2015 Gas Outlook
Natural Gas Supply, Demand, Capacity and
Prices in the Pacific Northwest
Projections through October 2024
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 2024. 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.
1
What’s New
The transformation of North America’s energy landscape
continues. As producers bring to market the ample supply
of natural gas and other hydrocarbons found in shale rock
GHG emissions and achieve environmental
Henry Hub would average $7.25 per thousand
objectives. A new 220-megawatt (MW) natural gas
cubic feet (Mcf ), or dekatherm (Dth)2, in 2012.3 The
plant built by Portland General Electric (PGE) to
actual average Henry Hub spot price for natural gas
options, and reduced greenhouse gas (GHG)
support renewable energy resources went online
in 2012 was $2.75/Dth.4 The EIA currently forecasts
emissions.1 Adding to this remarkable
in December, 2014; construction of another plant
the average annual spot price of natural gas to
in Boardman is under way and plans are being
remain below $7/Dth through 2035.5
intensive industry and natural gas transportation
trifecta: North America’s approaching
energy independence.
The Pacific Northwest, ideally
positioned between two prolific
Finally, long-term projections of natural gas’s
continue to be relevant and key conclusions and
analyses are consistent with current conditions.
Therefore, NWGA is publishing this abbreviated
continuing to benefit from this
natural gas in our region’s environment and
Outlook for 2015. The Supply and Prices sections
economy. Natural gas remains a good economic
are brief and, for Web-version viewers, contain links
value as an energy source, especially when
allowing for easy access to last year’s sections and
compared to its price levels of just a few years ago
charts. The Demand and Infrastructure sections
and to the price of substitute fuels like oil. This
are more robust. Our analyses and updated tables/
remains true even in the current environment of
graphics provide details of what’s new.
natural gas consumers are considering
locating or expanding in the region, spurred by
access to low-cost supply. Likewise, regional electric
5
generation in the region.
The trends identified in the 2014 Outlook
affordability continue to augment the role of
Outlook, manufacturers and other large
4
developed to replace soon-to-be-retired coal-fired
natural gas producing areas, is also
abundant gas supply. As noted in this
3
cleaner-burning fuel, proposing or already building the U.S. Energy Information Administration (EIA)
projected that the spot price of natural gas at the
benefits of low prices, increased investment in energy
2
lower priced oil. In its 2008 Annual Energy Outlook,
natural gas-fired plants as one means to reduce
formations across the continent, we continue to reap the
1
utilities are taking advantage of this economical,
Natural gas emits about 50% less carbon dioxide as coal when burned in power plants and 25% less than gasoline or diesel when used for vehicle fuel. http://www.eia.gov/tools/faqs/faq.cfm?id=73&t=11
A 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).
$6.37 in $2006, converted to $2012 using Bureau of Labor Statistics inflation calculator
U.S. Energy Information Administration (EIA) website, http://www.eia.gov/dnav/ng/ng_pri_fut_s1_a.htm
EIA, 2015 Annual Energy Outlook ($2013), April 2015
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Regional Economic Outlook
GDP growth in the U.S. and Canada over the last
interest rate predict a policy change in the mid- to
2% range. Similarly, Canadian forecasters see BC’s
several years can be called many things, but nothing
latter-half of 2015. Given the expected timing of the
employment growth in the same range as Canada’s
that can be printed in a family friendly economic
Fed’s move, which is predicted to come before any
growth, which is expected to be 1% or less.
outlook. Looking across forecasts, 2015 is still
BOC tightening, a growing number of forecasters
predicted to be the high water mark for U.S. GDP
(including U.S. futures markets as of April 2015) expect
growth, which is expected to be around 3%. The sharp
a continued depreciation of the loonie against the
drop in oil and natural gas prices is expected to have
dollar in 2015. Given an improving U.S. economy, this
a net negative impact on Canada’s GDP growth—in
should boost Canada’s non-oil export growth.
recent months average GDP forecasts for 2015 have
fallen from around 2.5% to 2%. Inflation forecasts for
2015 are averaging below the 2% central target of
the Federal Reserve (the Fed) and the Bank of Canada
(BOC).
The primary external risks to North American growth
include slowing growth in China, recessionary growth
in Japan, and near-recessionary growth in Europe.
Ongoing political instability in Greece, the Ukraine,
and the Middle East also offer potential drags to
In the Pacific Northwest (PNW), Idaho, Oregon,
growth. Risks internal to North America include larger
Washington, and British Columbia (BC) will largely
than expected declines in U.S. consumer and business
follow the fortunes of the U.S. and Canadian
spending caused by Fed interest rate increases and
economies in 2015. On the U.S. side, although the
Canada’s historically high household debt levels.
majority of growth will occur in the Puget Sound,
After 2015, a majority of forecasters expect U.S. GDP
Portland, and Boise metro areas, employment growth
growth to slowly decelerate, largely reflecting a reversal
is expected to pick up in smaller MSAs*. In 2015,
of the Fed’s low short-term interest policy. At the time
U.S. PNW employment growth will likely exceed U.S.
of this writing, futures contracts for the Federal Funds
growth, which forecasters expected to be in the low
– Grant D. Forsyth, Chief Economist, Avista Corp.
Sources: Bank of Canada, Bank of Montreal, B.C. Stats, Bloomberg.com, CIBC,
Canada Department of Finance, Canada Mortgage and Housing Corporation,
Scotiabank, Statistics Canada, RBC, T.D. Economics, The Economist, U.S. Bureau
of Labor Statistics, U.S. Federal Reserve.
*MSAs: Metropolitan Statistical Area
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2015 GAS OUTLOOK –
Supply
Summary
Key Conclusions
• The enormity of North America’s natural gas resource, made available by extracting
hydrocarbons from shale rock formations deep underground, continues to transform the
energy landscape.
• Improving production techniques continue to deliver results that exceed expectations,
despite lower natural gas and oil prices, reallocation of capital, and growing regulation of
shale gas development to strengthen environmental protection.
The Potential Gas Committee (PGC) recently released its 2014 estimate of Total Potential
Natural Gas Resource. Continuing a remarkable 10-year run, the PGC’s 2014 potential
resource estimate of 2,515 trillion cubic feet (Tcf ) is once again the largest in its more than
half a century history of issuing this biennial report. The 2014 estimate exceeds the 2012
assessment by more than 5 percent. In 2013, shale plays represented the largest source of
U.S. natural gas production at 40 percent of gross withdrawals,6 a share that is expected to
grow over time.
• Pacific Northwest natural gas consumers benefit from their proximity to the prolific Western
Canadian Sedimentary Basin (WCSB) and U.S. Rocky Mountain (Rockies) natural gasproducing regions.
FIGURE S1. North American Shale Formations
FIGURE S2. PGC Estimate of Total Potential Resources
3,000
2,515
Trillion Cubic Feet
2,500
2,000
Shale resource not assessed separately
1,500
1,000
500
1,003
147
147
147
146
856
854
881
921
1,119
~200
141
155
169
169
166
897
936
958
950
955
0
Traditional
6
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EIA, Natural Gas Gross Withdrawals and Production
Coalbed
Shale
616
687
163
159
1,057
1,052
1,073
1,253
158
158
1,153
1,104
4
According to Baker Hughes’ North America Rig Count, there were 2,039 oil and natural
gas drilling rigs operating in the U.S. and Canada in September 2008. (The primary
distinction between the two rig types is the targeted resource but both produce natural
gas.) In March 2015, the combined number was down to 1,209, a decline of more than 40
percent. Gas rigs alone declined more than 80 percent over the same time frame. Yet the
EIA forecasts natural gas production to continue increasing.7
The two large natural gas production areas serving the Pacific Northwest produced
an average of 24 Bcf/d in 2013,9 or almost 30 percent of North America’s total natural gas
supply. Production from these two areas is projected to approach 30 Bcf/d by 2024.10
FIGURE S4. Supply Regions Serving the Pacific Northwest
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. According to the EIA, “In December 2014, dry natural
FIGURE S4. U.S. EIA Forecasts and Actual Shale Production
gas production hit a record high of 74.3 billion cubic feet per day (Bcf/d). This production
8
increase occurred despite declining prices and falling rig counts.”
FIGURE S3. Continued Increase in Natural Gas Production Despite
Decline in Rigs
Actual
2010 AEO
2012 AEO
2014 AEO (ER)
Source: U.S. EIA, based on data from EIA Short-Term Energy Outlook (March) and Baker Hughes, Inc.
EIA, Despite decline in rigs, natural gas production forecast to increase, Natural Gas Weekly Update, March 11, 2015
Ibid
9
Statistics Canada, Table 131-0001 – Supply and Disposition of Natural Gas, 2013; EIA, Natural Gas Gross Withdrawals and Production
by State (CO, UT, WY), 2013
10
National Energy Board of Canada (NEB), Canada’s Energy Future 2013: Appendix 4.2 - WCSB, November 2013; EIA, 2015 AEO Lower 48
Natural Gas Production and Prices by Supply Region – Dakotas/Rocky Mountain Region, April 2015
7
8
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Supply Variables
Responsible Gas Production
Key issues identified in the 2014 Outlook as
having the potential to affect natural gas supplies
are still relevant. They include:
• The development of new or improved wellcompletion technologies and techniques.
• The effect of the current low oil price
environment on future production.
• The potential impact environmental concerns
may have on natural gas production.
• Local and national legislation or regulations
affecting production/extraction processes.
The arrival of new and abundant natural gas supplies
has changed the nation's energy picture. It also has brought
new attention to gas production methods. Fracking – an
abbreviation for hydraulic fracturing – is now a common term
in our country's energy debate.
In fact, hydraulic fracturing isn't new: oil and gas developers
have been using it for more than 60 years. Hydraulic fracturing
uses water, sand and small amounts of chemicals to break
open solid rock, releasing trapped fuels. According to the U.S.
Department of Energy (DOE), more than 2 million wells have
been hydraulically fractured to date and about 95 percent of
new wells drilled today are fractured.11
So, why are we only hearing about it now?
In the last 10 years, engineers learned how to combine
hydraulic fracturing with another time-tested construction
practice: horizontal drilling. Conventional drilling uses
fracturing along the length of a vertical well. Now it's possible
to send fracturing equipment horizontally along a shale
deposit, releasing natural gas in larger volumes than ever
before.
The combination of these technologies has helped the U.S.
become the world's largest natural gas producer.
As with any industrial process, gas producers experienced
a learning curve in terms of environmental protection. But as
the industry and regulators have learned more about these
processes, drillers are continually improving their operations.
Some areas of interest are:
• Water use. Increasingly, gas producers are recycling the
water they use to fracture rock. Some are starting with
non-potable water, and the industry is studying ways to
eliminate water entirely from the fracturing process.
