
growth is expected to come from gasfired electrical generation and an uptick in
anticipated industrial consumption. Core
market demand (residential, commercial) is
characterized by modest but steady growth
(Figure D1).
FIGURE D1. Expected Sector Demand
300
250
Million Dth
200
150
100
50
2013 Outlook Figures-6.xlsxFIGURE8
0
2013/14
280
N W G A
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O U T L O O K
260
2014/15
4/2/133:04 PM
2015/16
Industrial
2016/17
2017/18
Residential
2018/19
Generation
2019/20
2020/21
Commercial
2021/22
2022/23
14
Core Market (residential,
commercial) – Growth rates in the
residential and commercial sectors remain
about the same as last year (0.9 and 0.8
percent, respectively). Forecasted residential
volumes, however, start out 3 percent
lower than in the 2013 Outlook (Figure D2).
New housing construction, long a bastion
of dependable growth for the natural gas
industry in the region, continues to lag
behind pre-recession levels. New customer
additions are barely keeping pace with
continuing declines in per-customer use
of natural gas due to ever more efficient
buildings and appliances.
Industrial – The “Great Recession”
cost the region more than 20 percent of
its industrial gas load between 2007 and
2012, although industry remains the largest
user (Figure D3). A significant portion of
that loss of load came from the permanent
closure of a number of wood and paper
products plants in the region. As the region
is now beginning to shed the effects of the
recession, the 2014 Outlook forecasts
6 percent higher industrial volumes than in
2013 and a faster growth rate (0.9 percent
vs. 0.6 percent forecast last year). Favorable
gas prices are driving the growth, spurring
existing industries to resume pre-recession
Figure D2. Residential Demand Forecast Comparison
production levels. NWGA members are also
reporting increased inquiries from industrial
users interested in expanding or locating in
the region, and there are proposals to build
facilities to export LNG and petrochemicals
that utilize natural gas as a feedstock. In
response to heightened industrial interest
and activity, we analyze an accelerated
industrial demand scenario at the end of this
section. LNG exports are not included in this
scenario.
Generation – Projected annual
generation loads are lower at the start of
the forecast period than in the 2013 Outlook
and higher at the end. The forecast average
annual growth rate is 3.3 percent, higher
than the 2.6 percent forecast in 2013. This
reflects the region’s expectation that, while
the timing is delayed, it will increasingly rely
on natural gas as the marginal generation
resource. The 2014 Outlook forecast for
natural gas-fired generation is consistent
with the findings of the Pacific Northwest
Utility Conference Committee (PNUCC) in its
Northwest Regional Forecast.10
Public policy and regulatory initiatives in
Washington and Oregon have compelled
the pending closure of two coal-fired
generation facilities in the region: TransAlta’s
Centralia units and the Boardman plant
Figure D3. Historic Natural Gas Demand By Sector
1000
300
900
250
800
700
200
Million Dth
Million Dth
600
150
100
500
400
300
200
50
100
0
0
1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014*
Residential
2013 Outlook Forecast
Commercial
Industrial
Generation
* 2014 Outlook Year 1 Forecast
2014 Outlook Forecast
PNUCC, 2013 Regional Forecast, May, 2013
10
N W G A
2 0 1 4
G A S
O U T L O O K
15
operated by Portland General Electric
(PGE). Though no commercial agreements
have been executed, it is reasonable to
expect that some portion of the output of
these plants will be replaced with gas-fired
generation. Therefore, we include a simple
expanded generation demand scenario at
the end of this section.
Demand Composition – How and
when the region uses natural gas has
changed. Industrial use of natural gas is
typically constant throughout the year; it
doesn’t vary much with the weather. While
industrial loads once made up more than
half of all regional natural gas demand,
today it makes up about one-third of total
annual demand (Figure D4) and its share is
forecast to be less than 30 percent at the
end of this forecast period.
Conversely, gas-fired generation – a
load that can be quite variable depending
on weather and other market conditions
– once represented a small portion of
natural gas demand in the region. By
2012, however, generation claimed more
than 20 percent of regional annual gas
demand and, in 10 years, is expected to
account for more than a quarter of all
regional natural gas use. Residential and
commercial loads are also largely weather-
Figure D4. Shift In Demand Composition
driven and hover around the same
proportionate shares of annual demand.
Overall, then, regional natural gas
demand is more variable today, more
subject to the vagaries of weather than
when gas was first delivered to the region
more than 50 years ago. Currently, variable
weather-sensitive loads make up more
than two-thirds of the region’s natural
gas use, a share that the 2014 Outlook
forecasts will increase. Consequently, the
region’s infrastructure is being utilized
differently today than when it was first
built.
System Planning – Planning
standards are designed to meet demand
on the coldest day that could occur
in a gas utility’s service territory. While
each company approaches the task a
little differently, “peak” or “design” days
are typically based on historical 24-hour
average temperatures actually recorded
at representative locations. A comparison
of the NWGA member company
weather design standards can be found
in Appendix B. While peak day loads
are higher on average than last year’s
forecast, they remain significantly lower
than the 2008 forecast issued prior to the
recession (Figure D5).
Figure D5. Regional Peak Day Forecast Comparison
8
Generation: 3%
7
Industrial:
51%
Commercial:
20%
Industrial:
32%
6
Residential:
26%
Commercial:
19%
MillionMillion
DthDth
Million
Dth
Residential:
26%
Generation:
20%
5
4
3
2
1
0
1996
2013
2008 Peak Day
N W G A
2 0 1 4
G A S
O U T L O O K
2014 Peak Day
16
Key Variables Affecting Natural
Gas Demand
Understanding demand – how much, when,
where and for what duration natural gas is needed –
defines the type and size of infrastructure required to
serve it. Regional growth in the use of natural gas has
historically been driven by the construction of new
housing, commercial and institutional facilities, and
new industry. The demand projections in this outlook
anticipate continued modest economic growth.
However, forecast data don’t always reflect what’s
occurring in real-time. The demand for natural gas
in the region is changing and NWGA members are
watching a number of demand drivers that have yet
to be quantified, including:
t 5IFBEFRVBDZPGOBUVSBMHBTJOGSBTUSVDUVSFUP
support regional growth opportunities.
t 5IFNBHOJUVEFBOEOBUVSFPGUIFVTFPGOBUVSBMHBT
for generating electricity to serve growth, balance
the system and transition from coal.
t 5IFQPTTJCJMJUZPGOFXJOEVTUSJBMMPBETJODMVEJOH
exports) due to sustained lower natural gas
commodity costs.
t 5IFTJHOJmDBOUSFHJPOBMHSPXUIQPUFOUJBMGPS
natural gas as a transportation fuel in a variety of
applications.
t 5IFJNQBDUPGGVUVSFFOFSHZQPMJDJFTPOEFNBOE
particularly GHG legislation.
Market Development Successes and Challenges
Residential customers typically make up a majority
of a local distribution company’s (LDC) revenues, while
industrial customers make up the majority of the load.
Many LDCs are seeing stagnant volumes and declining
use per customer on the residential side coupled, until
recently, with very little growth on the industrial side.
With little or no growth, the utilization of a
distribution system remains flat or even declines.
However, the cost of safely and reliably maintaining and
operating those systems is increasing. As customers face
ever-increasing rates, they may choose other energy
options, thereby exacerbating the situation. That’s why
LDCs need to grow: to increase system utilization and
spread system costs across a broader base.
FortisBC has employed a number of initiatives
meant to increase the use of its assets, promote system
investments and manage the rate impact on customers.
A few examples follow.
Confronted with a reduction in water heating load
and installations in new buildings (primarily multifamily), FortisBC established a pilot pairing an energy
efficiency incentive with a sales incentive to install high
efficiency on-demand water heaters in individual suites
of multifamily developments.
At the end of the pilot, FortisBC had secured 19
projects, representing 1,000 individually metered
customers. In every case, developers installed not only
gas water heating but also other appliances such as
cooktops, fireplaces, dryers, BBQs and heating. The
revenues realized from the pilot paid for the project
costs in less than two years.
Natural gas transportation offers another great
opportunity to add constant (not weather dependent)
loads to the system, thereby increasing utilization and
reducing rates for all customers. LDCs are targeting
return-to-home fleets including waste hauling, buses,
and short-haul tractor-trailers.
FortisBC was successful in obtaining the support of
the BC Government for these initiatives. Specifically, the
Government authorized the utility to earn its authorized
rate of return on up to $62 million by offering incentives
to vehicle fleets to offset the incremental cost of a
natural gas vehicle. To date over half of these incentives
have been committed.
The Provincial government also directed the British
Columbia Utilities Commission (BCUC) to approve
a new LNG rate schedule for FortisBC and exempt
it from having to secure BCUC approval for a $400
million upgrade to its LNG facility in Tilbury, BC. In
response, FortisBC will build new LNG capacity for the
transportation market. Prospective demand already
exceeds the project’s initial proposed capacity.
LDCs are also actively engaged in growing loads
by helping their communities achieve reductions in
greenhouse gas emissions and other pollutants. Biogas,
also known as biomethane or renewable natural gas
(RNG), has the dual benefit of providing a very low net
carbon fuel because it is extracted from waste streams
(e.g., landfills, water treatment plants, animal and other
agricultural wastes).
FortisBC is operating an RNG program, bringing
limited volumes of RNG into its system and offering it
to customers. FortisBC currently operates two projects
extracting methane from a landfill and from agricultural
waste. Together these projects supply RNG to more than
5,000 residential customers and several commercial
customers.
– Prepared by Jason Wolfe, Director, Market Development–
FortisBC
N W G A
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17
SCENARIO 1: Accelerated Industrial
Demand
Possible Regional
Demand Scenarios
We have developed two
scenarios to explore the impact
the above variables could
have on regional demand
and capacity utilization.
They include an accelerated
industrial growth scenario and
a coal replacement scenario.
