2017 ANNUAL REPORT
GROWTH
SUSTAINABILITY
INNOVATION
NW NATURAL 2017 ANNUAL REPORT
With an unwavering commitment to our customers and a clear-eyed focus
on the future, 2017 was a pivotal year for NW Natural.
We welcomed new customers at the fastest rate in a decade; we made
progress on an important expansion project; we continued to invest in our
distribution system— one of the most modern in the nation; we announced
plans to expand into the water utility sector; and once again, our customers
rewarded us with high satisfaction ratings.
For nearly 160 years, leadership has been a hallmark of NW Natural’s
success—in our industry, in our region and in the communities we serve.
That, coupled with innovation, has made us resilient in a changing world.
But leadership and progress require balancing interests, and, at times,
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of our Gill Ranch storage facility in California. Ultimately, we determined that
Gill Ranch is no longer central to our broader utility strategy, which is focused
on providing stable, regulated earnings growth for shareholders.
Going forward, we will continue pursuing all strategic options to maximize its
value, as we remain focused on operating the facility safely and serving our
current customers.
Financially in 2017, we reported a loss of $1.94 per share compared to
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after-tax $142 million impairment of Gill Ranch, partially offset by a noncash
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Excluding these items on a non-GAAP basis, we delivered strong earnings
and performed very well. Adjusted net income was $2.24 per share for 2017,1
up 5 cents compared to $2.19 per share for 2016.2
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ship team and employees to position us for growth and sustainable success.
4
CORPORATE
PROFILE
NW NNATURAL (NYSE: NWN)
is a 159-year-old natural
gas distribution company
headqquartered in
Portlaand, Oregon.
NW NNATURAL serves nearly
740,0000 utility customers
in Oreegon and Southwest
Washington and provides
natural gas storage to customers
on thee West Coast. In keeping
with iits steady growth strategy,
the coompany has increased
divideends paid to shareholders
for 622 consecutive years.
DAVID ANDERSON at Portland’s Columbia Boulevard Wastewater
Treatment Plant. In 2017 the city announced it will build a renewable
natural gas (RNG) processing facility and vehicle fueling station at
the site in partnership with NW Natural.
2017 HIGHLIGHTS
• Added over 12,700 new customers for an annual growth rate of 1.8
• Completed major components of the North Mist gas storage
percent, bringing our customer base to nearly 740,000—and marking
2017 as the highest growth rate in a decade.
expansion—a multiyear $132 million project—one of the largest
projects in NW Natural history.
• Reduced residential customer rates for the third year in a row. Oregon
customers received a cumulative rate decrease of 15 percent over the
past three years on top of annual bill credits, and Washington customer
rates dropped a total of 18 percent.
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among large utilities in the West in the J.D. Power Gas Utility Residential
Customer Satisfaction Study. This is the 10th time in 11 years NW Natural
has scored second or higher in the nation. We also earned the highest
customer satisfaction score among utilities in the West in the J.D. Power
Gas Utility Business Customer Satisfaction Study.
• Invested $214 million of capital expenditures for utility customer growth,
system reliability and improvements.
• Announced our expansion into the regulated water utility sector with
planned acquisitions in Oregon and Idaho, which will add about 6,500
water customers. While these transactions are not material to our
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(cid:274)(cid:3) (cid:41)(cid:76)(cid:79)(cid:72)(cid:71) (cid:87)(cid:75)(cid:72) (cid:403)(cid:85)(cid:86)(cid:87) (cid:50)(cid:85)(cid:72)(cid:74)(cid:82)(cid:81) (cid:74)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79) (cid:85)(cid:68)(cid:87)(cid:72) (cid:70)(cid:68)(cid:86)(cid:72) (cid:76)(cid:81) (cid:86)(cid:76)(cid:91) (cid:92)(cid:72)(cid:68)(cid:85)(cid:86)(cid:17)
• Increased dividends paid for the 62nd consecutive year, one of the
longest dividend increase records of any company on the NYSE.
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recognized in 2017. See Financial Overview on page 8 for reconciliation.
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of 2016. See Financial Overview on page 8 for reconciliation.
3
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hood offers hands-on, scenario-based training and replicates
real-world conditions.
We upgraded facilities across our service
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centers so crews are positioned to respond
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customer base effectively.
We also continued our focus on cybersecurity
to ensure NW Natural’s online systems are
protected with the technology we need to
safeguard our infrastructure. In 2017, we
advanced our cybersecurity efforts by imple-
menting additional data encryption, investing in
industrial control systems infrastructure, and
increasing employee awareness and training.
Customer Satisfaction
LEADS TO GROWTH
Every day, our employees work diligently to
deliver safe, reliable energy and best-in-class
service. It’s why we’ve earned the trust of
customers and the communities we serve.
Once again, we’re proud that NW Natural
earned the highest customer satisfaction
score among large utilities in the West in
the 2017 J.D. Power Gas Utility Residential
Customer Satisfaction Study. This marks
the 10th time in 11 years that NW Natural
has posted among the top two scores for
residential customer satisfaction in the nation.
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in the 2017 J.D. Power Gas Utility Business
Customer Satisfaction Study.
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(cid:75)(cid:82)(cid:90) (cid:86)(cid:68)(cid:87)(cid:76)(cid:86)(cid:403)(cid:72)(cid:71) (cid:82)(cid:88)(cid:85) (cid:70)(cid:88)(cid:86)(cid:87)(cid:82)(cid:80)(cid:72)(cid:85)(cid:86) (cid:73)(cid:72)(cid:72)(cid:79)(cid:17) (cid:55)(cid:75)(cid:72) (cid:70)(cid:82)(cid:86)(cid:87)
of natural gas continued to drop nationally,
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row, we reduced the rates our customers pay.
This winter, Oregon residential customers saw
their bills drop by 6.4 percent, and Washington
residential customers enjoyed savings of
3.1 percent. In fact, our customers are paying
20 percent less for natural gas today than
they did 15 years ago.
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competitive position. For the typical home we
serve, heating with a natural gas furnace
provides up to a 70 percent price advantage
over heating with an electric or oil furnace.
SAFETY IN ALL THINGS
System Safety, Employee Training & Preparedness
NW Natural is focused on operating a safe, reliable system and
delivering outstanding service for our customers and communities.
In 2017, we worked on upgrades to boost our distribution system
reliability and support our fastest-growing community in Clark
County, Washington. This project, estimated at $25 million, is
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(cid:58)(cid:72) (cid:68)(cid:79)(cid:86)(cid:82) (cid:403)(cid:81)(cid:76)(cid:86)(cid:75)(cid:72)(cid:71) (cid:85)(cid:72)(cid:73)(cid:88)(cid:85)(cid:69)(cid:76)(cid:86)(cid:75)(cid:76)(cid:81)(cid:74) (cid:87)(cid:90)(cid:82) (cid:79)(cid:76)(cid:84)(cid:88)(cid:72)(cid:403)(cid:72)(cid:71) (cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79) (cid:74)(cid:68)(cid:86) (cid:11)(cid:47)(cid:49)(cid:42)(cid:12)
storage facilities, which are critical for delivering natural gas on the
coldest winter days. In 2017, we completed a multiyear $25 million
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(cid:51)(cid:82)(cid:85)(cid:87)(cid:79)(cid:68)(cid:81)(cid:71) (cid:47)(cid:49)(cid:42) (cid:73)(cid:68)(cid:70)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:15) (cid:69)(cid:88)(cid:76)(cid:79)(cid:87) (cid:76)(cid:81) (cid:20)(cid:28)(cid:25)(cid:28)(cid:15) (cid:90)(cid:72) (cid:70)(cid:82)(cid:80)(cid:83)(cid:79)(cid:72)(cid:87)(cid:72)(cid:71) (cid:76)(cid:80)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)(cid:86)
totaling just under $10 million.
(cid:40)(cid:84)(cid:88)(cid:76)(cid:83)(cid:83)(cid:76)(cid:81)(cid:74) (cid:82)(cid:88)(cid:85) (cid:72)(cid:80)(cid:83)(cid:79)(cid:82)(cid:92)(cid:72)(cid:72)(cid:86) (cid:87)(cid:82) (cid:85)(cid:72)(cid:86)(cid:83)(cid:82)(cid:81)(cid:71) (cid:87)(cid:82) (cid:72)(cid:80)(cid:72)(cid:85)(cid:74)(cid:72)(cid:81)(cid:70)(cid:76)(cid:72)(cid:86) (cid:74)(cid:82)(cid:72)(cid:86) (cid:75)(cid:68)(cid:81)(cid:71) (cid:76)(cid:81)
(cid:75)(cid:68)(cid:81)(cid:71) (cid:90)(cid:76)(cid:87)(cid:75) (cid:78)(cid:72)(cid:72)(cid:83)(cid:76)(cid:81)(cid:74) (cid:82)(cid:88)(cid:85) (cid:86)(cid:92)(cid:86)(cid:87)(cid:72)(cid:80) (cid:86)(cid:68)(cid:73)(cid:72)(cid:17) (cid:49)(cid:58) (cid:49)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79) (cid:403)(cid:72)(cid:79)(cid:71) (cid:72)(cid:80)(cid:83)(cid:79)(cid:82)(cid:92)(cid:72)(cid:72)(cid:86)
regularly participate in extensive training at our state-of-the-art
training center in Sherwood, Oregon.
(cid:58)(cid:72) (cid:82)(cid:73)(cid:73)(cid:72)(cid:85) (cid:75)(cid:68)(cid:81)(cid:71)(cid:86)(cid:16)(cid:82)(cid:81)(cid:15) (cid:86)(cid:70)(cid:72)(cid:81)(cid:68)(cid:85)(cid:76)(cid:82)(cid:16)(cid:69)(cid:68)(cid:86)(cid:72)(cid:71) (cid:87)(cid:85)(cid:68)(cid:76)(cid:81)(cid:76)(cid:81)(cid:74) (cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:86) (cid:87)(cid:82) (cid:403)(cid:85)(cid:86)(cid:87)
responders—teaching them about natural gas safety and how
to work together effectively during a gas emergency. In 2017,
(cid:90)(cid:72) (cid:75)(cid:82)(cid:86)(cid:87)(cid:72)(cid:71) (cid:82)(cid:89)(cid:72)(cid:85) (cid:27)(cid:19) (cid:87)(cid:85)(cid:68)(cid:76)(cid:81)(cid:76)(cid:81)(cid:74)(cid:86) (cid:73)(cid:82)(cid:85) (cid:80)(cid:82)(cid:85)(cid:72) (cid:87)(cid:75)(cid:68)(cid:81) (cid:20)(cid:15)(cid:21)(cid:19)(cid:19) (cid:79)(cid:82)(cid:70)(cid:68)(cid:79) (cid:403)(cid:85)(cid:72)(cid:403)(cid:74)(cid:75)(cid:87)(cid:72)(cid:85)(cid:86)(cid:15)
and we plan to increase that number in 2018.
The cost of natural gas is about 20% lower than it was 15 years ago.
+102%
+41%
+27%
+16%
-20%
Source: Bureau of Labor Statistics
4
ENGAGING CONSTRUCTIVELY
with Regulators
(cid:15)
(cid:44)(cid:81) (cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85)
(cid:50)(cid:85)(cid:72)(cid:74)(cid:82)(cid:81) (cid:73)(cid:82)(cid:85) (cid:87)(cid:75)(cid:72) (cid:403)(cid:85)(cid:86)(cid:87) (cid:87)(cid:76)(cid:80)(cid:72) (cid:76)(cid:81) (cid:86)(cid:76)(cid:91) (cid:92)(cid:72)(cid:68)(cid:85)(cid:86)(cid:17)
(cid:21)(cid:19)(cid:20)(cid:26)(cid:15) (cid:68)(cid:73)(cid:87)(cid:72)(cid:85) (cid:70)(cid:68)(cid:85)(cid:72)(cid:73)(cid:88)(cid:79)
(cid:70)(cid:82)(cid:81)(cid:86)(cid:76)(cid:71)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15) (cid:90)(cid:72) (cid:403)(cid:79)(cid:72)(cid:71) (cid:68) (cid:85)(cid:68)(cid:87)(cid:72) (cid:70)(cid:68)(cid:86)(cid:72) (cid:76)(cid:81)
(cid:15)
NW Natural’s Customer Contact Center receives
approximately one million calls each year.
These advantages—coupled with the strong
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convert and attract new customers to natural
gas. At year-end, we reported more than 12,700
(cid:81)(cid:72)(cid:90) (cid:70)(cid:88)(cid:86)(cid:87)(cid:82)(cid:80)(cid:72)(cid:85)(cid:86)(cid:15) (cid:72)(cid:84)(cid:88)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74) (cid:87)(cid:82) (cid:68) (cid:20)(cid:17)(cid:27) (cid:83)(cid:72)(cid:85)(cid:70)(cid:72)(cid:81)(cid:87) (cid:68)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79)
growth rate—our best performance in a decade.
We also made inroads into the multifamily
sector—which has been historically underserved
by natural gas — through a comprehensive
effort to make it easier for developers to build
(cid:90)(cid:76)(cid:87)(cid:75) (cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79) (cid:74)(cid:68)(cid:86) (cid:90)(cid:76)(cid:87)(cid:75) (cid:72)(cid:84)(cid:88)(cid:76)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87) (cid:76)(cid:81)(cid:70)(cid:72)(cid:81)(cid:87)(cid:76)(cid:89)(cid:72)(cid:86)(cid:15)
streamlined gas infrastructure designs and
promotional support.
In July 2017, the Public Utility Commission of
(cid:50)(cid:85)(cid:72)(cid:74)(cid:82)(cid:81) (cid:11)(cid:50)(cid:51)(cid:56)(cid:38)(cid:12) (cid:68)(cid:83)(cid:83)(cid:85)(cid:82)(cid:89)(cid:72)(cid:71) (cid:68) (cid:81)(cid:72)(cid:90) (cid:80)(cid:88)(cid:79)(cid:87)(cid:76)(cid:73)(cid:68)(cid:80)(cid:76)(cid:79)(cid:92)
(cid:87)(cid:68)(cid:85)(cid:76)(cid:73)(cid:73) (cid:86)(cid:83)(cid:72)(cid:70)(cid:76)(cid:403)(cid:70)(cid:68)(cid:79)(cid:79)(cid:92) (cid:71)(cid:72)(cid:86)(cid:76)(cid:74)(cid:81)(cid:72)(cid:71) (cid:73)(cid:82)(cid:85) (cid:80)(cid:76)(cid:91)(cid:72)(cid:71)(cid:16)(cid:88)(cid:86)(cid:72)
developments—buildings with commercial
and residential customers —to install natural
gas more easily.
We will continue to pursue growth in all
sectors in 2018.
UTILITY CUSTOMERS AT YEAR-END
740,000
720,000
700,000
680,000
660,000
640,000
620,000
600,000
580,000
2013
2014
2015
2016
2017
RESIDENTIAL
COMMERCIAL
INDUSTRIAL
We added 12,728 new customers in 2017, and now serve
nearly 740,000 customers.
(cid:58)(cid:72) (cid:75)(cid:68)(cid:89)(cid:72) (cid:85)(cid:72)(cid:84)(cid:88)(cid:72)(cid:86)(cid:87)(cid:72)(cid:71) (cid:68) (cid:23) (cid:83)(cid:72)(cid:85)(cid:70)(cid:72)(cid:81)(cid:87) (cid:76)(cid:81)(cid:70)(cid:85)(cid:72)(cid:68)(cid:86)(cid:72) (cid:87)(cid:82) (cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92) (cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:86)(cid:15)
after an adjustment for the conservation tariff deferral, to cover our
costs to operate and maintain the natural gas distribution system
and continue to provide customers with safe, reliable service.
(cid:55)(cid:75)(cid:72) (cid:50)(cid:51)(cid:56)(cid:38) (cid:68)(cid:81)(cid:71) (cid:82)(cid:87)(cid:75)(cid:72)(cid:85) (cid:86)(cid:87)(cid:68)(cid:78)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86) (cid:90)(cid:76)(cid:79)(cid:79) (cid:85)(cid:72)(cid:89)(cid:76)(cid:72)(cid:90) (cid:82)(cid:88)(cid:85) (cid:403)(cid:79)(cid:76)(cid:81)(cid:74) (cid:87)(cid:75)(cid:85)(cid:82)(cid:88)(cid:74)(cid:75)
a process that could take up to 10 months, with new rates likely
effective Nov. 1, 2018.
Companies across the country adopted the Federal Tax Cuts and
Jobs Act at the end of December 2017. For NW Natural, this meant
an earnings increase of $21 million related to nonregulated
(cid:68)(cid:70)(cid:87)(cid:76)(cid:89)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86)(cid:17) (cid:58)(cid:72) (cid:75)(cid:68)(cid:89)(cid:72) (cid:68) (cid:85)(cid:72)(cid:84)(cid:88)(cid:72)(cid:86)(cid:87) (cid:87)(cid:82) (cid:58)(cid:68)(cid:86)(cid:75)(cid:76)(cid:81)(cid:74)(cid:87)(cid:82)(cid:81) (cid:68)(cid:81)(cid:71) (cid:50)(cid:85)(cid:72)(cid:74)(cid:82)(cid:81) (cid:70)(cid:82)(cid:80)(cid:80)(cid:76)(cid:86)-
(cid:86)(cid:76)(cid:82)(cid:81)(cid:86) (cid:87)(cid:82) (cid:68)(cid:79)(cid:79)(cid:82)(cid:90) (cid:88)(cid:86) (cid:87)(cid:82) (cid:85)(cid:72)(cid:87)(cid:88)(cid:85)(cid:81) (cid:87)(cid:75)(cid:72) (cid:85)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71) (cid:88)(cid:87)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:267)(cid:86) (cid:82)(cid:89)(cid:72)(cid:85)(cid:68)(cid:79)(cid:79) (cid:81)(cid:72)(cid:87) (cid:69)(cid:72)(cid:81)(cid:72)(cid:403)(cid:87)(cid:86)
from tax reform to customers. We amended our Oregon rate case
to address the impact of the lower tax rate and will work closely
with the regulators in the coming months to determine the best
path forward.
Construction of the 16-inch portion of the pipeline for the North Mist Expansion
project is complete.
BUILDING THE FUTURE
Abundant and clean-burning natural gas is a critical resource that
is facilitating a smooth transition to a low-carbon energy future
across the country.
An exciting example is a project to expand our natural gas
storage infrastructure in Mist, Oregon, which has been integral to
our ability to support reliable energy service in our region since
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with limited competition from other facilities and is highly valued
due to its premium Northwest location. The Mist facility is once
(cid:68)(cid:74)(cid:68)(cid:76)(cid:81) (cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:81)(cid:74) (cid:76)(cid:87)(cid:86) (cid:89)(cid:68)(cid:79)(cid:88)(cid:72) (cid:90)(cid:76)(cid:87)(cid:75) (cid:82)(cid:88)(cid:85) (cid:72)(cid:91)(cid:83)(cid:68)(cid:81)(cid:86)(cid:76)(cid:82)(cid:81) (cid:87)(cid:82) (cid:86)(cid:88)(cid:83)(cid:83)(cid:79)(cid:92) (cid:88)(cid:81)(cid:76)(cid:84)(cid:88)(cid:72)(cid:15)
(cid:81)(cid:82)(cid:16)(cid:81)(cid:82)(cid:87)(cid:76)(cid:70)(cid:72) (cid:86)(cid:72)(cid:85)(cid:89)(cid:76)(cid:70)(cid:72) (cid:87)(cid:75)(cid:68)(cid:87) (cid:51)(cid:82)(cid:85)(cid:87)(cid:79)(cid:68)(cid:81)(cid:71) (cid:42)(cid:72)(cid:81)(cid:72)(cid:85)(cid:68)(cid:79) (cid:40)(cid:79)(cid:72)(cid:70)(cid:87)(cid:85)(cid:76)(cid:70) (cid:11)(cid:51)(cid:42)(cid:40)(cid:12) (cid:70)(cid:68)(cid:81) (cid:71)(cid:85)(cid:68)(cid:90)
on rapidly to integrate more wind power into the grid, ensuring
reliable natural gas backup response.
5
NW Natural Environmental Managgement and Sustainabilityy
Director Bill Edmonds with President and CEO David Anderson.
)
(in millions)
illi
(i
$300
$250
$200
$150
$100
$50
$0
2013
2014
2015
2016
2017
CUSTOMER
GROWTH
SAFETY AND
RELIABILITY
OTHER
NORTH
MIST
Total investment in capital expenditures during 2017 was
more than $250 million on an accrual basis.
There are three major components to this
$132 million project: a new underground
reservoir providing up to 2.5 billion cubic feet
of available storage, an additional compressor
station, and a new dedicated 13-mile pipeline
to connect NW Natural’s facility to PGE’s
Port Westward industrial park.
The investment will be included in rates under
an established tariff when it is placed into
service with an initial 30-year contract with
options to extend totaling up to an additional
50 years upon mutual agreement.
LOW CARBON PATHWAY
Just as we’re able to support renewable energy with the North
Mist project, we know there are other ways NW Natural can help
the region move to a low-carbon future.
Today, natural gas is the cleanest option to reliably meet our
region’s biggest energy needs. In Oregon, NW Natural delivers
more energy over a year than any other utility, yet the use of
natural gas—in our customers’ homes, businesses and industry
—accounts for about 8 percent of Oregon’s total greenhouse
gas emissions.
OREGON GREENHOUSE GAS EMISSIONS
Source: Oregon DEQ
In-Boundary GHG
Inventory 2015 data.
6
(cid:58)(cid:75)(cid:76)(cid:79)(cid:72) (cid:90)(cid:72) (cid:87)(cid:75)(cid:76)(cid:81)(cid:78) (cid:87)(cid:75)(cid:68)(cid:87)(cid:267)(cid:86) (cid:68) (cid:83)(cid:85)(cid:72)(cid:87)(cid:87)(cid:92) (cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:87) (cid:86)(cid:87)(cid:68)(cid:85)(cid:87)(cid:76)(cid:81)(cid:74) (cid:83)(cid:82)(cid:76)(cid:81)(cid:87)(cid:15) (cid:90)(cid:72) (cid:69)(cid:72)(cid:79)(cid:76)(cid:72)(cid:89)(cid:72)
we can do even better. It’s why we set a voluntary goal of 30 percent
carbon emissions savings by 2035, with a starting point of 2015
emission levels.
(cid:44)(cid:81) (cid:21)(cid:19)(cid:20)(cid:26)(cid:15) (cid:90)(cid:72) (cid:76)(cid:71)(cid:72)(cid:81)(cid:87)(cid:76)(cid:403)(cid:72)(cid:71) (cid:81)(cid:72)(cid:90) (cid:82)(cid:83)(cid:83)(cid:82)(cid:85)(cid:87)(cid:88)(cid:81)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86) (cid:87)(cid:82) (cid:83)(cid:85)(cid:82)(cid:68)(cid:70)(cid:87)(cid:76)(cid:89)(cid:72)(cid:79)(cid:92) (cid:85)(cid:72)(cid:71)(cid:88)(cid:70)(cid:72)
emissions using our existing infrastructure — one of the most
modern, tightest pipeline systems in the nation.
(cid:58)(cid:72) (cid:68)(cid:85)(cid:72) (cid:72)(cid:86)(cid:83)(cid:72)(cid:70)(cid:76)(cid:68)(cid:79)(cid:79)(cid:92) (cid:72)(cid:91)(cid:70)(cid:76)(cid:87)(cid:72)(cid:71) (cid:68)(cid:69)(cid:82)(cid:88)(cid:87) (cid:68) (cid:85)(cid:72)(cid:81)(cid:72)(cid:90)(cid:68)(cid:69)(cid:79)(cid:72) (cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79) (cid:74)(cid:68)(cid:86) (cid:11)(cid:53)(cid:49)(cid:42)(cid:12)
project with the City of Portland. Announced in April 2017, the city
is building an RNG production facility at its largest wastewater
treatment plant to recover and clean biogas to meet our pipeline
(cid:84)(cid:88)(cid:68)(cid:79)(cid:76)(cid:87)(cid:92) (cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:68)(cid:85)(cid:71)(cid:86)(cid:17) (cid:36) (cid:83)(cid:82)(cid:85)(cid:87)(cid:76)(cid:82)(cid:81) (cid:82)(cid:73) (cid:87)(cid:75)(cid:72) (cid:85)(cid:72)(cid:86)(cid:88)(cid:79)(cid:87)(cid:76)(cid:81)(cid:74) (cid:53)(cid:49)(cid:42) (cid:90)(cid:76)(cid:79)(cid:79) (cid:69)(cid:72) (cid:88)(cid:86)(cid:72)(cid:71) (cid:87)(cid:82)
fuel heavy-duty vehicles locally, and the rest will be injected into
NW Natural’s existing pipeline system.
NW Natural built and installed the vehicle fueling station in 2017
and will maintain it for the city. We expect the entire project to be
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Portland on its single largest climate action effort to date.
Collaboration is a pivotal part of reaching our carbon savings goal
—and we’re working on many fronts up and down the natural gas
value chain. Because our customers are
key partners, we launched a multiyear
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inviting them to join us in working toward
a low-carbon future. We are working in
g
the communities we serve and have
shared the company’s low-carbon vision
with more than 100 policymakers and
stakeholders.
In 2017, NW Natural also hosted the
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10 years of our Smart Energy carbon
offset program, and joined the Natural
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upstream production practices.
But these steps are just part of the story.
We are also focused on new technologies
Idaho Falls is one of two locations where NW Natural plans to acquire
a water utility.
to reduce our emissions footprint. Power-to-Gas is a cutting-edge
process that captures surplus wind and solar energy and converts
it to RNG or hydrogen through electrolysis. This renewable energy
could be stored and then blended into our pipeline system to one
day serve homes, businesses and vehicles.
FUTURE OPPORTUNITIES
(cid:47)(cid:82)(cid:82)(cid:78)(cid:76)(cid:81)(cid:74) (cid:87)(cid:82) (cid:87)(cid:75)(cid:72) (cid:73)(cid:88)(cid:87)(cid:88)(cid:85)(cid:72)(cid:15) (cid:90)(cid:72) (cid:85)(cid:72)(cid:80)(cid:68)(cid:76)(cid:81) (cid:73)(cid:82)(cid:70)(cid:88)(cid:86)(cid:72)(cid:71) (cid:82)(cid:81) (cid:74)(cid:85)(cid:82)(cid:90)(cid:76)(cid:81)(cid:74) (cid:82)(cid:88)(cid:85) (cid:81)(cid:68)(cid:87)(cid:88)(cid:85)(cid:68)(cid:79)
gas utility business and examining opportunities that are a good
(cid:403)(cid:87) (cid:73)(cid:82)(cid:85) (cid:82)(cid:88)(cid:85) (cid:72)(cid:91)(cid:83)(cid:72)(cid:85)(cid:87)(cid:76)(cid:86)(cid:72)(cid:15) (cid:70)(cid:85)(cid:72)(cid:68)(cid:87)(cid:72) (cid:89)(cid:68)(cid:79)(cid:88)(cid:72) (cid:68)(cid:81)(cid:71) (cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:72) (cid:68) (cid:86)(cid:76)(cid:80)(cid:76)(cid:79)(cid:68)(cid:85) (cid:85)(cid:76)(cid:86)(cid:78)
(cid:83)(cid:85)(cid:82)(cid:403)(cid:79)(cid:72) (cid:87)(cid:82) (cid:82)(cid:88)(cid:85) (cid:76)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:86)(cid:17)
(cid:58)(cid:72) (cid:87)(cid:82)(cid:82)(cid:78) (cid:68)(cid:81) (cid:72)(cid:91)(cid:70)(cid:76)(cid:87)(cid:76)(cid:81)(cid:74) (cid:403)(cid:85)(cid:86)(cid:87) (cid:86)(cid:87)(cid:72)(cid:83) (cid:76)(cid:81) (cid:39)(cid:72)(cid:70)(cid:72)(cid:80)(cid:69)(cid:72)(cid:85) (cid:21)(cid:19)(cid:20)(cid:26) (cid:90)(cid:75)(cid:72)(cid:81) (cid:90)(cid:72)
announced our expansion into the regulated water sector with
(cid:83)(cid:79)(cid:68)(cid:81)(cid:81)(cid:72)(cid:71) (cid:68)(cid:70)(cid:84)(cid:88)(cid:76)(cid:86)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86) (cid:82)(cid:73) (cid:87)(cid:90)(cid:82) (cid:90)(cid:68)(cid:87)(cid:72)(cid:85) (cid:88)(cid:87)(cid:76)(cid:79)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86) (cid:90)(cid:76)(cid:87)(cid:75) (cid:81)(cid:72)(cid:68)(cid:85)(cid:79)(cid:92) (cid:25)(cid:15)(cid:24)(cid:19)(cid:19)
customers in Oregon and Idaho. We view regulated water utility
(cid:82)(cid:83)(cid:83)(cid:82)(cid:85)(cid:87)(cid:88)(cid:81)(cid:76)(cid:87)(cid:76)(cid:72)(cid:86) (cid:68)(cid:86) (cid:68)(cid:81) (cid:72)(cid:91)(cid:70)(cid:72)(cid:79)(cid:79)(cid:72)(cid:81)(cid:87) (cid:86)(cid:87)(cid:85)(cid:68)(cid:87)(cid:72)(cid:74)(cid:76)(cid:70) (cid:403)(cid:87) (cid:73)(cid:82)(cid:85) (cid:82)(cid:88)(cid:85) (cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:17)
NW Natural’s core competencies — customer service, safety,
environmental stewardship, reliability and managing critical
distribution infrastructure—are directly applicable to the water
utility business.
With substantial investment opportunities in the water sector
over the long term, we will be working to build out this broader
strategy in the coming years.
To better respond to growth opportunities, like our regulated
water strategy, we are seeking a corporate holding company
structure. This structure is widely used, particularly among
utilities, and would allow us to further serve the best interests
(cid:82)(cid:73) (cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85)(cid:86) (cid:69)(cid:92) (cid:83)(cid:85)(cid:82)(cid:89)(cid:76)(cid:71)(cid:76)(cid:81)(cid:74) (cid:68) (cid:80)(cid:82)(cid:85)(cid:72) (cid:68)(cid:74)(cid:76)(cid:79)(cid:72) (cid:68)(cid:81)(cid:71) (cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:87) (cid:83)(cid:79)(cid:68)(cid:87)(cid:73)(cid:82)(cid:85)(cid:80)
to pursue new growth opportunities. Our business operations
and strategy would not change — we remain focused on stable,
utility-type earnings growth for investors and safe, reliable service
for our customers.
GROWTH
TODAY AND TOMORROW
(cid:47)(cid:72)(cid:68)(cid:71)(cid:76)(cid:81)(cid:74) (cid:68) (cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92) (cid:82)(cid:73) (cid:81)(cid:72)(cid:68)(cid:85)(cid:79)(cid:92) (cid:20)(cid:15)(cid:21)(cid:19)(cid:19) (cid:72)(cid:80)(cid:83)(cid:79)(cid:82)(cid:92)(cid:72)(cid:72)(cid:86)
who live our core values and share a common
vision for the future inspires me every day.
Their dedication, innovation and energy fuel
our success and keep us nimble.
We made tough decisions and achieved great
things in 2017. I look forward to building on what
we’ve created—a strong foundation positioned
(cid:73)(cid:82)(cid:85) (cid:86)(cid:88)(cid:86)(cid:87)(cid:68)(cid:76)(cid:81)(cid:68)(cid:69)(cid:79)(cid:72) (cid:74)(cid:85)(cid:82)(cid:90)(cid:87)(cid:75)(cid:17) (cid:44)(cid:267)(cid:80) (cid:70)(cid:82)(cid:81)(cid:403)(cid:71)(cid:72)(cid:81)(cid:87) (cid:90)(cid:72) (cid:90)(cid:76)(cid:79)(cid:79)
make the most of the opportunities ahead.
NW Natural has consistently led the industry
on many fronts: environmental stewardship,
(cid:86)(cid:92)(cid:86)(cid:87)(cid:72)(cid:80) (cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:70)(cid:92) (cid:68)(cid:81)(cid:71) (cid:80)(cid:82)(cid:71)(cid:72)(cid:85)(cid:81)(cid:76)(cid:93)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)
customer service, and commitment to our
communities. We take this legacy seriously
and will continue to focus on delivering the
highest level of performance.