•Groundwater. Groundwater protection is one of the
highest priorities of drilling engineers. Without proper well
casings, drilling fluids and natural gas can leak into the
11
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U.S. Department of Energy, Natural Gas From Shale: Questions and Answers, April 2013
groundwater. That's why the American Petroleum Institute
has established detailed standards for well casings, and
state regulators closely inspect well construction. It's
important to note that hydraulic fracturing itself has not
been associated with groundwater contamination.
•Disposal. The industry and regulators have established
practices to prevent spills from water emerging from wells
and to protect municipal water treatment facilities.
•Methane. The industry has been working hard to reduce
methane emissions from gas production. A recent U.S.
Environmental Protection Agency (EPA) study found
that total methane emissions from gas production are
38 percent lower than they were in 2005 – although gas
production grew by 26 percent during that time.
•Earthquakes. Increased gas production has been
associated with new earthquake activity. Scientists have
determined that injection wells used to dispose of water
from drilling sites have caused earthquakes in some
locations. Most of these earthquakes are so mild they can't
be felt on the earth's surface.
The technology exists to help well developers avoid
earthquakes. Additionally, the industry already has backed
new regulations in gas-producing states to reduce earthquake
potential, and a new working group through the Interstate Oil
& Gas Compact Commission and the Ground Water Protection
Council is now focusing on this evolving issue.
The rapid growth of gas production has spurred regulators
and academics to learn more about the environmental impact
of gas development. NWGA looks forward to emerging
information and continued cooperation between the natural
gas industry and state and federal regulators.
– Sources: FracFocus, Energy In Depth, U.S. Department of Energy
6
2015 GAS OUTLOOK –
FIGURE P1. Natural Gas Spot Price Forecast Comparisons
Natural Gas Prices
Key Conclusions
• Despite a steep drop in oil prices in late 2014/early 2015, natural gas retains a
price advantage over gasoline and diesel.
$2013/Dth
• Spot and future commodity prices continue to reflect the sustained growth of
North American natural gas production.
• Most long-term price forecasts have declined significantly since 2008, when
material volumes of natural gas from shale were first brought to market.
Summary
The EIA expects the Henry Hub natural gas spot price to average $3.16/Dth in 2015, one
third lower than the average spot price in 2014 ($4.52/Dth).11 These prices demonstrate
a continuing surplus of natural gas supply across North America due mostly to
unprecedented production from shale formations. They also reflect winter-ending storage
2015 AEO HH
2008 AEO HH
NPCC AECO
NPCC SUMAS
levels across the U.S. that were 75 percent higher than a year earlier. In 2008, the spot price
FIGURE P2. Btu Equivalent Price Comparison: Oil vs. Natural Gas
of natural gas averaged almost $9/Dth.
Natural Gas (Henry Hub Spot)
Even in the context of today’s low oil price environment, natural gas remains the
best energy value by a factor of three (e.g., on a Btu basis, natural gas still has a 3:1 price
advantage over today’s lower-priced oil – Figure P2). In the recent past, the Btu price of oil
has exceeded natural gas by a factor of 4:1 and as much as 8:1 when oil was $140 a barrel.14
EIA, Short-Term Energy Outlook, April 7, 2015.
EIA, 2015 Annual Energy Outlook, April 2015
14
NVGAmerica 2015 paper: https://www.ngvamerica.org/natural-gas/pricing/
$24
$22
$20
$18
Dollars/Dth
Analysts continue to be bullish on the ability of the U.S. and Canada to develop and
deliver economically priced natural gas for years to come. While natural gas prices will
likely continue to be vulnerable to volatility and spikes during periods of high demand (as
was seen during the winter of 2013/14), they are not expected to return to the sustained
high price environment of a few years ago. That means consumers can expect to enjoy a
good economic value from natural gas for the years to come. We are already seeing growth
in business and industrial use because of this. (Please see the Demand chapter.) Even
factoring in a growing economy, prices are not expected to rise above $7/Dth ($2013) for
more than 20 years (Figure P1).13
Crude Oil (WTI Spot)
$26
$16
$14
$12
$10
$8
$6
$4
$2
$0
12
13
Natural Gas (Henry Hub Spot)
Crude Oil (WTI Spot)
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The natural gas price advantage is unlikely to change dramatically over time.
According to the EIA, natural gas prices are expected to remain relatively low, while other
fuels that are already higher priced continue to trend upward (Figure P3).
Figure P3. EIA Projected Transportation Fuel Price Differentials (AEO 2015)
$5.00
$4.50
$4.00
$3.50
$2013/gallon
$2013/gallon
$3.00
$2.50
$2.00
$1.50
Diesel
Gasoline
NatGas (GGE)
$1.00
2040
2039
2038
2037
2036
2035
2034
2033
2031
2032
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
$-
2016
$0.50
Price Variables
NWGA members are tracking a number of market dynamics that could influence natural
gas prices going forward:
• North American economic growth.
• The pace of adoption of natural gas for generation, industrial and transportation uses.
• Whether future regulations add to the cost of production or limit access to reserves.
• The effect of new and improved production technologies.
• The effect of infrastructure constraints on regional pricing.
• Benefits and costs of North American natural gas (such as LNG) exports to premium
overseas markets.
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Oil Price Volatility
Currently, world oil supply is outpacing world demand
for a number of reasons, many of which are well-known
and include the significant U.S. production increases
associated with hydraulic fracturing.
Oil supplies began to overtake demand sometime
around Q1 of 2012 and have remained firmly above
demand since late 2013, largely because of economic
stagnation in Europe and economic slowing in China.
Demand for oil is still increasing but not as fast as was
once forecasted. In short, when demand does not keep
up with growing supply, prices decline.
Supply has reached historic levels, in part, spurred by
recent $100 oil prices and the use of hydraulic fracturing
to tap oil resources that were previously uneconomical to
recover. In the past, large oil producing countries would
cut back on supplies to offset declines in demand, but
the Organization of Petroleum Export Countries (OPEC)
has been unwilling or unable to limit production by its
members. Furthermore, much of the recent growth in
supply is outside of OPEC’s control.
There are also a variety of geopolitical factors that
some analysts believe are influencing the price of oil
(e.g., some believe the Saudi’s are trying to drive smaller
oil producing countries and U.S. shale producers with
higher costs out of the market). This analysis will leave
those matters aside except to agree that world events
and concerns over the stability of some oil producing
countries will always play a key role in the volatility of oil
supplies and pricing.
Over the long-term, oil demand is likely to increase
as economic growth returns to more normal levels and
economic activity picks up. As has been the case in
recent years, the developing countries led by China and
India will likely lead the way in driving oil demand. The
developed countries, including the U.S., are not expected
to experience much growth in overall levels of petroleum
use.
Boom and bust in the oil industry is nothing new. In
fact, since 2009, the oil markets have been fairly volatile.
While it may not be possible to predict where prices
will settle in the short-term, some analysts believe that
the current levels could put a temporary halt on new
production as producers find it difficult to justify going
after new supplies with oil below $60 a barrel. There
is also the likelihood that today’s prices and reduced
revenues will lead to consolidation in the oil industry,
which could further drive down future production.
According to the International Energy Agency (IEA)
and the U.S. Energy Information Administration (EIA),
oil markets may turn the corner sometime in late 2015,
as that is when these agencies are predicting that oil
demand and supply will cross back over.
Click here to download a complete copy of
NGVAmerica’s January 2015 Whitepaper, Oil Price Volatility
Source: NGVAmerica, Oil Price Volatility, January 2015
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2015 GAS OUTLOOK -
Summary
Regional Natural Gas Demand
Key Conclusions
• Annual and peak day growth rates in the Pacific Northwest over this forecast period are
a little lower than the 2014 Outlook.
The moderate economic growth that began in the Pacific Northwest in 2013 is
accelerating, but those gains are not translating into natural gas demand growth in the
region. In fact, we are projecting a slower rate of growth than we did in the 2014 Outlook:
an average of 1.2 percent per year for a total volume increase of 10.3 percent (97 million
dekatherms, or MMDth) over the next 10 years (Table D1). New gas-fired generation
demand continues to account for the majority of load growth in the region, though at a
slower pace than in years past. Core market (residential, commercial) and industrial demand
are characterized by modest but steady growth. (Figure D1).
• A number of variables could significantly affect demand during the forecast period. This
Outlook explores two plausible scenarios: some natural gas replacement of regional
coal-fired generation along with accelerated industrial and transportation loads; and
significant demand growth from LNG exports and major petrochemical developments. 2015 Summary Data and ChartsCR.xlsxFigure D1. Sector Demand
TABLE D1. Projected Regional Demand Growth through 2024
FIGURE D1. Expected Sector Demand
300
Low
Expected
High
Annual Rate Cumulative Annual Rate Cumulative Annual Rate Cumulative
0.5% 4.7% 1.2% 10.3% 2.1%17.2%
250
0.5% 4.4%0.8% 6.9% 1.0%8.9%
0.2% 2.0%0.7% 6.2% 1.1%9.5%
200
0.3% 2.6% 0.8% 7.2% 1.2%10.0%
1.1% 9.6% 2.5% 19.7% 4.3%31.5%
Million Dth
Total
Residential
Commercial
Industrial
Generation
5/21/152:11 PM
150
100
50
2013 Outlook Figures-6.xlsxFIGURE8
0
2014/15
280
260
240
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Million Dth
220
200
180
2015/16
4/2/133:04 PM
2016/17
Industrial
2017/18
2018/19
Residential
2019/20
2020/21
Generation
2021/22
2022/23
Commercial
2023/24
10
Core Market (residential, commercial) – Growth rates in the residential and
commercial sectors are slightly lower than that projected in the 2014 Outlook (0.8 and
0.7 percent, respectively, vs. 0.9 and 0.8 percent last year). Forecasted residential volumes,
however, are 8 percent lower than in the 2013 Outlook. New customer additions are just
keeping pace with continuing declines in per-customer use of natural gas due to ever
more efficient buildings and appliances, as well as a growth in construction of multifamily
units, which use less gas per dwelling.
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 D2).
This year’s forecast projects slightly higher industrial volumes than the 2014 Outlook,
although the growth rate is a tick lower at 0.8 percent vs. 0.9 percent forecast last year. NWGA
members continue to report increased inquiries from industrial users interested in expanding
or locating in the region. While some proposals to build facilities to export LNG or produce
and export methanol have advanced since the 2014 Outlook was published, associated
volumes are not accounted for in the expected, low or high forecasts. We examine the
Figure D2. Historic PNW
Natural
Demand
By Sector
GasGas
Deliveries
(source:
US EIA, StatCan)
potential impacts of these projects through a separate, accelerated demand scenario at the
end of this section.