NOTE: these scenarios are
created wholly by the NWGA. In
developing them, we accessed
public information and tested
whether our assumptions were
reasonable with a number of
regional stakeholders. They
are solely intended to illustrate
possible future outcomes. To
our knowledge, neither scenario
The most likely candidates for new demand (as opposed
to expansion of existing facilities) include L/CNG for
transportation (marine, rail, trucking, etc.), food processing,
fertilizer and petrochemical production. Loads for a typical
facility that might locate here could range from: 3,0005,000 Dth/day for a food processor; 8,000-12,000 Dth/day
for a fertilizer plant; 25,000-50,000 Dth/day for LNG fueling
facilities and 125,000-150,000 Dth/day for a petrochemical
plant. All together, these industrial facilities could add
between 59 and 79 million Dth to the last year of the
expected forecast (2022/23), or an increase in industrial load
of between 22 and 29 percent over the expected case.
In this scenario, NWGA adjusted the expected case as
follows: 5% increase for 2015-16, 15% increase for 2017-18
and 5% increase for 2019-20.
The scenario yields an additional 59.3 million Dth of
industrial load by the end of the forecast period, an increase
of 22 percent in the last year of the forecast than in the
expected case (at the low end of the range described
above). The average annual industrial growth rate increases
to 3.2 percent from 0.9 percent in the expected case. The
scenario adds 6.5 percent to total load and increases the
overall growth rate from 1.5 percent to 2.2 percent.
reflects any actual negotiations
or commercial agreements,
nascent or otherwise, except as
can be found publicly.
http://www.transalta.com/us/2011/12/growth-2/
EFSEC, Amendment 5 to Grays Harbor Energy Center Site Certification Agreement, December 21, 2010
13
A heat rate of 7,000 is representative of the newest CCCT generating units operating in the region (e.g. Port Westward, Mint Farm, etc.).
11
12
N W G A
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G A S
O U T L O O K
SCENARIO 2: Expanded Generation Demand
In response to policy and regulatory requirements, PGE agreed to cease
coal-fueled generation at the Boardman plant in 2020. TransAlta will phase out
its Centralia plant, closing Unit 1 by 2020 and Unit 2 by 2025.
Depending on market conditions, TransAlta intends to replace its coal-fired
facility with a clean-burning natural gas plant as part of a planned Centralia
3. Per TransAlta: “The Centralia 3 project develops replacement power for the
current 1,340-MW capacity Centralia coal-fired plant…[t]he proposed new
natural gas plant is assumed initially as a roughly one-for-one replacement of
Centralia’s 670-MW coal-fired Unit 1.” 11
PGE is keenly focused on developing renewable fuel alternatives to replace
as much of the 550-MW capacity of the Boardman plant as possible, but it
has not dismissed the possibility that natural gas generation may contribute.
In addition, Grays Harbor Energy (GHE) sought and received approval from
Washington’s Energy Facility Site Evaluation Council (EFSEC) to add 650 MW of
gas-fired generating capacity to its existing 650-MW facility (construction period
of up to 22 months to begin no later than December, 2020).12
This NWGA scenario assumes 800 MW of new combined-cycle gas
combustion turbine (CCCT) generation above our expected case forecast
(which already accounts for the new PGE Carty plant). Three hundred (300)
MW will be added to Western Washington loads in 2018-19, 200 MW to Eastern
Oregon loads (off the GTN pipeline) in 2019-20 and another 300 MW to Western
Washington loads in 2020-21. Further assumptions include current turbine
technology with a heat rate of 7,000 Btu/kilowatt-hour13 operated 75 percent of
the time (utilization rate).
The scenario yields an additional 36.8 million Dth of generation load by
the end of the forecast period, an increase of 15 percent in the last year of the
forecast than in the expected case. The scenario increases the average annual
growth rate to 4.9 percent from 3.3 percent in the expected case. The scenario
adds 4 percent to total load in the last year of the forecast and increases the
overall growth rate from 1.5 percent to 1.9 percent.
18
FIGURE D6. Additional Growth Scenarios
Gas & Electric Industries Continue to Collaborate
1100
1000
900
800
Million
Million
Dth Dth
700
600
500
400
300
200
100
0
2013/14
2014/15
2015/16
2016/17
Annual Demand – Expected Case
2017/18
2018/19
2019/20
Accelerated Industrial
2020/21
2021/22
2022/23
Accelerated Generation
Combined Results – If both scenarios were realized, the total annual demand in the
last year of the forecast would be 96 million Dth (10.5 percent) higher than the expected
case and the overall annual growth rate would increase from 1.5 percent to 2.6 percent.
As discussed in more detail in the following section, this suggests accelerated need for
additional capacity in the region.
Today, natural gas is the go-to fuel for new on-demand electric
generation. Natural gas power plants provide flexibility to meet changes
in power demand and can help integrate intermittent resources. Gas is
also used for baseload generation and will likely replace 2,000 megawatts
of Northwest coal set to retire by 2025. As the region constructs more
gas-fired power plants, it is important to ensure that the infrastructure
can deliver gas to power plants and other users during high demand
days.
The PNUCC and NWGA have been and will continue to examine
gas-electric issues together. One area of recent focus is the Interstate-5
Corridor. Not only does this portion of the system have a significant
number of gas power plants, it is the highest populated area of the region
and has potential for growing electric power and gas demand. During
2013 we examined the gas infrastructure in the I-5 Corridor under a range
of scenarios, including a peak demand day. The initial findings are that
the infrastructure is adequate. The report is available at: www.pnucc.org/
system-planning/reports.
There are numerous other organizations studying gas-electric
interdependence and striving to improve system reliability. The Western
Interstate Energy Board is conducting an analysis of gas infrastructure
in the Western Interconnection. ColumbiaGrid recently published a
report examining electric transmission in the event of a gas constraint.
The Northwest Mutual Assistance Agreement helps coordinate regional
response during gas emergencies. FERC is attentive to the growing gaselectric overlap and is considering synchronizing the gas and electric
scheduling day.
Natural gas is and will continue to be an important part of the
Northwest’s electric generation portfolio. PNUCC looks forward to
continuing to work with NWGA and other regional entities to study and
discuss gas-electric interdependence.
– Prepared by PNUCC Staff
N W G A
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G A S
O U T L O O K
19
2014 GAS OUTLOOK -
A Closer Look
The Pacific Northwest’s 48,000-mile
network of transmission and distribution
Regional System Capacity
Rockies can deliver more than 4 Bcf/day to
the region. Combined with underground
Key Conclusions
pipelines safely and reliably serves almost
and peak storage facilities (Table C1), the
3.5
million
natural
gas
customers.
The
region‘s natural gas infrastructure is currently
t 5IFFYJTUJOHTZTUFNPGOBUVSBMHBTQJQFMJOFTBOETUPSBHFGBDJMJUJFTIBTSFMJBCMZTFSWFEUIFMPBE
pipelines that transport natural gas from
capable of delivering more than 6.5 million
requirements of the region for decades and is sufficient to meet today’s needs.
production areas in Alberta, BC, and the U.S. Dth/day of gas at peak capacity.
t "EEJUJPOBMDBQBDJUZJTMJLFMZUPCFSFRVJSFEXJUIJOUIFGPSFDBTUIPSJ[POUPTFSWFOFXEFNBOE
for natural gas, particularly on a peak (design) day. Industrial and generation demand above FIGURE C1. Pacific Northwest Infrastructure and Capacities (MDth)
the expected case will amplify and accelerate the need for incremental capacity.
t 3FHJPOBMQJQFMJOFBOETUPSBHFFYQBOTJPOTIBWFCFFOVOEFSUBLFOUPNBJOUBJOBOEFOIBODF
system reliability in response to increases in base load and peak day demand.
t 5IFUJNJOHMPDBUJPOBOEUZQFPGGVUVSFDBQBDJUZFYQBOTJPOTPSBEEJUJPOTBOEVUJMJ[BUJPOPG
existing infrastructure, will depend on the changing nature of regional natural gas demand.
TABLE C1. Regional Storage Facilities
Facility
Owner
Jackson Prairie, WA Avista, PSE, NWP
Mist,
ORC1. Regional
NWStorage
Natural Facilities
Table
Underground Subtotal
Plymouth, WA
NWP
Newport, OR
NW Natural
Portland, OR
NW Natural
Tilbury, BC
FortisBC Energy
Nampa, ID
Intermountain Gas
Gig Harbor, WA
PSE
Swarr Station, WA PSE
Mt. Hayes, BC
FortisBC Energy
Peak Storage Subtotal
Total Storage
Type
Capacity1 Max Withdrawal
(MDth)
(MDth/day)
Underground 25,448
1,1962
Underground 16,100
5202
41,548
1,716
LNG
2,388
305
LNG
1,000
60
LNG
600
120
LNG
591
155
LNG
588
60
LNG
13
3
3
LPG
130
10
LNG
1,530
153
6,840
866
48,388
2,582
Working gas capacity; gas that can be used to serve the market.
Start of season or full rate; storage withdrawal rates decline as working gas volumes decline below certain levels.
3
LPG= Liquid Propane Gas and Air mixture.
1
2
N W G A
2 0 1 4
G A S
O U T L O O K
Pipelines
Spectra BCP
Williams NWP
TCPL - GTN
Other TCPL
FortisBC SCP
K-M Ruby
Underground Storage
Jackson Prairie
Mist
LNG Storage
Nampa
Newport
Plymouth
Portland
Tilbury
Mt. Hayes
20
Peak Day Capabilities – Because natural gas utilities are committed to preventing
service disruptions regardless of the circumstances, they design their systems to
accommodate extreme but still plausible weather conditions called peak or design days
(see Appendix B for a comparison of NWGA member company weather design standards).
Figure C2 aggregates the projected design day volumes of NWGA gas utility members and
plots them against available capacity. Under the expected and high demand cases, peak
day loads could stress the system, approaching or exceeding the region’s infrastructure
capacity within the forecast horizon.
The probability of design days occurring on every system across the entire region
on the same day (“coincidental peak day”) is small. However, the possibility of very cold
weather occurring simultaneously along the I-5 Corridor is reasonably high. Figure C3
plots projected design day volumes along the I-5 Corridor against the pipeline and storage
resources available to serve the area. The expected and high demand cases along the I-5
Corridor approach system capabilities within the forecast horizon.