(cid:55)(cid:75)(cid:68)(cid:81)(cid:78) (cid:92)(cid:82)(cid:88) (cid:73)(cid:82)(cid:85) (cid:92)(cid:82)(cid:88)(cid:85) (cid:70)(cid:82)(cid:81)(cid:403)(cid:71)(cid:72)(cid:81)(cid:70)(cid:72) (cid:68)(cid:81)(cid:71) (cid:87)(cid:85)(cid:88)(cid:86)(cid:87) (cid:76)(cid:81)
NW Natural. We look forward to working
on your behalf in the year ahead.
David H. Anderson
(cid:51)(cid:85)(cid:72)(cid:86)(cid:76)(cid:71)(cid:72)(cid:81)(cid:87) (cid:68)(cid:81)(cid:71) (cid:38)(cid:75)(cid:76)(cid:72)(cid:73) (cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72) (cid:50)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85)
7
FINANCIAL OVERVIEW
2017
2016
EARNINGS
(cid:41)(cid:76)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79) (cid:73)(cid:68)(cid:70)(cid:87)(cid:86) (cid:11)(cid:7)(cid:19)(cid:19)(cid:19)(cid:12)(cid:29)
(cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:86)
(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74) (cid:85)(cid:72)(cid:89)(cid:72)(cid:81)(cid:88)(cid:72)(cid:86)
(cid:50)(cid:83)(cid:72)(cid:85)(cid:68)(cid:87)(cid:76)(cid:81)(cid:74)
Utility margin1
(cid:49)(cid:72)(cid:87) (cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72) (cid:11)(cid:79)(cid:82)(cid:86)(cid:86)(cid:12)
Adjusted net income
(cid:3)
COMMON STOCK
(cid:54)(cid:75)(cid:68)(cid:85)(cid:72)(cid:75)(cid:82)(cid:79)(cid:71)(cid:72)(cid:85) (cid:71)(cid:68)(cid:87)(cid:68) (cid:11)(cid:19)(cid:19)(cid:19)(cid:12)(cid:29)(cid:3)
(cid:36)(cid:89)(cid:72)(cid:85)(cid:68)(cid:74)(cid:72) (cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86) (cid:82)(cid:88)(cid:87)(cid:86)(cid:87)(cid:68)(cid:81)(cid:71)(cid:76)(cid:81)(cid:74)(cid:264)(cid:71)(cid:76)(cid:79)(cid:88)(cid:87)(cid:72)(cid:71)(cid:3)
Year-end shares outstanding
(cid:51)(cid:72)(cid:85) (cid:86)(cid:75)(cid:68)(cid:85)(cid:72) (cid:71)(cid:68)(cid:87)(cid:68) (cid:11)(cid:7)(cid:12)(cid:29)(cid:3)
(cid:39)(cid:76)(cid:79)(cid:88)(cid:87)(cid:72)(cid:71) (cid:72)(cid:68)(cid:85)(cid:81)(cid:76)(cid:81)(cid:74)(cid:86) (cid:11)(cid:79)(cid:82)(cid:86)(cid:86)(cid:12)
Adjusted diluted earnings
Dividends paid
Book value at year-end
(cid:48)(cid:68)(cid:85)(cid:78)(cid:72)(cid:87) (cid:89)(cid:68)(cid:79)(cid:88)(cid:72) (cid:68)(cid:87) (cid:92)(cid:72)(cid:68)(cid:85)(cid:16)(cid:72)(cid:81)(cid:71)(cid:3)
UTILITY OPERATING HIGHLIGHTS
(cid:42)(cid:68)(cid:86) (cid:71)(cid:72)(cid:79)(cid:76)(cid:89)(cid:72)(cid:85)(cid:76)(cid:72)(cid:86) (cid:11)(cid:19)(cid:19)(cid:19) (cid:87)(cid:75)(cid:72)(cid:85)(cid:80)(cid:86)(cid:12)
Degree days
Customers at year-end
Employees at year-end
DIVIDENDS PAID ON COMMON STOCK (cid:11)(cid:83)(cid:72)(cid:85) (cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:12)
Payment date
February
May
August
November
Total dividends paid
(cid:26)(cid:25)(cid:21)(cid:15)(cid:20)(cid:26)(cid:22)
(cid:26)(cid:25)(cid:21)(cid:15)(cid:20)(cid:26)(cid:22)(cid:3)
(cid:22)(cid:28)(cid:21)(cid:15)(cid:25)(cid:22)(cid:21)(cid:3)
(cid:11)(cid:24)(cid:24)(cid:15)(cid:25)(cid:21)(cid:22)(cid:12)(cid:3)
64,4702
(cid:25)(cid:26)(cid:24)(cid:15)(cid:28)(cid:25)(cid:26)
(cid:25)(cid:26)(cid:24)(cid:15)(cid:28)(cid:25)(cid:26)
(cid:22)(cid:26)(cid:25)(cid:15)(cid:24)(cid:28)(cid:20)(cid:3)
(cid:24)(cid:27)(cid:15)(cid:27)(cid:28)(cid:24)
(cid:25)(cid:19)(cid:15)(cid:27)(cid:28)(cid:20)3
(cid:21)(cid:27)(cid:15)(cid:25)(cid:25)(cid:28)(cid:3)
28,736
(cid:3)
(cid:21)(cid:26)(cid:15)(cid:26)(cid:26)(cid:28)
28,630
(cid:11)(cid:20)(cid:17)(cid:28)(cid:23)(cid:12)
2.242
1.88
(cid:21)(cid:24)(cid:17)(cid:27)(cid:24)(cid:3)
(cid:24)(cid:28)(cid:17)(cid:25)(cid:24)
(cid:21)(cid:17)(cid:20)(cid:21)
(cid:21)(cid:17)(cid:20)(cid:28)3
1.87
(cid:21)(cid:28)(cid:17)(cid:26)(cid:20)
(cid:24)(cid:28)(cid:17)(cid:27)(cid:19)
(cid:20)(cid:15)(cid:21)(cid:23)(cid:19)(cid:15)(cid:21)(cid:28)(cid:22)(cid:3)
4,553
737,874
1,146
(cid:20)(cid:15)(cid:19)(cid:27)(cid:23)(cid:15)(cid:28)(cid:28)(cid:25)
3,551
725,146
1,108
$0.4700
0.4700
0.4700
0.4725
$1.8825
$0.4675
0.4675
0.4675
0.4700
$1.8725
UTILITY MARGIN
(in $000)
DIVIDENDS PAID PER SHARE
($)
$400,000
$390,000
$380,000
$370,000
$360,000
$350,000
$340,000
$330,000
2013
2014
2015
2016
2017
Utility margin increased $16.0 million to
(cid:7)(cid:22)(cid:28)(cid:21)(cid:17)(cid:25) (cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81) (cid:76)(cid:81) (cid:21)(cid:19)(cid:20)(cid:26)(cid:17)
$1.90
$1.85
$1.80
$1.75
$1.70
$1.65
$1.60
$1.55
2013
2014
2015
2016
2017
Annual dividends paid per share in 2017
increased for the 62nd consecutive year.
The current indicated annual dividend is
(cid:7)(cid:20)(cid:17)(cid:27)(cid:28) (cid:83)(cid:72)(cid:85) (cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:17)
SERVICE TERRITORY
AND STORAGE FACILITIES
WASHINGTON
AS
SASASTORIA
MIST
STORAGE
VANCOUVERR
GASCO LNG
PORTLANDD
D
THE DALLES
TRAINING
CENTER
LINCOLN CITY
NEWPORT LNG
SALEM
ALBANY
EUGENE
OREGON
COOS BAYAY
AYAY
KEY
NW NATURAL SERVICE TERRITORY
TRAINING CENTER
REGIONAL RESOURCE CENTER
LNG PLANT
UNDERGROUND STORAGE
HEADQUARTERS
SASAN FRANCISCO
1 References to the utility margin refer to utility segment.
CALIFORNIA
GILL RANCH
STORAGE
FRESNO
2 (cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71) (cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71) (cid:81)(cid:72)(cid:87) (cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72) (cid:68)(cid:81)(cid:71) (cid:40)(cid:51)(cid:54) (cid:73)(cid:82)(cid:85) (cid:21)(cid:19)(cid:20)(cid:26) (cid:68)(cid:85)(cid:72) (cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51) (cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79) (cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86) (cid:87)(cid:75)(cid:68)(cid:87) (cid:72)(cid:91)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72) (cid:87)(cid:75)(cid:72) (cid:42)(cid:76)(cid:79)(cid:79) (cid:53)(cid:68)(cid:81)(cid:70)(cid:75)
(cid:76)(cid:80)(cid:83)(cid:68)(cid:76)(cid:85)(cid:80)(cid:72)(cid:81)(cid:87) (cid:82)(cid:73) (cid:7)(cid:20)(cid:28)(cid:21)(cid:17)(cid:24) (cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81) (cid:83)(cid:85)(cid:72)(cid:87)(cid:68)(cid:91) (cid:82)(cid:85) (cid:7)(cid:20)(cid:23)(cid:20)(cid:17)(cid:24) (cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81) (cid:68)(cid:73)(cid:87)(cid:72)(cid:85)(cid:16)(cid:87)(cid:68)(cid:91) (cid:68)(cid:81)(cid:71) (cid:87)(cid:75)(cid:72) (cid:7)(cid:21)(cid:20)(cid:17)(cid:23) (cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81) (cid:69)(cid:72)(cid:81)(cid:72)(cid:403)(cid:87) (cid:85)(cid:72)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71) (cid:87)(cid:82) (cid:76)(cid:80)(cid:83)(cid:79)(cid:72)(cid:80)(cid:72)(cid:81)(cid:87)-
ing tax reform. The after-tax impairment is calculated using the combined federal and state statutory tax rate of
26.5%. EPS is calculated using 28.7 million diluted shares.
3(cid:3)(cid:36)(cid:71)(cid:77)(cid:88)(cid:86)(cid:87)(cid:72)(cid:71) (cid:70)(cid:82)(cid:81)(cid:86)(cid:82)(cid:79)(cid:76)(cid:71)(cid:68)(cid:87)(cid:72)(cid:71) (cid:81)(cid:72)(cid:87) (cid:76)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72) (cid:68)(cid:81)(cid:71) (cid:40)(cid:51)(cid:54) (cid:73)(cid:82)(cid:85) (cid:21)(cid:19)(cid:20)(cid:25) (cid:68)(cid:85)(cid:72) (cid:81)(cid:82)(cid:81)(cid:16)(cid:42)(cid:36)(cid:36)(cid:51) (cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79) (cid:80)(cid:72)(cid:68)(cid:86)(cid:88)(cid:85)(cid:72)(cid:86) (cid:87)(cid:75)(cid:68)(cid:87) (cid:72)(cid:91)(cid:70)(cid:79)(cid:88)(cid:71)(cid:72) (cid:87)(cid:75)(cid:72) (cid:85)(cid:72)(cid:74)(cid:88)(cid:79)(cid:68)(cid:87)(cid:82)(cid:85)(cid:92)
environmental disallowance of $3.3 million pretax or $2.0 million after-tax. The after-tax disallowance is calculated
(cid:88)(cid:86)(cid:76)(cid:81)(cid:74) (cid:87)(cid:75)(cid:72) (cid:70)(cid:82)(cid:80)(cid:69)(cid:76)(cid:81)(cid:72)(cid:71) (cid:73)(cid:72)(cid:71)(cid:72)(cid:85)(cid:68)(cid:79) (cid:68)(cid:81)(cid:71) (cid:86)(cid:87)(cid:68)(cid:87)(cid:72) (cid:86)(cid:87)(cid:68)(cid:87)(cid:88)(cid:87)(cid:82)(cid:85)(cid:92) (cid:87)(cid:68)(cid:91) (cid:85)(cid:68)(cid:87)(cid:72) (cid:82)(cid:73) (cid:22)(cid:28)(cid:17)(cid:24)(cid:8)(cid:17) (cid:40)(cid:51)(cid:54) (cid:76)(cid:86) (cid:70)(cid:68)(cid:79)(cid:70)(cid:88)(cid:79)(cid:68)(cid:87)(cid:72)(cid:71) (cid:88)(cid:86)(cid:76)(cid:81)(cid:74) (cid:21)(cid:26)(cid:17)(cid:27) (cid:80)(cid:76)(cid:79)(cid:79)(cid:76)(cid:82)(cid:81) (cid:71)(cid:76)(cid:79)(cid:88)(cid:87)(cid:72)(cid:71) (cid:86)(cid:75)(cid:68)(cid:85)(cid:72)(cid:86)(cid:17)
8
CORPORATE OFFICERS
BOARD OF DIRECTORS
DAVID H. ANDERSON
President and
Chief Executive Officer
FRANK BURKHARTSMEYER
Senior Vice President and
Chief Financial Officer
LEA ANNE DOOLITTLE
Senior Vice President and
Chief Administrative Officer
DAVID H. ANDERSON
President and Chief Executive
Officer, NW Natural
TIMOTHY P. BOYLE
President and Chief Executive
Officer, Columbia Sportswear
Company
JAMES DOWNING
Vice President and
Chief Information Officer
SHAWN M. FILIPPI
Vice President, Chief Compliance
Officer and Corporate Secretary
KIMBERLY HEITING
Senior Vice President
Operations and
Chief Marketing Officer
MARTHA L. “STORMY”
BYORUM
Chief Executive Officer,
Cori Investment Advisors, LLC
JOHN D. CARTER
Chairman of the Board,
Schnitzer Steel Industries, Inc.
THOMAS J. IMESON
Vice President Public Affairs
JUSTIN B. PALFREYMAN
Vice President, Strategy and
Business Development
LORI L. RUSSELL
Vice President Utility Services
MARK S. DODSON
Former Chief Executive
Officer, NW Natural
C. SCOTT GIBSON
President, Gibson Enterprises
MARDILYN SAATHOFF
Senior Vice President,
Regulation and General Counsel
BRODY J. WILSON
Vice President,
Chief Accounting Officer,
Controller and Treasurer
GRANT M. YOSHIHARA
Senior Vice President
Utility Operations
TOD R. HAMACHEK
Chairman of the Board,
NW Natural
JANE L. PEVERETT
Former President and Chief
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Transmission Corporation
OUR MISSION
We provide safe, reliable
and affordable energy
in an environmentally
responsible way to better
the lives of the public
we serve.
OUR CORE VALUES
Integrity
Safety
Service Ethic
Caring
Environmental Stewardship
KENNETH THRASHER
Chairman of the Board,
Compli Corporation
MALIA H. WASSON
Former Executive
Vice President of Commercial
Banking, U.S. Bank
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CORPORATE INFORMATION
Notice of Annual Meeting
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(cid:55)(cid:75)(cid:72) (cid:21)(cid:19)(cid:20)(cid:27) (cid:36)(cid:81)(cid:81)(cid:88)(cid:68)(cid:79) (cid:48)(cid:72)(cid:72)(cid:87)(cid:76)(cid:81)(cid:74) (cid:90)(cid:76)(cid:79)(cid:79) (cid:69)(cid:72) (cid:75)(cid:72)(cid:79)(cid:71) (cid:68)(cid:87) (cid:21) (cid:83)(cid:17)(cid:80)(cid:17)(cid:15) (cid:55)(cid:75)(cid:88)(cid:85)(cid:86)(cid:71)(cid:68)(cid:92)(cid:15) (cid:48)(cid:68)(cid:92) (cid:21)(cid:23)(cid:15) (cid:68)(cid:87) (cid:87)(cid:75)(cid:72) (cid:70)(cid:82)(cid:80)(cid:83)(cid:68)(cid:81)(cid:92)(cid:267)(cid:86) (cid:75)(cid:72)(cid:68)(cid:71)(cid:84)(cid:88)(cid:68)(cid:85)(cid:87)(cid:72)(cid:85)(cid:86)(cid:15) (cid:50)(cid:81)(cid:72) (cid:51)(cid:68)(cid:70)(cid:76)(cid:403)(cid:70) (cid:54)(cid:84)(cid:88)(cid:68)(cid:85)(cid:72)(cid:15) (cid:21)(cid:21)(cid:19) (cid:49)(cid:58) (cid:21)(cid:81)(cid:71) (cid:36)(cid:89)(cid:72)(cid:17)(cid:15)
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the annual meeting, you will need to detach and retain the admission ticket attached to your proxy card mailed or emailed to you
with the notice of the annual meeting and the proxy statement. As space is limited, you may bring only one guest to the meeting.
If you hold your stock through a broker, bank or other nominee, please bring a legal proxy or other evidence to the meeting showing
that you owned NW Natural Common Stock as of the record date, April 5, 2018, and we will provide you with an admission ticket.
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Dividend reinvestment
and direct stock purchase plan
Participants may make an initial invest-
ment in company stock and common
shareholders of record may reinvest all or
part of their dividends in additional shares
under the company’s plan. Cash purchases
may also be made. Participants in the plan
bear the cost of brokerage fees and com-
missions for shares purchased on the open
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COMPARISON OF FIVE-YEAR
CUMULATIVE TOTAL RETURN
(Based on $100 invested on 12/31/2012)
$250
$200
$150
$100
$50
$0
2012
2013
2014
2015
2016
2017
NWN
S&P UTILITIES INDEX
S&P 500 INDEX
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years ending December 31, 2017 for NW Natural was
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Index return of 12.61%, and the S&P 500 Index return
of 15.77%.
Scheduled dividend payment dates
Subject to Board approval, the following
dates are scheduled for dividend payment:
February 15, 2018
May 15, 2018
August 15, 2018
November 15, 2018
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NYSE on June 26, 2017, that as of that date,
he was not aware of any violation by the
company of NYSE’s corporate governance
listing standards, and the company had
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31.2 to its Annual Report on Form 10-K
for the year ended December 31, 2016,
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company’s public disclosure. For the year
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(cid:82)(cid:73) (cid:87)(cid:75)(cid:72) (cid:38)(cid:75)(cid:76)(cid:72)(cid:73) (cid:40)(cid:91)(cid:72)(cid:70)(cid:88)(cid:87)(cid:76)(cid:89)(cid:72) (cid:50)(cid:73)(cid:403)(cid:70)(cid:72)(cid:85) (cid:68)(cid:81)(cid:71) (cid:38)(cid:75)(cid:76)(cid:72)(cid:73)
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31.1 and 31.2 to the Form 10-K included in
this Annual Report.
Contact the NW Natural Board
Concerns may be directed to the
nonmanagement directors by writing
to NW Natural Board of Directors,
c/o Corporate Secretary.
Forward-looking statements
The statements made in this Annual
Report that are not purely historical,
including statements regarding plans,
goals, strategies, success, opportunities,
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demand or preference for gas, the future
of clean energy and the role of natural
gas in it, renewable natural gas, power to
gas, commodity costs, customer rates and
service, competitive position, revenues,
customer and business growth, capital
expenditures, Mist storage expansion
project, including but not limited to cost
and timelines, emergency preparedness,
cybersecurity, system reliability, safety,
environmental stewardship, regulatory
proceedings and actions, including, but
not limited to our rate case and the timing
and results thereof, the regional economy,
expansion into the water sector, Gill Ranch
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multifamily sector, system modernization
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reorganization as a holding company, and
effects of legislation, including the Federal
Tax Cuts and Jobs Act, are forward-looking
statements within the “safe harbor” pro-
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results could differ materially from those
anticipated in these forward-looking
statements as a result of risks and uncer-
tainties, including those described in the
attached report on Form 10-K. For a more
complete description of these risks and
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with the SEC on Forms 10-K and 10-Q.
Request for publications
The following publications may be obtained
without charge by contacting the Corporate
Secretary at NW Natural’s address: Annual
Report; Form 10-K; Form 10-Q; Corporate
Governance Standards; Director Indepen-
dence Standards; Code of Ethics; and Board
Committee Charters. These publications,
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are also available on our website at nwnat-
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Securities and Exchange Commission,
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sec.gov. You can obtain information about
access to the Public Reference Room and
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the SEC at 1-800-SEC-0330.
Produced by NW Natural’s Corporate Communications
PHOTO CREDITS ANDY BAUER - page 5, North Mist expansion pipeline; DALE HEADRICK - page 2, J.D. Power Awards;
page 4, Training Town, System Operations; page 5, Customer Contact Center; page 6, Bill Edmonds and David Anderson;
ROBBIE McCLARAN - page 3, David Anderson • PRINTING Donnelley Financial Solutions
10
Form 10-K
Annual Report
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to____________
Commission file number 1-15973
NORTHWEST NATURAL GAS COMPANY
(Exact name of registrant as specified in its charter)
Oregon
(State or other jurisdiction of
incorporation or organization)
93-0256722
(I.R.S. Employer
Identification No.)
220 N.W. Second Avenue, Portland, Oregon 97209
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (503) 226-4211
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes [ X ] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yes [ ] No [ X ]
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every
Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained
herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated
by reference in Part III of this Form 10-K or any amendment to this Form 10-K.[ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a
smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer,"
"smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer [ X ] Accelerated Filer [ ]
Non-accelerated Filer [ ] Smaller Reporting Company [ ]
Emerging Growth Company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period
for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.[ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes [ ] No [ X ]
As of June 30, 2017, the aggregate market value of the shares of Common Stock (based upon the closing price of these
shares on the New York Stock Exchange on that date) held by non-affiliates was $1,695,121,435.
At February 16, 2018, 28,751,528 shares of the registrant’s Common Stock (the only class of Common Stock) were
outstanding.
Portions of the Proxy Statement of the registrant, to be filed in connection with the 2018 Annual Meeting of Shareholders, are
incorporated by reference in Part III.
DOCUMENTS INCORPORATED BY REFERENCE
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission on Form 10-K
For the Fiscal Year Ended December 31, 2017
TABLE OF CONTENTS
PART I
Glossary of Terms
Forward-Looking Statements
Item 1.
Business
Overview
Local Gas Distribution "Utility"
Gas Storage
Other
Environmental Matters
Employees
Additions to Infrastructure
Executive Officers of the Registrant
Available Information
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Item 6.
Item 7.
Purchases of Equity Securities
Selected Financial Data
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Financial Statements and Supplementary Data
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
PART IV
Item 15. Exhibits and Financial Statement Schedules
Item 16.
Form 10-K Summary
EXHIBIT INDEX
SIGNATURES
Page
1
3
4
4
4
8
11
11
12
12
12
12
14
23
24
24
24
25
26
27
52
54
91
91
91
92
93
93
94
94
94
94
95
100
GLOSSARY OF TERMS AND ABBREVIATIONS
AFUDC
Allowance for Funds Used During Construction
AOCI / AOCL
Accumulated Other Comprehensive Income (Loss)
ASC
ASU
Accounting Standards Codification
Accounting Standards Update as issued by the FASB
Average Weather
The 25-year average of heating degree days based on temperatures established in our last Oregon
general rate case
Bcf
CNG
Billion cubic feet, a volumetric measure of natural gas, where one Bcf is roughly equal to 10 million
therms
Compressed Natural Gas
Core Utility Customers Residential, commercial, and industrial customers receiving firm service from the utility
Cost of Gas
CPUC
Decoupling
Demand Cost
EBITDA
EE/CA
Encana
The delivered cost of natural gas sold to customers, including the cost of gas purchased or withdrawn/
produced from storage inventory or reserves, gains and losses from gas commodity hedges, pipeline
demand costs, seasonal demand cost balancing adjustments, regulatory gas cost deferrals and
Company gas use
California Public Utilities Commission, the entity that regulates our California gas storage business at
our Gill Ranch facility with respect to rates and terms of service, among other matters
A billing rate mechanism, also referred to as our conservation tariff, which is designed to allow the
utility to encourage industrial and small commercial customers to conserve energy while not adversely
affecting its earnings due to reductions in sales volumes
A component in core utility customer rates representing the cost of securing firm pipeline capacity,
whether the capacity is used or not
Earnings before interest, taxes, depreciation and amortization, a non-GAAP financial measure
Engineering Evaluation / Cost Analysis
Encana Oil & Gas (USA) Inc.
Energy Corp
Northwest Energy Corporation, a wholly-owned subsidiary of NW Natural
EPA
EPS
FASB
FERC
Firm Service
FMBs
GAAP
Environmental Protection Agency
Earnings per share
Financial Accounting Standards Board
Federal Energy Regulatory Commission; the entity regulating interstate storage services offered by
our Mist gas storage facility as part of our gas storage segment
Natural gas service offered to customers under contracts or rate schedules that will not be disrupted
to meet the needs of other customers
First Mortgage Bonds
Accounting principles generally accepted in the United States of America
General Rate Case
A periodic filing with state or federal regulators to establish billing rates for utility customers
GHG
Gill Ranch
Gill Ranch Facility
GTN
Greenhouse gases
Gill Ranch Storage, LLC, a wholly-owned subsidiary of NWN Gas Storage
Underground natural gas storage facility near Fresno, California, with 75% owned by Gill Ranch and
25% owned by PG&E
Gas Transmission Northwest, which owns a transmission pipeline serving California and the Pacific
Northwest
Heating Degree Days
Units of measure reflecting temperature-sensitive consumption of natural gas, calculated by
subtracting the average of a day’s high and low temperatures from 65 degrees Fahrenheit
HATFA
IBEW
Highway and Transportation Funding Act of 2014
International Brotherhood of Electrical Workers Local Union No. 1245, which is also referred to as the
Union formerly representing NW Natural's bargaining unit employees at Gill Ranch
Interruptible Service
Natural gas service offered to customers (usually large commercial or industrial users) under
contracts or rate schedules that allow for interruptions when necessary to meet the needs of firm
service customers
IRP
KB
LNG
Integrated Resource Plan
Kelso-Beaver Pipeline, of which 10% is owned by KB Pipeline Company, a subsidiary of NNG
Financial
Liquefied Natural Gas, the cryogenic liquid form of natural gas. To reach a liquid form at atmospheric
pressure, natural gas must be cooled to approximately negative 260 degrees Fahrenheit
1
MAP-21
Moody's
NAV
A federal pension plan funding law called the Moving Ahead for Progress in the 21st Century Act, July
2012
Moody's Investors Service, Inc., credit rating agency
Net Asset Value
NNG Financial
NNG Financial Corporation, a wholly-owned subsidiary of NW Natural
NOL
NRD
Net Operating Loss
Natural Resource Damages
NWN Energy
NW Natural Energy, LLC, a wholly-owned subsidiary of NW Natural
NWN Gas Reserves
NWN Gas Reserves LLC, a wholly-owned subsidiary of Northwest Energy Corporation
NWN Gas Storage
NW Natural Gas Storage, LLC, a wholly-owned subsidiary of NWN Energy
ODEQ
OPEIU
OPUC
PBGC
PG&E
PGA
PGE
PHMSA
PRP
RI/FS
ROD
ROE
ROR
S&P
Oregon Department of Environmental Quality
Office and Professional Employees International Union Local No. 11, AFL-CIO, which is also referred
to as the Union representing NW Natural's bargaining unit employees
Public Utility Commission of Oregon; the entity that regulates our Oregon utility business with respect
to rates and terms of service, among other matters; the OPUC also regulates our Mist gas storage
facility's intrastate storage services
Pension Benefit Guaranty Corporation
Pacific Gas & Electric Company; 25% owner of the Gill Ranch Facility
Purchased Gas Adjustment, a regulatory mechanism which adjusts customer rates to reflect changes
in the forecasted cost of gas and differences between forecasted and actual gas costs from the prior
year
Portland General Electric; primary customer of the North Mist gas storage expansion
U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration
Potentially Responsible Parties
Remedial Investigation / Feasibility Study
Record of Decision
Return on Equity, a measure of corporate profitability, calculated as net income or loss divided by
average common stock equity. Authorized ROE refers to the equity rate approved by a regulatory
agency for use in determining utility revenue requirements
Rate of Return, a measure of return on utility rate base. Authorized ROR refers to the rate of return
approved by a regulatory agency and is generally discussed in the context of ROE and capital
structure
Standard & Poor's, a credit rating agency and division of The McGraw-Hill Companies, Inc.
Sales Service
Service provided whereby a customer purchases both natural gas commodity supply and
transportation from the utility
SEC
SRRM
TAIL
TCJA
Therm
TWH
TWP
U.S. Securities and Exchange Commission
Site Remediation and Recovery Mechanism, a billing rate mechanism for recovering prudently
incurred environmental site remediation costs allocable to Oregon through customer billings, subject
to an earnings test
TransCanada American Investments, Ltd., a 50% owner of TWH
H.R.1; An act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the
budget for fiscal year 2018, also known as the Tax Cuts and Jobs Act enacted on December 22, 2017
The basic unit of natural gas measurement, equal to one hundred thousand Btu’s
Trail West Holdings, LLC, 50% owned by NWN Energy
Trail West Pipeline, LLC, a subsidiary of TWH
TransCanada
TransCanada Pipelines Limited, owner of TAIL and GTN
Transportation Service Service provided whereby a customer purchases natural gas directly from a supplier but pays the
utility to transport the gas over its distribution system to the customer’s facility
Utility Margin
A financial measure consisting of utility operating revenues less the associated cost of gas, franchise
taxes, and environmental recoveries
WARM
WUTC
An Oregon billing rate mechanism applied to residential and commercial customers to adjust for
temperature variances from average weather
Washington Utilities and Transportation Commission, the entity that regulates our Washington utility
business with respect to rates and terms of service, among other matters
2
FORWARD-LOOKING STATEMENTS
This report contains forward-looking statements within the
meaning of the U.S. Private Securities Litigation Reform Act
of 1995, which are subject to the safe harbors created by
such Act. Forward-looking statements can be identified by
words such as anticipates, assumes, intends, plans, seeks,
believes, estimates, expects, and similar references to future
periods. Examples of forward-looking statements include,
but are not limited to, statements regarding the following:
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plans, projections and predictions;
objectives, goals or strategies;
assumptions, generalizations and estimates;
ongoing continuation of past practices or patterns;
future events or performance;
trends;
risks;
timing and cyclicality;
earnings and dividends;
capital expenditures and allocation;
capital or organizational structure, including restructuring
as a holding company;
climate change and our role in a low-carbon future;
growth;
customer rates;
labor relations and workforce succession;
commodity costs;
gas reserves;
operational performance and costs;
energy policy, infrastructure and preferences;
public policy approach and involvement;
efficacy of derivatives and hedges;
liquidity, financial positions, and planned securities
issuances;
valuations;
project and program development, expansion, or
investment;
business development efforts, including acquisitions and
integration thereof;
pipeline capacity, demand, location, and reliability;
adequacy of property rights and headquarter
development;
technology implementation and cybersecurity practices;
competition;
procurement and development of gas supplies;
estimated expenditures;
costs of compliance;
credit exposures;
rate or regulatory outcomes, recovery or refunds;
impacts or changes of laws, rules and regulations;
tax liabilities or refunds, including effects of tax reform;
levels and pricing of gas storage contracts and gas
storage markets;
outcomes, timing and effects of potential claims,
litigation, regulatory actions, and other administrative
matters;
projected obligations, expectations and treatment with
respect to retirement plans;
availability, adequacy, and shift in mix, of gas supplies;
effects of new or anticipated changes in critical accounting
policies or estimates;
approval and adequacy of regulatory deferrals;
effects and efficacy of regulatory mechanisms; and
environmental, regulatory, litigation and insurance costs
and recoveries, and timing thereof.
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Forward-looking statements are based on our current
expectations and assumptions regarding our business, the
economy, and other future conditions. Because forward-
looking statements relate to the future, they are subject to
inherent uncertainties, risks, and changes in circumstances
that are difficult to predict. Our actual results may differ
materially from those contemplated by the forward-looking
statements. We therefore caution you against relying on any
of these forward-looking statements. They are neither
statements of historical fact nor guarantees or assurances of
future performance. Important factors that could cause
actual results to differ materially from those in the forward-
looking statements are discussed at Item 1A., "Risk Factors"
of Part I and Item 7. and Item 7A., "Management’s
Discussion and Analysis of Financial Condition and Results
of Operations" and "Quantitative and Qualitative Disclosures
About Market Risk", respectively, of Part II of this report.
Any forward-looking statement made by us in this report
speaks only as of the date on which it is made. Factors or
events that could cause our actual results to differ may
emerge from time to time, and it is not possible for us to
predict all of them. We undertake no obligation to publicly
update any forward-looking statement, whether as a result of
new information, future developments or otherwise, except
as may be required by law.
3
NORTHWEST NATURAL GAS
COMPANY
PART I
ITEM 1. BUSINESS
OVERVIEW
Northwest Natural Gas Company (NW Natural or the
Company) was incorporated under the laws of Oregon in
1910. Our Company and its predecessors have supplied
gas service to the public since 1859, and we have been
doing business as NW Natural since 1997. We maintain
operations in Oregon, Washington, and California and
conduct business through NW Natural and its subsidiaries.