Generation – The forecast average annual growth rate for loads supporting electrical
generation is 2.5 percent, lower than the 3.3 percent forecast in 2014 but still the driving
force in overall load growth. Our forecast for natural gas-fired generation is consistent
with the findings of the Pacific Northwest Utility Conference Committee (PNUCC) in its
Northwest Regional Forecast.15
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 operated by PGE. Although no commercial agreements have
been executed, it is expected that some portion of these plants’ output will be replaced
with gas-fired generation. Therefore we include a simple expanded generation demand
scenario at the end of this section.
Demand Composition – Regional 26
natural gas loads are more sensitive to weather
19
variations today than when gas was first delivered to the region more than 50 years ago.
32
20
Figure D3. Shift in Demand Composition
Generation: 3%
1,000
900
800
Million Dth
Generation:
20%
Residential:
26%
700
600
Industrial:
51%
500
400
300
Residential:
26%
Industrial:
32%
Commercial:
20%
Commercial:
19%
200
100
0
1996
Residential
15
2014
1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015*
Commercial
Industrial
Generation
* 2015 Outlook Year 1 Forecast
PNUCC, 2015 Regional Forecast, May, 2015
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Currently, variable weather-sensitive loads make up more than two-thirds of the region’s
natural gas use (Figure D3). Consequently, the region’s infrastructure is being utilized
differently today than when it was first built. Then, less than 50 percent of the region’s
annual load was subject to weather patterns.
System Planning – Planning standards are designed to meet demand on the
coldest day likely to occur in a gas utility’s service territory. While each company
approaches this forecasting requirement a little differently, “peak” or “design” days are
typically based on actual 24-hour average temperatures 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 2.3 percent higher on average
than last year’s forecast, they remain more than 12 percent lower than the 2008
forecast issued prior to the recession (Figure D4).
Figure D4. Regional Peak Day Forecast Comparison
8
7
6
Million Dth
5
4
3
2
1
0
2008 Outlook Peak Forecast
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2015 Outlook Peak Forecast
Demand Variables
The demand for natural gas in the region is changing and NWGA members continue to
watch a number of demand drivers that have yet to be quantified, including:
• The magnitude and nature of the use of natural gas for generating electricity.
• The possibility of new significant industrial loads (including exports).
• The regional growth potential for natural gas as a transportation fuel.
• The adequacy of natural gas infrastructure to support regional growth opportunities.
• The impact of future energy policies on demand, particularly GHG legislation
12
Clean and Efficient: Benefits of Direct
Use of Natural Gas
For many years, energy agencies have alerted Americans
to the importance of energy efficiency. A variety of tags and
certifications, backed by financial incentives, encourage us
to understand our equipment buying options. We know that
it makes sense to spend a little more on a product so that
we can save money and energy throughout its useful life.
These efforts continue to reduce per capita energy use
for both natural gas and electric customers. And the more
energy we save, the lower our impact on the environment.
But focusing on product efficiency only reveals half the
story. To get the whole picture, it’s important to look at
what’s called the full fuel cycle. That means understanding
how much energy is retained – or lost – from the energy’s
source until its final use in your water heater, oven or home
heating system.
And with the full fuel cycle in mind, direct use of natural
gas comes out a winner in the energy efficiency race.
For instance, by the time you turn on your electric
appliance, up to 62 of the energy value from the original
fuel has been lost. So the full fuel cycle efficiency is about
38 percent. The full fuel cycle efficiency of a natural gas
appliance is about 92 percent – a substantial difference.
Here’s how it works.
Even with advances in renewable power, most electricity
in the U.S. is generated by either coal or natural gas.
• We lose about 5 percent of the energy benefits
of those fuels during the transportation process –
before they arrive at the power plant.
• The major energy loss occurs during generation.
Burning a fuel to create electricity wastes about 62
percent of its energy. That lost energy turns into
heat, rather than useful power.
• Finally, we lose another 6 percent of the energy over
the electric transmission lines.
So for every 100 MMBtu of fuel that leaves
the mine or the well, only 32 MMBtu reaches our
appliances. The rest is lost.
These fuel choices have important environmental
implications. On average, the house fueled by
natural gas is responsible for about 37 percent
fewer greenhouse gas emissions than a comparable
all-electric home. Furthermore, the more fuel we
waste, the more we need to produce and transport
-- processes that also affect the environment.
We are approaching a future when a combination
of wind, solar, wave energy and usable storage will
reduce our reliance on fossil fuels. Until then, one of
the most effective ways we have to save energy and
reduce carbon emissions today is to use natural gas
directly in our homes and businesses wherever gas is
available.
N W G A
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G A S
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13
Possible Regional
Demand Scenarios
We have developed two
scenarios to explore the impact
that plausible but currently
unaddressed growth could
have on regional demand
and capacity utilization. They
include a coal replacement
scenario and an accelerated
industrial growth 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 a
possible future outcome. To our
knowledge, neither scenario
reflects any actual negotiations
or commercial agreements,
nascent or otherwise, except as
can be found publicly.
SCENARIO 1: Coal Replacement
SCENARIO 2: Accelerated Industrial Demand
In response to policy and regulatory requirements, PGE agreed
to cease coal-fueled generation at the Boardman plant in 2020.
Likewise, 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.” 16 Similarly PGE, while keenly
focused on developing renewable fuel alternatives to replace as
much of the 550-MW capacity of the Boardman plant as possible,
has not dismissed the possibility that natural gas may play some
role in its new generation portfolio.
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).17
This 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 2019-20, 200 MW to Eastern Oregon loads (off the GTN
pipeline) in 2020-21 and another 300 MW to Western Washington
loads in 2021-22. Further assumptions include current turbine
technology with a heat rate of 7,000 Btu/kilowatt-hour18 operated
75 percent of the time (utilization rate). Under this scenario, 300 MW
of generation equals an annual gas load of 9.2 MMDth and a daily
load of 45,000 Dth.
A number of projects have been announced and are being actively
pursued since the 2014 Outlook was published. We are classifying them
into two types of industrial load: general and large load projects.
The general category includes a number of BC projects like Woodfibre
LNG near Squamish, FortisBC’s Tilbury LNG expansion and local LNG, as
well as some generic U.S. and Canadian industrial loads not otherwise
accounted for in the Outlook forecast. It does not include the methanol
plants proposed for the region (see below). For this category of
prospective load, NWGA adjusted the base case industrial load by adding
35 thousand dekatherms a day (MDth/day) starting in the 2016-17
heating year, 200MDth/day in 2017-18 and another 200 MDth/day in
2019-20.
The large load category includes the methanol plants being proposed
for the region by Northwest Innovation Works (NWIW) in three locations:
Washington state at Kalama and Tacoma and Oregon at Port Westward.
We used the following phase-in scenario:
www.transalta.com/us/2011/12/growth-2/
EFSEC, Amendment 5 to Grays Harbor Energy Center Site Certification Agreement, December 21, 2010
18
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.).
16
17
N W G A
2 0 1 5
G A S
O U T L O O K
2018-19
2019-20
2020-21
2021-22
Kalama Train 1
Tacoma Train 1, Kalama Train 2
Tacoma Train 2, Port Westward Train 1
Port Westward Train 2
160 MDth/day
320 MDth/day
320 MDth/day
160 MDth/day
The average daily load for the entire region in 2014 was 2.3 MMDth
(more during the winter months, less during the summer). If fully built
out as proposed, the methanol plants will consume close to 1 MMDth/
day or almost half the region’s current average daily load. On a related
note, these methanol loads in aggregate approximate those of an LNG
export facility. The two are essentially interchangeable for the purpose
of illustrating the potential impact of a large project on overall regional
loads and the region’s natural gas infrastructure
14
Combined Results – If both scenarios were fully realized, the total annual demand
in the last year of the forecast would be 546 MMDth or 42 percent higher than the
expected case. The overall annual growth rate would increase from 1.5 percent to 6.5
percent. As discussed in more detail in the following section, these results suggest an
accelerated need for additional capacity in the region.
FIGURE D5. Growth Scenarios
1600
1400
1200
Million Dth
1000
800
600
400
200
0
2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24
Expected Annual
Coal Replacement
General Industrial
Demand Large Load
Industrial
Natural Gas and EPA’s Clean Power Plan (111[d])
The EPA issued proposed rules to regulate carbon dioxide emissions
from existing base load power plants under section 111 (d) of the Clean
Air Act. The provisions are called the Clean Power Plan, though most refer
to it as “111(d).” The goal of these regulations is to decrease cumulative
emissions from these generating units to 30 percent below 2005 levels by
2030, with interim emission rules becoming effective in 2020. The final EPA
rules are expected in summer of 2015. States will have one to two years to
develop state implementation plans. The rules provide states flexibility to
work together across state lines to meet emission reduction targets.
How does this affect the gas industry?
One key element of 111(d) calls for states to substitute coal-fired
generation with gas-fired generation. The idea is that states would
require combined cycle combustion gas plants to operate at a 70-percent
capacity factor and reduce dispatch of coal plants by that same amount
of generation. However, the EPA also provides flexibility to states to use
renewable electric generation and/or energy efficiency programs in
addition to or instead of substituting natural gas for coal-fired generation.
How big an impact might 111(d) have on Northwest natural gas
markets?
Any good economist will say…that depends. 111(d) is a very
complicated proposal, not a final rule. Even when the final rule is issued,
111(d) will require states to develop individual or joint implementation
plans. THAT is where the gas will hit the pilot light and we’ll understand real
implications. Also, several states and industry groups are already lining up
to file lawsuits about different elements of 111(d)—even before EPA has
issued final rules.
This is sure to be an issue we’ll be following for the next several years.
– Phillip Popoff: Resource Planning Manager, Puget Sound Energy; Chairman,
NWGA/PNUCC Power & Natural Gas Planning Task Force
N W G A
2 0 1 5
G A S
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15
2015 GAS OUTLOOK -
Summary
Regional System Capacity
Key Conclusions
• The existing system of natural gas pipelines and storage facilities has reliably served the
load requirements of the Pacific Northwest for decades and is sufficient to meet today’s
needs, though recent cold weather events have approached system limits.
The Pacific Northwest’s 48,000-mile network of transmission and distribution pipelines
safely and reliably serves almost 3.5 million natural gas customers. The pipelines that
transport natural gas from production areas in Alberta, BC, and the U.S. Rockies can deliver
more than 4 MMDth/day to the region.
FIGURE C1. Pacific Northwest Infrastructure and Capacities (MDth)
• Additional capacity is likely to be required within the forecast horizon to serve growing
demand for natural gas, particularly on a design day. Industrial and generation demand
above the expected case will amplify and accelerate the need for incremental capacity
required to serve the region.
AECO
• The timing, location and type of future capacity expansions or additions, whether
pipelines or storage, and utilization of existing infrastructure, will depend on the
changing nature of regional natural gas demand.
• Increased large industrial loads in the region are projected to bring daily baseload
demand that will alter the utilization profile of current and new pipeline systems, while
promoting greater consistency in gas flow on a year-round basis compared to a largely
winter-only profile of most systems.