Base
High Day
Pipeline
Underground Storage
FIGURE C2. Low
Region-wide
Peak
Resource/Demand
BalancePeak LNG
Base
High
Pipeline
Underground Storage
FIGURE C3.Low
I-5 Peak
Day Resource/Demand
Balance
6
9
Low
Base
High
Pipeline
Underground Storage
Peak LNG
Peak LNG
5
89
5
78
4
Million
Dth/day
Million
Dth/day
Million Dth/day
Million Dth/day
67
6
5
5
4
4
3
3
4
3
3
2
2
2
2
1
1
11
00
00
2013 /
2014
Low
2014 /
2015
Base
2015 /
2016
High
2016 /
2017
2017 /
2018
Pipeline
2018 /
2019
2019 /
2020
2020 /
2021
Underground Storage
2021 /
2022
2022 /
2023
2013 /
2014
Low
Peak LNG
2014 /
2015
Base
2015 /
2016
2016 /
2017
High
2017 /
2018
2018 /
2019
Pipeline
2019 /
2020
2020 /
2021
2021 /
2022
Underground Storage
2022 /
2023
Peak LNG
6
9
8
5
Million Dth/day
6
5
4
3
2
Million Dth/day
7
4
3
2
N W G A
2 0 1 4
G A S
O U T L O O K
21
Accelerated Demand Scenario – Two
potential scenarios are outlined in the
Demand Section of this report, including
accelerated industrial and generation
demand. Figure C4 includes the projected
incremental loads from these scenarios
plotted against the resources available to
serve the region.14 More capacity will be
required to serve the region more quickly if
these scenarios are realized.
Analyses such as these help send signals
Expected Peak Day Forecast
Pipeline
Peak LNG
to the market of an impending need for
additional capacity. Market participants
weigh the probability of disruptions and
the costs of various infrastructure options to
make decisions about what is needed and
when.
In response to these market signals,
projects are typically proposed to serve
future delivery capacity needs. Prior to
the recession, a number of projects were
proposed to serve the region. At that time,
California.
Subsequent to Ruby’s development,
TransCanada’s GTN Pipeline developed a
firm northbound service to allow delivery
of Ruby gas to customers along the GTN
system in Eastern Oregon. With this service,
GTN became a bi-directional pipeline
providing customers more gas supply
options and flexibility.
Reductions in projected demand, a slow
economic recovery and the new reality of a
Acclerated Demand Scenario
Underground Storage
FIGURE
C4. Accelerated Demand Peak Day Resource/Demand Balance
9
Million Dth/day
the market needed greater balance in its
supply options, including more access to
natural gas produced in the Rockies and
increased capacity across the Cascades.
One of those projects – Kinder Morgan’s
683-mile Ruby Pipeline – began operating
in July 2011, connecting the Opal trading
hub in southwestern Wyoming to the
Malin trading hub at the California-Oregon
border. The Ruby Pipeline brings gas supply
diversity, predominately to Northern
9
8
8
7
7
6
6
5
5
4
4
3
3
2
2
1
1
FIGURE C5. Proposed Natural Gas Infrastructure Projects
3
Southern
Crossing
TCPL
W
es
tc
oa
st
Kingsvale
Kingsgate
Sumas
Washington Expansion
Project
11 Washington
Expansion
Project
Install pipeline loop and compression
- Install pipeline loop and compression
1
Blue Bridge/Palomar Expansion
22 N-Max/Palomar
Expansion
Utilize capacity on GTN
and proposed
Palomar in combination with NWP
expansion in I-5 corridor
Spectra/FortisBC T-South System
33 Enhancement
Project
Enhancement Project
NWP
Utilize capacity on Westcoast in
combination with Southern Crossing
expansion to Kingsgate
4
N
Molalla
2
GT
Pacific Connector
Construct new pipeline for LNG exports
and regional markets
0
0
NW
Coos Bay
Expected Peak Day Forecast
Accelerated Demand Scenario
Pipeline
Underground Storage
Peak LNG
P
4
Opal
a
14
Figure C4 assumes that the entire load generated by the accelerated demand scenario will require, and contract for, firm
transportation and/or storage capacity. In fact, potential shippers have options including less costly interruptible service contracts
that can be curtailed as necessary by the capacity operator.
N W G A
2 0 1 4
G A S
O U T L O O K
Ruby
Ke
rn
rir
Tusca
PG&E
Malin
22
vast North American supply of natural gas all
combined to change the nature of projects
now being considered by the region. Today’s
market for regional infrastructure capacity
has evolved from valuing diversity to equally
valuing reliability; from providing market
access for imported LNG to accessing the
Asian LNG export markets. In any event, it is
only a matter of time before new capacity
within the region will be required. Figure
C5 illustrates active regional infrastructure
proposals, which include:
Washington Expansion Project – In
response to a request for an incremental
750 million cubic feet per day (MMcf/d) of
capacity, Williams Northwest Pipeline (NWP)
is planning to construct the Washington
Expansion Project. The project consists of
140 miles of 36-inch diameter pipe to be
constructed in 10 different segments in
or near NWP’s existing right-of-way along
the I-5 Corridor between Sumas, WA, and
Woodland, WA, plus additional compression
at five existing compressor stations. In
conjunction with this project, NWP is
also proposing an incremental scalable
expansion from Sumas to markets in the
I-5 Corridor as far south as Molalla, OR. This
phase of the project is not contingent upon
the aforementioned expansion.
Northwest Market Access Expansion
(N-MAX)/Cross Cascades Expansion
– NWP is working with the current Cross
Cascades pipeline sponsors – NW Natural
and TransCanada GTN – to develop the
project in conjunction with an expansion
of the existing NWP system. The Cross
Cascades project (formerly known as the
Palomar project) would consist of a 106mile, 30-inch diameter pipeline that would
run from GTN’s mainline in central Oregon
to a NW Natural/NWP hub near Molalla
– enhancing delivery capacity to the I-5
Corridor. The Cross Cascades project’s initial
design capacity is 300 MMcf/d, expandable
to 750 MMcf/d. It would be linked to the
N-MAX project on the NWP system to
deliver gas to other markets along the I-5
Corridor.
Spectra/FortisBC System
Enhancement – FortisBC and Spectra
Energy continue to evaluate using FortisBC’s
Southern Crossing system to provide
Spectra’s T-South shippers with flexible
receipt and delivery options between
Station 2 in Northeast BC and the Sumas,
WA and Kingsgate, ID market hubs. This
would involve expanding FortisBC’s existing
bi-directional Southern Crossing system
that connects Spectra’s T-South system
at Kingsvale, BC, to TransCanada’s system
at Yahk, BC, and will require a 100-mile
pipeline-looping project on the Kingsvale
to Oliver, BC, segment. Incremental capacity
from Station 2 on the Spectra system to
Kingsgate could be up to 450 MMcf/d.
Expanded Kingsgate-to-Sumas (east-towest) flow capability could also increase
supply delivered to Sumas to serve the
lower mainland of BC and the I-5 Corridor.
Pacific Connector DescriptionGas Pipeline Project (PCGP) – The Pacific
Connector Gas Pipeline Project (PCGP) is a 232-mile 36-inch diameter pipeline extending
from Malin to Coos Bay, Oregon. PCGP is being proposed by Williams to serve Veresen,
Inc.’s Jordan Cove LNG export terminal, as well as potential regional markets between
Malin and Coos Bay. PCGP includes 41,000 horsepower of compression to be installed
near Malin yielding a total project design capacity of 1.06 Bcf/d. PCGP will provide access
to supplies from Western Canada and the U.S. Rockies via interconnections with Gas
Transmission Northwest and the Ruby Pipeline. Williams will operate PCGP, which is a
50/50 joint venture with Veresen, Inc.
Key Variables affecting Natural Gas System Capacity
NWGA members continuously monitor a number of dynamics to ensure that regional
natural gas consumers have the gas they need when and where they need it, including:
t 8IFOXIFSFBOEIPXNVDIOBUVSBMHBTUIFSFHJPOXJMMSFRVJSFUPHFOFSBUFFMFDUSJDJUZ
to meet growing base load power demand and peaking capacity to support
intermittent renewable sources of generation.
t *NQBDUTPGUIFSFHJPOTDIBOHJOHMPBEQSPmMFPOFYJTUJOHOBUVSBMHBTJOGSBTUSVDUVSF
For example, the generation facilities planned to replace coal-fired power and new
industrial facilities could require significant capacity. Where existing pipelines are
underutilized, their load factors would increase. As annual load factors and peaking
requirements increase, expansion will be needed.
t 8IFUIFSFYJTUJOHSFHVMBUPSZIVSEMFTBSFFBTFEUPBMMPXDPOTUSVDUJPOPGOFXPS
expanded infrastructure in a timely manner to address capacity shortfalls. Projects can
take three to five years to develop, making foresight imperative.
t 5IFJNQBDUPOSFHJPOBMJOGSBTUSVDUVSFBOEHBTnPXTJGPOFPSNPSF8FTU$PBTU-/(
export terminals are built.
N W G A
2 0 1 4
G A S
O U T L O O K
23
Comparing Preferred Resources from Regional IRPs
Developing a sufficient and efficient regional system can be achieved by
Longer-term deficiencies are likely to be met with some combination of currently
looking at the total needs of the region, the resources available, and future resource
unsubscribed capacity, future capacity expansions and additional on-system storage
options. While current analysis shows resources sufficient to meet demand, these
including satellite LNG. There are several planning cycles in which to evaluate resource
methodologies may not fully capture the potential demand, both in magnitude
options for deficits far out into the future.
and timing, or the future availability of existing resources. Due to risks inherent in
What has not been fully incorporated are the resources regional generators plan
the forecasting process, changing needs and uses for natural gas, limited existing
to access to meet growing and increasingly variable generation demand. The Outlook
resources, and the lengthy permitting and construction time frames for new resources,
has captured future gas-fired generation loads to the extent they are planned, known
it is imperative to comprehensively assess regional resource adequacy and future
and available. However, it is difficult to project how and when those resources will be
resource needs.
required. The NWGA will continue working with the PNUCC to plan accordingly.