References in this discussion to "Notes" are to the Notes to
the Consolidated Financial Statements in Item 8 of this
report.
We have two core businesses: our regulated local gas
distribution business, referred to as the utility segment,
which serves residential, commercial, and industrial
customers in Oregon and southwest Washington; and our
gas storage businesses, referred to as the gas storage
segment, which provides storage services for utilities, gas
marketers, electric generators, and large industrial users
from storage facilities located in Oregon and California. In
addition, we have investments and other non-utility activities
we aggregate and report as other. See Note 4 for further
information.
The utility business is our largest segment, while our gas
storage business accounts for the majority of our remaining
net income or loss. The following table reflects the allocation
between segments and other as of December 31, 2017:
Non-Utility(1)
Gas
$
59.6
Total
Utility
Storage(2) Other
$ 2,961.3
In millions
Assets(3)
Net income (loss)(3)
(1) We refer to our gas storage segment and other as non-utility
as they are not included in our regulated gas distribution
business; however, certain aspects of the gas storage
segment and other may be regulated by the OPUC, WUTC,
CPUC, or FERC.
(116.2)
$ 18.8
60.5
0.1
$ 3,039.7
(55.6)
(2) Our gas storage segment includes asset management
services for both the utility and non-utility portion of our Mist
gas storage facility.
(3) Our assets and net loss include an impairment of long-lived
assets at the Gill Ranch Facility of $192.5 million and $141.5
million, respectively. See Part II, Item 7, "Application of Critical
Accounting Policies and Estimates—Impairment of Long-Lived
Assets."
LOCAL GAS DISTRIBUTION "UTILITY"
The utility is principally engaged in the regulated distribution
of natural gas in Oregon and southwest Washington to over
735,000 customers with approximately 89% of our
customers located in Oregon and 11% located in
Washington. In total, we provide natural gas service to over
100 cities in 18 counties with an estimated population of 3.7
million in our service territory.
4
We have been allocated an exclusive service territory by the
OPUC and WUTC, which includes a major portion of
western Oregon, including the Portland metropolitan area,
most of the Willamette Valley, the Coastal area from Astoria
to Coos Bay, and portions of Washington along the
Columbia River. Portland serves as one of the largest
international ports on the West Coast and is a key
distribution center due to its comprehensive transportation
system of ocean and river shipping, transcontinental
railways and highways, and an international airport. Major
businesses located in our service territory include retail,
manufacturing, and high-technology industries.
Customers
We serve residential, commercial, and industrial customers
with no individual customer or industry accounting for more
than 10% of our utility revenues. On an annual basis,
residential and commercial customers typically account for
55% to 60% of our utility’s total volumes delivered and 90%
of our utility’s margin. Industrial customers largely account
for the remaining volumes and utility margin.
The following table presents summary customer information
as of December 31, 2017:
Residential
Commercial
Industrial
Other
Total
Number of
Customers
% of
Volumes
% of Utility
Margin (1)
668,803
68,050
1,021
N/A
38%
22%
40%
N/A
63%
28%
8%
1%
737,874
100%
100%
(1) Utility margin is also affected by other items, including
miscellaneous services, gains or losses from our gas cost
incentive sharing mechanism, and other service fees.
Generally, residential and commercial customers purchase
both their natural gas commodity (gas sales) and natural
gas delivery services (transportation services) from the
utility. Industrial customers also purchase transportation
services from the utility, but may buy the gas commodity
either from the utility or directly from a third-party gas
marketer or supplier. Our gas commodity cost is primarily a
pass-through cost to customers; therefore, our profit
margins are not materially affected by an industrial
customer's decision to purchase gas from us or from third
parties. Industrial and large commercial customers may also
select between firm and interruptible service levels, with firm
services generally providing higher profit margins compared
to interruptible services.
To help manage gas supplies, our industrial tariffs are
designed to provide some certainty regarding industrial
customers' volumes by requiring an annual service election,
special charges for changes between elections, and in some
cases, a minimum or maximum volume requirement before
changing options.
Customer growth rates for natural gas utilities in the Pacific
Northwest historically have been among the highest in the
nation due to lower market saturation as natural gas
became widely available as a residential heating source
after other fuel options. We estimate natural gas was in
approximately 63% of single-family residential homes in
both 2017 and 2016 using our in-house system mapping
technology. Customer growth in our region comes from the
following main sources: single-family housing, both new
construction and conversions; multifamily housing new
construction; and commercial buildings, both new
construction and conversions. Single-family new
construction has consistently been our strongest performing
source of growth. Continued customer growth is closely tied
to the comparative price of natural gas to electricity and fuel
oil and the health of the Portland, Oregon and Vancouver,
Washington economies. We believe there is potential for
continued growth as natural gas is a preferred energy
source due to its affordable, reliable, and clean qualities.
Competitive Conditions
In our service areas, we have no direct competition from
other natural gas distributors, but we compete with other
forms of energy in each customer class. This competition
among energy suppliers is based on price, efficiency,
reliability, performance, preference, market conditions,
technology, federal, state, and local energy policy, and
environmental impacts.
For residential and small to mid-size commercial customers,
we compete primarily with providers of electricity, fuel oil,
and propane.
In the industrial and large commercial markets, we compete
with all forms of energy, including competition from
wholesale natural gas marketers. In addition, large industrial
customers could bypass our local gas distribution system by
installing their own direct pipeline connection to the
interstate pipeline system. We have designed custom
transportation service agreements with several of our
largest industrial customers to provide transportation service
rates that are competitive with the customer’s costs of
installing their own pipeline; these agreements generally
prohibit bypass. Due to the cost pressures confronting a
number of our largest customers competing in global
markets, bypass continues to be a competitive
threat. Although we do not expect a significant number of
our large customers to bypass our system in the
foreseeable future, we could experience deterioration of
utility margin if customers bypass or switch over to custom
contracts with lower profit margins.
Seasonality of Business
Our utility business is seasonal in nature due to higher gas
usage by residential and commercial customers during the
cold winter heating months. Our other categories of
customers experience seasonality in their usage but to a
lesser extent.
Regulation and Rates
The utility is subject to regulation by the OPUC, WUTC, and
FERC. These regulatory agencies authorize rates and allow
recovery mechanisms to provide our utility the opportunity to
recover prudently incurred capital and operating costs from
customers, while also earning a reasonable return on
investment for investors. In addition, the OPUC and WUTC
also regulate the system of accounts and issuance of
securities by our utility.
We file general rate cases and rate tariff requests
5
periodically with the commissions to establish approved
rates, an authorized ROE, an overall rate of return on rate
base (ROR), an authorized utility capital structure, and other
revenue/cost deferral and recovery mechanisms.
In addition, under our Mist interstate storage certificate with
FERC, the utility is required to file either a petition for rate
approval or a cost and revenue study every five years to
change or justify maintaining the existing rates for the
interstate storage service.
For further discussion on our most recent general rate
cases, see Part II, Item 7, "Results of Operations—
Regulatory Matters—Regulation and Rates".
Gas Supply
The utility strives to secure sufficient, reliable supplies of
natural gas to meet the needs of customers at the lowest
reasonable cost, while maintaining price stability and
managing gas purchase costs prudently. This is
accomplished through a comprehensive strategy focused on
the following items:
• Reliability - ensuring gas resource portfolios are
sufficient to satisfy customer requirements under
extreme cold weather conditions;
• Diverse Supply - providing diversity of supply sources;
• Diverse Contracts - maintaining a variety of contract
durations, types, and counterparties; and
• Cost Management and Recovery - employing prudent
gas cost management strategies.
Reliability
The effectiveness of our gas distribution system ultimately
rests on whether we provide reliable service to our core
utility customers. To ensure our effectiveness, we develop a
composite design year, including a seven-day design peak
event based on the most severe cold weather experienced
during the last 30 years in our service territory.
Our projected maximum design day firm utility customer
sendout is approximately 9.7 million therms. Of this total, we
are currently capable of meeting about 57% of our
maximum design day requirements with gas from storage
located within or adjacent to our service territory, while the
remaining supply requirements would come from gas
purchases under firm gas purchase contracts and recall
agreements.
To supplement near-term natural gas supplies, we can
segment transportation capacity during the heating seasons,
if needed. Pipeline segmentation is a natural gas
transportation mechanism under which a shipper can
leverage its firm pipeline transportation capacity by
separating it into multiple segments with alternate delivery
routes. The reliability of service on these alternate routes
will vary depending on the constraints of the pipeline
system. For those segments with acceptable reliability,
segmentation provides a shipper with increased flexibility
and potential cost savings compared to traditional pipeline
service. During the 2016-2017 and 2017-2018 heating
seasons, we segmented and relied on approximately 0.6
million therms per day of our firm pipeline transportation
capacity that flowed from Stanfield, Oregon to various points
south of Molalla, Oregon.
We believe our gas supplies would be sufficient to meet
existing firm customer demand if we were to experience
maximum design day weather conditions. We will continue
to evaluate and update our forecasted requirements and
incorporate changes in our IRP process.
The following table shows the sources of supply projected to
be used to satisfy the design day sendout for the 2017-2018
winter heating season:
We supplement our firm gas supply purchases with gas
withdrawals from gas storage facilities, including
underground reservoirs and LNG storage facilities. Storage
facilities are generally injected with natural gas during the
off-peak months in the spring and summer and the gas is
withdrawn for use during peak demand months in the winter.
The following table presents the storage facilities available
for our utility supply:
Therms in millions
Sources of utility supply:
Firm supply purchases
Mist underground storage (utility only)
Company-owned LNG storage
Off-system storage contract
Pipeline segmentation capacity
Recall agreements
Total
Therms
Percent
3.4
3.1
1.9
0.5
0.6
0.4
9.9
34%
32
19
5
6
4
100%
The OPUC and WUTC have IRP processes in which utilities
define different growth scenarios and corresponding
resource acquisition strategies in an effort to evaluate
supply and demand resource requirements, consider
uncertainties in the planning process and the need for
flexibility to respond to changes, and establish a plan for
providing reliable service at the least cost.
We file a full IRP biennially for Oregon and Washington with
the OPUC and the WUTC, respectively, and file updates
between filings. The OPUC acknowledges the Company's
action plan; whereas the WUTC provides notice that our IRP
has met the requirements of the Washington Administrative
Code. OPUC acknowledgment of the IRP does not
constitute ratemaking approval of any specific resource
acquisition strategy or expenditure. However, the
Commissioners generally indicate that they would give
considerable weight in prudence reviews to utility actions
consistent with acknowledged plans. The WUTC has
indicated the IRP process is one factor it will consider in a
prudence review. For additional information see Part II, Item
7, "Results of Operations—Regulatory Matters".
Diversity of Supply Sources
We purchase our gas supplies primarily from the Alberta
and British Columbia areas of Canada and multiple receipt
points in the U.S. Rocky Mountains to protect against
regional supply disruptions and to take advantage of price
differentials. For 2017, 59% of our gas supply came from
Canada, with the balance primarily coming from the U.S.
Rocky Mountain region. We believe gas supplies available
in the western United States and Canada are adequate to
serve our core utility requirements for the foreseeable
future. We continue to evaluate the long-term supply mix
based on projections of gas production and pricing in the
U.S. Rocky Mountain region as well as other regions in
North America; however, we believe the cost of natural gas
coming from western Canada and the U.S. Rocky Mountain
region will continue to track with broader U.S. market
pricing. Additionally, the extraction of shale gas has
increased the availability of gas supplies throughout North
America for the foreseeable future.
6
Gas Storage Facilities
Owned Facility
Mist, Oregon(1)
Contracted Facilities
Jackson Prairie, Washington(2)
Alberta, Canada(3)
LNG Facilities
Owned Facilities
Newport, Oregon
Portland, Oregon
Total
Maximum
Daily
Deliverability
(therms in
millions)
Designed
Storage
Capacity
(Bcf)
3.1
0.5
0.3
0.6
1.3
5.8
10.6
1.1
1.5
1.0
0.6
14.8
(1) The Mist gas storage facility has a total maximum daily
deliverability of 5.4 million therms and a total designed storage
capacity of about 16 Bcf, of which 3.1 million therms of daily
deliverability and 10.6 Bcf of storage capacity are reserved for
core utility customers.
(2) The storage facility is located near Chehalis, Washington and
is contracted from Northwest Pipeline, a subsidiary of The
Williams Companies.
(3) This resource does not add to our total peak day capacity, but
mitigates price risks as it displaces equivalent volumes of
heating season spot purchases.
The Mist facility is used for both utility and non-utility
purposes. Under our regulatory agreements with the OPUC
and WUTC, non-utility gas storage at Mist can be developed
in advance of core utility customer needs but is subject to
recall by the utility when needed to serve utility customers
as their demand increases. In 2017, the utility did not recall
additional deliverability or associated storage capacity from
the non-utility business to serve core utility customer needs.
In addition, we have the ability to recall pipeline capacity
and supply resources from certain customers if needed to
meet high demand requirements.
Diverse Contract Durations and Types
We have a diverse portfolio of short-, medium-, and long-
term firm gas supply contracts and a variety of contract
types including firm and interruptible supplies as well as
supplemental supplies from gas storage facilities.
Our portfolio of firm gas supply contracts typically includes
the following gas purchase contracts: year-round and
winter-only baseload supplies; seasonal supply with an
option to call on additional daily supplies during the winter
heating season; and daily or monthly spot purchases.
During 2017, we purchased a total of 857 million therms
under contracts with durations outlined in the chart below:
Contract Duration (primary term)
Long-term (one year or longer)
Short-term (more than one month, less than one
year)
Spot (one month or less)
Total
Percent of
Purchases
26%
23
51
100%
We renew or replace gas supply contracts as they expire.
During 2017, no individual supplier provided over 10% of
our gas supply requirements.
Gas Cost Management
The cost of gas sold to utility customers primarily consists of
the following items, which are included in annual PGA rates:
gas purchases from suppliers; charges from pipeline
companies to transport gas to our distribution system; gas
storage costs; gas reserves contracts; and gas commodity
derivative contracts.
We employ a number of strategies to mitigate the cost of
gas sold to utility customers. Our primary strategies for
managing gas commodity price risk include:
•
•
negotiating fixed prices directly with gas suppliers;
negotiating financial derivative contracts that: (1)
effectively convert floating index prices in physical gas
supply contracts to fixed prices (referred to as
commodity price swaps); or (2) effectively set a ceiling
or floor price, or both, on floating index priced physical
supply contracts (referred to as commodity price
options such as calls, puts, and collars). See Part II,
Item 7A, "Quantitative and Qualitative Disclosures
About Market Risk—Credit Risk—Credit Exposure to
Financial Derivative Counterparties";
buying physical gas supplies at a set price and injecting
the gas into storage for price stability and to minimize
pipeline capacity demand costs; and
investing in gas reserves for longer term price stability.
See Note 11 for additional information about our gas
reserves.
•
•
We also contract with an independent energy marketing
company to capture opportunities regarding our storage and
pipeline capacity when those assets are not serving the
needs of our core utility customers. Our asset management
activities provide opportunities for cost of gas savings for
our customers and incremental revenues for our
shareholders through a regulatory incentive-sharing
mechanism. These activities are included in our gas storage
segment.
Gas Cost Recovery
Mechanisms for gas cost recovery are designed to be fair
and reasonable, with an appropriate balance between the
interests of our customers and shareholders. In general,
utility rates are designed to recover the costs of, but not to
earn a return on, the gas commodity sold. We minimize risks
associated with gas cost recovery by resetting customer
rates annually through the PGA and aligning customer and
shareholder interests through the use of sharing, weather
normalization, and conservation mechanisms in Oregon.
7
See Part II, Item 7, "Results of Operations—Regulatory
Matters" and "Results of Operations—Business Segments—
Local Gas Distribution Utility Operations—Cost of Gas."
Transportation of Gas Supplies
Our local gas distribution system is reliant on a single, bi-
directional interstate transmission pipeline to bring gas
supplies into our distribution system. Although we are
dependent on a single pipeline, the pipeline’s gas flows into
the Portland metropolitan market from two directions: (1) the
north, which brings supplies from the British Columbia and
Alberta supply basins; and (2) the east, which brings
supplies from Alberta as well as the U.S. Rocky Mountain
supply basins.
We incur monthly demand charges related to our firm
pipeline transportation contracts. These contracts are multi-
year contracts with expirations ranging from 2018 to 2060.
Our largest pipeline agreements are with Northwest
Pipeline. We actively work with Northwest Pipeline and
others to renew contracts in advance of expiration to ensure
gas transportation capacity is sufficient to meet our utility
needs.
Rates for interstate pipeline transportation services are
established by FERC within the U.S. and by Canadian
authorities for services on Canadian pipelines.
As mentioned above, our service territory is dependent on a
single pipeline for its natural gas supply. Although supply
has not been disrupted in the recent past, pipeline
replacement projects and long-term projected natural gas
demand in our region underscore the need for pipeline
transportation diversity. In addition, there are potential
industrial projects in the region, which could increase the
demand for natural gas and the need for additional pipeline
capacity and pipeline diversity.
Currently, there are various interstate pipeline projects
proposed, including the Trail West pipeline in which we have
an interest, that could meet the forecasted demand for us
and the region. However, the location of any future pipeline
project will likely depend on the location of committed
industrial projects. We will continue to evaluate and closely
monitor the currently prospected projects to determine the
best option for our customers. We have an equity
investment in Trail West Holdings, LLC (TWH) that is
developing plans to build the Trail West pipeline. This
pipeline would connect TransCanada Pipelines Limited’s
(TransCanada) Gas Transmission Northwest (GTN)
interstate transmission line to our local gas distribution
system. If constructed, this pipeline would provide another
transportation path for gas purchases from Alberta and the
U.S. Rocky Mountains in addition to the one that currently
moves gas through the Northwest Pipeline system.
Gas Distribution
The primary goals of our gas distribution operations are
safety and reliability of our system, which entails building
and maintaining a safe pipeline distribution system.
Safety and the protection of our employees, our customers,
and the public at large are, and will remain, our top
priorities. We construct, operate, and maintain our pipeline
distribution system and storage operations with the goal of
ensuring natural gas is delivered and stored safely, reliably,
and efficiently.
NW Natural has one of the most modern distribution
systems in the country with no identified cast iron pipe or
bare steel main. We removed the final known bare steel
from our system in 2015 and completed our cast iron pipe
removal in 2000. Since the 1980s, we have taken a
proactive approach to replacement programs and partnered
with our Commissions on progressive regulation to further
safety and reliability efforts for our distribution system. In the
past, we had a cost recovery program in Oregon that
encompassed our programs for bare steel replacement,
transmission pipeline integrity management, and distribution
pipeline integrity management. If we want to have future
cost recovery programs, we would have to seek PUC
approval. For discussion on current regulatory programs,
see Part II, Item 7, "Results of Operations—Regulatory
Matters".
Natural gas distribution businesses will continue to be
subject to greater federal and state regulation in the future
due to pipeline incidents involving other companies.
Additional operating and safety regulations from the U.S.
Department of Transportation’s Pipeline and Hazardous
Materials Safety Administration (PHMSA) are currently
under development. In 2016, PHMSA issued proposed
regulations to update safety requirements for natural gas
transmission pipelines. The final draft of these regulations is
anticipated to be issued by the end of 2018, with final
regulations anticipated to be issued in 2019. Current
proposed regulations indicate a 15-year timeline for
implementation of compliance requirements. We will
continue to work diligently with industry associations as well
as federal and state regulators to ensure the safety of our
system and compliance with new laws and regulations. We
expect the costs to our utility associated with compliance
with federal, state, and local rules would be recoverable in
rates.
North Mist Gas Storage Expansion Project
In Oregon, there is a need to integrate intermittent
resources, such as wind and solar, into the power system
with policymakers committing to the elimination of coal-fired
electric generation and moving toward a 50% renewable
electricity standard by 2040. New, flexible natural gas-fired
electric generation facilities and associated gas storage are
necessary to support the integration of renewable
resources. In 2016, we began expanding our gas storage
facility near Mist, Oregon to provide innovative long-term,
no-notice underground gas storage service to support gas-
fired electric generating facilities that are intended to
facilitate the integration of more wind power into the region's
electric generation mix. Natural gas storage enables
generation to adjust quickly when renewable energy, such
as wind and solar, rises and falls.
This expansion project will be dedicated solely to Portland
General Electric (PGE), a local electric company, to support
their gas-fired electric power generation facilities under an
initial 30-year contract with options to extend, totaling up to
an additional 50 years upon mutual agreement of the
parties.
The expansion project includes a new reservoir providing up
to 2.5 Bcf of available storage, an additional compressor
station with design capacity of 120,000 decatherms of gas
per day, no-notice service that can be drawn on rapidly, and
a 13-mile pipeline to connect to PGE's gas plants at Port
Westward. The expansion project is considered part of the
utility segment and has an estimated cost of approximately
$132 million, with a targeted in-service date of the winter of
2018-19. See additional discussion in Part II, Item 7
"Financial Condition—Cash Flows—Investing Activities".
When the expansion is placed into service, the investment
will immediately be included in rate base under an
established tariff schedule already approved by the OPUC,
with revenues recognized consistent with the schedule.
Billing rates will be updated annually to the current
depreciable asset level and forecasted operating expenses.
GAS STORAGE
Our gas storage segment includes the following:
•
the non-utility portion of the Mist gas storage facility
near Mist, Oregon;
the Gill Ranch Facility near Fresno, California; and
asset management services provided by an
independent energy marketing company.
•
•
In general, the supply of natural gas remains relatively
stable over the course of a year, while the demand for
natural gas typically fluctuates seasonally. Storage facilities
allow customers to purchase and inject natural gas supplies
during periods of low demand and withdraw these supplies
for use or resale during periods of higher demand. These
facilities allow us to capitalize on the imbalance of supply
and demand and price volatility for natural gas.
For more information on gas storage assets and results of
operations, see Note 4 and Part II, Item 7, "Financial
Condition—Capital Structure—Liquidity and Capital
Resources".
Gas Storage Facilities
The following table provides information concerning our
non-utility gas storage facilities:
Maximum
Designed
Storage
Capacity
(Bcf)
Deliverability
(Therms in
millions/day(3)
Injection
(Therms in
millions/day)(3)
Mist Storage(1)
5.4
2.3
0.8
Gill Ranch Storage(2)
2.4
15.0
(1) Approximately 5.4 Bcf of a total designed storage capacity of
about 16 Bcf at Mist is currently available to our gas storage
segment. The remaining 10.6 Bcf is used to provide gas
storage for our local distribution business and its utility
customers.
4.9
(2) Our gas storage segment share of the Gill Ranch Facility is
currently 15 Bcf out of a total capacity of 20 Bcf.
(3) Our gas storage segment share of the designed daily
maximum injection and deliverability rates.
In addition to the designed storage capacity described
above, capacity may incrementally increase based on
variations in the heat content of the stored gas. All storage
capacity and daily deliverability currently developed for the
gas storage segment at Mist is available for recall by the
8
utility. In 2015, the utility recalled approximately 0.3 million
therms per day of deliverabiility and 0.7 Bcf of capacity for
core utility customer use. There were no recalls by the utility
in 2016 and 2017.
Mist Storage Facility
The Mist storage facility began operations in 1989. It is a 16
Bcf facility with 5.4 Bcf available for use in our gas storage
segment. The remaining 10.6 Bcf is used to provide gas
storage for our local distribution business and its utility
customers. Excluding the North Mist expansion, the facility
consists of seven depleted natural gas reservoirs, 22
injection and withdrawal wells, a compressor station,
dehydration and control equipment, gathering lines, and
other related facilities.
SERVICES. Mist provides multi-cycle gas storage services to
customers in the interstate and intrastate markets from the
facility located in Columbia County, Oregon, near the town
of Mist. The Mist field was initially converted to storage
operations for our utility customers. Since 2001, gas storage
capacity at Mist has also been made available to interstate
customers by developing new incremental capacity in
advance of core utility customer requirements to meet the
demands for interstate storage service. These interstate
storage services are offered under a limited jurisdiction
blanket certificate issued by FERC. In addition, since 2005
we have offered intrastate firm storage services in Oregon
under an OPUC-approved rate schedule as an optional
service to eligible non-residential utility customers.
CUSTOMERS. For Mist storage services, firm service
agreements with customers are entered into with terms
typically ranging from 1 to 10 years. Currently, our gas
storage revenues from Mist are derived primarily from firm
service customers who provide energy-related services,
including natural gas distribution, electric generation, and
energy marketing. Four storage customers currently account
for all of our existing contracted non-utility gas storage
capacity at Mist, with the largest customer accounting for
about half of the total capacity. These four customers have
contracts expiring at various dates through 2024.
COMPETITIVE CONDITIONS. Our Mist gas storage facility
benefits from limited competition from other Pacific
Northwest storage facilities primarily because of its
geographic location. However, competition from other
storage providers in Washington and Canada, as well as
competition for interstate pipeline capacity, does exist. In the
future, we could face increased competition from new or
expanded gas storage facilities as well as from new natural
gas pipelines, marketers, and alternative energy sources.
SEASONALITY. Mist gas storage revenues generally do not
follow seasonal patterns similar to those experienced by the
utility because most of the storage capacity is contracted
with customers for firm service, which are primarily in the
form of fixed monthly reservation charges and are not
affected by customer usage. However, there is seasonal
variation with Mist storage capacity and deliverability usage
related to customers' lower demand during the spring and
summer months, which can be optimized under regulatory
sharing agreements with the OPUC and WUTC. For
additional discussion, see "Asset Management" below.
9
REGULATION. Our Mist facility is subject to regulation by the
OPUC and WUTC. In addition, FERC has approved
maximum cost-based rates under our Mist interstate storage
certificate. We are required to file either a petition for rate
approval or a cost and revenue study with FERC at least
every five years to change or justify maintaining the existing
rates for the interstate storage service. For additional
regulation and rates discussion, see Part II, Item 7, "Results
of Operations—Regulatory Matters".
EXPANSION OPPORTUNITIES. We are currently expanding
our Mist Storage facility to provide 2.5 Bcf of storage to a
local electric company. For additional discussion, see "Local
Gas Distribution Company—North Mist Gas Storage
Expansion Project" above. While there are additional
expansion opportunities in the Mist storage field, further
development is not contemplated at this time and expansion
would be based on market demand, project execution, cost
effectiveness, available financing, receipt of future permits,
and other rights.
Gill Ranch Storage Facility
Gill Ranch Storage, LLC (Gill Ranch), our subsidiary, has a
joint project agreement with Pacific Gas and Electric
Company (PG&E) governing the development and
ownership of the Gill Ranch Facility, an underground natural
gas storage facility near Fresno, California. Currently, Gill
Ranch is the sole operator of the facility. The facility began
operations in 2010 and consists of three depleted natural
gas reservoirs, 12 injection and withdrawal wells, a
compressor station, dehydration and control equipment,
gathering lines, an electric substation, a natural gas
transmission pipeline extending 27 miles from the storage
field to an interconnection with the PG&E transmission
system, and other related facilities. Gill Ranch owns the
rights to 75%, or 15.0 Bcf, of the designed gas storage
capacity at the facility.
The California gas storage market is challenged by low
market prices and low market price volatility resulting from
the abundant supply of natural gas to, and natural gas
storage in, the region. We have substantially completed
contracting for this facility for the 2018-19 gas year at pricing
that was lower than expected and low relative to the pricing
in our original long-term contracts which ended primarily in
the 2013-14 gas storage year.
We have believed and continue to believe that we may see
storage price improvements or an increase in the demand
for natural gas in the future driven by a number of factors,
including changes in electric generation triggered by
California's renewable portfolio standards, an increase in
use of alternative fuels to meet carbon emission reduction
targets, growth of the California economy, growth of
domestic industrial manufacturing, potential exports of
liquefied natural gas from the west coast, and other
favorable storage market conditions in and around
California. These factors, if they were to occur, may
contribute to higher summer/winter natural gas price
spreads, gas price volatility, and gas storage values, but
there can be no assurance that any of the foregoing will
occur. To the contrary, we have not seen the rebound in
storage pricing as we originally anticipated.
For the last few years, we have been diligently pursuing
opportunities to increase revenues at the Gill Ranch Facility.
Simultaneously, we have been conducting a strategic review
of Gill Ranch and exploring all strategic alternatives.
In the fourth quarter of 2017, we completed our
comprehensive strategic review process, which included a
sale process for our portion of the Gill Ranch Facility, and
made a determination that Gill Ranch is no longer
considered core to our long-term growth plans.
We will continue to pursue all strategic options for this asset,
including, but not limited to, a potential sale. In the
meantime, we remain committed to operating the facility to
the highest safety standards. See Note 2 and Part II, Item 7
"Application of Critical Accounting Policies and Estimates".
SERVICES. Gill Ranch provides intrastate, multi-cycle
storage services in California at market-based rates under a
CPUC-approved tariff that includes firm storage service,
interruptible storage service, and park and loan storage
services. The Gill Ranch Facility is not currently authorized
to provide interstate gas storage services.
CUSTOMERS. Customer contracts for firm storage capacity
at Gill Ranch have contract terms for as long as 27 years in
duration; however, the majority of the contracted capacity is
shorter term in nature due to market conditions. In the near-
term, we expect Gill Ranch to contract for terms ranging
from one to five years. For the 2017-18 gas storage year,
Gill Ranch has several storage customers, with the largest
single contract accounting for approximately 13% of our
storage capacity. In the near-term, we continue to expect
shorter contract lengths reflecting current market prices and
trends.
The California market served by Gill Ranch is larger, and
has a greater diversity of prospective customers, than the
Pacific Northwest market served by Mist. Therefore, we
expect less sensitivity to any single customer or group of
customers at Gill Ranch. Current Gill Ranch customers
provide energy related services, including natural gas
production, marketing, and electric generation.
COMPETITIVE CONDITIONS. The Gill Ranch Facility currently
competes with a number of other storage providers,
including local integrated gas companies and other
independent storage providers (ISPs) in the northern
California market. There are currently four ISPs authorized
by the CPUC to provide storage services in California, with
the Gill Ranch Facility comprising approximately 12% of the
storage capacity held by ISPs. An acquisition during 2016
consolidated approximately 80% of the storage capacity
authorized by the CPUC to ISPs in California.
In late 2015, a significant natural gas leak occurred at an
unaffiliated southern California gas storage facility. In
response to the incident, both state and federal additional
regulations were developed. The California Department of
Oil, Gas and Geothermal Resources (DOGGR) developed
and proposed new regulations for gas storage wells that
focus on implementing additional well integrity requirements.
Initial draft regulations suggested that individual well risk
would be the basis for testing and implementation of
subsurface modifications for all wells. This would potentially
allow for a multiple year timeframe to comply after the
10
issuance of the regulations with any necessary capital
expenditures completed over several years after completing
the testing period. DOGGR released a new formulation of
these rules on February 12, 2018. Although these rules are
subject to a comment period and possible revision, these
rules establish a timeframe for completion of compliance
within seven years, a period much shorter than we originally
anticipated. We anticipate the final version of these
regulations will be finalized in 2018. In addition, PHMSA
proposed new federal regulations for underground natural
gas storage facilities that focus on implementing additional
pipeline safety requirements of downhole facilities, including
operations, maintenance, and emergency response
activities regarding wells, wellbore tubing, and casing.
While the regulations are still under development, and their
ultimate impact is unknown, it is likely the final PHMSA and
DOGGR regulations will result in higher costs for all storage
providers. As a result of the legislation and proposed
regulation, the nature of, and demand for, future storage
contracts, costs of operating, and market values in
California could be impacted and remain uncertain at this
time.
SEASONALITY. While the majority of our Gill Ranch
revenues are not subject to seasonality, and although we
expect much of the storage revenue at Gill Ranch to be in
the form of fixed monthly demand charges, cash flows can
fluctuate due to timing of asset management and other
revenues. In addition, a significant portion of operating costs
at Gill Ranch are subject to fluctuations based on periods
when storage customers elect to inject or withdraw.
REGULATION. Gill Ranch has a tariff on file with the CPUC
authorizing it to charge market-based rates for the storage
services offered. For additional discussion, see Part II, Item
7, "Results of Operations–Regulatory Matters".