Palouse
Sta$on 2 2060 Pipelines TABLE C1. Regional Storage Facilities
Facility
Owner
TypeCapacity1 Max Withdrawal
Sta$on 2 (MDth)(MDth/day)
2060 Jackson Prairie, WA Avista, PSE, NWP
Underground 25,448
1,1962
154 Mist,
OR
NWStorage
Natural Facilities
Underground 16,100
5202
Table
C1. Regional
Underground Subtotal 41,5481,716
Plymouth, WA
NWP
LNG
2,388
305
154 Newport, OR
NW Natural
LNG
1,000
60
154 Kingsgate Sumas Portland, OR
NW Natural
LNG
600
120
520 2796 1306 Tilbury, BC
FortisBC Energy
LNG
591
155
120 Nampa, ID
Intermountain Gas
LNG
588
60 Starr Road 165 60 Gig Harbor, WA
PSE
LNG
13
3
1196 305 Swarr Station, WA PSE
LPG3
13010
520 Stanfield 153
Mt. Hayes, BC
FortisBC Energy
LNG
1,530
120 638 Peak Storage Subtotal
6,840
866
60 Total Storage
48,388
2,582
60 Working gas capacity; gas that can be used to serve the market.
2
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
Malin N W G A
2 0 1 5
G A S
O U T L O O K
2080 AECO Pipelines 154 Kingsgate 2796 Malin
Sumas 1306 AECO Starr Road 165 1196 305 638 Malin Spectra BCP
Williams NWP
TCPL - GTN
Other TCPL
FortisBC SCP
K-M Ruby
Prairie Jackson Mist 495 158 1500 L NG Kemmerer S655 torage Nampa Newport Plymouth Portland Tilbury Mt. Hayes Underground Storage Jackson Prairie Jackson
Prairie
Mist Mist
60 2080 Kemmerer 655 Spectra BCP Williams NWP TCPL -­‐ GTN Other TCPL For;sBC SCP K-­‐M Ruby Underground
Storage
Underground Storage Stanfield Pipelines
495 158 Spectra BCP Williams NWP TCPL -­‐ GTN Other TCPL For;sBC SCP K-­‐M Ruby LNG
Storage
L NG Storage Nampa
Nampa Newport
Newport Plymouth
Plymouth Portland
Portland Tilbury
Tilbury Hayes Mt.Mt. Hayes
16
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.
FIGURE C2. Region-wide Peak Day Resource/Demand Balance19
FIGURE C3. I-5 Peak Day Resource/Demand Balance19
Expected
High
Pipeline
Underground Storage
Peak LNG
8
8
7
7
6
6
5
4
3
Expected
High
Pipeline
Underground Storage
Peak LNG
5
4
3
2
2
1
1
0
19
Low
9
Million
Dth/day
Million
Dth/day
MillionDth/day
Dth/day
Million
Low
9
0
2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24
Gas Year (Nov-Oct)
2014/15 2015/16 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24
Gas Year (Nov-Oct)
Figures C2 and C3 assumptions include: a design weather day occurs simultaneously across the depicted region; existing infrastructure will
deliver 100 percent of its capability; gas will not flow to customers without firm pipeline transportation contracts (e.g., industrial users or
electricity generators with alternate fuels).
N W G A
2 0 1 5
G A S
O U T L O O K
17
Accelerated Demand Scenario – While regional capacity has served the Northwest’s
needs under severe circumstances, the winter of 2013-14 provided a cautionary tale:
the region’s delivery infrastructure may require augmentation to accommodate material
growth.
Two potential scenarios are outlined in the Demand Section of this report, including
accelerated industrial demand and coal-fired generation replacement. Figure C5 includes
the projected incremental loads from these scenarios plotted against the resources
available to serve the region.20 Quicker deployment of new capacity will be required to
serve the region if these scenarios are realized.
Expected
Coal Replacement
General Industrial
Pipeline
Underground Storage
Peak LNG
Large Industrial
FIGURE C4. Accelerated Demand Peak Day Resource/Demand Balance20
9
8
FIGURE C5. Proposed Natural Gas Infrastructure Projects
6
Kingsvale
3
Southern
Crossing
es
tc
oa
st
5
4
W
Million Dth/day
Dth/day
Million
7
Analyses such as these help send signals to the market of an impending need for
additional capacity. Market participants weigh the probability of disruptions against 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. Several have been proposed in the Pacific Northwest (Figure C4).
However, reductions in projected demand, a slow economic recovery and the new
reality of a vast North American supply of natural gas have all combined to change the
nature of projects now being considered within 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; from
serving a rapidly growing core market to serving potential industrial and electric generation
demand growth.
Still, it is only a matter of time before new capacity within the region will be required.
(See Appendix D for brief descriptions of proposed projects.)
TCPL
Kingsgate
Sumas
3
1
2
1
NWP
1
Washington Expansion Project
Install pipeline loop and compression
2
Trail West/N-MAX
Utilize capacity on GTN and proposed
Trail West in combination with NWP
expansion in the I-5 corridor
3
Spectra System Enhancements/
FortisBC KORP
Utilize capacity on Westcoast in
combination with Southern Crossing
expansion to Kingsgate
4
Pacific Connector
Construct new pipeline for LNG
exports and regional markets
0
Stanfield
Expected
Coal Replacement
General Industrial
Pipeline
Underground Storage
Peak LNG
Large Industrial
Molalla
2
Trail West
N
GT
Madras
9
6
N W3 G A
2 0 1 5
G A S
O U T L O O K
Ruby
Ke
rn
PG&E
a
4
Opal
Malin
rir
Tusca
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.
5
Million Dth/day
P
4
7
20
NW
Coos Bay
8
18
Capacity Variables
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:
• When, where and how much natural gas the region will require to generate electricity.
• Whether large industrial and/or LNG export loads proposed for the region materialize.
• The impact of the legal and regulatory environment on the ability to build new or
expand existing infrastructure in a timely manner. Projects can take three to five years to
develop, making foresight imperative.
N W G A
2 0 1 5
G A S
O U T L O O K
19
Appendices
N W G A
2 0 1 5
G A S
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20
Appendix A: Data Tables
Table A1. Maximum Capacity (Bcf/d)
SUPPLY
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022 / 2023
2023 / 2024
Pipeline Interconnects
4,105,153 4,105,153 4,105,153 4,105,153 4,105,153 4,105,153 4,105,153 4,105,1534,105,1534,105,153
WCSB via TCPL/GTN
1,626,888 1,626,888 1,626,888 1,626,888 1,626,888 1,626,888 1,626,888 1,626,8881,626,8881,626,888
Stanfield (NWP from GTN)
692,920 692,920 692,920 692,920 692,920 692,920 692,920 692,920692,920692,920
Starr Rd (NWP from GTN)
165,000 165,000 165,000 165,000 165,000 165,000 165,000 165,000165,000165,000
Palouse (NWP from GTN)
70,459 70,459 70,459 70,459 70,459 70,459 70,459 70,45970,45970,459
GTN Direct Connects
511,568 511,568 511,568 511,568 511,568 511,568 511,568 511,568511,568511,568
Kingsgate/Yahk BC Interior from TCPL
186,941 186,941 186,941 186,941 186,941 186,941 186,941 186,941186,941186,941
Rockies via NWP
495,000 495,000 495,000 495,000 495,000 495,000 495,000 495,000495,000495,000
NWP north from NWP south
655,000 655,000 655,000 655,000 655,000 655,000 655,000 655,000655,000655,000
Max Demand on Reno Lateral
(160,000) (160,000) (160,000) (160,000) (160,000) (160,000) (160,000) (160,000)(160,000)(160,000)
WCSB via SET
1,983,265 1,983,265 1,983,265 1,983,265 1,983,265 1,983,265 1,983,265 1,983,2651,983,2651,983,265
T-South to Huntingdon
1,753,060 1,753,060 1,753,060 1,753,060 1,753,060 1,753,060 1,753,060 1,753,0601,753,0601,753,060
T-South to BC Interior
178,705 178,705 178,705 178,705 178,705 178,705 178,705 178,705178,705178,705
T-South to Kingsvale
51,500 51,500 51,500 51,500 51,500 51,500 51,500 51,50051,50051,500
Storage
2,429,758 2,585,058 2,585,058 2,585,058 2,585,058 2,585,058 2,585,058 2,585,0582,585,0582,585,058
Jackson Prairie (NWP from JP)
1,196,000 1,196,000 1,196,000 1,196,000 1,196,000 1,196,000 1,196,000 1,196,0001,196,0001,196,000
Mist Storage (NWN)
520,000 520,000 520,000 520,000 520,000 520,000 520,000 520,000520,000520,000
Plymouth (NWP from LNG)
150,000 305,300 305,300 305,300 305,300 305,300 305,300 305,300305,300305,300
Newport LNG (NWN)
60,000 60,000 60,000 60,000 60,000 60,000 60,000 60,00060,00060,000
Portland LNG (NWN)
120,000 120,000 120,000 120,000 120,000 120,000 120,000 120,000120,000120,000
Nampa LNG (IGC)
60,000 60,000 60,000 60,000 60,000 60,000 60,000 60,00060,00060,000
Gig Harbor Satellite LNG (PSE)
5,250 5,250 5,250 5,250 5,250 5,250 5,250 5,2505,2505,250
Swarr Stn Propane (PSE)
10,000 10,000 10,000 10,000 10,000 10,000 10,000 10,00010,00010,000
Tilbury LNG (FortisBC)
155,466 155,466 155,466 155,466 155,466 155,466 155,466 155,466155,466155,466
Mount Hayes LNG (FortisBC)
153,042 153,042 153,042 153,042 153,042 153,042 153,042 153,042153,042153,042
Total Available Supply
6,534,911 6,690,211 6,690,211 6,690,211 6,690,211 6,690,211 6,690,211 6,690,2116,690,2116,690,211
N W G A
2 0 1 5
G A S
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21
Appendix A2: Annual Demand Forecast (Dth) – Expected Case
2014 / 2015
Region/Sector
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022/2023
2023/2024
BC Lower Mainland & Van. Island 140,882,018 139,512,812 140,085,069 139,617,266 139,570,609 139,790,775 140,030,588 140,421,388 140,946,117 141,667,383
Residential
52,238,905 52,017,747 51,711,676 51,395,676 51,124,530 50,872,680 50,620,831 50,368,981 50,117,132 49,865,283
Commercial
40,360,171 40,230,031 40,007,380 39,789,679 39,618,932 39,465,635 39,312,339 39,159,042 39,005,745 38,852,448