NWGA member utilities strive to understand the planning issues, competitive
– Prepared by Kelly Fukai, Manager, Natural Gas Planning – Avista Utilities
environment and resource requirements for others
in the region because of the common infrastructure
TABLE C2. Regional IRPs Preferred Resource Acquisitions for Expected Cases
to serve both electricity and natural gas demand.
Company
IRP File Date
Jurisdiction
Year of Peak Day
Preferred Supply Resource(s)
Preparing a plan in isolation of these external
Deficiency
Selected
considerations could mask potential resource
Avista
Aug. 31, 2012
Washington/Idaho 2029
t 7JOUBHF(5/$BQBDJUZ
utilization constraints, ignore operational synergies,
Aug. 31, 2012
Oregon
2028
t 7JOUBHF(5/$BQBDJUZ
discount project economies of scale, and result in
t .FEGPSE-BUFSBM&YQBOTJPO
overreliance on existing resources.
Cascade
Dec. 14, 2012
Washington
2024
t /81$BQBDJUZ
For example, LDCs could be relying upon existing
t 4BUFMMJUF-/(
unsubscribed or under-utilized pipeline capacity
t $JUZ(BUF1VSDIBTFT
to meet a future deficit. That same capacity may
May 25, 2012
Oregon
Currently deficient
t 3VCZDBQBDJUZXJUI(5/#BDLIBVM
be relied upon by electric utilities that need gas for
FortisBC
July 15, 2010
British Columbia
No deficiency in
N/A
power generation sooner than the LDC. In this case,
planning horizon
the LDCs’ preferred resource would not be available.
No deficiency in
Intermountain Feb. 2013
Idaho
N/A
planning horizon
Therefore, evaluating who needs what, when and
Washington
2014
NW Natural
Mar. 22, 2013
t .JTUSFDBMM
where can highlight potential problems and hone in
t $SPTT$BTDBEFT1JQFMJOF
on regional solutions.
Currently
deficient
t .JTUSFDBMM
Jan. 12, 2011 – Original Oregon
Table C2 summarizes the identified deficiencies
Sept. 1, 2011 – Modified
and preferred supply resource portfolios of the
2017
t 48"336QHSBEF
Puget
Sound
May 30, 2013
Washington
member utilities from their most recently filed IRPs. It
t 14&-/(
Energy
is apparent from the data in Table C2 that near-term
t .JTU/81&YQBOTJPO
deficiencies can be handled with existing resources.
N W G A
2 0 1 4
G A S
O U T L O O K
24
APPENDICES
A1. Maximum Capacity (Dth/d)
2013 / 2014
2014 / 2015
2015 / 2016
4,039,582
Pipeline Interconnects
1,561,317
WCSB via TCPL/GTN
692,920
Stanfield (NWP from GTN)
165,000
Starr Rd (NWP from GTN)
70,459
Palouse (NWP from GTN)
445,997
GTN Direct Connects
Kingsgate/Yahk BC Interior from TCPL 186,941
495,000
Rockies via NWP
655,000
NWP north from NWP south
(160,000)
Max Demand on Reno Lateral
1,983,265
WCSB via SET
1,753,060
T-South to Huntingdon
178,705
T-South to BC Interior
51,500
T-South to Kingsvale
2,585,058
Storage
1,196,000
Jackson Prairie (NWP from JP)
520,000
Mist Storage (NWN)
305,300
Plymouth (NWP from LNG)
60,000
Newport LNG (NWN)
120,000
Portland LNG (NWN)
60,000
Nampa LNG (IGC)
Gig Harbor Satellite LNG (PSE)
5,250
Swarr Stn Propane (PSE)
10,000
Tilbury LNG (FortisBC)
155,466
Mount Hayes LNG (FortisBC)
153,042
Total Available Supply
6,624,640
4,039,582
4,039,582
4,039,582
4,039,582
1,561,317
1,561,317
1,561,317
692,920
692,920
165,000
165,000
70,459
SUPPLY
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022/2023
4,039,582
4,039,582
4,039,582
4,039,582
4,039,582
1,561,317
1,561,317
1,561,317
1,561,317
1,561,317
1,561,317
692,920
692,920
692,920
692,920
692,920
692,290
692,920
165,000
165,000
165,000
165,000
165,000
165,000
165,000
70,459
70,459
70,459
70,459
70,459
70,459
70,459
70,459
445,997
445,997
445,997
445,997
445,997
445,997
445,997
445,997
445,997
186,941
186,941
186,941
186,941
186,941
186,941
186,941
186,941
186,941
495,000
495,000
495,000
495,000
495,000
495,000
495,000
495,000
495,000
655,000
655,000
655,000
655,000
655,000
655,000
655,000
655,000
655,000
(160,000)
(160,000)
(160,000)
(160,000)
(160,000)
(160,000)
(160,000)
(160,000)
(160,000)
1,983,265
1,983,265
1,983,265
1,983,265
1,983,265
1,983,265
1,983,265
1,983,265
1,983,265
1,753,060
1,753,060
1,753,060
1,753,060
1,753,060
1,753,060
1,753,060
1,753,060
1,753,060
178,705
178,705
178,705
178,705
178,705
178,705
178,705
178,705
178,705
51,500
51,500
51,500
51,500
51,500
51,500
51,500
51,500
51,500
2,585,058
2,585,058
2,585,058
2,585,058
2,585,058
2,585,058
2,585,058
2,585,058
2,585,058
1,196,000
1,196,000
1,196,000
1,196,000
1,196,000
1,196,000
1,196,000
1,196,000
1,196,000
520,000
520,000
520,000
520,000
520,000
520,000
520,000
520,000
520,000
305,300
305,300
305,300
305,300
305,300
305,300
305,300
305,300
305,300
60,000
60,000
60,000
60,000
60,000
60,000
60,000
60,000
60,000
120,000
120,000
120,000
120,000
120,000
120,000
120,000
120,000
120,000
60,000
60,000
60,000
60,000
60,000
60,000
60,000
60,000
60,000
5,250
5,250
5,250
5,250
5,250
5,250
5,250
5,250
5,250
10,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000
10,000
155,466
155,466
155,466
155,466
155,466
155,466
155,466
155,466
155,466
153,042
153,042
153,042
153,042
153,042
153,042
153,042
153,042
153,042
6,624,640
6,624,640
6,624,640
6,624,640
6,624,640
6,624,640
6,624,640
6,624,640
6,624,640
N W G A
2 0 1 4
G A S
O U T L O O K
25
A2. Annual Demand Forecast (Dth) – Expected Case
2013 / 2014
2019 / 2020
2020 / 2021
BC Lower Mainland & Van. Island 146,657,195 147,043,410 146,129,220
Residential
53,402,250
53,186,886
52,971,522
Commercial
39,786,087
40,121,171
40,456,254
Industrial
36,600,559
36,867,054
37,133,549
Power Generation
16,868,299
16,868,299
15,567,894
W. Washington
240,238,252 240,359,067 242,002,038
Residential
68,887,384
69,780,216
70,890,177
Commercial
42,802,495
43,052,505
43,369,733
Industrial
76,592,421
77,163,100
78,032,385
Power Generation
51,955,953
50,363,246
49,709,742
W. Oregon
116,222,584 117,352,528 119,223,248
Residential
36,717,772
36,994,904
37,523,911
Commercial
26,613,687
26,666,457
26,830,632
Industrial
38,891,125
39,691,167
40,868,705
Power Generation
14,000,000
14,000,000
14,000,000
BC Interior
54,588,307 55,281,772
55,975,237
Residential
16,357,761
16,341,403
16,325,044
Commercial
10,109,222
10,200,023
10,290,824
Industrial
28,121,324
28,740,346
29,359,368
Power Generation
E. Washington & N. Idaho
71,667,641 72,916,524
74,227,056
Residential
19,643,317
19,898,121
20,290,389
Commercial
14,091,688
14,268,380
14,541,009
Industrial
28,445,007
28,834,911
29,202,895
Power Generation
9,487,628
9,915,112
10,192,763
E. Oregon & Medford
106,694,879 109,846,830 112,367,095
Residential
7,646,685
7,746,986
7,898,153
Commercial
5,498,263
5,568,217
5,667,016
Industrial
9,290,866
9,381,058
9,507,832
Power Generation
84,259,064
87,150,569
89,294,095
S. Idaho
68,001,728 69,060,245
72,510,038
Residential
21,061,498
21,353,967
21,728,518
Commercial
10,803,798
10,839,180
11,110,147
Industrial
28,136,432
28,867,097
31,671,374
Power Generation
8,000,000
8,000,000
8,000,000
146,055,129 145,820,910 145,586,691 145,352,472
52,589,820
52,150,588
51,711,356
51,272,124
40,752,476
41,034,812
41,317,149
41,599,485
37,144,939
37,067,615
36,990,292
36,912,969
15,567,894
15,567,894
15,567,894
15,567,894
252,787,085 257,820,244 260,880,313 261,257,311
72,081,314
73,316,779
74,647,878
76,022,402
43,694,046
43,992,672
44,302,352
44,661,156
78,645,587
79,149,686
79,647,996
80,309,536
58,366,138
61,361,108
62,282,087
60,264,217
119,931,434 120,809,798 121,729,852 122,973,417
37,804,593
38,236,538
38,684,015
39,333,520
26,774,159
26,829,501
26,905,672
27,099,774
41,352,682
41,743,759
42,140,164
42,540,123
14,000,000
14,000,000
14,000,000
14,000,000
56,120,773
56,078,245 56,035,717
55,993,190
16,263,101
16,185,448
16,107,794
16,030,141
10,375,808
10,458,633
10,541,458
10,624,283
29,481,864
29,434,165
29,386,465
29,338,766
75,530,332
76,832,506 77,838,465
79,234,416
20,535,477
20,817,372