EXPANSION OPPORTUNITIES. Subject to market demand,
project execution, available financing, receipt of future
permits, and other rights, the Gill Ranch Facility can be
expanded beyond the current combined ownership
designed storage capacity of 20 Bcf without further
expansion of the takeaway pipeline system. Taking these
considerations into account and with certain infrastructure
modifications, we currently estimate the Gill Ranch Facility
could support an additional 25 Bcf of storage capacity,
bringing the total storage capacity to approximately 45 Bcf,
of which our current rights would give us up to an additional
7.5 Bcf or ownership of a total of approximately 22.5 Bcf.
We have no plans to expand the facility.
Asset Management
We contract with an independent energy marketing
company to provide asset management services, primarily
through the use of commodity exchange agreements and
pipeline capacity release transactions. The results are
included in the gas storage segment, except for amounts
allocated to our utility pursuant to regulatory sharing
agreements involving the use of utility assets. Utility pre-tax
income from third-party asset management services is
subject to revenue sharing with core utility customers. For
additional discussion, see Part II, Item 7, "Results of
Operations—Business Segments—Gas Storage".
OTHER
We have non-utility investments and other business
activities which are aggregated and reported as other. Other
primarily consists of:
•
•
non-utility appliance retail center operations;
an equity method investment in TWH, a joint venture to
build and operate a gas transmission pipeline in
Oregon. TWH is owned 50% by NWN Energy, a wholly-
owned subsidiary of NW Natural, and 50% by
TransCanada American Investments Ltd., an indirect
wholly-owned subsidiary of TransCanada Corporation;
a minority interest in the Kelso-Beaver Pipeline held by
our wholly-owned subsidiary NNG Financial
Corporation (NNG Financial); and
other operating and non-operating income and
expenses of the parent company that are not included
in utility or gas storage operations.
•
•
The pipelines referred to above are regulated by FERC.
Less than 1% of our consolidated assets and consolidated
net loss are related to activities in other. For summary
information for these assets and results of operations, see
Note 4.
We have signed agreements to purchase two privately-
owned water utilities in the Pacific Northwest. If completed,
we do not expect these transactions or their continued
operations to have a material impact on our financial
position. We expect to include financial results from these
businesses in other.
ENVIRONMENTAL MATTERS
Properties and Facilities
We own, or previously owned, properties and facilities that
are currently being investigated that may require
environmental remediation and are subject to federal, state,
and local laws and regulations related to environmental
matters. These laws and regulations may require
expenditures over a long time frame to address certain
environmental impacts. Estimates of liabilities for
environmental costs are difficult to determine with precision
because of the various factors that can affect their ultimate
disposition. These factors include, but are not limited to, the
following:
•
•
the complexity of the site;
changes in environmental laws and regulations at the
federal, state, and local levels;
the number of regulatory agencies or other parties
involved;
new technology that renders previous technology
obsolete, or experience with existing technology that
proves ineffective;
the ultimate selection of a particular technology;
the level of remediation required;
variations between the estimated and actual period of
time that must be dedicated to respond to an
environmentally-contaminated site; and
the application of environmental laws that impose joint
and several liabilities on all potentially responsible
parties.
•
•
•
•
•
•
We have received recovery of a portion of such
environmental costs through insurance proceeds and seek
the remainder of such costs through customer rates, and we
believe recovery of these costs is probable. In Oregon, we
have a mechanism to recover expenses, subject to an
earnings test and allocation rules. See Part II, Item 7,
"Results of Operations—Rate Matters—Rate Mechanisms—
Environmental Costs", Note 2, and Note 15.
Greenhouse Gas Matters
We recognize our businesses are likely to be impacted by
future requirements to address greenhouse gas emissions.
Future federal and/or state requirements may seek to limit
emissions of greenhouse gases, including both carbon
dioxide (CO2) and methane. These potential laws and
regulations may require certain activities to reduce
emissions and/or increase the price paid for energy based
on its carbon content.
Current federal rules require the reporting of greenhouse
gas emissions. In September 2009, the Environmental
Protection Agency (EPA) issued a final rule requiring the
annual reporting of greenhouse gas emissions from certain
industries, specified large greenhouse gas emission
sources, and facilities that emit 25,000 metric tons or more
of CO2 equivalents per year. We began reporting emission
information in 2011. Under this reporting rule, local gas
distribution companies like NW Natural are required to
report system throughput to the EPA on an annual basis.
The EPA also issued additional greenhouse gas reporting
regulations requiring the annual reporting of fugitive
emissions from our operations.
In addition, the state of Washington's DOE enacted the
Clean Air Rule (CAR) in 2016, which capped the maximum
greenhouse gas emissions allowed from stationary sources,
such as natural gas utilities. For gas distribution utilities, the
production of emissions from usage by their customers was
considered to be production of emissions attributable to the
utility. In December 2017, in a Washington State Court
proceeding, the Judge ruled that the Department of Ecology
lacked legislative authority to regulate non-emitting sources,
such as local distribution companies. The DOE has not yet
indicated whether it will appeal the ruling. Currently, the
Washington state legislature is considering other similar
legislation.
Additionally, the Oregon legislature is currently considering
various greenhouse gas reduction proposals, including cap
and trade. One such bill would create a declining cap,
beginning 2021, on greenhouse gas emissions emitted by a
wide variety of emission sources, including electric and
natural gas utilities, and would require large utilities to hold
permits, or allowances, to emit greenhouse gas emissions
on a per ton basis. The Oregon legislature is currently
reviewing these proposals, and we expect them to review
similar proposals in the future. While there is uncertainty
regarding potential compliance costs and revenue sharing
impacts of these and other similar proposals, we currently
expect to be able to recover compliance costs in rates, and
as such, do not expect this legislation to materially affect our
consolidated financial position and results of operations.
The outcome of these or any additional federal and state
policy developments in the area of climate change cannot
11
be determined at this time, but these initiatives could
produce a number of results including new regulations, legal
actions, additional charges to fund energy efficiency
activities, or other regulatory actions. The adoption and
implementation of any regulations limiting emissions of
greenhouse gases from our operations could require us to
incur costs to reduce emissions of greenhouse gases
associated with our operations, which could result in an
increase in the prices we charge our customers or a decline
in the demand for natural gas. On the other hand, because
natural gas is a low-carbon fuel, it is also possible future
carbon constraints could create additional demand for
natural gas for electric generation, direct use of natural gas
in homes and businesses, and as a reliable and relatively
low-emission back-up fuel source for alternative energy
sources. Requirements to reduce greenhouse gas
emissions from the transportation sector, such as those in
Oregon’s clean fuel standard, could also result in additional
demand for natural gas fueled vehicles.
We continue to take proactive steps to collaboratively
address future greenhouse gas emission matters, including
actively participating in policy development in Oregon and,
at the federal level, within the American Gas Association.
We engage in policy development to help drive policies that
result in real and meaningful greenhouse gas emission
reductions that are affordable for our customers, and identify
ways to reduce greenhouse gas emissions in our own
operations. We have developed a voluntary carbon savings
initiative consisting of activities that fall into three broad
categories: (1) reducing the carbon intensity of our product,
(2) helping customers use less energy, and (3) displacing
higher carbon fuels, such as replacing diesel in heavy duty
vehicles. Additionally, we help our customers reduce and
offset their gas use through partnership with the Energy
Trust of Oregon offering efficiency programs and the Smart
Energy program, which allows customers to voluntarily
contribute funds to projects such as biodigesters on dairy
farms that offset the greenhouse gases produced from their
natural gas use.
EMPLOYEES
At December 31, 2017, our utility workforce consisted of
1,146 employees, of which 629 were members of the Office
and Professional Employees International Union (OPEIU)
Local No. 11, AFL-CIO, and 517 were non-union employees.
Our labor agreement with members of OPEIU covers
wages, benefits, and working conditions. On May 22, 2014,
our union employees ratified a new labor agreement (Joint
Accord) that extends to November 30, 2019, and thereafter
from year to year unless either party serves notice of its
intent to negotiate modifications to the collective bargaining
agreement.
At December 31, 2017, our non-utility subsidiaries had a
combined workforce of 14 non-union employees, of which
eight had unionized as part of IBEW Local Union No. 1245
(IBEW) and were in the process of negotiating a collective
bargaining agreement. In January 2018, we were notified by
the majority of those represented employees that they no
longer wished to be represented by IBEW as their
bargaining agent. Therefore, our gas storage segment is no
longer recognizing IBEW as the bargaining agent for these
eight employees.
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Our subsidiaries receive certain services from centralized
operations at the utility, and the utility is reimbursed for
those services pursuant to a Shared Services Agreement.
ADDITIONS TO INFRASTRUCTURE
We make capital expenditures in order to maintain and
enhance the safety and integrity of our pipelines, gate
stations, storage facilities, and related assets, to expand the
reach or capacity of those assets, or improve the efficiency
of our operations. We expect to make a significant level of
capital expenditures for additions to utility and gas storage
infrastructure over the next five years, reflecting continued
investments in customer growth, distribution system
improvements, technology, and an expansion at our North
Mist gas storage facility.
For the five-year period from 2018 to 2022, capital
expenditures are estimated to be between $750 and $850
million.
Included in the five year period, 2018 utility capital
expenditures are estimated to be between $190 and $220
million, including $20 to $30 million to complete the
construction of our North Mist gas storage facility expansion.
We expect to invest less than $5 million in non-utility capital
investments for gas storage and other activities in 2018.
Additional investments in our infrastructure during and after
2018 will depend largely on additional regulations and
expansion opportunities. See additional discussion in Part II,
Item 7 "Financial Condition—Cash Flows—Investing
Activities".
EXECUTIVE OFFICERS OF THE REGISTRANT
For information concerning our executive officers, see Part
III, Item 10.
AVAILABLE INFORMATION
We file annual, quarterly and current reports and other
information with the Securities and Exchange Commission
(SEC). Reports, proxy statements, and other information
filed by us can be read, copied, and requested through the
SEC by mail at U.S. Securities and Exchange Commission,
100 F Street, N.E., Washington, D.C. 20549, or online at its
website (http://www.sec.gov). You can obtain information
about access to the Public Reference Room and how to
access or request records by calling the SEC at 1-800-
SEC-0330. The SEC website contains reports, proxy and
information statements, and other information we file
electronically. In addition, we make available on our website
(http://www.nwnatural.com), our annual report on Form 10-
K, quarterly reports on Form 10-Q, current reports on Form
8-K, and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) and proxy materials filed
under Section 14 of the Securities Exchange Act of 1934, as
amended (Exchange Act), as soon as reasonably
practicable after we electronically file such material with, or
furnish it to, the SEC. We have included our website
address as an inactive textual reference only. Information
contained on our website is not incorporated by reference
into this annual report on Form 10-K.
We have adopted a Code of Ethics for all employees,
officers, and directors that is available on our website. We
intend to disclose revisions and amendments to, and any
waivers from, the Code of Ethics for officers and directors
on our website. Our Corporate Governance Standards,
Director Independence Standards, charters of each of the
committees of the Board of Directors, and additional
information about the Company are also available at the
website. Copies of these documents may be requested, at
no cost, by writing or calling Shareholder Services, NW
Natural, One Pacific Square, 220 N.W. Second Avenue,
Portland, Oregon 97209, telephone 503-226-4211 ext. 2402.
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ITEM 1A. RISK FACTORS
Our business and financial results are subject to a number
of risks and uncertainties, many of which are not within our
control, which could adversely affect our business, financial
condition, and results of operations. Additional risks and
uncertainties that are not currently known to the Company
or that are not currently believed by the Company to be
material may also harm the Company's business, financial
condition, and results of operations. When considering any
investment in our securities, investors should carefully
consider the following information, as well as information
contained in the caption "Forward-Looking Statements",
Item 7A, and other documents we file with the SEC. This list
is not exhaustive and the order of presentation does not
reflect management’s determination of priority or likelihood.
Additionally, our listing of risk factors that primarily affects
one of our business segments does not mean that such risk
factor is inapplicable to our other business segments.
Risks Related to our Business Generally
REGULATORY RISK. Regulation of our businesses, including
changes in the regulatory environment, failure of regulatory
authorities to approve rates which provide for timely
recovery of our costs and an adequate return on invested
capital, or an unfavorable outcome in regulatory
proceedings may adversely impact our financial condition
and results of operations.
The OPUC and WUTC have general regulatory authority
over our utility business in Oregon and Washington,
respectively, including the rates charged to customers,
authorized rates of return on rate base, including ROE, the
amounts and types of securities we may issue, services we
provide and the manner in which we provide them, the
nature of investments we make, actions investors may take
with respect to our company, and deferral and recovery of
various expenses, including, but not limited to, pipeline
replacement, environmental remediation costs, commodity
hedging expense, transactions with affiliated interests,
weather adjustment mechanisms and other matters.
Similarly, in our gas storage businesses FERC has
regulatory authority over interstate storage services, the
CPUC has regulatory authority over our Gill Ranch storage
operations, and the WUTC and OPUC have regulatory
authority over our Mist storage operations. Additionally,
expansion of our business, including into water or other
sectors, could result in regulation by other regulatory
authorities.
The prices the OPUC and WUTC allow us to charge for
retail service, and the maximum FERC-approved rates
FERC authorizes us to charge for interstate storage and
related transportation services, are the most significant
factors affecting our financial position, results of operations
and liquidity. The OPUC and WUTC have the authority to
disallow recovery of costs they find imprudently incurred or
otherwise disallowed. Additionally, the rates allowed by the
FERC may be insufficient for recovery of costs incurred. We
expect to continue to make expenditures to expand, improve
and operate our utility distribution and gas storage systems.
Regulators can find such expansions or improvements of
expenditures were not prudently incurred, and deny
recovery. Additionally, while the OPUC and WUTC have
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established an authorized rate of return for our utility
through the ratemaking process, the regulatory process
does not provide assurance that we will be able to achieve
the earnings level authorized. Moreover, in the normal
course of business we may place assets in service or incur
higher than expected levels of operating expense before
rate cases can be filed to recover those costs—this is
commonly referred to as regulatory lag. The failure of any
regulatory commission to approve requested rate increases
on a timely basis to recover increased costs or to allow an
adequate return could adversely impact our financial
condition and results of operations.
As a regulated utility, we frequently have dockets open with
our regulators. The regulatory proceedings for these
dockets typically involve multiple parties, including
governmental agencies, consumer advocacy groups, and
other third parties. Each party has differing concerns, but all
generally have the common objective of limiting amounts
included in rates. We cannot predict the timing or outcome
of these deferred proceedings or the effects of those
outcomes on our results of operations and financial
condition.
ENVIRONMENTAL LIABILITY RISK. Certain of our properties
and facilities may pose environmental risks requiring
remediation, the costs of which are difficult to estimate and
which could adversely affect our financial condition, results
of operations, and cash flows.
We own, or previously owned, properties that require
environmental remediation or other action. We accrue all
material loss contingencies relating to these properties. A
regulatory asset at the utility has been recorded for
estimated costs pursuant to a Deferral Order from the
OPUC and WUTC. In addition to maintaining regulatory
deferrals, we settled with most of our historical liability
insurers for only a portion of the costs we have incurred to
date and expect to incur in the future. To the extent amounts
we recovered from insurance are inadequate or we are
unable to recover these deferred costs in utility customer
rates, we would be required to reduce our regulatory assets
which would result in a charge to current year earnings. In
addition, in Oregon, the OPUC approved the SRRM, which
limits recovery of our deferred amounts to those amounts
which satisfy an annual prudence review and earnings test
that requires the Company to contribute additional amounts
toward environmental remediation costs above
approximately $10 million in years in which the Company
earns above its authorized Return on Equity (ROE). To the
extent the Company earns more than its authorized ROE in
a year, the Company would be required to cover
environmental expenses greater than the $10 million with
those earnings that exceed its authorized ROE. In addition,
the OPUC ordered a review of the SRRM in 2018 or when
we obtain greater certainty of environmental costs,
whichever occurs first. These ongoing prudence reviews,
the earnings test, or the three-year review could reduce the
amounts we are allowed to recover, and could adversely
affect our financial condition, results of operations and cash
flows.
Moreover, we may have disputes with regulators and other
parties as to the severity of particular environmental
matters, what remediation efforts are appropriate, and the
portion of the costs we should bear. We cannot predict with
certainty the amount or timing of future expenditures related
to environmental investigation, remediation or other action,
the portions of these costs allocable to us, or disputes or
litigation arising in relation thereto.
Our liability estimates are based on current remediation
technology, industry experience gained at similar sites, an
assessment of our probable level of responsibility, and the
financial condition of other potentially responsible parties.
However, it is difficult to estimate such costs due to
uncertainties surrounding the course of environmental
remediation, the preliminary nature of certain of our site
investigations, and the application of environmental laws
that impose joint and several liabilities on all potentially
responsible parties. These uncertainties and disputes
arising therefrom could lead to further adversarial
administrative proceedings or litigation, with associated
costs and uncertain outcomes, all of which could adversely
affect our financial condition, results of operations and cash
flows.
ENVIRONMENTAL REGULATION COMPLIANCE RISK. We are
subject to environmental regulations for our ongoing
operations, compliance with which could adversely affect
our operations or financial results.
We are subject to laws, regulations and other legal
requirements enacted or adopted by federal, state and local
governmental authorities relating to protection of the
environment, including those legal requirements that govern
discharges of substances into the air and water, the
management and disposal of hazardous substances and
waste, groundwater quality and availability, plant and wildlife
protection, and other aspects of environmental regulation.
For example, we are subject to reporting requirements to
the Environmental Protection Agency and the Oregon
Department of Environmental Quality regarding greenhouse
gas emissions. Similarly, there are current legislative efforts
in Oregon and Washington to cap or otherwise restrict the
maximum GHGs an entity may emit without reduction efforts
or other undertakings. These and other current and future
additional environmental regulations could result in
increased compliance costs or additional operating
restrictions, which may or may not be recoverable in
customer rates or through insurance. If these costs are not
recoverable, they could have an adverse effect on our
financial condition and results of operations.
GLOBAL CLIMATE CHANGE RISK. Future legislation to
address global climate change may expose us to regulatory
and financial risk. Additionally, our business may be subject
to physical risks associated with climate change, all of which
could adversely affect our financial condition, results of
operations and cash flows.
There are a number of international, federal and state
legislative and regulatory initiatives being proposed and
adopted in an attempt to measure, control or limit the effects
of global warming and climate change, including
greenhouse gas emissions such as carbon dioxide and
methane. Such current or future legislation or regulation
could impose on us operational requirements, additional
charges to fund energy efficiency initiatives, or levy a tax
based on carbon content. Such initiatives could result in us
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incurring additional costs to comply with the imposed
restrictions, provide a cost advantage to energy sources
other than natural gas, reduce demand for natural gas,
impose costs or restrictions on end users of natural gas,
impact the prices we charge our customers, impose
increased costs on us associated with the adoption of new
infrastructure and technology to respond to such
requirements, and may impact cultural perception of our
service or products negatively, diminishing the value of our
brand, all of which could adversely affect our business
practices, financial condition and results of operations.
Climate change may cause physical risks, including an
increase in sea level, intensified storms, water scarcity and
changes in weather conditions, such as changes in
precipitation, average temperatures and extreme wind or
other climate conditions. A significant portion of the nation’s
gas infrastructure is located in areas susceptible to storm
damage that could be aggravated by wetland and barrier
island erosion, which could give rise to gas supply
interruptions and price spikes.
These and other physical changes could result in
disruptions to natural gas production and transportation
systems potentially increasing the cost of gas and affecting
our ability to procure gas to meet our customer demand.
These changes could also affect our distribution systems
resulting in increased maintenance and capital costs,
disruption of service, regulatory actions and lower customer
satisfaction. Additionally, to the extent that climate change
adversely impacts the economic health or weather
conditions of our service territory directly, it could adversely
impact customer demand or our customers' ability to pay.
Such physical risks could have an adverse effect on our
financial condition, results of operations, and cash flows.
STRATEGIC TRANSACTION RISK. Our ability to successfully
complete strategic transactions, including merger,
acquisition, divestiture, joint venture, business development
projects or other strategic transactions is subject to
significant risks, including the risk that required regulatory or
governmental approvals may not be obtained, risks relating
to unknown or undisclosed problems or liabilities, and the
risk that for these or other reasons, we may be unable to
achieve some or all of the benefits that we anticipate from
such transactions which could adversely affect our financial
condition, results of operations, and cash flows.
From time to time, we have pursued and may continue to
pursue strategic transactions including merger, acquisition,
divestiture, joint venture, business development projects or
other strategic transactions. Any such transactions involve
substantial risks, including the following:
•
•
acquired businesses or assets may not produce
revenues, earnings or cash flow at anticipated
levels;
acquired businesses or assets could have, or
supply, environmental, permitting, or other
problems for which contractual protections prove
inadequate;
• we may experience difficulties in integration or
operation costs of new businesses;
• we may assume liabilities which were not disclosed
to us, that exceed our estimates, or for which our
rights to indemnification from the seller are limited;
• we may be unable to obtain the necessary
regulatory or governmental approvals to close a
transaction, such approvals may be granted
subject to terms that are unacceptable to us, or we
may be unable to achieve anticipated regulatory
treatment of any such transaction, or such benefits
may be delayed or not occur at all;
• we may agree to sell assets for a price that is less
than the book value of those assets.
One of more of these conditions could affect our financial
condition, results of operations, and cash flows.
BUSINESS DEVELOPMENT RISK. Our business development
projects may encounter unanticipated obstacles, costs,
changes or delays that could result in a project becoming
impaired, which could negatively impact our financial
condition, results of operations and cash flows.
Business development projects involve many risks. We are
currently engaged in several business development
projects, including, but not limited to, the early planning and
development stages for a regional pipeline in Oregon, and
an expansion of our gas storage facility at Mist. We may
also engage in other business development projects such
as investment in additional long-term gas reserves, CNG
refueling stations, or projects in the water sector. These
projects may not be successful. Additionally, we may not be
able to obtain required governmental permits and approvals
to complete our projects in a cost-efficient or timely manner
potentially resulting in delays or abandonment of the
projects. We could also experience startup and construction
delays, construction cost overruns, disputes with
contractors, inability to negotiate acceptable agreements
such as rights-of-way, easements, construction, gas supply
or other material contracts, changes in customer demand or
commitment, public opposition to projects, changes in
market prices, and operating cost increases. Additionally, we
may be unable to finance our business development
projects at acceptable interest rates or within a scheduled
time frame necessary for completing the project. One or
more of these events could result in the project becoming
impaired, and such impairment could have an adverse effect
on our financial condition and results of operations.
JOINT PARTNER RISK. Investing in business development
projects through partnerships, joint ventures or other
business arrangements affects our ability to manage certain
risks and could adversely impact our financial condition,
results of operations and cash flows.
We use joint ventures and other business arrangements to
manage and diversify the risks of certain utility and non-
utility development projects, including our Trail West
pipeline, Gill Ranch storage and our gas reserves
agreements. We may acquire or develop part-ownership
interests in other projects in the future, including but not
limited to, in the water sector. Under these arrangements,
we may not be able to fully direct the management and
policies of the business relationships, and other participants
in those relationships may take action contrary to our
interests including making operational decisions that could
affect our costs and liabilities. In addition, other participants
may withdraw from the project, divest important assets,
become financially distressed or bankrupt, or have
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economic or other business interests or goals that are
inconsistent with ours.
For example, our gas reserves arrangements, which
operate as a hedge backed by physical gas supplies,
involve a number of risks. These risks include gas
production that is significantly less than the expected
volumes, or no gas volumes; operating costs that are higher
than expected; changes in our consolidated tax position or
tax laws that could affect our ability to take, or timing of,
certain tax benefits that impact the financial outcome of this
transaction; inherent risks of gas production, including
disruption to operations or complete shut-in of the field; and
a participant in one of these business arrangements acting
contrary to our interests. In addition, while the cost of the
original gas reserves venture is currently included in
customer rates and additional wells under that arrangement
are recovered at a specific cost, the occurrence of one or
more of these risks, could affect our ability to recover this
hedge in rates. Further, any new gas reserves
arrangements have not been approved for inclusion in rates,
and our regulators may ultimately determine to not include
all or a portion of future transactions in rates. The realization
of any of these situations could adversely impact the project
as well as our financial condition, results of operations and
cash flows.
OPERATING RISK. Transporting and storing natural gas
involves numerous risks that may result in accidents and
other operating risks and costs, some or all of which may
not be fully covered by insurance, and which could
adversely affect our financial condition, results of operations
and cash flows.
Our operations are subject to all of the risks and hazards
inherent in the businesses of local gas distribution and
storage, including:
•
earthquakes, floods, storms, landslides and other
adverse weather conditions and hazards;
leaks or other losses of natural gas or other chemicals
or compounds as a result of the malfunction of
equipment or facilities;
damages from third parties, including construction, farm
and utility equipment or other surface users;
operator errors;
negative performance by our storage reservoirs that
could cause us to fail to meet expected or forecasted
operational levels or contractual commitments to our
customers;
problems maintaining, or the malfunction of, pipelines,
wellbores and related equipment and facilities that form
a part of the infrastructure that is critical to the operation
of our gas distribution and storage facilities;
collapse of underground storage caverns;
operating costs that are substantially higher than
expected;
•
•
•
•
•
•
•
•
• migration of natural gas through faults in the rock or to
some area of the reservoir where existing wells cannot
drain the gas effectively resulting in loss of the gas;
blowouts (uncontrolled escapes of gas from a pipeline
or well) or other accidents, fires and explosions; and
risks and hazards inherent in the drilling operations
associated with the development of the gas storage
facilities and/or wells.
•
These risks could result in personal injury or loss of human
life, damage to and destruction of property and equipment,
pollution or other environmental damage, breaches of our
contractual commitments, and may result in curtailment or
suspension of our operations, which in turn could lead to
significant costs and lost revenues. Further, because our
pipeline, storage and distribution facilities are in or near
populated areas, including residential areas, commercial
business centers, and industrial sites, any loss of human life
or adverse financial outcomes resulting from such events
could be significant. Additionally, we may not be able to
maintain the level or types of insurance we desire, and the
insurance coverage we do obtain may contain large
deductibles or fail to cover certain hazards or cover all
potential losses. The occurrence of any operating risks not
covered by insurance could adversely affect our financial
condition, results of operations and cash flows.
BUSINESS CONTINUITY RISK. We may be adversely
impacted by local or national disasters, pandemic illness,
terrorist activities, including cyber-attacks or data breaches,
and other extreme events to which we may not be able to
promptly respond.
Local or national disasters, pandemic illness, terrorist
activities, including cyber-attacks and data breaches, and
other extreme events are a threat to our assets and
operations. Companies in critical infrastructure industries
may face a heightened risk due to exposure to acts of
terrorism, including physical and security breaches of our
information technology infrastructure in the form of cyber-
attacks. These attacks could target or impact our
technology or mechanical systems that operate our
distribution, transmission or storage facilities and result in a
disruption in our operations, damage to our system and
inability to meet customer requirements. In addition, the
threat of terrorist activities could lead to increased economic
instability and volatility in the price of natural gas or other
necessary commodities that could affect our operations.
Threatened or actual national disasters or terrorist activities
may also disrupt capital or bank markets and our ability to
raise capital or obtain debt financing, or impact our suppliers
or our customers directly. Local disaster or pandemic illness
could result in part of our workforce being unable to operate
or maintain our infrastructure or perform other tasks
necessary to conduct our business. A slow or inadequate
response to events may have an adverse impact on
operations and earnings. We may not be able to maintain
sufficient insurance to cover all risks associated with local
and national disasters, pandemic illness, terrorist activities
and other events. Additionally, large scale natural disasters
or terrorist attacks could destabilize the insurance industry
making insurance we do have unavailable, which could
increase the risk that an event could adversely affect our
operations or financial results.
HOLDING COMPANY DIVIDEND RISK. If we were to
reorganize as a holding company, the holding company
would depend on its operating subsidiaries to meet financial
obligations and the ability of the holding company to pay
dividends on its common stock would be dependent on the
receipt of dividends and other payments from its
subsidiaries.
If we were to implement a holding company structure, NW
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Natural common stock would be converted or exchanged
into shares of a holding company with the only significant
assets being the stock of its operating subsidiaries,
including NW Natural. NW Natural and its current
subsidiaries, which would become NW Holding’s direct and
indirect subsidiaries, are separate and distinct legal entities,
managed by their own boards of directors, and, as is
currently the case, would have no obligation to pay any
amounts to their respective shareholders, whether through
dividends, loans or other payments. The ability of these
companies to pay dividends or make other distributions on
their common stock is now, and would continue to be,
subject to, among other things: their results of operations,
net income, cash flows and financial condition, as well as
the success of their business strategies and general
economic and competitive conditions; the prior rights of
holders of existing and future debt securities and any future
preferred stock issued by those companies; and any
applicable legal restrictions.
In addition, the ability of the holding company’s subsidiaries
to pay upstream dividends and make other distributions
would be subject to applicable state law and regulatory
restrictions. Under the OPUC and WUTC regulatory
approvals for the holding company formation, if NW Natural
ceases to comply with credit and capital structure
requirements approved by the OPUC and WUTC, it will not,
with limited exceptions, be permitted to pay dividends to the
holding company. Under the OPUC and WUTC orders
authorizing the Company to form a holding company, NW
Natural may not pay dividends or make distributions to the
holding company if NW Natural’s credit ratings and common
equity levels fall below specified ratings and levels. If NW
Natural’s long-term secured credit ratings are below A- for
S&P and A3 for Moody’s, dividends may be issued so long
as NW Natural’s common equity is 45% or above. If NW
Natural’s long-term secured credit ratings are below BBB for
S&P and Baa2 for Moody’s, dividends may be issued so
long as NW Natural’s common equity is 46% or above.
Dividends may not be issued if NW Natural’s long-term
secured credit ratings fall to BB+ or below for S&P or Ba1 or
below for Moody’s, or if NW Natural’s common equity is
below 44%. In each case, with the common equity level to
be determined on a preceding or projected 13-month basis.
HOLDING COMPANY PRIORITY RISK. If a holding company
structure is completed, the holding company’s ability to pay
dividends on its common stock would be subject to the prior
rights of holders of its indebtedness and preferred stock, if
any.
If we were to form a holding company, it may from time to
time issue debt securities and preferred stock, as well as
additional shares of holding company common stock, in
order to make capital contributions to one or more of its
subsidiaries or for other reasons, although NW Natural
would likely continue to issue its own debt securities and
may issue preferred stock. The holding company could also
guarantee indebtedness of non-utility subsidiaries. The
issuance or guaranty of securities by the holding company
would not be subject to the prior approval of the state utility
commissions. The consolidated enterprise could thus be
more highly leveraged than NW Natural and its current
subsidiaries. The holding company’s ability to pay dividends
on its common stock would be subject to the prior rights of
holders of the holding company’s debt securities (including
guarantees) and preferred stock, if any.
In addition, the right of the holding company, as a
shareholder, to receive assets of any of its direct or indirect
subsidiaries upon the subsidiary’s liquidation or
reorganization would be subject to the prior rights of the
holders of existing and future debt securities and preferred
stock issued by such subsidiaries, and, as in the case of
dividends, the rights of holders of the holding company
common stock to receive any such assets would be subject
to the prior rights of the holders of the holding company’s
debt securities (including guarantees) and preferred stock.
HOLDING COMPANY DIVERSIFICATION RISK. The holding
company may invest in unregulated activities that may prove
to be riskier than the current activities of NW Natural, which
could result in losses and adversely affect the holding
company’s financial condition, results of operations and
cash flows.
The holding company structure may allow us greater
opportunities to invest in regulated and unregulated
businesses. These investments may involve greater risk
than an investment in NW Natural. If losses are incurred in
unregulated businesses, they will likely not be recoverable
through utility rates and they could adversely affect the
holding company’s financial condition, results of operations
and cash flows.
EMPLOYEE BENEFIT RISK. The cost of providing pension
and postretirement healthcare benefits is subject to changes
in pension assets and liabilities, changing employee
demographics and changing actuarial assumptions, which
may have an adverse effect on our financial condition,
results of operations and cash flows.
Until we closed the pension plans to new hires, which for
non-union employees was in 2006 and for union employees
was in 2009, we provided pension plans and postretirement
healthcare benefits to eligible full-time utility employees and
retirees. Most of our current utility employees were hired
prior to these dates, and therefore remain eligible for these
plans. Our cost of providing such benefits is subject to
changes in the market value of our pension assets, changes
in employee demographics including longer life
expectancies, increases in healthcare costs, current and
future legislative changes, and various actuarial calculations
and assumptions. The actuarial assumptions used to
calculate our future pension and postretirement healthcare
expense may differ materially from actual results due to
significant market fluctuations and changing withdrawal
rates, wage rates, interest rates and other factors. These
differences may result in an adverse impact on the amount
of pension contributions, pension expense or other
postretirement benefit costs recorded in future periods.