Industrial
33,235,152 33,388,994 34,527,885 34,593,783 34,989,019 35,576,419 36,259,290 37,055,237 37,985,111 39,073,612
Power Generation
15,047,789 13,876,041 13,838,128 13,838,128 13,838,128 13,876,041 13,838,128 13,838,128 13,838,128 13,876,041
W. Washington
260,889,891 263,511,962 275,212,744 280,862,019 283,558,022 283,348,281 285,789,372 292,391,566 295,591,541 300,694,416
Residential
73,141,759 74,797,472 76,288,160 77,663,564 78,551,395 79,476,456 80,357,699 81,311,497 82,234,975 83,205,743
Commercial
42,985,457 44,013,927 44,944,212 45,693,201 46,227,797 46,754,981 47,247,778 47,830,800 48,410,571 49,065,821
Industrial
77,399,429 77,990,821 78,614,233 79,144,147 79,496,743 79,852,627 80,199,653 80,607,271 80,884,223 81,206,679
Power Generation
67,363,246 66,709,742 75,366,138 78,361,108 79,282,087 77,264,217 77,984,242 82,641,997 84,061,772 87,216,173
W. Oregon
128,399,308 130,112,664 130,531,417 131,234,090 132,044,447 133,223,829 133,951,833 135,017,418 136,195,207 137,760,720
Residential
38,489,942 38,966,030 39,093,599 39,415,929 39,762,969 40,308,721 40,517,221 40,901,729 41,314,762 41,939,677
Commercial
27,471,917 27,487,859 27,332,851 27,346,870 27,410,206 27,608,412 27,641,249 27,797,342 27,989,460 28,302,067
Industrial
47,437,448 48,658,775 49,104,968 49,471,291 49,871,273 50,306,695 50,793,362 51,318,346 51,890,985 52,518,977
Power Generation
15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000
BC Interior
54,661,981 54,837,534 54,938,527 55,059,473 54,835,829 54,537,744 54,239,659 53,941,574 53,643,489 53,345,404
Residential
16,617,255 16,644,163 16,643,128 16,634,435 16,641,679 16,656,226 16,670,773 16,685,319 16,699,866 16,714,413
Commercial
10,741,907 10,885,857 11,035,830 11,184,965 11,331,200 11,476,416 11,621,632 11,766,848 11,912,064 12,057,280
Industrial
27,302,818 27,307,514 27,259,569 27,240,072 26,862,950 26,405,102 25,947,254 25,489,406 25,031,559 24,573,711
Power Generation
- - - - - - - - - E. Washington & N. Idaho
72,321,028 72,994,715 73,672,874 74,465,812 75,761,468 77,131,553 78,252,745 78,918,700 79,508,262 81,473,632
Residential
19,821,796 20,147,076 20,196,855 20,440,177 20,655,550 20,952,459 21,025,466 21,067,461 21,258,229 21,562,650
Commercial
13,757,958 13,939,547 13,938,744 14,069,753 14,206,373 14,409,516 14,467,892 14,522,755 14,657,002 14,865,291
Industrial
29,131,643 29,407,237 29,813,793 30,251,240 30,676,072 31,114,382 31,525,191 31,963,518 32,352,811 32,772,635
Power Generation
9,609,631 9,500,854 9,723,482 9,704,642 10,223,473 10,655,195 11,234,196 11,364,966 11,240,219 12,273,056
E. Oregon & Medford
108,166,949 115,205,362 120,272,002 119,981,017 124,550,193 128,979,581 133,341,419 133,261,607 132,360,292 139,012,834
Residential
7,313,522 7,447,810 7,494,168 7,598,527 7,703,487 7,844,922 7,908,307 7,981,381 8,085,223 8,229,735
Commercial
5,327,078 5,413,712 5,447,401 5,514,026 5,584,107 5,678,307 5,722,003 5,774,754 5,842,591 5,935,417
Industrial
9,424,760 9,513,761 9,638,363 9,766,896 9,887,447 10,011,757 10,135,302 10,272,246 10,386,536 10,513,374
Power Generation
86,101,589 92,830,079 97,692,069 97,101,567 101,375,152 105,444,595 109,575,807 109,233,226 108,045,942 114,334,308
S. Idaho
72,653,023 74,842,242 76,453,705 77,104,977 78,051,907 78,546,934 79,057,789 79,573,087 80,092,871 80,617,183
Residential
23,241,408 23,778,674 24,407,613 24,723,904 25,277,326 25,530,100 25,785,401 26,043,255 26,303,687 26,566,724
Commercial
11,972,844 12,249,618 12,573,616 12,736,554 13,021,650 13,151,867 13,283,385 13,416,219 13,550,381 13,685,885
Industrial
27,938,771 29,313,950 29,972,476 30,144,519 30,252,931 30,364,968 30,489,003 30,613,613 30,738,803 30,864,574
Power Generation
9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000
Expected PNW Annual Demand 837,974,198 851,017,293 871,166,337 878,324,654 888,372,476 895,558,698 904,663,403 913,525,341 918,337,779 934,571,573
Residential
230,864,588233,798,973235,835,199 237,872,214239,716,936241,641,564242,885,697244,359,624 246,013,875248,084,225
Commercial
152,617,333154,220,551155,280,034 156,335,047157,400,265158,545,136159,296,279160,267,762 161,367,814162,764,210
Industrial
251,870,021255,581,052258,931,287 260,611,948262,036,434263,631,950265,349,056267,319,638 269,270,029271,523,561
Power Generation
202,622,255207,416,716221,119,817 223,505,444229,218,840231,740,047237,132,372241,578,318 241,686,061252,199,577
N W G A
2 0 1 5
G A S
O U T L O O K
22
Appendix A3: Annual Demand Forecast (Dth) – High Case
Region/Sector
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
142,734,917 50,938,394 40,300,239 37,620,243 13,876,041 330,371,271 82,681,555 48,507,128 82,121,100 117,061,488 134,822,599 40,644,195 28,868,735 50,309,669 15,000,000 56,061,863 16,768,354 11,788,739 27,504,770 - 105,885,815 21,820,004 15,220,886 31,511,912 37,333,011 186,197,523 8,246,008 5,975,335 10,163,266 161,812,914 85,097,074 27,783,031 14,312,467 33,501,576 9,500,000 2020 / 2021
2021 / 2022
143,574,631 144,644,296 50,697,519 50,456,954 40,268,561 40,236,216 38,770,423 40,112,998 13,838,128 13,838,128 333,967,863 353,670,542 84,390,963 85,444,580 49,504,631 50,143,404 82,598,938 82,999,111 117,473,330 135,083,447 135,831,928 137,220,763 40,932,528 41,420,962 29,102,983 29,478,100 50,796,417 51,321,701 15,000,000 15,000,000 55,975,454 55,885,712 16,799,782 16,831,257 11,985,657 12,183,961 27,190,015 26,870,493 - - 100,317,448 106,514,483 22,029,468 22,337,072 15,358,848 15,564,658 31,964,378 32,421,541 30,964,754 36,191,212 184,239,956 189,548,092 8,339,025 8,469,530 6,035,975 6,119,753 10,301,178 10,442,172 159,563,778 164,516,636 85,621,866 86,151,315 28,060,861 28,341,470 14,455,592 14,600,148 33,605,413 33,709,697 9,500,000 9,500,000 2022/2023
2023/2024
BC Lower Mainland & Van. Island
Residential
Commercial
Industrial
Power Generation
W. Washington
Residential
Commercial
Industrial
Power Generation
W. Oregon
Residential
Commercial
Industrial
Power Generation
BC Interior
Residential
Commercial
Industrial
Power Generation
E. Washington & N. Idaho
Residential
Commercial
Industrial
Power Generation
E. Oregon & Medford
Residential
Commercial
Industrial
Power Generation
S. Idaho
Residential
Commercial
Industrial
Power Generation
141,443,255 140,551,575 141,567,165 141,539,313 141,977,408 52,252,139 52,043,124 51,746,698 51,440,467 51,179,580 40,543,223 40,573,288 40,474,428 40,379,364 40,331,254 33,600,104 34,059,122 35,507,911 35,881,354 36,628,446 15,047,789 13,876,041 13,838,128 13,838,128 13,838,128 271,809,041 279,249,416 306,798,645 331,792,531 338,479,659 76,656,586 77,885,401 79,749,697 81,170,612 82,169,637 45,135,890 45,615,084 46,768,125 47,557,324 48,168,827 79,599,131 80,376,814 81,100,388 81,596,769 81,898,918 70,417,434 75,372,117 99,180,435 121,467,827 126,242,278 128,772,355 130,705,154 131,365,747 132,307,873 133,370,706 38,573,881 39,079,793 39,255,860 39,625,681 40,030,149 27,759,006 27,964,307 28,002,536 28,208,265 28,466,572 47,439,468 48,661,054 49,107,351 49,473,928 49,873,986 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 55,017,051 55,467,120 55,796,333 56,148,443 56,144,974 16,640,968 16,689,347 16,704,997 16,712,967 16,736,971 10,804,385 11,004,982 11,201,220 11,397,998 11,593,201 27,571,699 27,772,791 27,890,117 28,037,478 27,814,802 - - - - - 90,527,722 91,639,476 95,151,657 96,645,149 100,711,468 20,233,202 20,624,364 20,838,126 21,130,671 21,426,204 14,176,116 14,429,076 14,560,665 14,756,571 14,954,974 29,503,684 29,781,914 30,224,865 30,661,209 31,086,632 26,614,721 26,804,121 29,528,001 30,096,697 33,243,658 151,835,828 162,195,518 169,460,760 172,329,075 179,397,649 7,575,171 7,734,484 7,826,179 7,953,034 8,080,787 5,529,222 5,634,165 5,696,445 5,780,933 5,866,286 9,581,511 9,668,217 9,804,956 9,929,595 10,046,750 129,149,923 139,158,653 146,133,180 148,665,513 155,403,825 72,755,074 75,960,696 79,521,901 82,566,251 84,574,287 23,325,334 24,378,756 25,563,712 26,424,796 27,507,951 12,016,079 12,558,750 13,169,182 13,612,771 14,170,760 27,913,661 29,523,190 31,289,007 33,028,684 33,395,576 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 PNW Annual Demand – High
Residential
Commercial
Industrial
Power Generation
912,160,327 935,768,955 979,662,2071,013,328,6341,034,656,151 1,041,171,061 1,039,529,1451,073,635,201 1,081,303,065 1,102,145,945
235,257,280 238,435,269241,685,269244,458,228 247,131,278 248,881,540 251,250,146253,301,824 255,661,864 258,252,522
155,963,921 157,779,653159,872,600161,693,225 163,551,874 164,973,531 166,712,246168,326,240 170,205,101 172,280,077
255,209,259 259,843,101264,924,594268,609,016 270,745,110 272,732,536 275,226,763277,877,714 280,577,835 283,666,812
265,729,867 279,710,932313,179,745338,568,165 353,227,888 354,583,453 346,339,990374,129,422 374,858,265 387,946,535
N W G A
145,947,402 50,216,701 40,203,200 41,689,373 13,838,128 354,368,819 86,772,323 51,007,207 83,264,660 133,324,629 138,717,573 41,935,135 29,888,017 51,894,421 15,000,000 55,792,596 16,862,778 12,383,660 26,546,159 - 107,105,528 22,649,171 15,772,921 32,813,717 35,869,719 192,685,683 8,600,873 6,203,946 10,555,074 167,325,789 86,685,464 28,624,884 14,746,149 33,814,430 9,500,000 2 0 1 5