21,085,941
21,456,413
14,731,978
14,943,487
15,146,198
15,414,336
29,640,850
30,052,396
30,460,394
30,913,828
10,622,028
11,019,251
11,145,932
11,449,839
138,864,938 141,651,232 142,152,854 145,193,547
8,024,966
8,150,845
8,271,960
8,424,204
5,751,875
5,834,702
5,914,860
6,014,497
9,644,927
9,760,821
9,872,580
10,002,325
115,443,169
117,904,864
118,093,454
120,752,521
73,117,705
73,569,291 73,406,043
74,120,984
22,178,890
22,527,496
22,916,172
23,327,374
11,226,525
11,309,505
11,432,002
11,571,945
31,712,290
31,732,290
31,057,868
31,221,665
8,000,000
8,000,000
8,000,000
8,000,000
145,118,252
50,832,892
41,881,821
36,835,646
15,567,894
264,276,702
77,399,335
45,012,832
80,880,294
60,984,242
123,752,681
39,659,764
27,134,929
42,957,987
14,000,000
55,950,662
15,952,488
10,707,108
29,291,066
81,010,944
21,742,068
15,630,078
31,368,395
12,270,403
151,889,338
8,559,912
6,101,151
10,143,322
127,084,952
74,728,070
23,745,954
11,713,600
31,268,516
8,000,000
PNW Annual Demand – Base
Residential
Commercial
Industrial
Power Generation
862,407,396
229,478,162
153,306,866
257,623,139
221,999,229
Region/Sector
N W G A
2 0 1 4
G A S
2014 / 2015
804,070,585 811,860,375
223,716,666
225,302,482
149,705,241
150,715,933
246,077,734
249,544,734
184,570,944
186,297,226
O U T L O O K
2015 / 2016
822,433,931
227,627,714
152,265,614
255,776,109
186,764,494
2016 / 2017
2017 / 2018
2018 / 2019
872,582,226 877,629,936 884,125,337 896,726,650
231,385,066
233,425,117
235,866,178
237,892,414
154,403,312
155,559,691
156,985,477
158,181,519
258,940,731
259,555,761
261,239,211
262,745,226
227,853,116
229,089,367
230,034,471
237,907,491
2021 / 2022
2022/2023
145,099,431 145,155,100
50,621,081
50,487,909
42,160,805
42,438,646
36,749,651
36,660,651
15,567,894
15,567,894
271,330,733 275,449,915
78,835,771
80,419,898
45,433,475
45,993,729
81,419,490
81,974,516
65,641,997
67,061,772
124,762,852 125,859,876
40,106,580
40,622,992
27,282,997
27,449,025
43,373,275
43,787,859
14,000,000
14,000,000
55,958,784
55,984,513
15,931,931
15,931,052
10,793,661
10,881,632
29,233,192
29,171,829
82,273,869
83,199,465
22,061,845
22,406,302
15,859,728
16,100,452
31,775,217
32,175,443
12,577,078
12,517,268
154,482,949 154,418,964
8,691,401
8,825,542
6,183,576
6,266,588
10,264,984
10,381,966
129,342,988
128,944,868
75,627,559
76,895,391
24,172,044
24,605,779
11,856,988
12,002,133
31,598,527
32,287,479
8,000,000
8,000,000
909,536,176
240,420,653
159,571,230
264,414,336
245,129,958
916,963,223
243,299,473
161,132,206
266,439,743
246,091,802
26
A3. Annual Demand Forecast (Dth) – High Case
2019 / 2020
2020 / 2021
2021 / 2022
2022/2023
BC Lower Mainland & Van. Island 147,456,368 148,134,047 147,511,321 147,836,036 148,038,026 148,240,017 148,442,007
Residential
53,430,775
53,225,810
53,020,844
52,678,006
52,287,477
51,896,948
51,506,418
Commercial
40,137,453
40,600,709
41,063,966
41,547,052
42,036,808
42,526,564
43,016,321
Industrial
37,019,842
37,439,230
37,858,617
38,043,083
38,145,847
38,248,611
38,351,374
Power Generation
16,868,299
16,868,299
15,567,894
15,567,894
15,567,894
15,567,894
15,567,894
W. Washington
251,135,288 245,735,634 253,374,217 279,538,668 304,141,099 311,290,048 304,729,870
Residential
69,300,162
70,308,210
71,498,420
72,760,579
74,062,425
75,453,589
76,883,684
Commercial
43,450,937
44,085,336
44,615,279
45,011,962
45,441,322
45,843,414
46,284,069
Industrial
77,256,130
77,924,653
78,888,402
79,585,692
80,169,525
80,750,768
81,500,630
Power Generation
61,128,059
53,417,434
58,372,117
82,180,435
104,467,827
109,242,278
100,061,488
W. Oregon
119,081,955 120,295,341 122,264,227 123,037,478 123,985,246 124,976,616 126,297,967
Residential
37,801,896
38,121,481
38,695,375
39,014,608
39,489,078
39,980,018
40,677,140
Commercial
27,383,811
27,454,622
27,637,049
27,592,739
27,663,394
27,755,685
27,968,128
Industrial
39,896,248
40,719,239
41,931,803
42,430,131
42,832,775
43,240,912
43,652,700
Power Generation
14,000,000
14,000,000
14,000,000
14,000,000
14,000,000
14,000,000
14,000,000
BC Interior
55,137,205 56,030,689 56,924,173 57,302,179
57,503,369
57,704,558 57,905,748
Residential
16,368,816
16,356,487
16,344,158
16,300,996
16,247,208
16,193,421
16,139,633
Commercial
10,198,667
10,322,089
10,445,512
10,578,493
10,714,680
10,850,868
10,987,055
Industrial
28,569,722
29,352,113
30,134,503
30,422,690
30,541,480
30,660,270
30,779,059
Power Generation
E. Washington & N. Idaho
81,177,805 82,498,497 84,366,787 91,190,937
89,948,671
92,357,132 96,319,830
Residential
20,055,121
20,612,480
21,253,533
21,755,365
22,291,881
22,820,761
23,434,181
Commercial
14,231,140
14,582,051
15,000,548
15,342,956
15,703,358
16,057,749
16,467,484
Industrial
28,742,449
29,138,226
29,512,824
29,961,267
30,382,904
30,801,643
31,267,008
Power Generation
18,149,095
18,165,739
18,599,883
24,131,349
21,570,528
22,676,979
25,151,157
E. Oregon & Medford
116,551,317 123,770,200 128,108,062 158,526,493 162,453,002 162,572,130 165,913,083
Residential
7,808,670
7,976,229
8,184,659
8,370,546
8,555,054
8,735,774
8,944,123
Commercial
5,589,344
5,693,511
5,821,764
5,936,203
6,048,321
6,158,210
6,285,660
Industrial
9,391,778
9,483,571
9,612,694
9,752,350
9,870,402
9,984,259
10,116,458
Power Generation
93,761,526
100,616,888
104,488,944
134,467,394
137,979,226
137,693,887
140,566,842
S. Idaho
69,801,780 70,892,052 74,445,339 75,071,236
75,536,370
75,368,224 76,104,614
Residential
21,693,343
21,994,586
22,380,373
22,844,257
23,203,321
23,603,657
24,027,195
Commercial
11,127,912
11,164,356
11,443,451
11,563,320
11,648,790
11,774,962
11,919,103
Industrial
28,980,525
29,733,110
32,621,515
32,663,659
32,684,259
31,989,604
32,158,315
Power Generation
8,000,000
8,000,000
8,000,000
8,000,000
8,000,000
8,000,000
8,000,000
148,643,998
51,115,889
43,506,077
38,454,138
15,567,894
307,656,648
78,310,940
46,709,145
82,163,232
100,473,330
127,130,277
41,034,274
28,013,444
44,082,559
14,000,000
58,106,937
16,085,845
11,123,243
30,897,849
97,284,458
23,894,209
16,786,867
31,733,687
24,869,696
172,136,874
9,121,107
6,392,832
10,259,994
146,362,941
76,729,912
24,458,333
12,065,008
32,206,571
8,000,000
149,097,811
50,921,246
44,048,586
38,560,085
15,567,894
327,874,764
79,794,967
47,201,902
82,794,448
118,083,447
128,204,964
41,518,551
28,176,452
44,509,961
14,000,000
58,356,670
16,069,380
11,278,652
31,008,638
98,601,540
24,419,032
17,135,823
32,153,168
24,893,517
173,064,263
9,299,879
6,498,648
10,383,785
146,881,951
77,656,386
24,897,205
12,212,698
32,546,483
8,000,000
149,638,994
50,794,340
44,609,618
38,667,141
15,567,894
329,047,729
81,425,777
47,854,543
83,442,780
116,324,629
129,334,406
42,072,418
28,356,913
44,905,075
14,000,000
58,623,361
16,065,777
11,440,899
31,116,685
100,056,572
24,947,630
17,484,133
32,514,640
25,110,170
175,409,787
9,476,995
6,603,021
10,486,856
148,842,916
78,962,253
25,343,952
12,362,197
33,256,103
8,000,000
PNW High Demand by Sector
Residential
Commercial
Industrial
Power Generation
987,689,104 1,012,856,397 1,021,073,101
244,020,596
246,920,261
250,126,888
164,596,615
166,552,761
168,711,323
269,798,031
271,956,567
274,389,281
309,273,861
327,426,809
327,845,609
Region/Sector
2013 / 2014
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
840,341,717 847,356,460 866,994,126 932,503,027 961,605,782 972,508,724 975,713,119
226,458,782
228,595,284
231,377,361
233,724,357
236,136,444
238,684,166
241,612,374
152,119,264
153,902,674
156,027,569
157,572,726
159,256,672
160,967,453
162,927,820
249,856,693
253,790,141
260,560,359
262,858,873
264,627,191
265,676,067
267,825,545
211,906,979
211,068,361
219,028,838
278,347,071
301,585,474
307,181,038
303,347,381
N W G A
2 0 1 4
G A S
O U T L O O K
27
A4. Annual Demand Forecast (Dth) – Low Case