Sustained declines in equity markets and reductions in bond
rates may have a material adverse effect on the value of our
pension fund assets and liabilities. In these circumstances,
we may be required to recognize increased contributions
and pension expense earlier than we had planned to the
extent that the value of pension assets is less than the total
anticipated liability under the plans, which could have a
negative impact on our financial condition, results of
operations and cash flows.
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WORKFORCE RISK. Our business is heavily dependent on
being able to attract and retain qualified employees and
maintain a competitive cost structure with market-based
salaries and employee benefits, and workforce disruptions
could adversely affect our operations and results.
Our ability to implement our business strategy and serve our
customers is dependent upon our continuing ability to attract
and retain talented professionals and a technically skilled
workforce, and being able to transfer the knowledge and
expertise of our workforce to new employees as our largely
older workforce retires. We expect that a significant portion
of our workforce will retire within the current decade, which
will require that we attract, train and retain skilled workers to
prevent loss of institutional knowledge or skills gap. Without
an appropriately skilled workforce, our ability to provide
quality service and meet our regulatory requirements will be
challenged and this could negatively impact our earnings.
Additionally, within our utility segment, a majority of our
workers are represented by the OPEIU Local No.11 AFL-
CIO, and are covered by a collective bargaining agreement
that extends to November 30, 2019. Disputes with the union
representing our employees over terms and conditions of
their agreement could result in instability in our labor
relationship and work stoppages that could impact the timely
delivery of gas and other services from our utility and
storage facilities, which could strain relationships with
customers and state regulators and cause a loss of
revenues. Our collective bargaining agreements may also
limit our flexibility in dealing with our workforce, and our
ability to change work rules and practices and implement
other efficiency-related improvements to successfully
compete in today’s challenging marketplace, which may
negatively affect our financial condition and results of
operations.
LEGISLATIVE, COMPLIANCE AND TAXING AUTHORITY RISK.
We are subject to governmental regulation, and compliance
with local, state and federal requirements, including taxing
requirements, and unforeseen changes in or interpretations
of such requirements could affect our financial condition and
results of operations.
We are subject to regulation by federal, state and local
governmental authorities. We are required to comply with a
variety of laws and regulations and to obtain authorizations,
permits, approvals and certificates from governmental
agencies in various aspects of our business. Significant
changes in federal, state, or local governmental leadership
can accelerate or amplify changes in existing laws or
regulations, or the manner in which they are interpreted or
enforced. For example, the U.S. Presidential Administration
has made numerous leadership changes at federal
administrative agencies since the 2016 U.S. Presidential
election. Moreover, the U.S. Congress and the U.S.
Presidential Administration may make substantial changes
to fiscal, tax, regulation and other federal policies. The U.S.
Presidential Administration has called for significant
changes to U.S. fiscal policies, U.S. trade, healthcare,
immigration, foreign, and government regulatory policy. To
the extent the U.S. Congress or U.S. Presidential
Administration implements changes to U.S. policy, those
changes may impact, among other things, the U.S. and
global economy, international trade and relations,
unemployment, immigration, corporate taxes, healthcare,
the U.S. regulatory environment, inflation and other areas.
Although we cannot predict the impact, if any, of these
changes to our business, they could adversely affect our
financial condition and results of operations. Until we know
what policy changes are made and how those changes
impact our business and the business of our competitors
over the long term, we will not know if, overall, we will
benefit from them or be negatively affected by them.
Though we cannot predict the changes in laws, regulations,
or enforcement that are likely as a result of these transitions,
we expect there to be a number of significant changes. We
cannot predict with certainty the impact of any future
revisions or changes in interpretations of existing
regulations or the adoption of new laws and regulations.
Additionally, any failure to comply with existing or new laws
and regulations could result in fines, penalties or injunctive
measures that could affect operating assets. For example,
under the Energy Policy Act of 2005, the FERC has civil
authority under the Natural Gas Act to impose penalties for
current violations of up to $1 million per day for each
violation. In addition, as the regulatory environment for our
industry increases in complexity, the risk of inadvertent
noncompliance may also increase. Changes in regulations,
the imposition of additional regulations, and the failure to
comply with laws and regulations could negatively influence
our operating environment and results of operations.
Additionally, changes in federal, state or local tax laws and
their related regulations, or differing interpretations or
enforcement of applicable law by a federal, state or local
taxing authority, could result in substantial cost to us and
negatively affect our results of operations. Tax law and its
related regulations and case law are inherently complex and
dynamic. Disputes over interpretations of tax laws may be
settled with the taxing authority in examination, upon appeal
or through litigation. Our judgments may include reserves
for potential adverse outcomes regarding tax positions that
have been taken that may be subject to challenge by taxing
authorities. Changes in laws, regulations or adverse
judgments and the inherent difficulty in quantifying potential
tax effects of business decisions may negatively affect our
financial condition and results of operations.
In this regard, the Tax Cuts and Jobs Act of 2017 was
approved by the U.S. Congress on December 20, 2017 and
signed into law by the U.S. President on December 22,
2017. This legislation makes significant changes to the U.S.
Internal Revenue Code. Such changes include a reduction
in the corporate tax rate from 35% to 21% and limitations on
certain corporate deductions and credits, among other
changes. Certain of these changes may negatively affect
our financial condition and results of operations.
We expect that the elimination of bonus depreciation may
increase taxes in 2018 and 2019, which may have an
adverse effect on cash flows during this period. In addition,
there is uncertainty as to how our regulators will reflect the
impact of the legislation in rates. The resulting ratemaking
treatment may negatively affect our financial condition and
results of operations.
SAFETY REGULATION RISK. We may experience increased
federal, state and local regulation of the safety of our
systems and operations, which could adversely affect our
operating costs and financial results.
The safety and protection of the public, our customers and
our employees is and will remain our top priority. We are
committed to consistently monitoring and maintaining our
distribution system and storage operations to ensure that
natural gas is acquired, stored and delivered safely, reliably
and efficiently. Given recent high-profile natural gas
explosions, leaks and accidents in other parts of the country
involving both distribution systems and storage facilities, we
anticipate that the natural gas industry may be the subject of
even greater federal, state and local regulatory oversight.
For example, in 2016, the Protecting our Infrastructure of
Pipelines and Enhancing Safety Act (PIPES Act) was signed
into law increasing regulations for natural gas storage
pipelines and underground storage facilities. Similarly, in
2016, California passed legislation directing the Department
of Oil, Gas and Geothermal Resources (DOGGR) to
develop regulations affecting gas storage operations.
DOGGR has issued proposed regulations which we expect
to go into effect within the first half of 2018. As currently
written, these regulations require mechanical integrity
testing and implementation of gas flow limited to tubing only
for all wells at Gill Ranch within the next 7 years.
We intend to work diligently with industry associations and
federal and state regulators to seek to ensure compliance
with these and other new laws. We expect there to be
increased costs associated with compliance, and those
costs could be significant. If these costs are not recoverable
in our customer rates, they could have a negative impact on
our operating costs and financial results.
HEDGING RISK. Our risk management policies and hedging
activities cannot eliminate the risk of commodity price
movements and other financial market risks, and our
hedging activities may expose us to additional liabilities for
which rate recovery may be disallowed, which could result in
an adverse impact on our operating revenues, costs,
derivative assets and liabilities and operating cash flows.
Our gas purchasing requirements expose us to risks of
commodity price movements, while our use of debt and
equity financing exposes us to interest rate, liquidity and
other financial market risks. In our Utility segment, we
attempt to manage these exposures with both financial and
physical hedging mechanisms, including our gas reserves
transactions which are hedges backed by physical gas
supplies. While we have risk management procedures for
hedging in place, they may not always work as planned and
cannot entirely eliminate the risks associated with hedging.
Additionally, our hedging activities may cause us to incur
additional expenses to obtain the hedge. We do not hedge
our entire interest rate or commodity cost exposure, and the
unhedged exposure will vary over time. Gains or losses
experienced through hedging activities, including carrying
costs, generally flow through the PGA mechanism or are
recovered in future general rate cases. However, the hedge
transactions we enter into for the utility are subject to a
prudence review by the OPUC and WUTC, and, if found
imprudent, those expenses may be, and have been
previously, disallowed, which could have an adverse effect
on our financial condition and results of operations.
19
In addition, our actual business requirements and available
resources may vary from forecasts, which are used as the
basis for our hedging decisions, and could cause our
exposure to be more or less than we anticipated. Moreover,
if our derivative instruments and hedging transactions do not
qualify for regulatory deferral and we do not elect hedge
accounting treatment under generally accepted accounting
standards, our results of operations and financial condition
could be adversely affected.
We also have credit-related exposure to derivative
counterparties. Counterparties owing us money or physical
natural gas commodities could breach their obligations.
Should the counterparties to these arrangements fail to
perform, we may be forced to enter into alternative
arrangements to meet our normal business requirements. In
that event, our financial results could be adversely affected.
Additionally, under most of our hedging arrangements, any
downgrade of our senior unsecured long-term debt credit
rating could allow our counterparties to require us to post
cash, a letter of credit or other form of collateral, which
would expose us to additional costs and may trigger
significant increases in borrowing from our credit facilities if
the credit rating downgrade is below investment grade.
Further, based on current interpretations, we are not
considered a "swap dealer" or "major swap participant" in
2017, so we are exempt from certain requirements under
the Dodd-Frank Act. If we are unable to claim this
exemption, we could be subject to higher costs for our
derivatives activities.
INABILITY TO ACCESS CAPITAL MARKET RISK. Our inability
to access capital, or significant increases in the cost of
capital, could adversely affect our financial condition and
results of operations.
Our ability to obtain adequate and cost effective short-term
and long-term financing depends on maintaining investment
grade credit ratings as well as the existence of liquid and
stable financial markets. Our businesses rely on access to
capital and bank markets, including commercial paper, bond
and equity markets, to finance our operations, construction
expenditures and other business requirements, and to
refund maturing debt that cannot be funded entirely by
internal cash flows. Disruptions in capital markets could
adversely affect our ability to access short-term and long-
term financing. Our access to funds under committed credit
facilities, which are currently provided by a number of
banks, is dependent on the ability of the participating banks
to meet their funding commitments. Those banks may not
be able to meet their funding commitments if they
experience shortages of capital and liquidity. Disruptions in
the bank or capital financing markets as a result of
economic uncertainty, changing or increased regulation of
the financial sector, or failure of major financial institutions
could adversely affect our access to capital and negatively
impact our ability to run our business and make strategic
investments.
A negative change in our current credit ratings, particularly
below investment grade, could adversely affect our cost of
borrowing and access to sources of liquidity and capital.
Such a downgrade could further limit our access to
borrowing under available credit lines. Additionally,
downgrades in our current credit ratings below investment
20
grade could cause additional delays in accessing the capital
markets by the utility while we seek supplemental state
regulatory approval, which could hamper our ability to
access credit markets on a timely basis. A credit downgrade
could also require additional support in the form of letters of
credit, cash or other forms of collateral and otherwise
adversely affect our financial condition and results of
operations.
REPUTATIONAL RISKS. Customers', legislators', and
regulators' opinions of us are affected by many factors,
including system reliability and safety, protection of
customer information, rates, media coverage, and public
sentiment. To the extent that customers, legislators, or
regulators have or develop a negative opinion of us, our
financial positions, results of operations and cash flows
could be adversely affected.
A number of factors can affect customer satisfaction
including: service interruptions or safety concerns due to
failures of equipment or facilities or from other causes, and
our ability to promptly respond to such failures; our ability to
safeguard sensitive customer information; and the timing
and magnitude of rate increases, and volatility of rates.
Customers', legislators', and regulators' opinions of us can
also be affected by media coverage, including the
proliferation of social media, which may include information,
whether factual or not, that damages our brand and
reputation.
If customers, legislators, or regulators have or develop a
negative opinion of us and our utility services, this could
result in increased regulatory oversight and could affect the
returns on common equity we are allowed to earn.
Additionally, negative opinions about us could make it more
difficult for us to achieve favorable legislative or regulatory
outcomes. Negative opinions could also result in sales
volumes reductions or increased use of other sources of
energy. Any of these consequences could adversely affect
our financial position, results of operations and cash flows.
Risks Related Primarily to Our Local Utility Business
REGULATORY ACCOUNTING RISK. In the future, we may no
longer meet the criteria for continued application of
regulatory accounting practices for all or a portion of our
regulated operations.
If we could no longer apply regulatory accounting, we could
be required to write off our regulatory assets and precluded
from the future deferral of costs not recovered through rates
at the time such amounts are incurred, even if we are
expected to recover these amounts from customers in the
future.
GAS PRICE RISK. Higher natural gas commodity prices and
volatility in the price of gas may adversely affect our results
of operations and cash flows.
The cost of natural gas is affected by a variety of factors,
including weather, changes in demand, the level of
production and availability of natural gas supplies,
transportation constraints, availability and cost of pipeline
capacity, federal and state energy and environmental
regulation and legislation, natural disasters and other
catastrophic events, national and worldwide economic and
political conditions, and the price and availability of
alternative fuels. In our utility segment, the cost we pay for
natural gas is generally passed through to our customers
through an annual PGA rate adjustment. If gas prices were
to increase significantly, it would raise the cost of energy to
our utility customers, potentially causing those customers to
conserve or switch to alternate sources of energy.
Significant price increases could also cause new home
builders and commercial developers to select alternative
energy sources. Decreases in the volume of gas we sell
could reduce our earnings, and a decline in customers could
slow growth in our future earnings. Additionally, because a
portion of any (10% or 20%) difference between the
estimated average PGA gas cost in rates and the actual
average gas cost incurred is recognized as current income
or expense, higher average gas costs than those assumed
in setting rates can adversely affect our operating cash
flows, liquidity and results of operations. Additionally,
notwithstanding our current rate structure, higher gas costs
could result in increased pressure on the OPUC or the
WUTC to seek other means to reduce rates, which also
could adversely affect our results of operations and cash
flows.
Higher gas prices may also cause us to experience an
increase in short-term debt and temporarily reduce liquidity
because we pay suppliers for gas when it is purchased,
which can be in advance of when these costs are recovered
through rates. Significant increases in the price of gas can
also slow our collection efforts as customers experience
increased difficulty in paying their higher energy bills,
leading to higher than normal delinquent accounts
receivable resulting in greater expense associated with
collection efforts and increased bad debt expense.
CUSTOMER GROWTH RISK. Our utility margin, earnings and
cash flow may be negatively affected if we are unable to
sustain customer growth rates in our local gas distribution
segment.
Our utility margins and earnings growth have largely
depended upon the sustained growth of our residential and
commercial customer base due, in part, to the new
construction housing market, conversions of customers to
natural gas from other energy sources and growing
commercial use of natural gas. The last recession slowed
new construction. While construction has resumed and the
multi-family composition has been higher than its pre-
recession pace, overall construction has not returned to the
pre-recession pace. Insufficient growth in these markets, for
economic, political or other reasons could result in an
adverse long-term impact on our utility margin, earnings and
cash flows.
RISK OF COMPETITION. Our gas distribution business is
subject to increased competition which could negatively
affect our results of operations.
In the residential and commercial markets, our gas
distribution business competes primarily with suppliers of
electricity, fuel oil, and propane. In the industrial market, we
compete with suppliers of all forms of energy. Competition
among these forms of energy is based on price, efficiency,
reliability, performance, market conditions, technology,
environmental impacts and public perception.
21
Technological improvements in other energy sources such
as heat pumps, batteries or other alternative technologies
could erode our competitive advantage. If natural gas prices
rise relative to other energy sources, or if the cost,
environmental impact or public perception of such other
energy sources improves relative to natural gas, it may
negatively affect our ability to attract new customers or
retain our existing residential, commercial and industrial
customers, which could have a negative impact on our
customer growth rate and results of operations.
RELIANCE ON THIRD PARTIES TO SUPPLY NATURAL GAS
RISK. We rely on third parties to supply the natural gas in
our distribution segment, and limitations on our ability to
obtain supplies, or failure to receive expected supplies for
which we have contracted, could have an adverse impact on
our financial results.
Our ability to secure natural gas for current and future sales
depends upon our ability to purchase and receive delivery of
supplies of natural gas from third parties. We, and in some
cases, our suppliers of natural gas do not have control over
the availability of natural gas supplies, competition for those
supplies, disruptions in those supplies, priority allocations on
transmission pipelines, or pricing of those supplies.
Additionally, third parties on whom we rely may fail to deliver
gas for which we have contracted. If we are unable or are
limited in our ability to obtain natural gas from our current
suppliers or new sources, we may not be able to meet our
customers' gas requirements and would likely incur costs
associated with actions necessary to mitigate services
disruptions, both of which could significantly and negatively
impact our results of operations.
SINGLE TRANSPORTATION PIPELINE RISK. We rely on a
single pipeline company for the transportation of gas to our
service territory, a disruption of which could adversely
impact our ability to meet our customers’ gas requirements.
Our distribution system is directly connected to a single
interstate pipeline, which is owned and operated by
Northwest Pipeline. The pipeline’s gas flows are bi-
directional, transporting gas into the Portland metropolitan
market from two directions: (1) the north, which brings
supplies from the British Columbia and Alberta supply
basins; and (2) the east, which brings supplies from the
Alberta and the U.S. Rocky Mountain supply basins. If there
is a rupture or inadequate capacity in the pipeline, we may
not be able to meet our customers’ gas requirements and
we would likely incur costs associated with actions
necessary to mitigate service disruptions, both of which
could significantly and negatively impact our results of
operations.
WEATHER RISK. Warmer than average weather may have a
negative impact on our revenues and results of operations.
We are exposed to weather risk primarily in our utility
segment. A majority of our volume is driven by gas sales to
space heating residential and commercial customers during
the winter heating season. Current utility rates are based on
an assumption of average weather. Warmer than average
weather typically results in lower gas sales. Colder weather
typically results in higher gas sales. Although the effects of
warmer or colder weather on utility margin in Oregon are
expected to be mitigated through the operation of our
weather normalization mechanism, weather variations from
normal could adversely affect utility margin because we may
be required to purchase more or less gas at spot rates,
which may be higher or lower than the rates assumed in our
PGA. Also, a portion of our Oregon residential and
commercial customers (usually less than 10%) have opted
out of the weather normalization mechanism, and 11% of
our customers are located in Washington where we do not
have a weather normalization mechanism. These effects
could have an adverse effect on our financial condition,
results of operations and cash flows.
CUSTOMER CONSERVATION RISK. Customers’ conservation
efforts may have a negative impact on our revenues.
An increasing national focus on energy conservation,
including improved building practices and appliance
efficiencies may result in increased energy conservation by
customers. This can decrease our sales of natural gas and
adversely affect our results of operations because revenues
are collected mostly through volumetric rates, based on the
amount of gas sold. In Oregon, we have a conservation tariff
which is designed to recover lost utility margin due to
declines in residential and small commercial customers’
consumption. However, we do not have a conservation tariff
in Washington that provides us this margin protection on
sales to customers in that state.
RELIANCE ON TECHNOLOGY RISK. Our efforts to integrate,
consolidate and streamline our operations have resulted in
increased reliance on technology, the failure or security
breach of which could adversely affect our financial
condition and results of operations.
Over the last several years we have undertaken a variety of
initiatives to integrate, standardize, centralize and
streamline our operations. These efforts have resulted in
greater reliance on technological tools such as: an
enterprise resource planning system, an automated
dispatch system, an automated meter reading system, a
customer information system, a web-based ordering and
tracking system, and other similar technological tools and
initiatives. The failure of any of these or other similarly
important technologies, or our inability to have these
technologies supported, updated, expanded or integrated
into other technologies, could adversely impact our
operations. We take precautions to protect our systems, but
there is no guarantee that the procedures we have
implemented to protect against unauthorized access to
secured data and systems are adequate to safeguard
against all security breaches. Our utility could experience
breaches of security pertaining to sensitive customer,
employee, and vendor information maintained by the utility
in the normal course of business, which could adversely
affect the utility’s reputation, diminish customer confidence,
disrupt operations, materially increase the costs we incur to
protect against these risks, and subject us to possible
financial liability or increased regulation or litigation, any of
which could adversely affect our financial condition and
results of operations.
Furthermore, we rely on information technology systems in
our operations of our distribution and storage operations.
There are various risks associated with these systems,
22
including, hardware and software failure, communications
failure, data distortion or destruction, unauthorized access to
data, misuse of proprietary or confidential data,
unauthorized control through electronic means,
programming mistakes and other inadvertent errors or
deliberate human acts. In particular, cyber security attacks,
terrorism or other malicious acts could damage, destroy or
disrupt all of our business systems. Any failure of
information technology systems could result in a loss of
operating revenues, an increase in operating expenses and
costs to repair or replace damaged assets. As these
potential cyber security attacks become more common and
sophisticated, we could be required to incur costs to
strengthen our systems or obtain specific insurance
coverage against potential losses.
Risks Related Primarily to Our Gas Storage
Businesses
LONG-TERM LOW OR STABILIZATION OF GAS PRICE RISK.
Any significant stabilization of natural gas prices or long-
term low gas prices could have a negative impact on the
demand for our natural gas storage services, which could
adversely affect our financial results.
Storage businesses benefit from price volatility, which
impacts the level of demand for services and the rates that
can be charged for storage services. Largely due to the
abundant supply of natural gas made available by hydraulic
fracturing techniques, natural gas prices have dropped
significantly to levels that are near historic lows. If prices
and volatility remain low or decline further, then the demand
for storage services, and the prices that we will be able to
charge for those services, may decline or be depressed for
a prolonged period of time. Prices below the costs to
operate the storage facility could result in a decision to shut-
in all or a portion of the facility. A sustained decline in these
prices or a shut-in of all or a portion of the facility could have
an adverse impact on our financial condition, results of
operations and cash flows.
NATURAL GAS STORAGE COMPETITION RISK. Increasing
competition in the natural gas storage business could
reduce the demand for our storage services and drive prices
down for storage, which could adversely affect our financial
condition, results of operations and cash flows.
Our natural gas storage segment competes primarily with
other storage facilities and pipelines. Natural gas storage is
an increasingly competitive business, with the ability to
expand or build new storage capacity in California, the U.S.
Rocky Mountains and elsewhere in the United States and
Canada. Increased competition in the natural gas storage
business could reduce the demand for our natural gas
storage services, drive prices down for our storage
business, and adversely affect our ability to renew or
replace existing contracts at rates sufficient to maintain
current revenues and cash flows, which could adversely
affect our financial condition, results of operations and cash
flows.
IMPAIRMENT OF LONG-LIVED ASSETS RISK. Additional
impairments of the value of long-lived assets could have a
material effect on our financial condition, or results of
operations.
We review the carrying value of long-lived assets whenever
events or changes in circumstances indicate the carrying
amount of the assets might not be recoverable. The
determination of recoverability is based on the undiscounted
net cash flows expected to result from the operation of such
assets. Projected cash flows depend on the future operating
costs and projected revenues associated with the asset,
storage pricing, the ability to contract with higher value
customers, and the future market and price for gas storage
over the remaining life of the asset. We recognized a $192.5
million impairment of long-lived assets at the Gill Ranch
Facility as of December 31, 2017. Further changes in
revenues, operating costs, or a decision to sell the facility
may result in an additional impairment of long-lived assets
at the Gill Ranch Facility. Additionally, we review our other
long-lived assets to determine if an impairment analysis is
necessary. Any impairment charge taken with respect to our
long-lived assets could be material and could have a
material effect on our financial condition and results of
operations.
THIRD-PARTY PIPELINE RISK. Our gas storage businesses
depend on third-party pipelines that connect our storage
facilities to interstate pipelines, the failure or unavailability of
which could adversely affect our financial condition, results
of operations and cash flows.
Our gas storage facilities are reliant on the continued
operation of a third-party pipeline and other facilities that
provide delivery options to and from our storage facilities.
Because we do not own all of these pipelines, their
operations are not within our control. If the third-party
pipeline to which we are connected were to become
unavailable for current or future withdrawals or injections of
natural gas due to repairs, damage to the infrastructure, lack
of capacity or other reasons, our ability to operate efficiently
and satisfy our customers’ needs could be compromised,
thereby potentially having an adverse impact on our
financial condition, results of operations and cash flows.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments.
23
ITEM 2. PROPERTIES
ITEM 3. LEGAL PROCEEDINGS
Other than the proceedings disclosed in Note 15, we have
only nonmaterial litigation in the ordinary course of
business.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
Utility Properties
Our natural gas pipeline system consists of approximately
20,000 miles of distribution and transmission mains located
in our service territory in Oregon and Washington. In
addition, the pipeline system includes service pipelines,
meters and regulators, and gas regulating and metering
stations. Pipeline mains are located in municipal streets or
alleys pursuant to franchise or occupation ordinances, in
county roads or state highways pursuant to agreements or
permits granted pursuant to statute, or on lands of others
pursuant to easements obtained from the owners of such
lands. We also hold permits for the crossing of numerous
navigable waterways and smaller tributaries throughout our
entire service territory.
We own service building facilities in Portland, Oregon, as
well as various satellite service centers, garages,
warehouses, and other buildings necessary and useful in
the conduct of our business. We also lease office space in
Portland for our corporate headquarters, which expires on
May 31, 2020. Resource centers are maintained on owned
or leased premises at convenient points in the distribution
system to provide service within our utility service territory.
We also own LNG storage facilities in Portland and near
Newport, Oregon.
In October 2017, we entered into a 20-year operating lease
agreement for a new headquarters in Portland in
anticipation of the expiration of our current lease in 2020.
We executed an extensive search and evaluation process
that focused on seismic preparedness, safety, reliability, the
least cost to our customers, and a continued commitment to
our employees and the communities we serve. Payments
under the new lease are expected to commence in 2020.
Gas Storage Properties
We hold leases and other property interests in
approximately 12,000 net acres of underground natural gas
storage in Oregon, approximately 5,000 net acres of
underground natural gas storage in California, and
easements and other property interests related to pipelines
associated with those facilities. We own rights to depleted
gas reservoirs near Mist, Oregon that are continuing to be
developed and operated as underground gas storage
facilities. We also hold all future storage rights in certain
other areas of the Mist gas field in Oregon, as well as in
California related to the Gill Ranch Facility.
We consider all of our properties currently used in our
operations, both owned and leased, to be well maintained,
in good operating condition, and, along with planned
additions, adequate for our present and foreseeable future
needs.
Our Mortgage and Deed of Trust (Mortgage) is a first
mortgage lien on substantially all of the property constituting
our utility plant.
24
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed and trades on the New York Stock Exchange under the symbol NWN. The high and low trades for
our common stock during the past two years were as follows:
Quarter Ended
March 31
June 30
September 30
December 31
2017
2016
High
Low
High
Low
$
61.70
$
56.53
$
54.51
$
63.40
68.60
69.50
57.65
59.15
58.55
64.84
66.17
61.85
The closing price for our common stock on the last trading day of 2017 and 2016 was $59.65 and $59.80, respectively.
As of February 16, 2018, there were 5,213 holders of record of our common stock.
Dividends per share paid during the past two years were as follows:
Payment Month
February
May
August
November
Total per share
2017
2016
$
$
0.4700
$
0.4700
0.4700
0.4725
1.8825
$
48.90
49.46
57.96
53.50
0.4675
0.4675
0.4675
0.4700
1.8725
The declaration and amount of future dividends depend upon our earnings, cash flows, financial condition, and other factors. The
amount and timing of dividends payable on our common stock are within the sole discretion of our Board of Directors. Subject to
Board approval, we expect to continue paying cash dividends on our common stock on a quarterly basis.
The following table provides information about purchases of our equity securities that are registered pursuant to Section 12 of
the Securities Exchange Act of 1934 during the quarter ended December 31, 2017:
Period
Balance forward
10/01/17-10/31/17
11/01/17-11/30/17
12/01/17-12/31/17
Total
Issuer Purchases of Equity Securities
Total Number
of Shares Purchased(1)
Average
Price Paid per Share
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs(2)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the
Plans or Programs(2)
2,124,528
$
16,732,648
657
$
14,239
650
15,546
66.33
67.89
64.98
67.71
—
—
—
—
—
—
2,124,528
$
16,732,648
(1) During the quarter ended December 31, 2017, the following number of shares of our common stock were purchased on the open market:
13,539 shares to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan and 2,007 shares to meet the
requirements of our share-based programs. No shares of our common stock were accepted as payment for stock option exercises pursuant
to our Restated Stock Option Plan.
(2) During the quarter ended December 31, 2017, no shares of our common stock were repurchased pursuant to our Board-Approved share
repurchase program. For more information on this program, see Note 6.
25
ITEM 6. SELECTED FINANCIAL DATA
In thousands, except per share data
2017
2016
2015
2014
2013
Operating revenues
Net income (loss)
$
762,173
$
675,967
$
723,791
$
754,037
$
758,518
(55,623)
58,895
53,703
58,692
60,538
For the year ended December 31,
Earnings (Loss) per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
$
(1.94) $
2.13
$
1.96
$
2.16
$
(1.94)
1.88
2.12
1.87
1.96
1.86
2.16
1.85
2.24
2.24
1.83
Total assets, end of period
$
3,039,746
$
3,079,801
$
3,069,410
$
3,056,326
$
2,960,808
Total equity
Long-term debt
742,776
683,184
850,497
679,334
780,972
569,445
767,321
613,095
751,872
671,643
26
ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is management’s assessment of Northwest
Natural Gas Company’s (NW Natural or the Company)
financial condition, including the principal factors that affect
results of operations. The discussion refers to our
consolidated results for the years ended December 31,
2017, 2016, and 2015. References in this discussion to
"Notes" are to the Notes to Consolidated Financial
Statements in Item 8 of this report.
The consolidated financial statements include NW Natural
and its direct and indirect wholly-owned subsidiaries
including:
• NW Natural Energy, LLC (NWN Energy);
• NW Natural Gas Storage, LLC (NWN Gas Storage);
• Gill Ranch Storage, LLC (Gill Ranch);
• NNG Financial Corporation (NNG Financial);
• Northwest Energy Corporation (Energy Corp);
• NW Natural Water Company, LLC (NWN Water); and
• NWN Gas Reserves LLC (NWN Gas Reserves).
We operate in two primary reportable business segments:
local gas distribution and gas storage. We also have other
investments and business activities not specifically related
to one of these two reporting segments, which we
aggregate and report as other. We refer to our local gas
distribution business as the utility, and our gas storage
segment and other as non-utility. Our utility segment
includes our NW Natural local gas distribution business,
NWN Gas Reserves, which is a wholly-owned subsidiary of
Energy Corp, and the utility portion of our Mist underground
storage facility in Oregon (Mist). Our gas storage segment
includes NWN Gas Storage, which is a wholly-owned
subsidiary of NWN Energy, Gill Ranch, which is a wholly-
owned subsidiary of NWN Gas Storage, the non-utility
portion of Mist, and asset management services. Other
includes NWN Energy's equity investment in Trail West
Holding, LLC (TWH), which is pursuing the development of
a proposed natural gas pipeline through its wholly-owned
subsidiary, Trail West Pipeline, LLC (TWP), NNG
Financial's investment in Kelso-Beaver Pipeline (KB
Pipeline), and NWN Water, which pursuing investments in
the water sector itself and through its wholly-owned
subsidiary FWC Merger Sub, Inc. For a further discussion
of our business segments and other, see Note 4.
NON-GAAP FINANCIAL MEASURES. In addition to presenting
the results of operations and earnings amounts in total,
certain financial measures are expressed in cents per share
or exclude the effects of certain items, which are non-GAAP
financial measures. We present net income or loss and
earnings or loss per share adjusted for certain items along
with the U.S. GAAP measures to illustrate their magnitude
on ongoing business and operational results. Although the
excluded amounts are properly included in the
determination of net income or loss and earnings or loss
per share under U.S. GAAP, we believe the amount and
nature these items make period to period comparisons of
operations difficult or potentially confusing. We use such
non-GAAP financial measures to analyze our financial
performance because we believe they provide useful
information to our investors and creditors in evaluating our
financial condition and results of operations. Our non-GAAP
financial measures should not be considered a substitute
for, or superior to, measures calculated in accordance with
U.S. GAAP. Reconciliations of the non-GAAP financial
measures to their closest U.S. GAAP measure used in
subsequent sections of Item 7 are provided below.