G A S
147,572,272
49,976,761
40,169,509
43,549,962
13,876,041
361,944,507
87,958,992
51,833,897
83,515,586
138,636,033
140,628,506
42,673,228
30,432,601
52,522,676
15,000,000
55,696,071
16,894,345
12,584,762
26,216,964
112,365,740
23,066,061
16,052,563
33,254,276
39,992,840
196,714,490
8,772,002
6,313,134
10,687,733
170,941,622
87,224,359
28,911,133
14,893,611
33,919,615
9,500,000
O U T L O O K
23
Appendix A4: Annual Demand Forecast (Dth) – Low Case
2014 / 2015
Region/Sector
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
BC Lower Mainland & Van. Island139,631,643 137,185,369 136,780,141 135,369,551 134,316,279 133,456,346 132,534,091 Residential
52,090,282 51,736,222 51,328,950 50,913,264 50,543,349 50,193,775 49,845,398 Commercial
40,046,472 39,644,155 39,214,147 38,793,107 38,420,667 38,068,020 37,718,307 Industrial
32,447,100 31,928,951 32,398,916 31,825,051 31,514,135 31,318,509 31,132,258 Power Generation
15,047,789 13,876,041 13,838,128 13,838,128 13,838,128 13,876,041 13,838,128 W. Washington
245,034,942 250,280,495 254,461,117 255,023,837 257,005,316 253,307,787 259,223,514 Residential
70,120,062 71,146,369 72,494,240 73,754,090 74,517,817 75,042,126 76,188,367 Commercial
41,145,685 41,535,432 42,350,103 43,049,771 43,515,176 43,840,458 44,439,861 Industrial
75,020,985 75,818,679 76,472,725 76,990,025 77,301,576 77,571,008 77,957,823 Power Generation
58,748,210 61,780,014 63,144,049 61,229,951 61,670,747 56,854,196 60,637,463 W. Oregon
128,058,094 129,529,209 129,729,790 130,182,548 130,727,213 131,628,679 132,088,737 Residential
38,445,231 38,881,926 38,979,002 39,250,229 39,533,298 40,007,735 40,143,211 Commercial
27,175,505 26,988,884 26,646,254 26,461,723 26,323,435 26,315,300 26,153,282 Industrial
47,437,359 48,658,399 49,104,534 49,470,596 49,870,480 50,305,644 50,792,244 Power Generation
15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 15,000,000 BC Interior
53,964,805 53,610,422 53,280,268 52,971,614 52,346,406 51,663,223 50,992,548 Residential
16,546,262 16,509,100 16,458,554 16,400,612 16,358,515 16,323,695 16,288,938 Commercial
10,648,658 10,708,768 10,791,167 10,871,378 10,947,438 11,021,212 11,093,707 Industrial
26,769,885 26,392,554 26,030,548 25,699,625 25,040,453 24,318,316 23,609,904 Power Generation
- - - - - - - E. Washington & N. Idaho
70,038,677 69,919,596 70,610,004 71,520,361 72,174,928 73,177,663 74,065,818 Residential
19,254,652 19,335,654 19,313,246 19,368,619 19,397,726 19,551,748 19,550,097 Commercial
13,446,155 13,519,545 13,513,637 13,569,485 13,611,683 13,734,457 13,747,296 Industrial
28,934,388 29,201,639 29,602,509 30,032,627 30,448,967 30,879,047 31,282,999 Power Generation
8,403,482 7,862,758 8,180,612 8,549,630 8,716,552 9,012,411 9,485,425 E. Oregon & Medford
98,159,292 101,015,337 106,766,032 109,944,369 112,354,152 115,431,728 119,450,728 Residential
7,053,618 7,142,870 7,182,631 7,255,781 7,323,802 7,433,578 7,479,953 Commercial
5,163,404 5,228,938 5,261,503 5,315,157 5,366,416 5,443,100 5,476,264 Industrial
9,339,656 9,426,901 9,549,029 9,675,291 9,794,269 9,915,473 10,037,384 Power Generation
76,602,615 79,216,627 84,772,869 87,698,140 89,869,665 92,639,578 96,457,127 S. Idaho
72,438,351 73,044,394 73,489,067 73,536,453 73,946,289 74,312,027 74,681,422 Residential
23,201,543 23,543,452 23,836,936 23,868,211 24,138,702 24,380,090 24,623,890 Commercial
11,952,307 12,128,442 12,279,631 12,295,742 12,435,086 12,559,437 12,685,032 Industrial
27,784,501 27,872,500 27,872,500 27,872,500 27,872,500 27,872,500 27,872,500 Power Generation
9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 9,500,000 PNW Annual Demand – Low
Residential
Commercial
Industrial
Power Generation
N W G A
2 0 1 5
G A S
2021 / 2022
2022 / 2023
131,663,638 49,498,214 37,371,504 30,955,792 13,838,128 260,064,531 76,808,669 44,875,110 78,336,853 60,043,900 132,880,923 40,452,806 26,111,102 51,317,015 15,000,000 50,334,167 16,254,241 11,164,934 22,914,992 - 74,972,648 19,602,116 13,802,372 31,715,217 9,852,943 123,345,148 7,553,269 5,526,876 10,172,487 100,092,516 75,054,511 24,870,129 12,811,882 27,872,500 9,500,000 130,807,485 49,152,218 37,027,587 30,789,551 13,838,128 261,168,136 77,493,800 45,324,208 78,590,549 59,759,579 133,746,188 40,763,892 26,092,733 51,889,562 15,000,000 49,687,873 16,219,607 11,234,908 22,233,358 - 73,655,580 19,626,753 13,842,578 32,096,627 8,089,622 108,669,085 7,620,847 5,574,860 10,284,276 85,189,102 75,431,331 25,118,831 12,940,001 27,872,500 9,500,000 2023 / 2024
130,003,989
48,807,409
36,686,533
30,634,007
13,876,041
261,939,506
77,915,815
45,667,886
78,790,400
59,565,406
134,985,616
41,281,380
26,186,928
52,517,307
15,000,000
49,053,457
16,185,034
11,303,640
21,564,784
75,499,252
19,827,882
13,992,117
32,508,919
9,170,335
119,465,458
7,742,176
5,654,116
10,408,916
95,660,250
75,811,920
25,370,019
13,069,401
27,872,500
9,500,000
807,325,805 814,584,822 825,116,419 828,548,733 832,870,583 832,977,453 843,036,858 848,315,567 833,165,677
846,759,198
226,711,649228,295,593229,593,558230,810,807231,813,209232,932,746234,119,854 235,039,444 235,995,947 237,129,715
149,578,186149,754,165150,056,442150,356,362150,619,902150,981,985151,313,749 151,663,780 152,036,876 152,560,621
247,733,873249,299,624251,030,761251,565,716251,842,380252,180,497252,685,112 253,284,856 253,756,423 254,296,831
183,302,096187,235,440194,435,658195,815,849198,595,092196,882,226204,918,143 208,327,487 191,376,430 202,772,031
O U T L O O K
24
Appendix A5: Peak Day Demand/Supply Balance (Dth/day) – Expected Case
Demand (Region/Sector)
2014 / 2015
2015 / 2016
BC Lower Main & Van. Island (I-5 )
Residential
Commercial
Industrial
Power Generation
W. Washington (I-5 Corridor)
Residential
Commercial
Industrial
Power Generation
W. Oregon (I-5 Corridor)
Residential
Commercial
Industrial
Power Generation
BC Interior
Residential
Commercial
Industrial
Power Generation
E. Washington & N. Idaho
Residential
Commercial
Industrial
Power Generation
E. Oregon & Medford (Non I-5)
Residential
Commercial
Industrial
Power Generation
S. Idaho
Residential
Commercial
Industrial
Power Generation
Total Design (Peak) Day Demand
1,390,449
1,165,183
1,163,051
1,161,142
1,160,114
1,157,930
1,156,094
1,154,668 1,153,731
1,153,370
550,829 547,598544,320 540,936 537,483 534,148 530,813527,477524,142 520,807
420,583 417,526415,929 414,362 414,258 412,677 411,096409,514407,933 406,351
158,387 162,146164,889 167,932 170,460 173,193 176,273179,764183,743 188,299
260,650 37,91337,913 37,913 37,913 37,913 37,91337,91337,913 37,913
2,158,410
2,191,346
2,220,307
2,249,079
2,273,322
2,290,396
2,310,606
2,330,141 2,349,988
2,370,676
803,929 826,304845,074 864,302 880,358 890,547 902,509915,031927,696 939,965
367,885 377,149386,586 395,800 403,523 409,977 416,429423,276430,503 437,750
270,657 271,954272,708 273,039 273,502 273,933 275,729275,895275,851 277,022
715,939 715,939715,939 715,939 715,939 715,939 715,939715,939715,939 715,939
1,006,569
1,014,501
1,020,746
1,027,187
1,034,771
1,042,683
1,051,994
1,061,404 1,071,013
1,081,140
569,197 574,972580,576 586,252 592,458 598,973 605,687612,540619,337 626,631
292,171 292,177292,104 292,535 293,523 294,884 296,559298,542300,717 303,251
75,202 77,35278,066 78,400 78,790 78,826 79,74880,32280,958 81,257
70,000 70,00070,000 70,000 70,000 70,000 70,00070,00070,000 70,000
402,595 404,953407,117 409,147 411,029 413,141 415,252417,363419,474 421,586
192,437 192,470192,459 192,358 192,184 192,123 192,061191,999191,937 191,876
129,262 131,270133,196 135,114 136,912 138,826 140,740142,654144,569 146,483
80,895 81,21381,462 81,675 81,933 82,192 82,45182,71082,968 83,227
0 00 0 0 0 000 0
593,876
598,691
603,318
605,640
610,358
614,725
619,662
623,128
623,948
628,356
226,571 229,265232,030 233,473 236,294 238,686 241,103242,971243,184 245,392
152,337 153,895155,263 155,821 157,358 158,977 160,605161,937162,379 163,899
82,933 83,49683,992 84,311 84,671 85,027 85,92086,18586,350 87,030
132,035 132,035132,035 132,035 132,035 132,035 132,035132,035132,035 132,035
630,840
708,270
710,699
712,591
715,005
717,416
720,217
722,492
724,189
726,812
95,073 96,475 97,833 98,898 100,315 101,728 103,173 104,500105,473 106,876
60,654 61,36462,158 62,790 63,586 64,386 65,24366,03766,658 67,494
43,400 43,71743,994 44,189 44,391 44,588 45,08845,24245,344 45,728
431,714 506,714506,714 506,714 506,714 506,714 506,714506,714506,714 506,714
603,232 611,727620,711 630,860 641,089 645,311 649,575653,882658,232 662,626
253,987 259,277265,206 271,905 278,656 281,443 284,257287,100289,971 292,870
130,842 133,567136,622 140,072 143,550 144,986 146,435147,900149,379 150,873
113,787 114,267114,267 114,267 114,267 114,267 114,267114,267114,267 114,267
104,616 104,616104,616 104,616 104,616 104,616 104,616104,616104,616 104,616
6,785,971
6,694,671
6,745,949
6,795,646
6,845,689
6,881,602
6,923,400
6,963,079 7,000,576
7,044,566
Total Regional Supply (Table A1)
6,534,911
Supply Surplus/Shortfall
(251,060) (159,760)(211,038) (260,735) (310,778) (346,691) (388,489)(428,168)(465,665)(509,655)
6,690,211
2016 / 2017
6,690,211
2017 / 2018
6,690,211
2018 / 2019