2013 / 2014
Region/Sector
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
139,458,321
50,163,996
39,497,514
34,228,916
15,567,894
237,436,310
75,245,502
43,310,625
79,025,987
39,854,196
119,457,047
37,884,411
26,165,696
41,406,940
14,000,000
52,050,140
15,658,254
10,058,775
26,333,111
72,070,822
18,596,822
13,679,346
30,712,526
104,000,726
127,343,924
7,768,053
5,682,990
9,892,155
104,000,726
72,195,130
22,647,936
11,234,898
30,312,296
8,000,000
138,787,203
49,629,009
39,507,922
34,082,378
15,567,894
243,243,128
76,565,308
43,597,749
79,442,609
43,637,463
120,176,408
38,182,556
26,191,828
41,802,023
14,000,000
51,883,465
15,553,794
10,069,501
26,260,170
73,841,872
18,726,545
13,802,007
31,163,304
112,538,909
136,189,994
7,867,998
5,752,175
10,030,911
112,538,909
72,784,534
23,054,324
11,372,427
30,357,783
8,000,000
138,193,719 137,626,530
49,313,789
49,074,564
39,415,647
39,287,367
33,896,389
33,696,704
15,567,894
15,567,894
244,768,815 246,902,398
77,947,534
79,477,287
43,950,518
44,440,309
79,826,862
80,225,223
43,043,900
42,759,579
121,124,774 122,158,496
38,596,623
39,075,659
26,326,891
26,478,133
42,201,261
42,604,704
14,000,000
14,000,000
51,733,998
51,591,180
15,501,026
15,466,074
10,056,242
10,034,721
26,176,729
26,090,385
74,949,732
74,356,709
18,879,655
19,030,987
13,931,865
14,058,999
31,566,733
31,963,271
116,264,948
106,519,951
140,194,060 130,718,344
7,961,757
8,052,805
5,816,090
5,878,121
10,151,265
10,267,467
116,264,948
106,519,951
73,657,824
74,888,729
23,468,004
23,889,106
11,511,639
11,652,556
30,678,182
31,347,067
8,000,000
8,000,000
772,597,984 771,755,545 781,084,941 809,009,094 813,684,540 821,032,332 820,011,694
219,316,015
220,069,952
221,493,990
222,833,714
224,257,234
225,937,305
227,964,974
146,179,416
146,288,001
147,086,657
147,585,602
148,083,747
148,735,163
149,629,845
240,549,056
242,690,898
247,529,150
248,900,814
250,028,300
250,473,418
251,911,931
166,553,497
162,706,695
164,975,143
189,688,965
191,315,258
195,886,445
190,504,944
836,906,604
229,579,534
150,293,609
253,139,178
203,894,282
844,622,923
231,668,388
151,008,893
254,497,421
207,448,221
BC Lower Mainland & Van. Island 144,320,393 143,854,425 142,088,053 141,471,217 140,800,528 140,129,439
Residential
52,990,143
52,624,544
52,258,945
51,768,498
51,233,941
50,698,983
Commercial
39,191,461
39,309,604
39,427,747
39,466,292
39,476,700
39,487,107
Industrial
35,270,490
35,051,979
34,833,467
34,668,532
34,521,994
34,375,455
Power Generation
16,868,299
16,868,299
15,567,894
15,567,894
15,567,894
15,567,894
W. Washington
232,544,101 229,851,423 234,814,746 238,027,992 237,838,183 240,135,027
Residential
68,560,006
69,349,010
70,381,937
71,500,725
72,666,402
73,932,385
Commercial
42,210,592
42,121,102
42,308,566
42,574,803
42,775,231
43,015,364
Industrial
76,226,365
76,633,101
77,344,229
77,808,415
78,166,599
78,516,531
Power Generation
45,547,137
41,748,210
44,780,014
46,144,049
44,229,951
44,670,747
W. Oregon
113,149,071 114,184,020 115,927,383 116,580,252 117,399,854 118,274,464
Residential
35,513,123
35,741,134
36,206,869
36,455,410
36,851,469
37,271,804
Commercial
25,773,568
25,803,899
25,938,741
25,873,032
25,916,325
25,984,845
Industrial
37,862,380
38,638,987
39,781,773
40,251,809
40,632,059
41,017,815
Power Generation
14,000,000
14,000,000
14,000,000
14,000,000
14,000,000
14,000,000
BC Interior
52,566,296 52,522,975 52,479,654 52,394,553
52,294,916
52,195,278
Residential
16,208,760
16,138,095
16,067,430
15,971,632
15,867,173
15,762,713
Commercial
9,947,085
9,978,742
10,010,398
10,026,599
10,037,325
10,048,050
Industrial
26,410,450
26,406,138
26,401,826
26,396,322
26,390,419
26,384,515
Power Generation
E. Washington & N. Idaho
67,739,592 67,952,894 68,356,823 69,031,405
70,036,356
71,218,423
Residential
18,275,844
18,146,889
18,089,895
18,130,650
18,212,326
18,372,986
Commercial
13,236,050
13,191,252
13,204,757
13,273,523
13,365,694
13,500,716
Industrial
28,273,513
28,656,632
29,015,792
29,449,187
29,856,697
30,262,367
Power Generation
74,183,877
74,132,066
74,580,855
97,798,977
100,915,774
104,565,451
E. Oregon & Medford
96,024,427 96,108,017 96,787,177 120,282,602 123,655,197 127,578,688
Residential
7,320,083
7,338,272
7,393,266
7,473,895
7,554,568
7,649,722
Commercial
5,331,535
5,359,926
5,409,900
5,471,813
5,532,371
5,600,051
Industrial
9,188,932
9,277,752
9,403,157
9,537,917
9,652,485
9,763,465
Power Generation
74,183,877
74,132,066
74,580,855
97,798,977
100,915,774
104,565,451
S. Idaho
66,254,105 67,281,791 70,631,105 71,221,072
71,659,506
71,501,013
Residential
20,448,056
20,732,007
21,095,648
21,532,903
21,871,355
22,248,711
Commercial
10,489,125
10,523,476
10,786,550
10,899,539
10,980,102
11,099,031
Industrial
27,316,924
28,026,308
30,748,907
30,788,631
30,808,049
30,153,270
Power Generation
8,000,000
8,000,000
8,000,000
8,000,000
8,000,000
8,000,000
PNW Low Demand by Sector
Residential
Commercial
Industrial
Power Generation
N W G A
2 0 1 4
G A S
O U T L O O K
2021 / 2022
2022/2023
838,242,385
234,066,482
151,830,207
256,194,821
196,150,876
28
A5. Peak Day Demand/Supply Balance (Dth/day) – Expected Case
2013 / 2014
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022/2023
BC Lower Mainland & Van. Island (I-5) 1,378,589
Residential
570,995
Commercial
397,437
Industrial
149,508
Power Generation
260,650
W. Washington (I-5)
2,001,157
Residential
796,170
Commercial
340,383
Industrial
261,051
Power Generation
603,553
W. Oregon (I-5)
1,009,239
Residential
565,125
Commercial
292,524
Industrial
48,590
Power Generation
103,000
BC Interior
385,779
Residential
193,795
Commercial
124,394
Industrial
67,590
E. Washington & N. Idaho
564,262
Residential
206,082
Commercial
148,663
Industrial
80,785
Power Generation
128,731
E. Oregon & Medford (Non I-5 Supply) 615,443
Residential
84,342
Commercial
53,112
Industrial
40,895
Power Generation
437,094
S. Idaho
623,876
Residential
236,089
Commercial
121,621
Industrial
132,666
Power Generation
133,500
1,379,140
568,691
400,718
149,081
260,650
2,017,832
806,625
345,218
262,436
603,553
1,020,420
572,107
294,677
50,637
103,000
388,286
193,601
125,683
69,002
569,695
208,843
150,787
81,334
128,731
617,752
85,658
53,847
41,154
437,094
640,911
239,082
123,163
145,166
133,500
1,156,954
566,388
403,999
148,654
37,913
2,036,306
819,157
349,718
263,878
603,553
1,033,332
580,172
297,166
52,994
103,000
390,793
193,407
126,972
70,413
576,174
212,261
153,298
81,884
128,731
620,399
87,166
54,727
41,413
437,094
645,858
242,347
124,845
145,166
133,500
1,155,400
562,306
406,908
148,272
37,913
2,082,988
833,422
354,186
264,694
630,685
1,043,230
588,053
298,853
53,324
103,000
391,525
192,673
128,166
70,685
582,235
215,396
155,671
82,436
128,731
682,975
88,632
55,575
41,674
497,094
650,748
245,574
126,508
145,166
133,500
1,153,114
557,609
409,685
147,907
37,913
2,103,784
848,849
358,778
265,471
630,685
1,053,538
596,153
300,731
53,654
103,000
391,645
191,753
129,326
70,566
588,079
218,341
158,014
82,993
128,731
685,556
90,100
56,426
41,937
497,094
655,634
248,799
128,169
145,166
133,500
1,150,828
552,912
412,462
147,541
37,913
2,125,329
865,052
363,345
266,247
630,685
1,064,370
604,576
302,804
53,990
103,000
391,766
190,833
130,486
70,447
593,756
221,166
160,307
83,552
128,731
688,103
91,542
57,265
42,203
497,094
659,486
251,341
129,479
145,166
133,500
1,148,542
548,215
415,239
147,176
37,913
2,147,983
882,147
368,072
267,079
630,685
1,075,712
613,267
305,116
54,329
103,000
391,886
189,914
131,645
70,327
599,923
224,310
162,774
84,109
128,731
690,757
93,051
58,145
42,468
497,094
663,201
253,793
130,742
145,166
133,500
1,146,256
543,518
418,016
146,810
37,913
2,171,017
899,643
372,722
267,967
630,685