27
NON-GAAP RECONCILIATIONS
In millions, except per share data
Consolidated net income (loss)
Adjustments:
Regulatory environmental disallowance(1)
Impairment of long-lived assets(2)
Tax effects on TCJA(3)
Tax effects on non-GAAP adjustments
Adjusted consolidated net income
Utility net income (loss)
Adjustments:
Regulatory environmental disallowance(1)
Tax effects on TCJA(3)
Tax effects on non-GAAP adjustments
Adjusted utility net income
Gas storage net income (loss)
Adjustments:
Impairment of long-lived assets(2)
Tax effects on TCJA(3)
Tax effects on non-GAAP adjustments
Adjusted gas storage net income
Other net income (loss)
Adjustments:
Tax effects on TCJA(3)
2017
2016
2015
Amount
Per Share
Amount
Per Share
Amount
Per Share
$ (55.6)
$
(1.94)
$
58.9
$
2.12
$
53.7
$
1.96
$
$
—
192.5
(21.4)
(51.0)
64.5
60.5
—
1.0
—
$
61.5
$ (116.2)
192.5
(21.9)
(51.0)
3.4
0.1
$
$
$
$
$
$
$
$
—
6.71
(0.75)
(1.78)
2.24
2.11
—
0.03
—
2.14
(4.05)
6.71
(0.76)
(1.78)
$
$
$
$
3.3
—
—
(1.3)
60.9
54.6
3.3
—
(1.3)
56.6
4.3
—
—
—
$
$
$
$
0.12
—
—
(0.05)
2.19
1.96
0.12
—
(0.05)
2.03
0.16
—
—
—
$
$
$
$
0.12
$
4.3
$
0.16
$
0.2
— $
— $
— $
0.1
15.0
0.55
—
—
(5.9)
62.8
53.4
15.0
—
(5.9)
62.5
0.2
—
—
—
$
$
$
$
$
$
—
—
(0.22)
2.29
1.95
0.55
—
(0.22)
2.28
0.01
—
—
—
0.01
—
—
—
(0.6)
(0.02)
—
—
—
Adjusted other net income (loss)
$
(0.5)
$
(0.02)
$
— $
— $
0.1
$
(1) Regulatory environmental disallowance of $3.3 million in 2016 includes $2.8 million recorded in utility other income (expense), net and $0.5
million recorded in utility operations and maintenance expense. Regulatory environmental disallowance of $15.0 million in 2015 is recorded in
utility operations and maintenance expense. The tax effect of both years' adjustments are calculated using a combined federal and state
statutory rate of 39.5%. EPS amounts for the 2016 and 2015 adjustments are calculated using diluted shares of 27.8 million and 27.4 million,
respectively, as shown on our Consolidated Statements of Comprehensive Income (Loss).
(2) Non-cash impairment of long-lived assets at the Gill Ranch Facility of $192.5 million was recorded on December 31, 2017. The tax effect of
this adjustment is calculated using our new combined federal and state statutory tax rate of 26.5%. EPS amounts are calculated using diluted
shares of 28.7 million as shown on our Consolidated Statements of Comprehensive Income (Loss). See Part II, Item 7, "Application of Critical
Accounting Policies and Estimates—Impairment of Long-Lived Assets" for additional information on the impairment analysis.
(3) Non-cash Tax Cuts and Jobs Act (TCJA) benefit (expense) of $21.4 million was recorded in income tax expense (benefit) in the fourth quarter
of 2017 as a result of the federal tax rate changing from 35% to 21% effective December 22, 2017. EPS amounts are calculated using diluted
shares of 28.7 million as shown on our Consolidated Statements of Comprehensive Income (Loss), and the TCJA impacts in the segments
and other may not correlate exactly to the consolidated amount due to rounding. See Note 9 for additional information on TCJA.
28
EXECUTIVE SUMMARY
We manage our business and strategic initiatives with a
long-term view of providing natural gas service safely and
reliably to customers, working with regulators on key policy
initiatives, and remaining focused on growing our business.
See "2018 Outlook" below for more information. Highlights
for the year include:
•
added over 12,700 customers in 2017 for a growth rate
of 1.8% at December 31, 2017;
invested $214 million in our distribution system and
facilities for growth and reliability;
completed key components of the North Mist Gas
Storage Expansion Project with $107 million capital
•
•
Key financial highlights include:
In millions, except per share data
Consolidated net income (loss)
Adjusted consolidated net income(1)
Utility margin
•
•
•
•
expenditures incurred as of December 31, 2017, with
an additional $20 to $30 million expected in 2018;
ranked first in the West in the 2017 J.D. Powers' Gas
Utility Residential Customer Satisfaction Study and Gas
Utility Business Customer Satisfaction Study;
filed for a general rate increase in Oregon for first time
in six years;
delivered increasing dividends for the 62nd consecutive
year; and
announced our intent to expand into the regulated
water utility sector by entering into agreements to
acquire two small privately owned water utilities.
2017
2016
2015
Amount
Per Share
Amount
Per Share
Amount
Per Share
$ (55.6)
$
64.5
$ 392.6
$
$
(1.94)
2.24
$
$
58.9
60.9
$
$
2.12
2.19
$ 376.6
$
$
$
53.7
62.8
$
$
1.96
2.29
371.4
Gas storage operating revenues
(1) See the Non-GAAP Reconciliations table at the beginning of Item 7 for a reconciliation of this non-GAAP measure to its closest U.S.GAAP
23.6
25.3
21.4
$
$
$
measure.
2017 COMPARED TO 2016. Consolidated net loss was $55.6
million compared to consolidated net income of $58.9 million
in 2016, including $192.5 million pre-tax for the impairment
of long-lived assets at the Gill Ranch Facility and the $21.4
million benefit associated with TCJA in 2017, and the $3.3
million pre-tax regulatory environmental disallowance in
2016.
2016 COMPARED TO 2015. Overall, consolidated net income
increased $5.2 million. The increase was primarily due to
the $9.1 million after-tax charge from 2015 and a $2.0
million after-tax charge in 2016 related to the regulatory
disallowances associated with a February 2015 OPUC
Order and subsequent Order in our SRRM docket.
Excluding these items, adjusted consolidated net income
increased $3.6 million. See the Non-GAAP reconciliations at
the beginning of Item 7 for additional information. Adjusted
consolidated net income increased $3.6 million primarily due
to the following factors:
•
a $16.0 million increase in utility margin primarily due to
customer growth and effects of colder than average
weather in 2017 compared to warmer than average
weather in 2016; and
a $3.1 million increase in other income (expense), net
primarily due an increase of the equity portion of
AFUDC; partially offset by
a $15.7 million increase in operations and maintenance
expense driven by higher utility payroll and benefits
increases, as well as increased safety equipment
upgrade costs; and
a $1.6 million decrease in gas storage revenues driven
by lower revenues from our asset management
agreements for our Mist storage and transportation
capacity.
•
•
•
Excluding the impact of the non-cash charges from the
SRRM docket in 2015 and 2016, adjusted consolidated net
income decreased $1.9 million primarily due to the following
factors:
•
a $7.0 million increase in operations and maintenance
expense primarily due to cost savings initiatives that
were implemented in the second half of 2015 that did
not recur in 2016; and
a $5.5 million decrease in other income (expense), net
primarily related to the recognition of $5.3 million of
equity earnings on deferred regulatory asset balances
as a result of the 2015 OPUC Order; partially offset by
a $5.2 million increase in utility margin primarily due to
customer growth and gains from gas cost incentive
sharing; and
a $3.9 million increase in gas storage revenues largely
due to higher revenues from our asset management
agreements at both storage facilities and slightly higher
contract values at the Gill Ranch Facility for the
2016-17 gas year.
•
•
•
29
2018 OUTLOOK
Our 2018 goals leverage our resources and history of innovation to continue meeting the evolving needs of customers,
regulators, and shareholders. Our near-term outlook is centered on following six long-term strategic objectives:
Deliver Gas
Ensure Safe and Reliable Service
Provide a Superior Customer Experience
Advance Constructive Policies and Regulation
Grow Our Businesses
Enable Utility Growth
Lead in a Low-Carbon Future
Pursue Strategic Investments
SAFETY AND RELIABILITY. Delivering natural gas safely and
reliably to customers is our first priority. During 2018, we will
maintain our vigilant focus on safety and emergency
response through our hands-on scenario-based training for
our employees, third-party contractors, and local
authorities. To ensure reliability, resiliency, and safety of our
infrastructure, we intend to continue to invest in the
maintenance and necessary upgrades of our pipeline
system, including multi-year projects to replace end-of-life
equipment at our Mist storage facility and renovate several
resource centers. Safety also includes our vigilance in
maintaining strong cybersecurity defenses and preparing
for large-scale emergency events, such as seismic hazards
in our region.
SUPERIOR CUSTOMER EXPERIENCE. NW Natural has a
legacy of providing excellent customer service and a long-
standing dedication to continuous improvement, which have
resulted in consistently high rankings in the J.D. Power and
Associates customer satisfaction studies. In 2018, we will
continue to enhance our customers' experience to meet
their evolving expectations by prioritizing improvements to
technology which supports our customers' frequent
interactions and highest value touchpoints.
POLICIES AND REGULATION. We remain committed to
working constructively with policymakers and regulators to
provide the best outcomes for both our customers and
shareholders. We are working closely with the Oregon
commission and other stakeholders on several significant
dockets, including the best way to return TCJA benefits to
our customers and process our Oregon general rate case,
which we filed in December 2017. The rate case supports
the continued investment and maintenance of our system
for safety, reliability and resiliency. Additionally, we plan to
file an updated IRP in 2018 to support the long-term
investments needed for the growth and continued reliability
of our utility infrastructure. Finally, we will continue working
with the EPA and other stakeholders on an environmentally
protective and cost effective clean-up for the Portland
Harbor Superfund Site.
UTILITY GROWTH. Natural gas is the preferred energy
choice in our service territory given its efficient, affordable,
and clean-burning qualities. We are focused on leveraging
these key attributes to capitalize on our region's strong
economic growth. We continue to grow our market share in
the single-family residential sector and capture new
commercial customers. We have also focused on
expanding our share of mixed-use developments, a
growing segment of the multifamily housing market, through
equipment incentives, streamlined gas infrastructure
designs, promotional support, and a recently approved new
tariff. We will continue to pursue growth in all sectors in
2018.
LOW-CARBON PATHWAY. The Pacific Northwest and NW
Natural are deeply committed to a clean energy future. It's
why we launched our low-carbon initiative to further
emission savings for both the Company and our
communities by leveraging our modern pipeline systems in
new ways, working closely with customers, policymakers
and regulators, and embracing cutting-edge technology. We
have partnered with the City of Portland to bring renewable
natural gas (RNG) onto our system. We expect the entire
project to be operational in 2019. We will continue helping
our customers reduce and offset their consumption as we
support the development of renewable natural gas supply
and explore other cutting edge solutions to lower the
carbon intensity of our product, such as power to gas.
STRATEGIC INVESTMENTS. We remain focused on creating
value in all our businesses. We are investing in the
regulated utility expansion of our Mist gas storage facility,
which will provide innovative no-notice gas storage service
for a local electric company who will use the reliability of
natural gas to integrate more intermittent renewable energy
— like solar and wind — into the energy grid. In 2017, we
announced our intent to expand into the regulated water
utility sector and will continue pursuing this strategy in 2018
with a focus on water sector investments that fit our
conservative risk profile and core competencies. Our
pursuit of a holding company structure is important to this
growth strategy. With the OPUC and WUTC approvals for a
holding company reorganization received, we will be
focused on seeking shareholder approval for conversion to
a holding company structure at our 2018 annual
shareholders' meeting and executing on the conversions in
late 2018 or early 2019.
30
HOLDING COMPANY
Formation of a Holding Company
Holding company structures are well-established corporate
structures, and exist across all industries. In the utility
industry, holding companies have become the norm, and
are employed for the same purposes holding companies are
used in other industries. NW Natural intends to pursue
formation of a holding company to best position it to be able
to respond to opportunities and risks in a manner that
serves the best interests of its shareholders and customers.
We have received regulatory approval from the OPUC and
WUTC and expect regulatory approval from the CPUC to
reorganize into a holding company structure. Our Board of
Directors has determined to recommend a holding company
structure to our shareholders for vote at our 2018 Annual
Shareholders Meeting. If our shareholders approve, the
Board and Management must take additional actions to
implement the holding company structure, which we
currently expect to happen in the latter half of 2018 or at the
beginning of 2019. To implement a holding company
structure, NW Natural common stock would be converted or
exchanged into the same relative percentages of the holding
company that they own of NW Natural immediately prior to
the reorganization. The structure currently contemplated
involves placing a non-operating corporate entity over the
existing consolidated structure, and “ring-fencing” NW
Natural as described below to insulate the gas utility from
the operations of the holding company and its other direct
and indirect subsidiaries. NW Natural management
continuously looks for growth opportunities that would build
on core competencies and match the risk profile that NW
Natural and its shareholders seek. We believe a holding
company structure is a more agile and efficient platform
from which to pursue, finance and oversee new business
growth opportunities, such as in the water sector. Following
the formation of the holding company, NW Natural would
continue to operate as a gas utility subject to the jurisdiction
of the OPUC and the WUTC.
Holding Company Regulatory Restrictions and Conditions
The regulatory approvals for the formation of a holding
company require NW Natural and its holding company to
enter into and file an agreement with the OPUC and the
WUTC, which includes a number of “ring-fencing”
conditions. The ring-fencing provisions are designed to
operate the gas utility business conservatively and insulate
it from risks associated with other holding company
businesses. The ring-fencing and other provisions of the
approvals include the following:
• NW Natural may not pay dividends or make
distributions to the holding company if NW Natural’s
credit ratings and common equity levels fall below
specified ratings and levels. If NW Natural’s long-term
secured credit ratings are below A- for S&P and A3 for
Moody’s, dividends may be issued so long as NW
Natural’s common equity is 45% or above. If NW
Natural’s long-term secured credit ratings are below
BBB for S&P and Baa2 for Moody’s, dividends may be
issued so long as NW Natural’s common equity is 46%
or above. Dividends may not be issued if NW Natural’s
long-term secured credit ratings fall to BB+ or below for
S&P or Ba1 or below for Moody’s, or if NW Natural’s
common equity is below 44%. In each case, with the
common equity level to be determined on a preceding
31
or projected 13-month basis.
•
• Maintenance of separate credit ratings, long-term debt
ratings, and preferred stock ratings, if any, by NW
Natural and its holding company;
In the event NW Natural’s common equity, on a
preceding or projected basis, falls below 46%, NW
Natural is required to notify the OPUC, and if the level
of common equity falls below 44%, file a plan with the
OPUC to restore its equity to that level. Under the
WUTC order, the average equity component must not
exceed 56%;
• NW Natural must have one director who is independent
from NW Natural management and from the holding
company;
• NW Natural and its subsidiaries will not be permitted to
hold holding company investments, except under NW
Natural-sponsored employee benefit plans or employee
compensation plans;
•
•
• NW Natural must issue one share of preferred stock to
an independent party and require that NW Natural may
only file a voluntary petition for bankruptcy if approved
unanimously by the Board of Directors of NW Natural,
including the independent director, and by the holder of
the preferred share;
As is the case currently, NW Natural will be prohibited
from cross-subsidizing any business, including the
holding company and its unregulated subsidiaries;
The costs of the holding company reorganization must
be separately tracked and not charged or allocated to
NW Natural, and those costs and all other costs related
to future business endeavors of the holding company
must be excluded from NW Natural rate cases. NW
Natural and its holding company are required to
guarantee that NW Natural customers will not be
harmed by any increases in NW Natural costs that
result from the holding company reorganization,
including any higher costs of debt or equity, higher
revenue requirement, tax costs, or rate of return, due to
the reorganization; and
For three years, NW Natural will be required to provide
an annual $500,000 credit to Oregon customers and a
$55,000 credit to Washington customers. Cost-savings
over $50,000 that are allocable to NW Natural as a
result of holding company acquisition activity will be
deferred and credited to Oregon and Washington
customers until after NW Natural’s next general rate
case following the Company’s 2017 general rate case.
•
DIVIDENDS
Dividend highlights include:
Per common share
Dividends paid
2017
2016
2015
$ 1.8825
$ 1.8725
$ 1.8625
In January 2018, the Board of Directors declared a quarterly
dividend on our common stock of $0.4725 per share,
payable on February 15, 2018, to shareholders of record on
January 31, 2018, reflecting an indicated annual dividend
rate of $1.89 per share.
RESULTS OF OPERATIONS
Regulatory Matters
Regulation and Rates
UTILITY. Our utility business is subject to regulation by the
OPUC, WUTC, and FERC with respect to, among other
matters, rates and terms of service. The OPUC and WUTC
also regulate the system of accounts and issuance of
securities by our utility. In 2017, approximately 89% of our
utility gas customers were located in Oregon, with the
remaining 11% in Washington. Earnings and cash flows
from utility operations are largely determined by rates set in
general rate cases and other proceedings in Oregon and
Washington. They are also affected by the local economies
in Oregon and Washington, the pace of customer growth in
the residential, commercial, and industrial markets, and our
ability to remain price competitive, control expenses, and
obtain reasonable and timely regulatory recovery of our
utility-related costs, including operating expenses and
investment costs in utility plant and other regulatory assets.
See "Most Recent General Rate Cases" below.
GAS STORAGE. Our gas storage business is subject to
regulation by the OPUC, WUTC, CPUC, and FERC with
respect to, among other matters, rates and terms of service.
The OPUC and CPUC also regulate the issuance of
securities, system of accounts, and regulate intrastate
storage services. The FERC regulates interstate storage
services. The FERC uses a maximum cost of service model
which allows for gas storage prices to be set at or below the
cost of service as approved by each agency in their last
regulatory filing. The OPUC Schedule 80 rates are tied to
the FERC rates, and are updated whenever we modify our
FERC maximum rates. The CPUC regulates Gill Ranch
under a market-based rate model which allows for the price
of storage services to be set by the marketplace. In 2017,
approximately 70% of our storage revenues were derived
from FERC, Oregon, and Washington regulated operations
and approximately 30% from California operations.
Most Recent General Rate Cases
OREGON. Effective November 1, 2012, the OPUC
authorized rates to customers based on an ROE of 9.5%, an
overall rate of return of 7.78%, and a capital structure of
50% common equity and 50% long-term debt.
WASHINGTON. Effective January 1, 2009, the WUTC
authorized rates to customers based on an ROE of 10.1%
and an overall rate of return of 8.4% with a capital structure
of 51% common equity, 5% short-term debt, and 44% long-
term debt.
FERC. We are required under our Mist interstate storage
certificate authority and rate approval orders to file every
five years either a petition for rate approval or a cost and
revenue study to change or justify maintaining the existing
rates for our interstate storage services. In December 2013,
we filed a rate petition, which was approved in 2014, and
allows for the maximum cost-based rates for our interstate
gas storage services. These rates were effective January 1,
2014, with the rate changes having no significant impact on
our revenues. In January 2018, various state parties filed a
request with the FERC to adjust the revenue requirements
32
of public utilities to reflect the recent reduction in the federal
corporate income tax rate and other impacts resulting from
the TCJA. We will monitor this request and work the FERC
to evaluate the potential impact to these approved rates.
We continuously monitor the utility and evaluate the need
for a rate case. In December 2017, we filed a rate case in
Oregon with the OPUC. For additional information, see
"Regulatory Proceeding Updates—Rate Case" below.
Regulatory Proceeding Updates
During 2017, we were involved in the regulatory activities
discussed below.
HEDGING. In 2014, the OPUC opened a docket to discuss
broader gas hedging practices across gas utilities in
Oregon. In January 2018, the OPUC accepted the parties'
proposal to follow a uniform process to address any future
proposed long-term hedges and closed the docket.
The WUTC also conducted an investigation into the hedging
practices of gas utilities operating in Washington and
considered whether it should require gas utilities to
implement certain hedging practices. The WUTC issued and
outlined their policy in March 2017. The policy supports risk-
responsive hedging strategies that are adaptable to
variability in the market and required gas utilities to submit
with their 2017 PGA a preliminary hedging plan that outlines
the utilities' intended path to incorporate risk-responsive
hedging strategies. Beginning with the 2018 PGA, gas
utilities must submit an annual comprehensive hedging plan
that supports integration of risk responsive strategies into
their hedging framework. Beginning with the 2019 PGA
filing, utilities must provide a full strategy implementation
plan for year 2020 and beyond. As directed by the WUTC,
we submitted our preliminary hedging plan with our 2017
PGA in September 2017, and plan to submit our annual
comprehensive hedging plan with our 2018 PGA.
INTERSTATE STORAGE AND OPTIMIZATION SHARING. We
received an Order from the OPUC in March 2015 on their
review of the current revenue sharing arrangement that
allocates a portion of the net revenues generated from non-
utility Mist storage services and third-party asset
management services to utility customers. The Order
requires a third-party cost study to be performed and the
results of the cost study may initiate a new docket or the re-
opening of the original docket. In 2017, a third-party
consultant completed a cost study. We will continue to work
with all stakeholders as we review this completed study, and
expect resolution of this docket in 2018.
INTEGRATED RESOURCE PLAN (IRP). We file a full IRP with
Oregon and Washington bi-annually and file updates
between filings. Our last full IRPs were filed in 2016, and we
received a letter of compliance from the WUTC in December
of 2016 and acknowledgment by the OPUC in February of
2017. The IRP included analysis of different growth
scenarios and corresponding resource acquisition
strategies. The analysis is needed to develop supply and
demand resource requirements, consider uncertainties in
the planning process, and establish a plan for providing
reliable and low cost natural gas service. We anticipate filing
our next full IRP in 2018.
DEPRECIATION STUDY. Under OPUC regulations, the utility
is required to file a depreciation study every five years to
update or justify maintaining the existing depreciation rates.
In December 2016, we filed the required depreciation study
with the Commission. In September 2017, the parties to the
docket filed a settlement with the Commission requesting
approval of updated depreciation rates negotiated with the
parties. In January 2018, OPUC issued an order adopting
the stipulation. The depreciation rates included in the
stipulation do not materially change our current depreciation
rates.
HOLDING COMPANY APPLICATION. In February 2017, we
filed applications with the OPUC, WUTC, and CPUC for
approval to reorganize under a holding company structure.
In 2017, the OPUC and WUTC approved our applications
subject to certain restrictions or "ring-fencing" provisions
applicable to NW Natural, the entity that currently, and
would continue to, house our utility operations, and the
holding company. We continue to work with the CPUC, and
expect resolutions by the end of the first quarter of 2018.
MULTI-FAMILY TARIFF. In June 2017, we filed a request with
the OPUC to create a multi-family tariff to establish an
optional program to serve the mixed-use, multi-family
residential market. Under the tariff, NW Natural will provide
upfront incentives for builders to offset the initial cost of
installing natural gas piping to individual units, and then
recover the costs of the incentives through a fixed charge on
the customer's monthly bills. In July 2017, the OPUC
approved the tariff allowing us to further serve the multi-
family customer sector.
TAX REFORM DEFERRAL. In December 2017, we filed
applications with the OPUC and WUTC to defer the overall
net benefit associated with the TCJA that was enacted on
December 22, 2017 with a January 1, 2018 effective date.
We anticipate the impacts from the TCJA will accrue to our
customers in a manner approved by the Commissions. We
will continue to work with the OPUC and WUTC on this
throughout 2018. See Note 9 for more information on TCJA.
REGULATED WATER UTILITY. In December 2017, we entered
into agreements to acquire two privately-owned water
utilities: Salmon Valley Water Company, based in Welches,
Oregon, and Falls Water Company, based in Idaho Falls,
Idaho. These transactions are subject to certain conditions,
including approvals from the OPUC and the Idaho Public
Utilities Commission (IPUC), respectively. In January 2018,
we filed our application with the OPUC to acquire Salmon
Valley Water Company and filed with the IPUC in February
2018 to acquire Falls Water Company. We do not expect
these transactions or their continuing operations to have a
material financial impact. We continue to work with the
OPUC and IPUC and anticipate receiving approvals and
completing these acquisitions in 2018.
GENERAL RATE CASE. On December 29, 2017, we filed an
Oregon general rate case requesting a 6% revenue
increase, after an adjustment for the conservation tariff
deferral, to continue operating and maintaining our
distribution system and continue providing safe, reliable
service to our customers. Our December general rate case
filing was based on the following:
•
•
•
•
•
forward test year from November 1, 2018 through
October 31, 2019;
capital structure of 50% debt and 50% equity;
return on equity of 10.0%;
cost of capital of 7.62%; and
rate base of $1.19 billion, an increase of $304 million
since the last Oregon rate case in 2012.
The general rate case filing in December 2017 does not
include the benefit to customers’ rates of the newly passed
federal tax legislation. In the coming months, we will be
working with the OPUC to determine how to return these
benefits to customers, and we expect to amend or refile our
rate case to incorporate the benefit of the TCJA, which
would likely lower the original revenue requirement
requested. It is possible through this rate case proceeding
or another proceeding that the OPUC will also determine
how to treat historical deferred tax liabilities, which may
result in additional changes to our rate case request as well.
The general rate case review and approval process could
take up to 10 months with new rates anticipated to be
effective November 1, 2018.
Rate Mechanisms
During 2017, our approved rates and recovery mechanisms
for each service area included:
Authorized Rate Structure:
ROE
ROR
Oregon
Washington
9.5%
7.8%
10.1%
8.4%
Debt/Equity Ratio
50%/50%
49%/51%
Key Regulatory Mechanisms:
PGA
Gas Cost Incentive Sharing
Decoupling
WARM
Environmental Cost Deferral
SRRM
Pension Balancing
Interstate Storage Sharing
X
X
X
X
X
X
X
X
X
X
X
PURCHASED GAS ADJUSTMENT. Rate changes are
established for the utility each year under PGA mechanisms
in Oregon and Washington to reflect changes in the
expected cost of natural gas commodity purchases. This
includes gas costs under spot purchases as well as contract
supplies, gas costs hedged with financial derivatives, gas
costs from the withdrawal of storage inventories, the
production of gas reserves, interstate pipeline demand
costs, temporary rate adjustments, which amortize balances
of deferred regulatory accounts, and the removal of
temporary rate adjustments effective for the previous year.
In September 2017, we filed our PGA and received OPUC
and WUTC approval in October 2017. PGA rate changes
were effective November 1, 2017. The rate changes
decreased the average monthly bills of residential
customers by approximately 6.4% and 3.1% in Oregon and
Washington, respectively. The decrease in Oregon reflected
33
customers' portion of adjustments mainly for the effect of
changes in wholesale natural gas costs and for a portion of
WARM amounts that exceeded the maximum monthly
allowable amount to be returned to customers during the
2016-17 gas year. Oregon rates were offset by adjustments
related to our energy efficiency programs and additional
annual adjustments based on ongoing orders with the
OPUC. Washington rates reflected the effect of changes in
wholesale natural gas costs.
Each year, we typically hedge gas prices on a portion of our
utility's annual sales requirement based on normal weather,
including both physical and financial hedges. We entered
the 2017-18 gas year with our forecasted sales volumes
hedged at 49% in financial swap and option contracts and
26% in physical gas supplies. For additional hedging
matters from the WUTC and OPUC, see "Regulatory
Proceeding Updates—Hedging" above.
As of December 31, 2017, we have also hedged future gas
years with approximately 24% for the 2018-19 gas year and
between 4% and 11% over the subsequent five gas years
for utility's annual sales requirements based on normal
weather. Our hedge levels are subject to change based on
actual load volumes, which depend, to a certain extent, on
weather, economic conditions, and estimated gas reserve
production. Also, our gas storage inventory levels may
increase or decrease with storage expansion, changes in
storage contracts with third parties, variations in the heat
content of the gas, and/or storage recall by the utility.
Under the current PGA mechanism in Oregon, there is an
incentive sharing provision whereby we are required to
select each year an 80% deferral or a 90% deferral of higher
or lower actual gas costs compared to estimated PGA
prices, such that the impact on current earnings from the
incentive sharing is either 20% or 10% of the difference
between actual and estimated gas costs, respectively. For
the 2016-17 and 2017-18 gas years, we selected the 90%
deferral option. Under the Washington PGA mechanism, we
defer 100% of the higher or lower actual gas costs, and
those gas cost differences are passed on to customers
through the annual PGA rate adjustment.
EARNINGS TEST REVIEW. We are subject to an annual
earnings review in Oregon to determine if the utility is
earning above its authorized ROE threshold. If utility
earnings exceed a specific ROE level, then 33% of the
amount above that level is required to be deferred or
refunded to customers. Under this provision, if we select the
80% deferral gas cost option, then we retain all of our
earnings up to 150 basis points above the currently
authorized ROE. If we select the 90% deferral option, then
we retain all of our earnings up to 100 basis points above
the currently authorized ROE. For the 2015-16 gas year, we
selected the 80% deferral option. For the 2016-17 and
2017-18 gas years, we selected the 90% deferral option.
The ROE threshold is subject to adjustment annually based
on movements in long-term interest rates. For calendar
years 2015, 2016, and 2017, the ROE threshold was
10.60%, 11.06%, and 10.66%, respectively. There were no
refunds required for 2015 and 2016. We do not expect a
refund for 2017 based on our results and anticipate filing the
2017 earnings test in May 2018.
34
GAS RESERVES. In 2011, the OPUC approved the Encana
gas reserves transaction to provide long-term gas price
protection for our utility customers and determined our costs
under the agreement would be recovered on an ongoing
basis through our annual PGA mechanism. Gas produced
from our interests is sold at then prevailing market prices,
and revenues from such sales, net of associated operating
and production costs and amortization, are included in our
cost of gas. The cost of gas, including a carrying cost for the
rate base investment made under the original agreement, is
included in our annual Oregon PGA filing, which allows us to
recover these costs through customer rates. Our net
investment under the original agreement earns a rate of
return.
In 2014, we amended the original gas reserves agreement
in response to Encana's sale of its interest in the Jonah field
located in Wyoming to Jonah Energy. Under our amended
agreement with Jonah Energy, we have the option to invest
in additional wells on a well-by-well basis with drilling costs
and resulting gas volumes shared at our amended
proportionate working interest for each well in which we
invest. Volumes produced from the additional wells drilled
after our amended agreement are included in our Oregon
PGA at a fixed rate of $0.4725. We did not have the
opportunity to participate in additional wells in 2015, 2016,
or 2017.
DECOUPLING. In Oregon, we have a decoupling
mechanism. Decoupling is intended to break the link
between utility earnings and the quantity of gas consumed
by customers, removing any financial incentive by the utility
to discourage customers’ efforts to conserve energy.
The Oregon decoupling mechanism was reauthorized and
the baseline expected usage per customer was set in the
2012 Oregon general rate case. This mechanism employs a
use-per-customer decoupling calculation, which adjusts
margin revenues to account for the difference between
actual and expected customer volumes. The margin
adjustment resulting from differences between actual and
expected volumes under the decoupling component is
recorded to a deferral account, which is included in the
annual PGA filing. In Washington, customer use is not
covered by such a tariff.
WARM. In Oregon, we have an approved weather
normalization mechanism, which is applied to residential
and commercial customer bills. This mechanism is designed
to help stabilize the collection of fixed costs by adjusting
residential and commercial customer billings based on
temperature variances from average weather, with rate
decreases when the weather is colder than average and
rate increases when the weather is warmer than average.
The mechanism is applied to bills from December through
May of each heating season. The mechanism adjusts the
margin component of customers’ rates to reflect average
weather, which uses the 25-year average temperature for
each day of the billing period. Daily average temperatures
and 25-year average temperatures are based on a set point
temperature of 59 degrees Fahrenheit for residential
customers and 58 degrees Fahrenheit for commercial
customers. The collections of any unbilled WARM amounts
due to tariff caps and floors are deferred and earn a carrying
charge until collected in the PGA the following year. This
weather normalization mechanism was reauthorized in the
2012 Oregon general rate case without an expiration date.
Residential and commercial customers in Oregon are
allowed to opt out of the weather normalization mechanism,
and as of December 31, 2017, 9% of total customers had
opted out. We do not have a weather normalization
mechanism approved for residential and commercial
Washington customers, which account for about 11% of total
customers. See "Business Segments—Local Gas
Distribution Utility Operations" below.