6,690,211
2019 / 2020
6,690,211
2020 / 2021
6,690,211
2021 / 2022
6,690,211
N W G A
2022 / 2023
6,690,211
2 0 1 5
G A S
2023 / 2024
6,690,211
O U T L O O K
25
Appendix A6: Expected I-5 Corridor Peak Day Demand/Supply Balance (Dth/day)
Demand (Region/Sector)
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022 / 2023
2023 / 2024
BC Lower Main & Van. Island (I-5 Corridor) 1,390,449 1,165,183 1,163,051 1,161,142 1,160,114 1,157,930 1,156,094
1,154,668 1,153,731
1,153,370
Residential
550,829547,598544,320540,936537,483534,148 530,813 527,477524,142 520,807
Commercial (Firm Sales & Transport)
420,583417,526415,929414,362414,258412,677 411,096 409,514407,933 406,351
Industrial (Firm Sales & Transport)
158,387162,146164,889167,932170,460173,193 176,273 179,764183,743 188,299
Power Generation
260,65037,91337,91337,91337,91337,913 37,913 37,91337,913 37,913
W. Washington (I-5 Corridor)
2,158,4102,191,3462,220,3072,249,0792,273,3222,290,396 2,310,606 2,330,1412,349,988 2,370,676
Residential
803,929826,304845,074864,302880,358890,547 902,509 915,031927,696 939,965
Commercial (Firm Sales & Transport)
367,885377,149386,586395,800403,523409,977 416,429 423,276430,503 437,750
Industrial (Firm Sales & Transport)
270,657271,954272,708273,039273,502273,933 275,729 275,895275,851 277,022
Power Generation
715,939715,939715,939715,939715,939715,939 715,939 715,939715,939 715,939
W. Oregon (I-5 Corridor)
1,006,5691,014,5011,020,7461,027,1871,034,7711,042,683 1,051,994 1,061,4041,071,013 1,081,140
Residential
569,197574,972580,576586,252592,458598,973 605,687 612,540619,337 626,631
Commercial (Firm Sales & Transport)
292,171292,177292,104292,535293,523294,884 296,559 298,542300,717 303,251
Industrial (Firm Sales & Transport)
75,20277,35278,06678,40078,79078,826 79,748 80,32280,958 81,257
Power Generation
70,00070,00070,00070,00070,00070,000 70,000 70,00070,000 70,000
Total I-5 Design (Peak) Day Demand
4,555,428 4,371,030 4,404,104 4,437,408 4,468,207 4,491,009 4,518,693
4,546,213 4,574,732
4,605,186
I-5 Supply
Pipeline Interconnects
2,304,0602,304,0602,304,0602,304,0602,304,0602,304,060 2,304,060 2,304,0602,304,060 2,304,060
Max north flow on NWP @ Gorge
551,000
551,000
551,000
551,000
551,000
551,000
551,000
551,000
551,000
551,000
T-South to Huntingdon
1,753,0601,753,0601,753,0601,753,0601,753,0601,753,060 1,753,060 1,753,0601,753,060 1,753,060
Underground Storage
1,716,0001,716,0001,716,0001,716,0001,716,0001,716,000 1,716,000 1,716,0001,716,000 1,716,000
Jackson Prairie (NWP from JP)
1,196,0001,196,0001,196,0001,196,0001,196,0001,196,000 1,196,000 1,196,0001,196,000 1,196,000
Mist Storage (NWN)
520,000520,000520,000520,000520,000520,000 520,000 520,000520,000 520,000
Peak LNG
503,758503,758503,758503,758503,758503,758 503,758 503,758503,758 503,758
Newport LNG (NWN)
60,00060,00060,00060,00060,00060,000 60,000 60,00060,000 60,000
Portland LNG (NWN)
120,000120,000120,000120,000120,000120,000 120,000 120,000120,000 120,000
Gig Harbor Satellite LNG (PSE)
5,2505,2505,2505,2505,2505,250 5,250 5,2505,250 5,250
Swarr Stn Propane (PSE)
10,00010,00010,00010,00010,00010,000 10,000 10,00010,000 10,000
Tilbury LNG (TGI)
155,466 155,466 155,466 155,466 155,466 155,466 155,466 155,466 155,466 155,466
Mount Hayes LNG 153,042 153,042 153,042 153,042 153,042 153,042 153,042 153,042 153,042 153,042
Total I-5 Supply
4,523,8184,523,8184,523,8184,523,8184,523,8184,523,818 4,523,818 4,523,8184,523,818 4,523,818
Supply Surplus/Shortfall
(31,610)152,788119,714 86,410 55,611 32,809 5,125 (22,395)(50,914) (81,368)
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Appendix A7: Accelerated Annual Demand
Demand (Region/Sector)
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022 / 2023
2023 / 2024
Expected Annual Demand (Table A2) 837,974,198 851,017,293 871,166,337
878,324,654
888,372,476 895,558,698 904,663,403
913,525,341 918,337,779 934,571,573
Coal Replacement
0
0
0
0
013,800,00023,000,000 36,800,00036,800,00036,800,000
General Industrial
0
0 12,775,000 85,775,000 85,775,000158,775,000158,775,000 158,775,000158,775,000158,775,000
Large Load Industrial
0
0
0
58,400,000
175,200,000
292,000,000
350,400,000
350,400,000
350,400,000
350,400,000
Accelerated Annual Demand
837,974,198 851,017,293 883,941,337 1,022,499,654 1,149,347,476 1,360,133,698 1,436,838,403 1,459,500,341 1,464,312,779 1,480,546,573
Appendix A8: Accelerated Peak Day Demand
Demand (Region/Sector)
2014 / 2015
2015 / 2016
2016 / 2017
2017 / 2018
2018 / 2019
2019 / 2020
2020 / 2021
2021 / 2022
2022 / 2023
2023 / 2024
Expected Peak Demand (Table A5)
6,785,971
6,694,671
6,745,949
6,795,646
6,845,689
6,881,602
6,923,400
6,963,079
7,000,576
7,044,566
Coal Replacement
0
0
0
0
037,80863,014100,822
100,822
100,822
General Industrial
0
0 35,000 235,000 235,000435,000435,000 435,000435,000435,000
Large Load Industrial
0
0
0
160,000
480,000
800,000
960,000
960,000
960,000
960,000
Accelerated Peak Day Demand
6,785,971
6,694,671
6,780,949
7,190,646
7,560,689
8,154,410
8,381,414
8,458,901
8,496,398
8,540,388
Total Regional Supply (Table A1)
6,534,911
6,690,211
6,690,211
6,690,211
6,690,211
6,690,211
6,690,211
6,690,211
6,690,211
6,690,211
Supply Surplus/Shortfall
(251,060) (4,460) (90,738) (500,435) (870,478) (1,464,199) (1,691,203) (1,768,690) (1,806,187) (1,850,177)
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Appendix B: Integrated Resource Plan Assumptions
Company
Avista
Region/Area
8 Demand Areas which can be broken
into 4 service territories and 2 divisions.
Customer Classes
Residential, commercial, industrial, core
interruptible.
Forecast Length Econometrics
Separate forecast for customers and use per customer. Key drivers: Population
20 years
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 production; and real
natural gas prices. Normal weather is based on a 20-year moving average.
Cascade
Currently 9 load areas (zones) principally
based on major upstream pipeline
constraints. CNGC will be forecasting at
our 66 citygates level beginning with the
2015 IRP.
6 regions (includes an “all other”
category); West, Central, and East
for market share rates; by county for
economic forecasting.
Residential, commercial, Industrial, core
interruptible.
20 years
Customer Counts: Population growth, Farm earnings, Construction earnings,
Manufacturing earnings, weather, natural gas prices.
Residential, commercial, and industrial
(potato processors, other food processors,
chemical and fertilizer, manufacturers,
institutions, and all other).
5 years
Customer growth forecast: New residential construction customers, # of residential
customers who convert to natgas fr/ an alt fuel, and number of small commercial
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 residential anticipated % of conversion customers relative to new
construction customers in those locales = # of expected res. conversion customers.
(+ residential new construction #s = total expected additional residential customers
across the periods, by county).
Customer growth forecasts based on third party housing starts forecast.
Customer growth by region and 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.).
Intermountain
One company with 4 service areas.
FortisBC
NW Natural 12 Regions based on topology of the
gas distribution system
PG&E
10 climate zones, do not follow county
borders, are based on similar geographic
and climatic characteristics and
approved by the CPUC.
Residential, commercial, and industrial.
20 years
20 years
Residential existing, new construction single
family, new construction multi-family and
residential conversion; commercial existing, new
construction and conversions; industrial firm sales;
firm transport.
Residential, commercial, industrial & electric 18 years
generation.
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
Forecast by state and customer class. Key drivers: New technologies/end use,
discussion in the demographics, employment, income, weather, DSM, and energy efficiency
main text only
mandates.
concentrates on
the first 10 years,
2011-2020
PacifiCorp By state (California, Oregon, Washington,
Idaho, Utah, and Wyoming) which is
allocated to 34 “bubbles,” including 10
load “bubbles.”
Residential, commercial, industrial, irrigation,
and Public Street and Highway Lighting.
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)
Puget
Sound
Energy
Single contiguous service area.
20 years
Questar
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.
Firm: residential, commercial, industrial, large
volume commercial, large volume industrial.
Interruptible: commercial and 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.
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Precarious economic conditions, demographic trends such as in-migration and
life expectancy, a business environment that favors future growth; Oregon’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.
Regional and national economic growth, demographic changes, weather, prices,
seasonality, usage, and behavior factors for customer and use per customer
forecasts; Stochastic approach for developing Low and High growth scenarios.
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.