1,087,544
622,186
307,686
54,672
103,000
392,007
188,994
132,805
70,208
607,143
228,111
165,599
84,702
128,731
693,646
94,716
59,099
42,738
497,094
666,669
256,082
131,921
145,166
133,500
1,146,337
541,252
420,751
146,422
37,913
2,222,040
917,665
377,656
268,901
657,818
1,099,703
631,229
310,455
55,019
103,000
392,846
188,750
134,031
70,065
613,922
231,632
168,285
85,274
128,731
696,425
96,308
60,018
43,006
497,094
669,853
258,184
133,004
145,166
133,500
1,147,237
539,828
423,472
146,025
37,913
2,248,436
937,410
383,326
269,882
657,818
1,112,245
640,418
313,458
55,369
103,000
393,936
188,740
135,282
69,914
621,003
235,510
170,896
85,866
128,731
699,321
97,974
60,975
43,279
497,094
672,697
260,061
133,971
145,166
133,500
Total Design (Peak) Day Demand
Total Supply
Supply Surplus/(Shortfall)
6,634,036
6,624,640
(9,396)
6,459,815
6,624,640
164,825
6,589,100
6,624,640
35,539
6,631,350
6,624,640
(6,711)
6,673,638
6,624,640
(48,998)
6,718,004
6,624,640
(93,364)
6,764,283
6,624,640
(139,643)
6,841,127
6,624,640
(216,488)
6,894,876
6,624,640
(270,236)
Demand (Region/Sector)
6,578,344
6,624,640
46,296
N W G A
2 0 1 4
G A S
O U T L O O K
29
A6. I-5 Corridor Peak Day Demand/Supply Balance (Dth/day) – Expected Case
Demand (Region/Sector)
2013 / 2014
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022/2023
BC Lower Mainland & Van. Island
Residential
Commercial
Industrial
Power Generation
W. Washington (I-5)
Residential
Commercial
Industrial
Power Generation
W. Oregon (I-5)
Residential
Commercial
Industrial
Power Generation
Total Peak (Design) Day Demand
SUPPLY
Pipeline Interconnects
Max north flow on NWP @ Gorge
Huntingdon/Sumas
T-South to Huntingdon
Kingsvale to Huntingdon
(via Southern Crossing)
Underground Storage
Jackson Prairie (NWP from JP)
Mist Storage (NWN)
Peak LNG
Newport LNG (NWN)
Portland LNG (NWN)
Gig Harbor Satellite LNG (PSE)
Swarr Stn Propane (PSE)
Tilbury LNG (Fortis BC)
Mount Hayes LNG (Fortis BC)
1,378,589
570,995
397,437
149,508
260,650
2,001,157
796,170
340,383
261,051
603,553
1,009,239
565,125
292,524
48,590
103,000
4,388,985
1,379,140
568,691
400,718
149,081
260,650
2,017,832
806,625
345,218
262,436
603,553
1,020,420
572,107
294,677
50,637
103,000
4,417,392
1,156,954
566,388
403,999
148,654
37,913
2,036,306
819,157
349,718
263,878
603,553
1,033,332
580,172
297,166
52,994
103,000
4,226,591
1,155,400
562,306
406,908
148,272
37,913
2,082,988
833,422
354,186
264,694
630,685
1,043,230
588,053
298,853
53,324
103,000
4,281,618
1,153,114
557,609
409,685
147,907
37,913
2,103,784
848,849
358,778
265,471
630,685
1,053,538
596,153
300,731
53,654
103,000
4,310,436
1,150,828
552,912
412,462
147,541
37,913
2,125,329
865,052
363,345
266,247
630,685
1,064,370
604,576
302,804
53,990
103,000
4,340,527
1,148,542
548,215
415,239
147,176
37,913
2,147,983
882,147
368,072
267,079
630,685
1,075,712
613,267
305,116
54,329
103,000
4,372,237
1,146,256
543,518
418,016
146,810
37,913
2,171,017
899,643
372,722
267,967
630,685
1,087,544
622,186
307,686
54,672
103,000
4,404,818
1,146,337
541,252
420,751
146,422
37,913
2,222,040
917,665
377,656
268,901
657,818
1,099,703
631,229
310,455
55,019
103,000
4,468,080
1,147,237
539,828
423,472
146,025
37,913
2,248,436
937,410
383,326
269,882
657,818
1,112,245
640,418
313,458
55,369
103,000
4,507,918
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
2,304,060
551,000
1,753,060
1,753,060
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
1,716,000
1,196,000
520,000
503,758
60,000
120,000
5,250
10,000
155,466
153,042
Total Supply
4,523,818
4,523,818
4,523,818
4,523,818
4,523,818
4,523,818
4,523,818
4,523,818
4,523,818
4,523,818
Supply Surplus/(Shortfall)
134,833
106,426
297,227
242,200
213,382
183,291
151,581
119,000
55,738
15,900
N W G A
2 0 1 4
G A S
O U T L O O K
30
A7. Accelerated Demand
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022/2023
Annual Demand (Dth)
804,070,585 811,860,375 822,433,931
Year-to-Year Growth
1.0%
1.4%
Residential
223,716,666 225,302,482 227,627,714
Commercial
149,705,241 150,715,933 152,265,614
Industrial
246,077,734 249,544,734 255,776,109
Industrial Growth
1.4%
2.4%
Power Generation
184,570,944 186,297,226 186,764,494
Generation Growth
0.9%
0.3%
Accelerated Industrial Demand (Dth)
Adjusted Annual Demand
804,070,585
811,860,375
828,679,792
Adjusted Annual Growth
1.0%
2.0%
Residential
223,716,666 225,302,482 227,627,714
Commercial
149,705,241 150,715,933 152,265,614
Accelerated Industrial Load
246,077,734 249,544,734 262,021,971
Adjusted Industrial Growth
1.4%
4.8%
Power Generation
184,570,944 186,297,226 186,764,494
Accelerated Generation Demand (Dth)
Adjusted Annual Demand
804,070,585
811,860,375
822,433,931
Adjusted Annual Growth
1.0%
1.3%
Residential
223,716,666 225,302,482 227,627,714
Commercial
149,705,241 150,715,933 152,265,614
Industrial
246,077,734 249,544,734 255,776,109
Accelerated Generation Load
184,570,944 186,297,226 186,764,494
Adjusted Generation Growth
0.9%
0.3%
Combined Accelerated Demand (Dth)
Adjusted Annual Demand
804,070,585 811,860,375 828,679,792
Adjusted Annual Growth
1.0%
2.0%
Residential
223,716,666 225,302,482 227,627,714
Commercial
149,705,241 150,715,933 152,265,614
Industrial
246,077,734 249,544,734 262,021,971
Power Generation
184,570,944 186,297,226 186,764,494
862,407,396
4.6%
229,478,162
153,306,866
257,623,139
0.7%
221,999,229
15.9%
872,582,226
1.2%
231,385,066
154,403,312
258,940,731
0.5%
227,853,116
2.6%
877,629,936
0.6%
233,425,117
155,559,691
259,555,761
0.2%
229,089,367
0.5%
884,125,337
0.7%
235,866,178
156,985,477
261,239,211
0.6%
230,034,471
0.4%
896,726,650
1.4%
237,892,414
158,181,519
262,745,226
0.6%
237,907,491
3.3%
909,536,176
1.4%
240,420,653
159,571,230
264,414,336
0.6%
245,129,958
2.9%
916,963,223
0.8%
243,299,473
161,132,206
266,439,743
0.8%
246,091,802
0.4%
868,692,786
4.6%
229,478,162
153,306,866
263,908,529
0.7%
221,999,229
917,136,303
5.3%
231,385,066
154,403,312
303,494,808
13.0%
227,853,116
922,297,371
0.6%
233,425,117
155,559,691
304,223,196
0.2%
229,089,367
942,320,481
2.1%
235,866,178
156,985,477
319,434,355
4.8%
230,034,471
955,236,555
1.4%
237,892,414
158,181,519
321,255,131
0.6%
237,907,491
968,400,878
1.4%
240,420,653
159,571,230
323,279,038
0.6%
245,129,958
976,259,439
0.8%
243,299,473
161,132,206
325,735,959
0.8%
246,091,802
862,407,396
4.6%
229,478,162
153,306,866
257,623,139
221,999,229
15.9%
872,582,226
1.2%
231,385,066
154,403,312
258,940,731
227,853,116
2.6%
891,426,936
2.1%
233,425,117
155,559,691
259,555,761
242,886,367
6.2%
907,120,337
1.7%
235,866,178
156,985,477
261,239,211
253,029,471
4.0%
933,518,650
2.8%
237,892,414
158,181,519
262,745,226
274,699,491
7.9%
946,328,176
1.4%
240,420,653
159,571,230
264,414,336
281,921,958
2.6%
953,755,223
0.8%
243,299,473
161,132,206
266,439,743
282,883,802
0.3%
868,692,786
4.6%
229,478,162
153,306,866
263,908,529
221,999,229
917,136,303
5.3%
231,385,066
154,403,312
303,494,808
227,853,116
936,094,371
2.0%
233,425,117
155,559,691
304,223,196
242,886,367
965,315,481
3.0%
235,866,178
156,985,477
319,434,355
253,029,471
992,028,555 1,005,192,878 1,013,051,439
2.7%
1.3%
0.8%
237,892,414
240,420,653
243,299,473
158,181,519
159,571,230
161,132,206
321,255,131
323,279,038
325,735,959
274,699,491
281,921,958
282,883,802
Demand (Region/Sector)
2013 / 2014
2014 / 2015
N W G A
2 0 1 4
G A S
O U T L O O K
31
B. IRP Assumptions
Company
Avista
Region/Area
Customer Classes
8 Demand Areas which can be broken into 4 Residential, core commercial, core industrial
service territories and 2 divisions
Cascade
Currently 9 load areas (zones) principally
based on major upstream pipeline constraints.
CNGC will be forecasting at the our 70+
citygates level beginning with the 2015 IRP.