INDUSTRIAL TARIFFS. The OPUC and WUTC have
approved tariffs covering utility service to our major
industrial customers, which are intended to give us certainty
in the level of gas supplies we need to acquire to serve this
customer group. The approved terms include, among other
things, an annual election period, special pricing provisions
for out-of-cycle changes, and a requirement that industrial
customers complete the term of their service election under
our annual PGA tariff.
ENVIRONMENTAL COST DEFERRAL AND SRRM. We have a
SRRM through which we track and have the ability to
recover past deferred and future prudently incurred
environmental remediation costs allocable to Oregon,
subject to an earnings test.
Under the SRRM collection process, there are three types of
deferred environmental remediation expense:
•
Pre-review - This class of costs represents remediation
spend that has not yet been deemed prudent by the
OPUC. Carrying costs on these remediation expenses
are recorded at our authorized cost of capital. We
anticipate the prudence review for annual costs and
approval of the earnings test prescribed by the OPUC
to occur by the third quarter of the following year.
Post-review - This class of costs represents
remediation spend that has been deemed prudent and
allowed after applying the earnings test, but is not yet
included in amortization. We earn a carrying cost on
these amounts at a rate equal to the five-year treasury
rate plus 100 basis points.
Amortization - This class of costs represents amounts
included in current customer rates for collection and is
generally calculated as one-fifth of the post-review
deferred balance. We earn a carrying cost equal to the
amortization rate determined annually by the OPUC,
which approximates a short-term borrowing rate. We
included $7.4 million and $10.0 million of deferred
remediation expense approved by the OPUC for
collection during the 2017-18 and 2016-17 PGA years,
respectively.
•
•
In addition, the SRRM also provides for the annual
collection of $5.0 million from Oregon customers through a
tariff rider. As we collect amounts from customers, we
recognize these collections as revenue and separately
amortize an equal and offsetting amount of our deferred
regulatory asset balance through the environmental
remediation operating expense line shown separately in the
operating expense section of our Consolidated Statement of
Comprehensive Income (Loss). See Note 15 for more
information on our environmental matters.
The SRRM earnings test is an annual review of our adjusted
utility ROE compared to our authorized utility ROE, which is
35
currently 9.5%. To apply the earnings test first we must
determine what if any costs are subject to the test through
the following calculation:
Annual spend
Less: $5.0 million base rate rider(1)
Prior year carry-over(2)
$5.0 million insurance + interest on insurance
Total deferred annual spend subject to earnings test
Less: over-earnings adjustment, if any
Add: deferred interest on annual spend(3)
Total amount transferred to post-review
(1) Base rate rider went into Oregon customer rates beginning
November 1, 2015.
(2) Prior year carry-over results when the prior year amount
transferred to post-review is negative. The negative amount is
carried over to offset annual spend in the following year.
(3) Deferred interest is added to annual spend to the extent the
spend is recoverable.
To the extent the utility earns at or below its authorized
ROE, the total amount transferred to post-review is
recoverable through the SRRM. To the extent the utility
earns more than its authorized ROE in a year, the amount
transferred to post-review would be reduced by those
earnings that exceed its authorized ROE.
For 2017, we have performed this test, which we anticipate
submitting to the OPUC in May 2018, and we do not expect
an earnings test adjustment for 2017.
The WUTC has also previously authorized the deferral of
environmental costs, if any, that are appropriately allocated
to Washington customers. This Order was effective in
January 2011 with cost recovery and carrying charges on
amount deferred for costs associated with services provided
to Washington customers to be determined in a future
proceeding. Annually, or more often if circumstances
warrant, we review all regulatory assets for recoverability. If
we should determine all or a portion of these regulatory
assets no longer meet the criteria for continued application
of regulatory accounting, then we would be required to
write-off the net unrecoverable balances against earnings in
the period such a determination was made.
PENSION COST DEFERRAL AND PENSION BALANCING
ACCOUNT. The OPUC permits us to defer annual pension
expenses above the amount set in rates, with recovery of
these deferred amounts through the implementation of a
balancing account, which includes the expectation of higher
and lower pension expenses in future years. Our recovery of
these deferred balances includes accrued interest on the
account balance at the utility’s authorized rate of return.
Future years’ deferrals will depend on changes in plan
assets and projected benefit liabilities based on a number
of key assumptions and our pension contributions. Pension
expense deferrals, excluding interest, were $6.5 million,
$6.3 million, and $8.2 million in 2017, 2016 and 2015,
respectively.
INTERSTATE STORAGE AND OPTIMIZATION SHARING. On an
annual basis, we credit amounts to Oregon and Washington
customers as part of our regulatory incentive sharing
mechanism related to net revenues earned from Mist gas
storage and asset management activities. Generally,
amounts are credited to Oregon customers in June, while
credits are given to customers in Washington through
reductions in rates through the annual PGA filing in
November.
Excluding these items, adjusted utility net income increased
$5.0 million, or $0.11 per share. The primary factors
contributing to this increase in adjusted utility net income
were as follows:
•
a $16.0 million increase in utility margin primarily due
to:
The following table presents the credits to customers:
In millions
Oregon utility
customer credit
Washington utility
customer credit
2017
2016
2015
$
11.7
$
9.4
$
1.0
1.0
9.6
0.8
Business Segments - Local Gas Distribution Utility
Operations
Utility margin results are primarily affected by customer
growth, revenues from rate-base additions, and, to a certain
extent, by changes in delivered volumes due to weather and
customers’ gas usage patterns because a significant portion
of our utility margin is derived from natural gas sales to
residential and commercial customers. In Oregon, we have
a conservation tariff (also called the decoupling
mechanism), which adjusts utility margin up or down each
month through a deferred regulatory accounting adjustment
designed to offset changes resulting from increases or
decreases in average use by residential and commercial
customers. We also have a weather normalization tariff in
Oregon, WARM, which adjusts customer bills up or down to
offset changes in utility margin resulting from above- or
below-average temperatures during the winter heating
season. Both mechanisms are designed to reduce, but not
eliminate, the volatility of customer bills and our utility’s
earnings. See "Regulatory Matters—Rate Mechanisms"
above.
Utility segment highlights include:
Dollars and therms in
millions, except EPS data
2017
2016
2015
Utility net income
$
60.5
$
54.6
$
53.4
Adjusted utility net
income(1)
EPS - utility segment
Adjusted EPS - utility
segment(1)
61.5
2.11
2.14
56.6
1.96
2.03
62.5
1.95
2.28
Gas sold and delivered
(in therms)
Utility margin(2)
371.4
(1) See the Non-GAAP Reconciliations table at the beginning of Item
7 for a reconciliation of this non-GAAP measure to its closest
U.S.GAAP measure.
1,240
376.6
392.6
1,085
1,029
$
$
$
(2) See Utility Margin Table below for a reconciliation and additional
detail.
2017 COMPARED TO 2016. Utility net income was $60.5
million in 2017 compared to $54.6 million in 2016, which
includes the $1.0 million loss associated with the TCJA in
2017 and the after-tax $2.0 million regulatory environmental
disallowance in 2016. See the Non-GAAP reconciliations at
the beginning of Item 7 for additional information.
36
a $6.8 million increase from customer growth;
partially offset by
a $2.7 million decrease in gains in gas cost
incentive sharing due to actual gas prices being
lower than those estimated in the 2016-17 PGA,
but not by the same magnitude as in the prior
period.
a portion of the remaining increase was due to the
effects of colder than average weather in 2017
compared to warmer than average weather in
2016.
•
•
•
a $3.1 million increase in other income (expense), net,
primarily due to an increase in the equity portion of
AFUDC in 2017; partially offset by
a $9.5 million increase in operations and maintenance
expense driven largely from payroll and benefits due to
increased headcount, general salary increases, and
increased safety equipment update costs; and
a $3.4 million increase in depreciation expense
primarily due to additional capital expenditures.
Total utility volumes sold and delivered in 2017 increased
14% over 2016 primarily due to the impact of weather that
was 28% colder than the prior period and 7% colder than
average.
2016 COMPARED TO 2015. The primary factors contributing
to the $1.2 million, or $0.01 per share, increase in utility net
income were as follows:
•
a $5.2 million increase in utility margin primarily due to:
a $5.7 million increase from customer growth;
a $0.8 million increase from gains in gas cost
incentive sharing resulting from lower gas prices
than those estimated in the PGA; partially offset by
a $1.3 million decrease due to lower contributions
from our gas reserve investments, which
decreased due to amortization.
•
•
•
an $8.3 million decrease in operations and
maintenance expense primarily due to the
environmental disallowance recognized in 2015, offset
in part by increases in payroll costs due to additional
headcount and general pay increases along with
increased non-payroll costs for professional services
and contract work; partially offset by
an $8.7 million, decrease in other income (expense),
net, primarily due to the environmental interest
disallowance recognized in 2016 and the recognition of
$5.3 million of equity earnings on deferred regulatory
asset balances in 2015; and
a $1.9 million, increase in depreciation expense
primarily due to additional capital expenditures.
Total utility volumes sold and delivered in 2016 increased
5% over 2015 primarily due to comparatively colder weather
in the first quarter during our peak heating season and
colder weather in December 2016.
UTILITY MARGIN TABLE. The following table summarizes the composition of utility gas volumes, revenues, and cost of sales:
In thousands, except degree day and customer data
2017
2016
2015
Utility volumes (therms):
Residential and commercial sales
Industrial sales and transportation
740,369
499,924
609,222
475,774
570,728
457,884
Total utility volumes sold and delivered
1,240,293
1,084,996
1,028,612
Favorable/(Unfavorable)
2017 vs.
2016
2016 vs.
2015
131,147
24,150
155,297
38,494
17,890
56,384
Utility operating revenues:
Residential and commercial sales
Industrial sales and transportation
Other revenues
Less: Revenue taxes
Total utility operating revenues
Less: Cost of gas
Less: Environmental remediation expense
Utility margin
Utility margin:(1)
Residential and commercial sales
Industrial sales and transportation
Miscellaneous revenues
Gain from gas cost incentive sharing
Other margin adjustments
Utility margin
Degree days
Average(2)
Actual
Percent colder (warmer) than average weather(2)
Customers - end of period:
Residential customers
Commercial customers
Industrial customers
$ 684,214
$ 604,390
$ 644,835
$
79,824
$ (40,445)
63,925
3,872
19,069
732,942
325,019
15,291
59,386
3,812
17,111
650,477
260,588
13,298
71,495
3,914
18,034
702,210
327,305
3,513
$ 392,632
$ 376,591
$ 371,392
$ 355,736
$ 338,060
$ 334,134
31,847
30,989
30,081
3,865
1,237
(53)
3,796
3,960
(214)
3,913
3,182
82
4,539
60
1,958
82,465
(12,109)
(102)
(923)
(51,733)
(64,431)
66,717
$
$
$
$
(1,993)
16,041
17,676
858
69
(2,723)
161
(9,785)
5,199
3,926
908
(117)
778
(296)
$ 392,632
$ 376,591
$ 371,392
$
16,041
$
5,199
4,240
4,553
4,256
3,551
4,240
3,458
(16)
28%
16
3%
7%
(17)%
(18)%
668,803
656,855
646,841
11,948
10,014
68,050
1,021
67,278
1,013
66,584
1,003
772
8
694
10
Total number of customers
737,874
725,146
714,428
12,728
10,718
Customer growth:
Residential customers
Commercial customers
Industrial customers
Total customer growth
1.8%
1.1%
0.8%
1.8%
1.5 %
1.0 %
1.0 %
1.5 %
(1) Amounts reported as margin for each category of customers are operating revenues, which are net of revenue taxes, less cost of gas and
environmental remediation expense.
(2) Average weather represents the 25-year average of heating degree days, as determined in our 2012 Oregon general rate case.
37
Residential and Commercial Sales
The primary factors that impact results of operations in the
residential and commercial markets are customer growth,
seasonal weather patterns, energy prices, competition from
other energy sources, and economic conditions in our
service areas. The impact of weather on margin is
significantly reduced through our weather normalization
mechanism in Oregon; approximately 80% of our total
customers are covered under this mechanism. The
remaining customers either opt out of the mechanism or are
located in Washington, which does not have a similar
mechanism in place. For more information on our weather
mechanism, see "Regulatory Matters—Rate Mechanisms—
Weather Normalization Mechanism" above.
Residential and commercial sales highlights include:
In millions
Volumes (therms):
Residential sales
Commercial sales
Total volumes
Operating revenues:
2017
2016
2015
465.2
275.2
740.4
379.2
230.0
609.2
350.9
219.8
570.7
Residential sales
$
455.9
$
404.3
$
424.6
•
partially offset by a 7% increase in sales volumes; and
utility margin increased $4.0 million, due to both
residential and commercial customer growth offset by
lower contributions from our gas reserve investments,
which decreased due to amortization.
Industrial Sales and Transportation
Industrial customers have the option of purchasing sales or
transportation services from the utility. Under the sales
service, the customer buys the gas commodity from the
utility. Under the transportation service, the customer buys
the gas commodity directly from a third-party gas marketer
or supplier. Our gas commodity cost is primarily a pass-
through cost to customers; therefore, our profit margins are
not materially affected by an industrial customer's decision
to purchase gas from us or from third parties. Industrial and
large commercial customers may also select between firm
and interruptible service options, with firm services generally
providing higher profit margins compared to interruptible
services. To help manage gas supplies, our industrial tariffs
are designed to provide some certainty regarding industrial
customers' volumes by requiring an annual service election
which becomes effective November 1, special charges for
changes between elections, and in some cases, a minimum
or maximum volume requirement before changing options.
228.3
200.1
220.2
Industrial sales and transportation highlights include:
$
684.2
$
604.4
$
644.8
In millions
2017
2016
2015
Commercial sales
Total operating
revenues
Utility margin:
Residential:
Sales
Weather normalization
Decoupling
Total residential utility
margin
Commercial:
Sales
Weather normalization
Decoupling
Total commercial utility
margin
$
262.1
$
223.2
$
211.6
(11.9)
(2.4)
12.7
0.8
14.0
7.2
247.8
236.7
232.8
101.5
(4.6)
11.1
87.2
5.0
9.2
84.8
5.8
10.7
108.0
101.4
101.3
Total utility margin
$
355.8
$
338.1
$
334.1
2017 COMPARED TO 2016. The primary factors contributing
to changes in the residential and commercial markets were
increases of $79.8 million in operating revenue and $17.7
million in utility margin as a result of sales volume increases
of 131.2 million therms, or 22%, due to customer growth and
the effects of colder than average weather in 2017
compared to warmer than average weather in the prior
period.
2016 COMPARED TO 2015. The primary factors contributing
to changes in the residential and commercial markets were
as follows:
•
sales volumes increased 38.5 million therms, or 7%,
due to customer growth and comparatively colder
weather in the first quarter and December of 2016
compared to record warm weather in 2015;
operating revenues decreased $40.4 million, due to a
24% decrease in average cost of gas over last year,
•
Volumes (therms):
Industrial - firm sales
35.7
33.8
32.4
Industrial - firm
transportation
Industrial - interruptible
sales
Industrial - interruptible
transportation
Total volumes
Utility margin:
Industrial - sales and
transportation
167.7
156.9
144.0
55.1
50.4
57.3
241.4
499.9
234.7
475.8
224.2
457.9
$
31.8
$
31.0
$
30.1
2017 COMPARED TO 2016. Sales and transportation volumes
increased by 24.1 million therms and utility margin
increased $0.8 million due to higher usage from colder than
average weather in 2017 compared to warmer than average
weather in 2016, and increased usage from higher
production load.
2016 COMPARED TO 2015. Sales and transportation volumes
increased by 17.9 million therms and utility margin
increased $0.9 million due to annual customer service
election changes, higher fee revenue due to system
restrictions from cold weather in December 2016, and an
increase in usage from a few large customers.
Other Revenues
Other revenues include miscellaneous fee income as well
as regulatory revenue adjustments, which reflect current
period deferrals to and prior year amortizations from
regulatory asset and liability accounts, except for gas cost
deferrals which flow through cost of gas. Decoupling and
other regulatory amortizations from prior year deferrals are
included in revenues from residential, commercial, and
38
industrial firm customers.
Other revenue for 2017, 2016, and 2015 remained flat year-
over-year as expected.
In millions
2017
2016
2015
Other revenues
$
3.9
$
3.8
$
3.9
Cost of Gas
Cost of gas as reported by the utility includes gas
purchases, gas withdrawn from storage inventory, gains and
losses from commodity hedges, pipeline demand costs,
seasonal demand cost balancing adjustments, regulatory
gas cost deferrals, gas reserves costs, and company gas
use. The OPUC and WUTC generally require natural gas
commodity costs to be billed to customers at the actual cost
incurred, or expected to be incurred, by the utility. Customer
rates are set each year so that if cost estimates were met
we would not earn a profit or incur a loss on gas commodity
purchases; however, in Oregon we have an incentive
sharing mechanism which has been described under
"Regulatory Matters—Rate Mechanisms—Purchased Gas
Adjustment" above. In addition to the PGA incentive sharing
mechanism, gains and losses from hedge contracts entered
into after annual PGA rates are effective for Oregon
customers are also required to be shared and therefore may
impact net income. Further, we also have a regulatory
agreement whereby we earn a rate of return on our
investment in the gas reserves acquired under the original
agreement with Encana and include gas from our amended
gas reserves agreement at a fixed rate of $0.4725 per
therm, which are also reflected in utility margin. See
"Application of Critical Accounting Policies and Estimates—
Accounting for Derivative Instruments and Hedging
Activities" below.
Cost of gas highlights include:
Dollars and therms in
millions
2017
2016
2015
Cost of gas
$
325.0
$
260.6
$
327.3
Volumes sold (therms)
831
693
660
Average cost of gas
(cents per therm)
Gain from gas cost
incentive sharing
$
0.39
$
0.38
$
0.50
1.2
4.0
3.2
2017 COMPARED TO 2016. Cost of gas increased $64.4
million, or 25%, primarily due to the 20% increase in
volumes sold due to colder than average weather in 2017
compared to warmer than average weather in 2016, and
customer growth.
2016 COMPARED TO 2015. Cost of gas decreased $66.7
million, or 20%, reflecting lower natural gas prices and
resulting in a $19.4 million credit to customers, partially
offset by a 5% increase in volume mainly from
comparatively colder weather in the first quarter and
December 2016.
The effect on net income from our gas cost incentive
sharing mechanism resulted in a margin gain of $1.2 million,
$4.0 million and $3.2 million for 2017, 2016 and 2015,
respectively, as actual prices were lower than the estimated
prices included in customer rates due to national warmer
than average weather, which resulted in lower national
natural gas commodity prices. For a discussion of our gas
cost incentive sharing mechanism, see “Regulatory Matters
—Rate Mechanisms—Purchased Gas Adjustment” above.
Business Segments - Gas Storage
Our gas storage segment primarily consists of the non-utility
portion of our Mist underground storage facility in Oregon
and our 75% undivided ownership interest in the Gill Ranch
Facility, an underground storage facility in California. We
also contract with an independent energy marketing
company to provide asset management services using our
utility and non-utility storage and transportation capacity, the
results of which are included in the gas storage business
segment. For additional information, see also Note 4.
At Mist, we provide gas storage services to customers in the
interstate and intrastate markets using storage capacity that
has been developed in advance of core utility customers’
requirements. Pre-tax income from gas storage at Mist and
asset management services is subject to revenue sharing
with core utility customers. Under this regulatory incentive
sharing mechanism, we retain 80% of pre-tax income from
Mist gas storage services and asset management services
when the underlying costs of the capacity being used are
not included in our utility rates, and 33% of pre-tax income
from such storage and asset management services when
the capacity being used is included in utility rates. The
remaining 20% and 67%, respectively, are credited to a
deferred regulatory account for credit to our core utility
customers. See "Regulatory Matters—Regulatory
Proceeding Updates" above for information regarding an
open docket related to this incentive sharing mechanism.
Our 75% undivided ownership interest in the Gill Ranch
Facility is held by our wholly-owned subsidiary Gill Ranch,
LLC, which is also the operator of the facility. Our portion of
the facility is approximately 15 Bcf of designed gas storage
capacity.
Gas storage segment highlights include:
In millions, except EPS data
2017
2016
2015
Operating revenues
Operating expenses
Gas storage net income (loss)
Adjusted gas storage net income(1)
208.7
(116.2)
3.4
16.1
4.3
4.3
$
23.6
$
25.3
$
21.4
EPS - gas storage segment
(4.05)
0.16
16.3
0.2
0.2
0.01
Adjusted EPS - gas storage
segment(1)
(1) See the Non-GAAP Reconciliations table at the beginning of Item
7 for a reconciliation of this non-GAAP measure to its closest
U.S.GAAP measure.
0.01
0.16
0.12
2017 COMPARED TO 2016. Our gas storage segment net loss
was $116.2 million, or $4.05 per share, compared to net
income of $4.3 million, or $0.16 per share, which includes
the non-cash after-tax impairment of long-lived assets at the
Gill Ranch Facility of $141.5 million in the fourth quarter of
2017 and a $21.9 million benefit associated with the TCJA in
2017. In the fourth quarter, we completed a comprehensive
strategic review and evaluation process of the Gill Ranch
Facility that evaluated various alternatives, including a
39
standards, an increase in use of alternative fuels to meet
carbon emissions reduction targets, recovery of the
California economy, growth of domestic industrial
manufacturing, potential exports of liquefied natural gas
from the west coast and other favorable storage market
conditions in and around California. We have not seen the
rebound in storage prices that we originally anticipated. For
the last few years, we have worked diligently to operate the
facility efficiently and have been pursuing various strategic
alternatives to increase revenues. These efforts included
working to identify higher-value customers in and/or near
the northern California market that Gill Ranch serves as well
as exploring the possibility of providing energy storage
services such as compressed gas energy storage (CGES).
In the fourth quarter of 2017, we completed our
comprehensive strategic review process, which included a
sale process for the Gill Ranch Facility, and made a
determination that the Gill Ranch Facility is no longer core to
our long-term plans.
Additionally, in late 2015, a significant natural gas leak
occurred at an unaffiliated southern California gas storage
facility. In response to the incident, both state and federal
additional regulations were developed. The California
Department of Oil, Gas and Geothermal Resources
(DOGGR) developed and proposed new regulations for gas
storage wells that focus on implementing additional well
integrity requirements. DOGGR released a new formulation
of these rules on February 12, 2018. Although these rules
are subject to a comment period and possible revision,
these rules establish a timeframe for completion of
compliance of seven years, a period much shorter than the
15 or more years we previously anticipated. In addition,
PHMSA proposed new federal regulations for underground
natural gas storage facilities that focus on implementing
additional pipeline safety requirements of downhole
facilities, including operations, maintenance and emergency
response activities regarding wells, wellbore tubing, and
casing.
While both sets of regulations are still under development,
and their ultimate impact is unknown, it is likely that the final
PHMSA and DOGGR regulations will likely result in higher
costs for all storage providers.
We will continue to evaluate all strategic options for the
facility to maximize the value of this asset, and in the
meantime, we are committed to operating the facility to the
highest safety standards.
Other
Other primarily consists of our non-utility appliance retail
center operations, NNG Financial's investment in KB
Pipeline, an equity investment in TWH, which has invested
in the Trail West pipeline project, and other miscellaneous
non-utility investments and business activities. See Note 4
and Note 12 for further details on other activities and our
investment in TWH.
potential sale of the asset and we substantially completed
contracting for the 2018-19 gas year at lower than
anticipated pricing. These events triggered a requirement
that management re-evaluate the carrying value of the Gill
Ranch Facility. That analysis resulted in the non-cash
impairment.
Excluding these items, adjusted gas storage net income
decreased $0.9 million, or $0.04 per share, primarily due to
a decrease in gas storage revenues largely due to lower
asset management revenues from our Mist facility and
transportation capacity. See the Non-GAAP reconciliations
at the beginning of Item 7 for additional information.
2016 COMPARED TO 2015. Our gas storage segment net
income increased $4.1 million, or $0.15 per share, primarily
due to the following factors:
•
a $3.9 million increase in operating revenue primarily
from higher asset management revenues from our Mist
facility and transportation capacity, and slightly higher
firm contract prices at the Gill Ranch Facility for the
2016-17 gas year; and
a $2.8 million decrease in interest expense from the
early retirement of $20 million of Gill Ranch debt in
December 2015.
•
We have completed contracting for the 2017-18 gas year for
our Mist facility, which remains under long-term contracts at
similar prices to prior periods. Our Mist facility benefits from
limited competition from other Pacific Northwest storage
facilities primarily because of its geographic location.
The gas storage market dynamics at the Gill Ranch Facility
differ from our Mist facility. Over the past few years, market
prices for natural gas storage, particularly in California, were
negatively affected by the abundant supply of natural gas,
low volatility of natural gas prices, and surplus gas storage
capacity.
In 2007, NW Natural's subsidiary Gill Ranch Storage, LLC
jointly with Pacific Gas and Electric (PG&E) made an
investment decision to build the Gill Ranch Facility, a gas
storage facility in California. At that time, our market analysis
projected that natural gas storage would be critical in
achieving California's renewable portfolio standards and
supporting the region's drive to a lower carbon energy
landscape. Construction was completed and operations
began at the Gill Ranch Facility in 2010 under multi-year
storage agreements with terms that ended as the full market
implications from the shale gas revolution were transforming
the natural gas industry. The additional shale gas eliminated
the resource constraints that were expected to exist over the
long term and resulted in lower gas prices, decreased
seasonal price spreads and volatility, and consequently,
reduced the value of gas storage to customers. As a result,
over the last few years, we have contracted the Gill Ranch
Facility under short-term agreements to allow us to take
advantage of any rebound in storage prices or other
strategies that would increase revenues.
We have believed and continue to believe that we may see
storage price improvement or an increase in the demand for
natural gas storage in California in the future driven by a
number of factors, including changes in the electric
generation triggered by California’s renewable portfolio
40
Consolidated Operations
Operations and Maintenance
Operations and maintenance highlights include:
In millions
2017
2016
2015
Operations and maintenance
$ 165.2
$ 150.0
$ 157.5
2017 COMPARED TO 2016. Operations and maintenance
expense increased $15.3 million, primarily due to the
following factors:
•
a $6.4 million increase in utility payroll and benefits due
to increased headcount and general salary increases;
and
a $1.0 million increase in safety equipment upgrade
costs.
•
2016 COMPARED TO 2015. Operations and maintenance
expense decreased $7.5 million, primarily due to the
following factors:
•
the $15.0 million pre-tax charge for the regulatory
disallowance associated with the February 2015 OPUC
Order on the recovery of past environmental cost
deferrals recorded in 2015. We also expensed an
additional $1.0 million related to the 2015 Order;
partially offset by
a $6.5 million increase in non-payroll costs, which
returned to a more sustainable level in 2016 after
temporary cost savings initiatives in the prior year. Non-
payroll increases were primarily related to higher
professional service and contract work costs due to
general customer service cost increases from system
integrity work, and other maintenance; and
a $1.2 million increase in payroll and benefits due to
increased headcount and general pay increases.
•
•
Depreciation and Amortization
Depreciation and amortization highlights include:
In millions
2017
2016
2015
Depreciation and amortization
$
85.6
$
82.3
$
80.9
2017 COMPARED TO 2016. Depreciation and amortization
expense increased by $3.3 million due to utility plant
additions that included investments in our natural gas
transmission and distribution system, facility upgrades, and
enhanced technology.
2016 COMPARED TO 2015. Depreciation and amortization
expense increased by $1.4 million due to utility plant
additions that included investments in our natural gas
transmission and distribution system, storage facilities, and
technology.
Other Income (Expense), Net
Other income (expense), net highlights include:
In millions
2017
2016
2015
Equity portion of AFUDC
$
2.7
$
— $
Gains from company-
owned life insurance
Interest income
Loss from equity
investments
Net interest income
(expense) on deferred
regulatory accounts
Other non-operating
Total other income
(expense), net
2.5
0.2
1.7
0.1
—
2.2
0.1
(0.1)
(0.1)
(0.1)
2.0
(2.0)
(0.1)
(2.1)
8.2
(2.7)
$
5.3
$
(0.5) $
7.7
Delinquent customer receivable balances continue to
remain at historically low levels. The utility's bad debt
expense as a percent of revenues was 0.1% for 2017, 2016,
and 2015.
In addition to fluctuations in operations and maintenance
expense reported above, we have OPUC approval to defer
certain utility pension costs in excess of what is currently
recovered in customer rates. This pension cost deferral is
recorded to a regulatory balancing account, which stabilizes
the amount of operations and maintenance expense each
year. Pension cost deferrals, excluding interest, were $6.5
million, $6.3 million, and $8.2 million for the years ended
December 31, 2017, 2016 and 2015, respectively. As a
result, increased pension costs had a minimal effect on
operations and maintenance expense in 2017, 2016, and
2015, with the increase principally related to the costs
allocated to our Washington operations, which are not
covered by the pension balancing account. For further
explanation of the pension balancing account, see Note 8
and “Regulatory Matters—Rate Mechanisms—Pension Cost
Deferral and Prepaid Pension Assets,” above.
2017 COMPARED TO 2016. Other income (expense), net,
increased $5.9 million primarily due to the January 2016
Order from the OPUC, which resulted in a pre-tax $2.8
million interest disallowance in 2016, an increase of $2.7
million in the equity portion of AFUDC, and $0.8 million of
gains from company-owned life insurance.
2016 COMPARED TO 2015. Other income (expense), net,
increased $8.3 million primarily due to the recognition of
$5.3 million of the equity component in interest income from
our deferred environmental expenses in the prior year,
which did not recur in 2016. We recognized the equity
earnings of these deferred regulatory asset balances as a
result of the OPUC SRRM Order we received in February
2015. In addition, a January 2016 Order from the OPUC
resulted in a write-off of $2.8 million of interest during 2016.
Interest Expense, Net
Interest expense, net highlights include:
In millions
2017
2016
2015
Interest expense, net
$
38.5
$
39.1
$
42.5
2017 COMPARED TO 2016. Interest expense, net decreased
$0.6 million primarily due to a $2.1 million increase in the
interest-related portion of AFUDC, partially offset by
increased interest expense of $1.5 million due to the
41
issuance of long-term debt in December 2016 and August
2017.
Our consolidated capital structure was as follows:
2016 COMPARED TO 2015. Interest expense, net of amounts
capitalized, decreased $3.4 million primarily due to the
redemption of $40 million of utility First Mortgage Bonds
(FMBs) in June 2015 and the early retirement of $20 million
of Gill Ranch's debt in December 2015, which included a
make whole interest provision.
Income Tax Expense
Income tax expense highlights include:
In millions
2017
2016
2015
Income tax (benefit) expense
$ (30.8)
$ 40.7
$ 35.8
Effects of non-GAAP
adjustments(1)
Effects from the TCJA(1)
51.0
21.4
1.3
—
5.9
—
Adjusted income tax expense
$ 41.6
$ 42.0
$ 41.7
Effective tax rate
35.6%
40.9%
40.0%
Adjusted effective tax rate
39.2%
40.8%
39.9%
(1) See the Non-GAAP Reconciliations table at the beginning of Item
7 for a reconciliation of this non-GAAP measure to its closest
U.S.GAAP measure.
2017 COMPARED TO 2016. Our effective tax rate decreased
by 5.3%. Excluding the tax benefits associated with the
impairment of long-lived assets at the Gill Ranch Facility
and the TCJA enactment in 2017 of $51.0 million and $21.4
million, respectively, and the $1.3 million tax effects of non-
GAAP adjustments in 2016, our adjusted effective tax rate
decreased 1.6%. See the Non-GAAP reconciliations at the
beginning of Item 7 for additional information. The adjusted
effective tax rate decreased primarily as a result of AFUDC
equity income and increased stock-based compensation
deductions in 2017.
2016 COMPARED TO 2015. The increase in the effective
income tax rate is due to lower benefits of depletion
deductions from our gas reserves activity.
FINANCIAL CONDITION
Capital Structure
One of our long-term goals is to maintain a strong
consolidated capital structure with a long-term target utility
capital structure of 50% common stock and 50% long-term
debt. When additional capital is required, debt or equity
securities are issued depending on both the target capital
structure and market conditions. These sources of capital
are also used to fund long-term debt retirements and short-
term commercial paper maturities. See "Liquidity and
Capital Resources" below and Note 7.
Achieving the target capital structure and maintaining
sufficient liquidity to meet operating requirements are
necessary to maintain attractive credit ratings and provide
access to capital markets at reasonable costs.