28
Company
Avista
Cascade
Intermountain
FortisBC
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,
Schneider Electric, Wood Mackenzie
PacifiCorp
Portland
General
Puget
Sound
Energy
Questar
Price Forecast
Wood Mackenzie – first five years modified to
include Nymex forward prices.
Low, Medium, High, High Growth with Low Price, A blend of public and private sources (EIA 20 yr,
Low Growth with High Price, Moderate CO2 costs, Bentek 5yr, Wood Mackenzie, NYMEX strips,
Texas Comptroller)– based on Cascade’s general
High CO2 costs.
portfolio mix.
Church 2012 Forecast; NOAA
NYMEX & 2 five year forecasts from “multi-national
Low, base and high (combined with other
energy companies, similar enough to use 1 for
variables create 18 total demand scenarios),
model.
Conference Board of Canada, user surveys Reference Case, High and Low (driven by
Internally developed forecast based on GLJ forecast
(industrial customers)
customer additions forecasts) scenarios by region for AECO, forward price basis between Sumas and
Station 2, and forecast basis between AECO and
Kingsgate.
NW Natural OEA & NWPCC; Woods & Poole
PG&E
Scenarios Developed
An Average Case, Expected Case, High Growth
with Low Price, Low Growth with High Price, and
an Alternate Weather Standard.
High Customer Growth; Low Customer Growth;
Carbon Prices; Reliability; Gas Prices; Low/Medium/
High Emerging Markets
Average and high, as well as abnormal peak day
(APD)
IHS CERA (augmented for scenario development
purposes)
Peak Day Determination
Coldest day on record, historic peak, and
average weather data for each demand
region.
59 HDD, based on coldest day in past 30
years.
81 HDD weighted by customers in each
district; several distinct laterals and areas of
interest are assigned unique DDs.
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; result could vary
from the coldest day experienced in the
last 20 years.
System-weighted 53 HDD; coldest day last
30 years.
Average of NYMEX futures, long-term CEC forecasts, PG&E uses a 1 in 90 year cold temp by
location but only provides a system
EIA, and private sources
weighted mean temp (27°F) in their text.
PacifiCorp’s 2014 DSM potential study,
A 1-in-20 weather occurrence. This is
2015 IRP studied 34 core cases, including 3 different Third-party proprietary data & forecasting services
conducted by Applied Energy Group
included in their alternative load forecast
regional haze approaches, incorporated EPA 111(d) establish a range of global gas price scenarios, then,
to determine the resource type and timing
IPM® simulates the North American system (allows
alternatives as well as additional CO2 taxes. Study
natgas prices to respond to demand changes fr/ envir. impacts.
had 15 sensitivities focusing on low, high, and
1-in-20 load growth, low and high DG penetration, compliance). Results used in the AURORAxmp® model,
as well as two types of storage additions, solar cost simulates the Western Interconnection. Low, medium,
and high nat gas prices from Henry Hub are obtained.
sensitivities, two transmission sensitivities and
Those 3 forecasts were used to develop the unique
stricter emission requirements.
price projections for the cases analyzed in the 2015 IRP.
Oregon Office of Economic Analysis
Expected normal weather w/ a 50%
PGE relies on PIRA Energy Group for natural gas
A reference (likely) case, high load, and low load,
March 2009 economic forecast and Global assuming normal weather. 15 portfolios represent
prices (and coal)’s long-term fundamental forecast probability–PGE’s reserve cover ~ 80% of
Insight’s February 2009 U.S.
a 1-in-5 weather event. PGE and the PNW
starting in 2014 and going through 2025 for the
either a single resource or a mix of resources. Then
assess total expected portfolio costs and test using long-term Henry Hub price and basis differentials to have historically been winter peaking, but
Sumas, AECO, and other WECC (for electric) supply summer demand has been growing and
21 futures. Stochastic analysis includes changes
is projected to increase at a faster rate
hubs. PIRA’s forecasts are available through 2025,
in load, hydro, natgas price, wind availability &
than winter demand, transforming PGE’s
after which PGE escalates at inflation.
unplanned thermal generating resource outages
system from winter-peaking to summerpeaking by the end of the decade.
Moody’s Analytics US Macroeconomic
Base, Low, High, High + High CO2, Base + Very High For 2014-2016, used 3 month average forward marks. 52 HDD Daily Average
Forecast, PSE’s regional and economic
Beyond 2016, Wood Mackenzie. Also generated Very
CO2, Very Low Gas Price, Very High Gas Price.
forecasts, Washington Office of Financial
Low, Low, High & Very High gas prices using WM
Management.
forecasts
University of Utah (Bureau of Economic & Mean, median, a normal case and a base case. For
A 1-in-20 year weather occurrence:
Determined the means and standard deviations
Business Research) and the Utah Governor’s the IRP, Questar does Stochastic modeling which
associated with historical data from each of 9 area price design-day firm customer gas demand
Office of Planning and Budget. When cur- more than encompasses low, medium, and high.
projection is based on a theoretical day
indices. Used avg of 2 price forecasts fr/ PIRA Energy
rent local data were not available, nationally From the Stochastic output they calculate mean,
w/ mean temp -5 ° F @ the Salt Lake
Group (19 months) and IHS CERA (252 months) as
recognized sources such as the U.S. Energy median, and base cases. A normal case was
basis for projecting the stochastic modeling inputs. Airport and corresponding design-day
Information Administration, the U.S. Census included in the last IRP to help with the quarterly
temperatures are seen coincidentally
Bureau and IHS Global Insight were used. variance report and pass-through cases.
across the service territory.
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Appendix C: Regional Resource Deficiencies and Preferred Resource Options
FortisBC
IRP File Date
August 29, 2013
May 29, 2015
May 29, 2015
March 25, 2014
Jurisdiction
Washington/Oregon/Idaho
Washington
Oregon
British Columbia
Intermountain
NW Natural
February, 2013
August 29, 2014
Puget Sound Energy
May 30, 2013
Company
Avista
Cascade
Preferred Supply Resources Selected
N/A
Incremental NWP Capacity, Incremental storage
Incremental GTN Capacity, Incremental storage
South Loop from Ellis Creek and Additional Compression, North
Loop from Savona and Kelowna Lateral, LNG Storage Facility
Idaho
Oregon/Washington
Year of Peak Day Deficiency
No deficiency in planning horizon
2030
2023
2018, though potentially delayed based on long
term asset replacements yet to be determined for
the Interior Transmission System
No deficiency in planning horizon
Currently Deficient
Washington
2017
SWARR Upgrade, PSE LNG, Mist/NWP Expansion
Developing a sufficient and efficient regional system can be achieved by looking
at the total needs of the region, the resources available, and future resource options.
While current analysis shows resources sufficient to meet demand, these methodologies
may not fully capture potential demand, both in magnitude and timing, or the future
availability of existing resources.
Due to risks inherent in the forecasting process, changing needs and uses for natural
gas, limited existing resources, and the lengthy permitting and construction time frames
required to bring new resources on line, it is imperative to comprehensively assess
regional resource adequacy and future resource needs.
NWGA member utilities strive to understand the planning issues, competitive
environment and resource requirements for others in the region because of the region’s
reliance on a common infrastructure to serve both electricity and natural gas demand.
Preparing a plan in isolation of these external considerations could mask potential
resource utilization constraints, ignore operational synergies, discount project economies
of scale, and result in over-reliance on existing resources.
For example, LDCs may plan to rely upon existing unsubscribed or under-utilized
pipeline capacity to meet a future deficit. That same capacity may be relied upon by
electric utilities that need gas for power generation sooner than the LDC. In this case, the
LDCs’ preferred resource would not be available. Therefore, evaluating who needs what,
when and where can highlight potential problems and hone in on regional solutions.
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N/A
Mist Recall, North Mist Expansion, Pipeline Capacity*
*Specific pipeline resource depends on future scenarios
This table summarizes the identified deficiencies and preferred supply resource
portfolios of the member utilities from their most recently filed IRPs. It is apparent from
the data in the table that near-term deficiencies can be handled with existing resources.
Longer-term deficiencies are likely to be met with some combination of currently
unsubscribed capacity, future capacity expansions and additional on-system storage
including satellite LNG. There are several planning cycles in which to evaluate resource
options for deficits far out into the future.
What has not been fully incorporated, however, are the resources regional electricity
generators plan to access to meet growing and increasingly variable generation demand.
The Outlook has captured future gas-fired generation loads to the extent they are
planned, known and available. However, it is difficult to project how and when those
resources will be required. The NWGA will continue working with the PNUCC to plan
accordingly.
30
Appendix D: Proposed Regional Natural Gas Infrastructure Project Descriptions
Reductions in projected demand, a slow economic recovery and the new reality of a
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
on page 17 in the Capacity Section 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 loop to be constructed in 10 different segments in or near
NWP’s existing right-of-way along the I-5 corridor between Sumas 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 and could go in service fall of 2018.
Northwest Market Access Expansion (NWP N-MAX)/Trail West – NWP
is working with the current Trail West pipeline project sponsors – NW Natural and
TransCanada GTN – to develop Trail West in conjunction with an expansion of the
existing NWP system. The Trail West project would consist of a 106-mile, 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. Trail
West’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 T-South Expansions – Spectra Energy continues to evaluate expansion of
its T-South system to provide incremental delivery options for growing Western Canada
gas supply to markets in the Pacific Northwest. All expansions on T-South would require
pipeline looping and compression and can be brought into service between 2018-2020.
T-South expansion options include the following from Station 2:
• to Sumas delivering gas to the BC Lower Mainland and Northwest Markets;
• to Kingsvale delivering up to 450 MMcf/day gas to Fortis Energy’s Southern Crossing
system;
• to Summit Lake delivering gas to PNG’s pipeline system.
FortisBC Kingsvale–Oliver Reinforcement Project (KORP) – Expanding Fortis
Energy’s existing bi-directional Southern Crossing system (connecting Spectra’s T-South
system at Kingsvale, BC, to TransCanada’s system at Yahk, BC) would facilitate access
to an additional 300-400 MMcf/d of AECO priced gas supply for westbound delivery
to markets in the Lower Mainland of BC and the I-5 corridor where several new large
industrial projects are proposed. The expansion of the Southern Crossing system will
require a 100-mile pipeline-looping project on the Kingsvale to Oliver, BC, segment, as
well as an expansion of Spectra’s T-South system from Kingsvale to Huntingdon to meet
the incremental flow.
Pacific Connector Gas Pipeline Project (PCGP) – The Pacific Connector Gas
Pipeline Project (PCGP) is a 232-mile 36-inch diameter pipeline extending from Malin to
Coos Bay, OR. Williams and Veresen, Inc. are proposing PCGP to serve the 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.
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1914 Willamette Falls Dr. #260
West Linn, OR 97068
503-344-6637
www.nwga.org
@nwgas