5 regions (includes an “all other” category);
West, Central, and East for market share
rates; by county for economic forecasting
Intermountain
FortisBC
Residential, commercial, Industrial, core
Interruptible
20 years
Residential, commercial, and Industrial (potato 5 years
processors, other food processors, chemical
and fertilizer, manufacturers, institutions, and
all other)
3 regions which can be broken into 7 service Residential, commercial and industrial
territories and 4 companies
NW Natural 12 Regions based on topology of the gas
distribution system
Forecast Length Econometrics
20 years
Separate forecast for customers and use per customer. Key drivers:
Population growth; service area residential permitting; U.S., California, and
service area employment growth; average household size; U.S. industrial
production; U.S. GDP growth; non-weather seasonal factors; and real natural
gas prices. Normal weather is based on a 20-year moving average.
Residential existing, new construction single
family, new construction multi-fam., and res.
conversion; commercial existing, new construction
& conversions; industrial firm sales; firm transport
Residential, commercial, industrial & electric
generation
Customer Counts: employment, # of households, mortgage rate for
residential or Prime Rate for commercial/industrial. Therms per Customer:
median household income, weather, natural gas prices.
Customer growth forecast: New res. construction customers, # of res. customers
who convert to natgas fr/ an alt fuel, & # of small com. customers (assuming a
new household = a new dwelling needed). The annual change in households
by county x IGC’s market penetration rate in that region = the additional res.
anticipated % of conversion customers relative to new construction customers in
those locales = # of expected res. conversion customers. (+ res. new construction
#s = total expected additional res. customers across the periods, by county).
5 years for PBR,
and 20 years
for Long Term
Resource Plan
20 years
Customer growth by region & category. Recent usage data for customer
base use + heat use behavior response to historic weather and gas rates.
Net residential customer additions (+ stock of convertible dwellings,
incentives, technology, marketing programs, etc)
18 years
Customer usage patterns influenced by underlying economic, demographic, and
technological changes such as growth in population and employment, changes
in prevailing prices, growth in electricity demand and in electric generation by
renewables, changes in the efficiency profiles of residential and commercial
buildings and the appliances within them, and the response to climate change.
20 years, but
New technologies/end uses, demographics, fuel switching, DSM, and
discussion in the economic growth
main text only
concentrates on
the first 10 years,
2011-2020
PG&E
10 climate zones, do not follow county
borders, are based on similar geographic
and climatic characteristics and approved by
the CPUC
PacifiCorp
34 “bubbles:” 15 west, 19 east designed to
best describe major load and generation
centers, regional transmission congestion
impacts, import/export availability, and
external market dynamics
Residential, commercial, and industrial. For
Demand Response, grouped commercial and
industrial demand buyback together.
Portland
General
Single contiguous service area
Residential, commercial, or industrial. For
demand response, by residential and small
C&I, medium C&I (30-499kW), large C&I (500999kW), and largest C&I (>1,000kW)
30 years (20102040, but they
are only required
to forecast out for
20 years)
Precarious economic conditions, demographic trends such as in-migration
and life expectancy, a business environment that favors future growth;
OR’s position as a magnet state, the presence of prominent industry leaders, continued gains in productivity, and emerging sectors sustaining and
creating new growth; and the high tech sector
Firm: residential, commercial, industrial,large
volume commercial, large volume industrial.
Interruptible: commercial and industrial.
Transportation: firm and interruptible
commercial, firm and interruptible industrial.
Residential by state; small commercial by
state; large commercial, industrial and electric
generation gas demand all together; firm
customer and transportation. All rate classes
are forecasted by state, but non-GS (all but
residential and small commercial) is only
presented system-wide in the IRP document.
20 years
Regional and national economic growth, demographic changes, weather,
prices, seasonality, usage, and behavior factors: Structural (population
driven) approach for developing Low and High growth scenarios.
Puget Sound Single contiguous service area.
Energy
Questar
N W G A
By state: Utah and Wyoming (Idaho is rolled
into Utah), and pipeline served and class
(only by state in the text though). Whole
system summaries provided.
2 0 1 4
G A S
O U T L O O K
11 years, through Population, personal income, housing starts, and unemployment rate are
used in forecasting by state.
2022 for the
demand forecast,
and 21 years for the
SendOut model.
32
Economic Sources
IHS Global Insight; Bureau of Labor Statistics; U.S.
Census; Bureau of Economic Analysis; NOAA; University
of Oregon Economic Indicator; Construction Monitor;
U.S. Federal Reserve; The Economist; Wall Street Journal;
IMF; World Bank; Bloomberg; Blue Chip Consensus,
Washington Office of Financial Management.
Woods & Poole, FHLMC, Federal Reserve, NOAA,
Wood Mackenzie.
Scenarios Developed
Price Forecast
An Average Case, Expected Case, High Growth with Wood Mackenzie – first five years modified to
Low Price, Low Growth with High Price, and an
include Nymex forward prices
Alternate Weather Standard
Peak Day Determination
Coldest day on record, historic peak, and
average weather data for each demand region.
Low, Medium, High, High Growth with Low Price,
Low Growth with High Price, Moderate CO2 costs,
High CO2 costs
A blend of public and private sources (EIA 20 yr,
Bentek 5yr , NYMEX strips, Texas Comptroller) –
based on Cascade’s general portfolio mix
61 HDD, based on coldest day in past 30 years
Church 2012 Forecast; NOAA
Low, base, and high (combined w/ other variables
create 18 total demand scenarios)
NYMEX & 2 five yr forecasts fr/ “multi-national
energy companies”=> Similar enough to use (1)
for model.
81 HDD weighted by customers in each
district; several distinct laterals and areas of
interest are assigned unique DDs.
Low, Medium, High
Internally developed forecast based on GLJ forecast
for AECO, forward price basis between Stn 2 and
Aeco, forecast basis between Sumas and Stn 2, and
forecast basis between AECO and Kingsgate.
The coldest day that is expected to occur once every
20 years, determined through an extreme value analysis. The Extreme Value analysis is based on weather
data from the last 60 years and the result could vary
from the coldest day experienced in the last 20 years.
System-weighted 53 HDD; coldest day last 30
years
OEA & NWPCC; Woods & Poole
High Customer Growth; Low Customer Growth;
IHS CERA (augmented for scenario development
Carbon Prices; Reliability; Gas Prices; Low/Medium/ purposes)
High Emerging Markets;
?
Average and high, as well as an abnormal peak day Avg. of NYMEX futures, long-term CEC forecasts,
(APD)
EIA, & private sources
PacifiCorp’s 2010 DSM potential study, conducted low, medium, and high scenarios – developed 49 cases: 19
by The Cadmus Group
Core cases on portfolio performance results for 4 variables
(level of a per-ton CO₂ tax, the type of CO₂ regulation – tax
or hard emission cap, natural gas and wholesale electricity
prices); 14 sensitivity on changes to resource-specific
assumptions and alternative load growth forecasts. To
minimize data processing and model run-time requirements PC excluded improbable combinations.
Third-party proprietary data & forecasting services
establish a range of global gas price scenarios, then,
IPM® simulates the North American system (allows
natgas prices to respond to demand changes fr/ envir.
compliance). Results used in a regional Midas model,
simulates the Western Interconnection. Low, medium,
and high nat gas prices from Henry Hub are obtained.
Those 3 forecasts are used to develop 15 unique price
projections for the cases analyzed.
PGE relies on PIRA Energy Group for natural gas prices
Oregon Office of Economic Analysis March 2009 A reference (likely) case, high load, and low load,
economic forecast and Global Insight’s February assuming normal weather. 15 portfolios represent (and coal)’s long-term fundamental forecast starting in
2009 U.S.
either a single resource or a mix of resources. Then 2014 and going through 2025 for the long-term Henry
assess total expected portfolio costs and test using Hub price and basis differentials to Sumas, AECO, and
other WECC (for electric) supply hubs. PIRA’s forecasts
21 futures. Stochastic analysis includes changes
are available through 2025, after which PGE escalates
in load, hydro, natgas price, wind availability &
at inflation.
unplanned thermal generating resource outages
Base, Low, High, High + High CO2, Base + Very High For 2014-16, used 3 mo. avg fwd marks. Beyond 2016,
Moody’s Analytics US Macroeconomic Forecast, PSE’s
Wood MacKenzie. Also generated Very Low, Low, High &
regional and economic forecasts, WA Office of Financial CO2, Very Low Gas Price, Very High Gas Price.
Very High Gas Prices derived from WM Forecasts
Management.
University of Utah (Bureau of Economic & Business
Research) and the Utah Governor’s Office of Planning
and Budget. When current local data were not available,
nationally recognized sources such as the U.S. Energy
Information Administration, the U.S. Census Bureau and
IHS Global Insight were used.
Mean, median, a normal cases and a base case. For the
IRP, Questar does Stochastic modeling which more than
encompasses low, medium and high. From the Stochastic
output they calculate mean, median, and base cases. A
normal case was included in the last IRP to help with the
quarterly variance report and pass-through cases.
Determined the means and standard deviations
associated with historical data from each of 9 area price
indices. Used avg of 2 price forecasts fr/ PIRA Energy
Group (19 months) and IHS CERA (252 months) as basis
for projecting the stochastic modeling inputs.
PG&E uses a 1 in 90 year cold temp by location
but only provides a system weighted mean
temp (27˚F) in their text.
No HDDs: assume a 10 % probability high
temperature load. This is included in their
alternative load forecast cases to determine
the resource type and timing impacts resulting
from a structural change in the economy.
Expected normal weather w/ a 50%probability - PGE’s
reserve cover ~ 80% of a 1-in-5 weather event. PGE
and the PNW have historically been winter peaking,
but summer demand has been growing and is projected to increase at a faster rate than winter demand,
transforming PGE’s system from winter-peaking to
summer-peaking by the end of the decade.
52 HDD daily average
A 1-in-20 year weather occurrence: design-day
firm customer gas demand projection is based
on a theoretical day w/ mean temp -5˚F @ the
Salt Lake Airport and corresponding design-day
temperatures are seen coincidentally across the
service territory.
N W G A
2 0 1 4
G A S
O U T L O O K
1914 Willamette Falls Dr. #255
West Linn, OR 97068