Common stock equity
Long-term debt
Short-term debt, including current
maturities of long-term debt
Total
December 31,
2017
2016
47.1%
43.3
52.4%
41.9
9.6
5.7
100.0%
100.0%
During 2017, changes to our capital structure were primarily
due to issuances of long-term debt instruments and the
impairment of long-lived assets at the Gill Ranch Facility.
The net proceeds from the debt issuances will be used for
general corporate purposes, primarily to fund our ongoing
utility construction programs. See further discussion below
in "Cash Flows — Financing Activities".
Liquidity and Capital Resources
At both December 31, 2017 and December 31, 2016, we
had approximately $3.5 million of cash and cash
equivalents. In order to maintain sufficient liquidity during
periods when capital markets are volatile, we may elect to
maintain higher cash balances and add short-term
borrowing capacity. In addition, we may also pre-fund utility
capital expenditures when long-term fixed rate environments
are attractive. As a regulated entity, our issuance of equity
securities and most forms of debt securities are subject to
approval by the OPUC and WUTC. Our use of retained
earnings is not subject to those same restrictions.
Utility Segment
For the utility segment, the short-term borrowing
requirements typically peak during colder winter months
when the utility borrows money to cover the lag between
natural gas purchases and bill collections from customers.
Our short-term liquidity for the utility is primarily provided by
cash balances, internal cash flow from operations, proceeds
from the sale of commercial paper notes, as well as
available cash from multi-year credit facilities, short-term
credit facilities, company-owned life insurance policies, the
sale of long-term debt, and issuances of equity. Utility long-
term debt and equity issuance proceeds are primarily used
to finance utility capital expenditures, refinance maturing
debt of the utility, and provide temporary funding for other
general corporate purposes of the utility.
Based on our current debt ratings (see "Credit Ratings"
below), we have been able to issue commercial paper and
long-term debt at attractive rates and have not needed to
borrow or issue letters of credit from our back-up credit
facility. In the event we are not able to issue new debt due to
adverse market conditions or other reasons, we expect our
near-term liquidity needs can be met using internal cash
flows or, for the utility segment, drawing upon our committed
credit facility. We also have a universal shelf registration
statement filed with the SEC for the issuance of secured
and unsecured debt or equity securities, subject to market
conditions and certain regulatory approvals. As of December
31, 2017, we have Board authorization to issue up to $75
million of additional FMBs. We also have OPUC approval to
issue up to $75 million of additional long-term debt for
approved purposes.
42
Our issuance of FMBs, which includes our medium-term
notes, under our mortgage and deed of trust is limited by
eligible properties, satisfaction of an adjusted net earnings
test, and other provisions of the mortgage. The non-cash
impairment of long-lived assets at the Gill Ranch Facility is
expected to result in our inability to satisfy the earnings test
throughout most of 2018. However, we are permitted to
issue FMBs without meeting the earnings test on the basis
of the $97.0 million of FMBs which will mature in 2018, an
amount that is sufficient to accommodate our expected
issuances of FMBs in 2018. There is no similar restriction on
our ability to issue unsecured long-term debt.
In the event our senior unsecured long-term debt ratings are
downgraded, or our outstanding derivative position exceeds
a certain credit threshold, our counterparties under
derivative contracts could require us to post cash, a letter of
credit, or other forms of collateral, which could expose us to
additional cash requirements and may trigger increases in
short-term borrowings while we were in a net loss position.
We were not required to post collateral at December 31,
2017. However, if the credit risk-related contingent features
underlying these contracts were triggered on December 31,
2017, assuming our long-term debt ratings dropped to non-
investment grade levels, we could have been required to
post $15.4 million in collateral with our counterparties. See
"Credit Ratings" below and Note 13.
Other items that may have a significant impact on our
liquidity and capital resources include pension contribution
requirements and environmental expenditures.
PENSION CONTRIBUTION. We expect to make significant
contributions to our company-sponsored defined benefit
plan, which is closed to new employees, over the next
several years until we are fully funded under the Pension
Protection Act rules, including the new rules issued under
the Moving Ahead for Progress in the 21st Century Act
(MAP-21) and the Highway and Transportation Funding Act
of 2014 (HATFA). See "Application of Critical Accounting
Policies—Accounting for Pensions and Postretirement
Benefits" below.
BONUS DEPRECIATION. Regarding income tax, 50 percent
bonus depreciation was available for a large portion of our
capital expenditures in 2015, 2016 and most of 2017 for
both federal and Oregon. This reduced taxable income and
provided cash flow benefits. However, due to the enactment
of TCJA on December 22, 2017, bonus depreciation is
eliminated for property acquired after September 27, 2017.
Accordingly, we do not anticipate similar cash flow benefits
related to bonus depreciation in the future.
ENVIRONMENTAL EXPENDITURES. Concerning
environmental expenditures, we expect to continue using
cash resources to fund our environmental liabilities. In 2015,
we received an Order from the OPUC regarding our SRRM
and began recovering amounts through utility rates in
November 2015. In addition, the OPUC issued a
subsequent Order regarding SRRM implementation in
January 2016. See Note 15, and "Results of Operations—
Regulatory Matters—Environmental Costs" above.
GAS STORAGE. Short-term liquidity for the gas storage
segment is supported by cash balances, internal cash flow
43
from operations, equity contributions from its parent
company, and, if necessary, additional external financing.
The amount and timing of the Gill Ranch Facility's cash
flows from year to year are uncertain, as the majority of
current storage contracts are short-term. In the fourth
quarter of 2017, we recognized a non-cash pretax
impairment of long-lived assets at the Gill Ranch Facility of
$192.5 million, which is included in our gas storage
segment. As a result of the impairment considerations,
estimated cash flows from the Gill Ranch Facility were re-
evaluated, and although determined no longer sufficient to
cover the carrying value of the assets, we do not anticipate
material changes in our ability to access sources of cash for
short-term liquidity.
CONSOLIDATED LIQUIDITY. Based on several factors,
including our current credit ratings, our commercial paper
program, current cash reserves, committed credit facilities,
and our expected ability to issue long-term debt in the
capital markets, we believe our liquidity is sufficient to meet
anticipated near-term cash requirements, including all
contractual obligations, investing, and financing activities as
discussed in Contractual Obligations and Cash Flows below.
DIVIDEND POLICY. We have paid quarterly dividends on our
common stock each year since stock was first issued to the
public in 1951. Annual common stock dividend payments
per share, adjusted for stock splits, have increased each
year since 1956. The declarations and amount of future
dividends will depend upon our earnings, cash flows,
financial condition and other factors. The amount and timing
of dividends payable on our common stock is at the sole
discretion of our Board of Directors.
OFF-BALANCE SHEET ARRANGEMENTS. Except for certain
lease and purchase commitments, we have no material off-
balance sheet financing arrangements. See "Contractual
Obligations" below.
In October 2017, we entered into a 20-year operating lease
agreement for our new headquarters location in Portland,
Oregon. Our existing headquarters lease expires in 2020
and after an extensive search and evaluation process with a
focus on seismic preparedness, safety, reliability, least cost
to our customers and a continued commitment to our
employees and the communities we serve, we executed a
new lease for suitable commercial office space in Portland,
Oregon. Payments under the lease are expected to
commence in 2020 and total estimated base rent payments
over the life of the lease are approximately $160 million. We
have the option to extend the term of the lease for two
additional seven-year periods.
Additionally, the lease was analyzed in consideration of
build-to-suit lease accounting guidance, and we concluded
that we are the accounting owner of the asset during
construction. As a result, we recognized $0.5 million in
Property, plant and equipment and an obligation in Other
non-current liabilities for the same amount on our
consolidated balance sheet at December 31, 2017. In 2018,
we expect to recognize an additional $27.0 million
associated with the build-to-suit accounting treatment of this
lease. These accounting transactions are non-cash in
nature, and as such, are not included in our cash flow
analysis and capital expenditures forecasts below, and have
no impact on our short-term liquidity. In 2019, pursuant to
the new lease standard issued by the FASB, we expect to
de-recognize the associated build-to-suit asset and liability
as we will not be subject to build-to-suit accounting under
the new lease standard.
Contractual Obligations
The following table shows our contractual obligations at December 31, 2017 by maturity and type of obligation:
Payments Due in Years Ending December 31,
In millions
2018
2019
2020
2021
2022
Thereafter
Total
Short-term debt maturities
$
54.2
$
— $
— $
— $
— $
— $
Long-term debt maturities
Interest on long-term debt
Postretirement benefit payments(1)
Operating leases
Gas purchases(2)
Gas pipeline capacity commitments
Other purchase commitments(3)
Other long-term liabilities(4)
97.0
36.4
25.1
5.4
63.9
83.5
12.9
17.3
30.0
34.7
26.0
5.4
2.7
82.1
0.9
—
75.0
28.9
27.0
6.9
2.7
77.0
0.6
—
60.0
27.8
28.0
7.5
2.3
65.6
0.1
—
—
26.1
28.6
7.6
—
60.1
—
—
524.7
249.9
161.0
169.4
—
601.8
—
—
54.2
786.7
403.8
295.7
202.2
71.6
970.1
14.5
17.3
Total
$
395.7
$
181.8
$
218.1
$
191.3
$
122.4
$
1,706.8
$
2,816.1
(1) Postretirement benefit payments primarily consists of two items: (1) estimated pension and other postretirement plan payments, which are
funded by plan assets and future cash contributions, and (2) required payments to the Western States multiemployer pension plan due to
our withdrawal from the plan in December 2013. See Note 8.
(2) Gas purchases include contracts which use price formulas tied to monthly index prices. The commitment amounts presented incorporate
the December 2017 first of month index price for each supply basin from which gas is purchased. For a summary of gas purchase and gas
pipeline capacity commitments, see Note 14.
(3) Other purchase commitments primarily consist of base gas requirements and remaining balances under existing purchase orders.
(4) Other long-term liabilities includes accrued vacation liabilities for management employees and deferred compensation plan liabilities for
executives and directors. The timing of these payments are uncertain; however, these payments are unlikely to all occur in the next 12
months.
In addition to known contractual obligations listed in the
above table, we have also recognized liabilities for future
environmental remediation or action. The exact timing of
payments beyond 12 months with respect to those liabilities
cannot be reasonably estimated due to numerous
uncertainties surrounding the course of environmental
remediation and the preliminary nature of site investigations.
See Note 15 for a further discussion of environmental
remediation cost liabilities.
finance gas purchases and accounts receivable, short-term
debt may also be used to temporarily fund utility capital
requirements. Commercial paper and bank loans are
periodically refinanced through the sale of long-term debt or
equity securities. When we have outstanding commercial
paper, which is sold through two commercial banks under
an issuing and paying agency agreement, it is supported by
one or more unsecured revolving credit facilities. See
“Credit Agreements” below.
At December 31, 2017, 629 of our utility employees were
members of the Office and Professional Employees
International Union (OPEIU) Local No. 11. In May 2014, our
union employees ratified a new labor agreement (Joint
Accord) that expires on November 30, 2019, and thereafter
from year to year unless either party serves notice of its
intent to negotiate modifications to the collective bargaining
agreement. The remaining terms of Joint Accord include the
following items: a scheduled 3% wage increase effective
December 1 each year with the potential for up to an
additional 3% per year based on wage inflation at or above
4%. The Joint Accord also maintains competitive health
benefits, including a 15% to 20% premium cost sharing by
employees, a 401(k) contribution of 4% for employees hired
after our pension plan was closed on December 31, 2009,
and a 401(k) match of 50% of the first 6% of savings, and
other flexibility provisions benefiting the Company.
At December 31, 2017 and 2016, our utility had short-term
debt outstanding of $54.2 million and $53.3 million,
respectively. The effective interest rate on short-term debt
outstanding at December 31, 2017 and 2016 was 1.9% and
0.8%, respectively.
Credit Agreements
We have a $300 million credit agreement, with a feature that
allows us to request increases in the total commitment
amount, up to a maximum of $450 million. The maturity date
of the agreement is December 20, 2019.
All lenders under the agreement are major financial
institutions with committed balances and investment grade
credit ratings as of December 31, 2017 as follows:
In millions
Lender rating, by category
Loan Commitment
Short-Term Debt
Our primary source of utility short-term liquidity is from the
sale of commercial paper and bank loans. In addition to
issuing commercial paper or bank loans to meet working
capital requirements, including seasonal requirements to
AA/Aa
A/A1
Total
44
$
$
201,000
99,000
300,000
Based on credit market conditions, it is possible one or more
lending commitments could be unavailable to us if the
lender defaulted due to lack of funds or insolvency;
however, we do not believe this risk to be imminent due to
the lenders' strong investment-grade credit ratings.
Our credit agreement permits the issuance of letters of
credit in an aggregate amount of up to $100 million. The
principal amount of borrowings under the credit agreement
is due and payable on the maturity date. There were no
outstanding balances under this credit agreement at
December 31, 2017 or 2016. The credit agreement requires
us to maintain a consolidated indebtedness to total
capitalization ratio of 70% or less. Failure to comply with this
covenant would entitle the lenders to terminate their lending
commitments and accelerate the maturity of all amounts
outstanding. We were in compliance with this covenant at
December 31, 2017 and 2016, with consolidated
indebtedness to total capitalization ratios of 52.9% and
47.6%, respectively.
The agreement also requires us to maintain credit ratings
with Standard & Poor's (S&P) and Moody's Investors
Service, Inc. (Moody’s) and notify the lenders of any change
in our senior unsecured debt ratings or senior secured debt
ratings, as applicable, by such rating agencies. A change in
our debt ratings by S&P or Moody’s is not an event of
default, nor is the maintenance of a specific minimum level
of debt rating a condition of drawing upon the credit
agreement. Rather, interest rates on any loans outstanding
under the credit agreements are tied to debt ratings and
therefore, a change in the debt rating would increase or
decrease the cost of any loans under the credit agreements
when ratings are changed. See "Credit Ratings" below.
Credit Ratings
Our credit ratings are a factor of our liquidity, potentially
affecting our access to the capital markets including the
commercial paper market. Our credit ratings also have an
impact on the cost of funds and the need to post collateral
under derivative contracts. The following table summarizes
our current debt ratings:
Commercial paper (short-term debt)
Senior secured (long-term debt)
Senior unsecured (long-term debt)
Corporate credit rating
Ratings outlook
S&P
Moody's
A-1
AA-
n/a
A+
P-2
A1
A3
n/a
Stable
Negative
•
•
•
In January 2018, Moody's revised our ratings outlook from
"stable" to "negative". This revision was a result of their view
of the potential negative impact that TCJA could have on our
regulated utility cash flow metrics. We expect the elimination
of bonus depreciation on regulated utilities will increase
cash taxes in the near term. However, we expect to see a
net increase in cash flows as a result of TCJA over the
longer term as taxes are a pass through to customers and
lower deferred tax liabilities and no bonus depreciation are
expected to increase regulatory returns.
The above credit ratings and ratings outlook are dependent
upon a number of factors, both qualitative and quantitative,
and are subject to change at any time. The disclosure of or
reference to these credit ratings is not a recommendation to
buy, sell or hold NW Natural securities. Each rating should
be evaluated independently of any other rating.
Long-Term Debt
The following debentures were retired:
In millions
Utility First Mortgage Bonds
Years Ended December 31,
2017
2016
2015
4.70% Series B due 2015
$
— $
— $
5.15% Series B due 2016
7.00% Series B due 2017
Subsidiary Debt
Fixed-rate
Cash Flows
—
40
40
$
25
—
25
$
— $
— $
40
$
25
$
$
$
$
40
—
—
40
20
60
Operating Activities
Changes in our operating cash flows are primarily affected
by net income or loss, changes in working capital
requirements, and other cash and non-cash adjustments to
operating results.
Operating activity highlights include:
In millions
2017
2016
2015
Cash provided by operating
activities
$ 206.7
$ 222.1
$ 184.7
2017 COMPARED TO 2016. The significant factors
contributing to the $15.4 million decrease in cash flows
provided by operating activities were as follows:
•
a decrease of $21.9 million due to $14.8 million income
taxes paid in 2017 compared to a refund of $7.2 million
in 2016 as a result of the enactment of bonus
depreciation in December 2015;
a decrease of $5.0 million due to an increase in
contributions paid to qualified defined benefit pension
plans; and
a net decrease of $11.4 million from changes in working
capital related to receivables, inventories, and accounts
payable reflecting colder than average weather in 2017
compared to the prior period; partially offset by
an increase of $27.3 million in cash flow benefits from
changes in deferred gas cost balances primarily due to
the $19.4 million gas cost savings credited to
customers in 2016 that did not occur in 2017.
2016 COMPARED TO 2015. The significant factors
contributing to the $37.5 million increase in operating cash
flows provided by operating activities were as follows:
•
a net increase of $29.4 million from changes in working
capital related to cold weather in December 2016 and
its impact on receivables, inventories, and accounts
payable; and
an increase of $27.6 million in tax related accounts
primarily due to a federal tax refund and an increase in
accrued taxes and net deferred tax liabilities primarily
•
45
•
•
•
due to the enactment of bonus depreciation;
an increase of $17.7 million from increased cash
collections from our decoupling mechanism;
an increase of $9.8 million from collections under the
SRRM; partially offset by
a decrease of $42.1 million from changes in deferred
gas cost balances due to lower natural gas prices than
those embedded in the PGA, which also resulted in a
$19.4 million early credit to customers’ bills in June
2016.
During the year ended December 31, 2017, we contributed
$19.4 million to our utility's qualified defined benefit pension
plan, compared to $14.5 million for 2016 and $14.1 million
for 2015. The amount and timing of future contributions will
depend on market interest rates and investment returns on
the plans’ assets. See Note 8.
Bonus depreciation of 50% has been available for federal
and Oregon purposes in 2015, 2016 and most of 2017. This
reduced taxable income and provided cash flow benefits.
Bonus depreciation for 2015 was not enacted until
December 18, 2015, and was extended retroactively back to
January 1, 2015 of the respective year. As a result,
estimated income tax payments were made throughout
2015 without the benefit of bonus depreciation for the year.
This delayed the cash flow benefit of bonus depreciation
until refunds could be requested and received. We received
refunds of federal income tax overpayments of $7.9 million
and $2.0 million in during 2016 and 2015, respectively. As a
result of TCJA, bonus depreciation was eliminated for
property acquired after September 27, 2017. Accordingly,
we do not anticipate similar cash flow benefits related to
bonus depreciation in the future.
We have lease and purchase commitments relating to our
operating activities that are financed with cash flows from
operations. For information on cash flow requirements
related to leases and other purchase commitments, see
“Financial Condition—Contractual Obligations” above and
Note 14.
Investing Activities
Investing activity highlights include:
In millions
2017
2016
2015
Total cash used in investing
activities
$ (214.2) $ (136.6) $ (115.3)
Capital expenditures
(213.6)
(139.5)
(118.3)
2017 COMPARED TO 2016. The $77.6 million increase in cash
used in investing activities was primarily due to higher
capital expenditures primarily related to our North Mist Gas
Storage Expansion Project as well as customer growth,
system reinforcement, technology, and facilities.
2016 COMPARED TO 2015. The $21.3 million increase in cash
used in investing activities was primarily due to higher utility
capital expenditures related to improvements at our Newport
LNG facility in Oregon, additional infrastructure investments
in Clark County, Washington, and capital expenditures for
our North Mist gas storage expansion project.
For the five-year period 2018 to 2022, capital expenditures
are estimated to be between $750 and $850 million. This
includes investments ranging from $650 to $700 million for
core utility capital expenditures that will support continued
customer growth, distribution system maintenance and
improvements, technology investments, and utility gas
storage facility maintenance. In addition, the five-year period
range includes $20 to $30 million of additional investments
to complete the North Mist gas storage expansion in 2018,
and investments of $60 to $70 million related to planned
upgrades and refurbishments to utility storage facilities and
resource centers. Most of the required funds for these
investments are expected to be internally generated over
the five-year period, with short-term and long-term debt and
equity providing liquidity.
Included in the five year period, 2018 utility capital
expenditures are estimated to be between $190 and $220
million, including $20 to $30 million to complete the
construction of our North Mist gas storage facility expansion.
We expect to invest less than $5 million in non-utility capital
expenditures for gas storage and other activities during
2018. Additional spend for gas storage and other
investments during and after 2018 are expected to be paid
from working capital and additional equity contributions from
NW Natural as needed.
Financing Activities
Financing activity highlights include:
In millions
2017
2016
2015
Total cash provided by (used
in) financing activities
$
Change in short-term debt
Change in long-term debt
Change in common stock
issued, net
7.4
0.9
60.0
$
(86.2) $
(74.7)
(216.7)
125.0
35.3
(60.0)
—
52.8
—
2017 COMPARED TO 2016. The $93.6 million increase in cash
provided by financing activities was primarily due to $217.6
million lower repayments of short-term debt compared to the
prior period, partially offset by $65.0 million lower net
proceeds from long-term debt activity in 2017 and $52.8
million of common stock proceeds in 2016.
2016 COMPARED TO 2015. The $11.5 million increase in cash
used in financing activities was primarily due to higher
repayments of short term loans and commercial paper of
$252 million, partially offset by proceeds from $150 million
of long-term debt issued in December 2016 and $53 million
of common stock issued in November 2016, along with a
$35 million decrease in repayments of long-term debt as
compared to 2015.
Pension Cost and Funding Status of Qualified
Retirement Plans
Pension costs are determined in accordance with
accounting standards for compensation and retirement
benefits. See “Application of Critical Accounting Policies and
Estimates – Accounting for Pensions and Postretirement
Benefits” below. Pension expense for our qualified defined
benefit plan, which is allocated between operations and
maintenance expenses, capital expenditures, and the
deferred regulatory balancing account, totaled $18.1 million
in 2017, an increase of $0.8 million from 2016. The fair
46
market value of pension assets in this plan increased to
$287.9 million at December 31, 2017 from $257.7 million at
December 31, 2016. The increase was due to a return on
plan assets of $40.3 million and $19.4 million in employer
contributions, offset by benefit payments of $29.5 million.
• derivative instruments and hedging activities;
• pensions and postretirement benefits;
• income taxes;
• environmental contingencies; and
• impairment of long-lived assets.
We make contributions to the company-sponsored qualified
defined benefit pension plan based on actuarial
assumptions and estimates, tax regulations, and funding
requirements under federal law. Our qualified defined
benefit pension plan was underfunded by $161.7 million at
December 31, 2017. We plan to make contributions during
2018 of $15.5 million. See Note 8 for further pension
disclosures.
Ratios of Earnings to Fixed Charges
For the year ended December 31, 2017, our earnings were
insufficient to cover our fixed charges by $86.4 million as a
result of the non-cash impairment of long-lived assets at the
Gill Ranch Facility. For the years ended December 31, 2016
and 2015, our ratios of earnings to fixed charges, computed
using the method outlined by the SEC, were 3.39 and 3.00,
respectively. For this purpose, earnings consist of net
income before income taxes plus fixed charges, and fixed
charges consist of interest on all indebtedness, the
amortization of debt expense and discount or premium, and
the estimated interest portion of rentals charged to income
or loss. See Exhibit 12 for the detailed ratio calculation.
Contingent Liabilities
Loss contingencies are recorded as liabilities when it is
probable that a liability has been incurred and the amount of
the loss is reasonably estimable in accordance with
accounting standards for contingencies. See “Application of
Critical Accounting Policies and Estimates” below. At
December 31, 2017, our total estimated liability related to
environmental sites is $127.4 million. See Note 15 and
"Results of Operations—Regulatory Matters—Rate
Mechanisms—Environmental Costs" above.
New Accounting Pronouncements
For a description of recent accounting pronouncements that
may have an impact on our financial condition, results of
operations, or cash flows, see Note 2.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
AND ESTIMATES
In preparing our financial statements in accordance with
GAAP, management exercises judgment in the selection
and application of accounting principles, including making
estimates and assumptions that affect reported amounts of
assets, liabilities, revenues, expenses, and related
disclosures in the financial statements. Management
considers our critical accounting policies to be those which
are most important to the representation of our financial
condition and results of operations and which require
management’s most difficult and subjective or complex
judgments, including accounting estimates that could result
in materially different amounts if we reported under different
conditions or used different assumptions. Our most critical
estimates and judgments include accounting for:
• regulatory accounting;
• revenue recognition;
47
Management has discussed its current estimates and
judgments used in the application of critical accounting
policies with the Audit Committee of the Board. Within the
context of our critical accounting policies and estimates,
management is not aware of any reasonably likely events or
circumstances that would result in materially different
amounts being reported. For a description of recent
accounting pronouncements that could have an impact on
our financial condition, results of operations, or cash flows,
see Note 2.
Regulatory Accounting
Our utility is regulated by the OPUC and WUTC, which
establish the rates and rules governing utility services
provided to customers, and, to a certain extent, set forth
special accounting treatment for certain regulatory
transactions. In general, we use the same accounting
principles as non-regulated companies reporting under
GAAP. However, authoritative guidance for regulated
operations (regulatory accounting) requires different
accounting treatment for regulated companies to show the
effects of such regulation. For example, we account for the
cost of gas using a PGA deferral and cost recovery
mechanism, which is submitted for approval annually to the
OPUC and WUTC. See "Results of Operations—Regulatory
Matters—Rate Mechanisms—Purchased Gas Adjustment"
above. There are other expenses and revenues that the
OPUC or WUTC may require us to defer for recovery or
refund in future periods. Regulatory accounting requires us
to account for these types of deferred expenses (or deferred
revenues) as regulatory assets (or regulatory liabilities) on
the balance sheet. When we are allowed to recover these
regulatory assets from, or refund regulatory liabilities to,
customers, we recognize the expense or revenue on the
income statement at the same time we realize the
adjustment to amounts included in utility rates charged to
customers.
The conditions we must satisfy to adopt the accounting policies
and practices of regulatory accounting include:
an independent regulator sets rates;
•
the regulator sets the rates to cover specific costs of
•
delivering service; and
the service territory lacks competitive pressures to reduce
rates below the rates set by the regulator.
•
Because our utility satisfies all three conditions, we continue
to apply regulatory accounting to our utility operations.
Future accounting changes, regulatory changes, or changes
in the competitive environment could require us to
discontinue the application of regulatory accounting for
some or all of our regulated businesses. This would require
the write-off of those regulatory assets and liabilities that
would no longer be probable of recovery from or refund to
customers.
Based on current accounting and regulatory competitive
conditions, we believe it is reasonable to expect continued
application of regulatory accounting for our utility activities.
Further, it is reasonable to expect the recovery or refund of
our regulatory assets and liabilities at December 31, 2017
through future customer rates. If we should determine all or
a portion of these regulatory assets or liabilities no longer
meet the criteria for continued application of regulatory
accounting, then we would be required to write-off the net
unrecoverable balances against earnings in the period such
determination is made. The net balance in regulatory asset
and liability accounts was a net liability of $217.7 million and
a net asset of $10.3 million as of December 31, 2017 and
2016, respectively. See Note 2 for more detail on our
regulatory balances.
Revenue Recognition
Utility and non-utility revenues, which are derived primarily
from the sale, transportation, and storage of natural gas, are
recognized upon the delivery of gas commodity or services
rendered to customers.
Accrued Unbilled Revenue
For a description of our policy regarding accrued unbilled
revenue for both the utility and non-utility revenues, see
Note 2. The following table presents changes in key metrics
if the estimated percentage of unbilled volume at December
31 was adjusted up or down by 1%:
In millions
Unbilled revenue increase (decrease)
Utility margin increase (decrease)(1)
Net loss increase (decrease)(1)
(1)
Includes impact of regulatory mechanisms including
decoupling mechanism.
2017
Up 1%
Down 1%
$
$
0.6
0.1
—
(0.6)
(0.1)
—
Derivative Instruments and Hedging Activities
Our gas acquisition and hedging policies set forth guidelines
for using financial derivative instruments to support prudent
risk management strategies. These policies specifically
prohibit the use of derivatives for trading or speculative
purposes. We enter into financial derivative contracts to
hedge a portion of our utility’s natural gas sales
requirements. These contracts include swaps, options, and
combinations of option contracts. We primarily use these
derivative financial instruments to manage commodity price
variability. A small portion of our derivative hedging strategy
involves foreign currency exchange contracts.
Derivative instruments are recorded on our balance sheet at
fair value. If certain regulatory conditions are met, then the
derivative instrument fair value is recorded together with an
offsetting entry to a regulatory asset or liability account
pursuant to regulatory accounting, and no unrealized gain or
loss is recognized in current income or loss. See Regulatory
Accounting above for additional information. The gain or
loss from the fair value of a derivative instrument subject to
regulatory deferral is included in the recovery from, or
refund to, utility customers in future periods. If a derivative
contract is not subject to regulatory deferral, then the
accounting treatment for unrealized gains and losses is
recorded in accordance with accounting standards for
derivatives and hedging which is either in current income or
loss or in accumulated other comprehensive income or loss
(AOCI or AOCL). Our derivative contracts outstanding at
48
December 31, 2017, 2016 and 2015 were measured at fair
value using models or other market accepted valuation
methodologies derived from observable market data. Our
estimate of fair value may change significantly from period-
to-period depending on market conditions and prices. These
changes may have an impact on our results of operations,
but the impact would largely be mitigated due to the majority
of our derivative activities being subject to regulatory
deferral treatment. For more information on our derivative
activity and associated regulatory treatment, see Note 2 and
Note 13.
The following table summarizes the amount of losses
realized from commodity price transactions for the last three
years:
In millions
Net utility loss on:
Commodity
Swaps
2017
2016
2015
$
(7.8) $
(26.9) $
(37.7)
Realized losses from commodity hedges shown above were
recorded as increases to cost of gas and were, or will be,
included in our annual PGA rates.
Pensions and Postretirement Benefits
We maintain a qualified non-contributory defined benefit
pension plan, non-qualified supplemental pension plans for
eligible executive officers and certain key employees, and
other postretirement employee benefit plans covering
certain non-union employees. We also have a qualified
defined contribution plan (Retirement K Savings Plan) for all
eligible employees. Only the qualified defined benefit
pension plan and Retirement K Savings Plan have plan
assets, which are held in qualified trusts to fund the
respective retirement benefits. The qualified defined benefit
retirement plan for union and non-union employees was
closed to new participants several years ago. These plans
are not available to employees at any of our subsidiary
companies. Non-union and union employees hired or re-
hired after December 31, 2006 and 2009, respectively, and
employees of NW Natural subsidiaries are provided an
enhanced Retirement K Savings Plan benefit. The
postretirement Welfare Benefit Plan for non-union
employees was also closed to new participants several
years ago.
Net periodic pension and postretirement benefit costs
(retirement benefit costs) and projected benefit obligations
(benefit obligations) are determined using a number of key
assumptions including discount rates, rate of compensation
increases, retirement ages, mortality rates and an expected
long-term return on plan assets. See Note 8.
Accounting standards also require balance sheet
recognition of the overfunded or underfunded status of
pension and postretirement benefit plans in AOCI or AOCL,
net of tax, based on the fair value of plan assets compared
to the actuarial value of future benefit obligations. However,
the retirement benefit costs related to our qualified defined
benefit pension and postretirement benefit plans are
generally recovered in utility rates, which are set based on
accounting standards for pensions and postretirement
benefit expenses. As such, we received approval from the
OPUC to recognize the overfunded or underfunded status
as a regulatory asset or regulatory liability based on
expected rate recovery, rather than including it as AOCI or
AOCL under common equity. See "Regulatory Accounting"
above and Note 2, "Industry Regulation".
We believe our pension assumptions to be appropriate
based on plan design and an assessment of market
conditions. However, the following shows the sensitivity of
our retirement benefit costs and benefit obligations to
changes in certain actuarial assumptions:
In 2011, we received regulatory approval from the OPUC
and began deferring a portion of our pension expense
above or below the amount set in rates to a regulatory
balancing account on the balance sheet. At December 31,
2017, the cumulative amount deferred for future pension
cost recovery was $60.4 million. The regulatory balancing
account includes the recognition of accrued interest on the
account balance at the utility's authorized rate of return, with
the equity portion of this interest being deferred until
amounts are collected in rates.
A number of factors, as discussed above, are considered in
developing pension and postretirement benefit assumptions.
For the December 31, 2017 measurement date, we
reviewed and updated:
•
our weighted-average discount rate assumptions for
pensions decreased from 4.00% for 2016 to 3.52% for
2017, and our weighted-average discount rate
assumptions for other postretirement benefits
decreased from 3.85% for 2016 to 3.44% for 2017. The
new rate assumptions were determined for each plan
based on a matching of benchmark interest rates to the
estimated cash flows, which reflect the timing and
amount of future benefit payments. Benchmark interest
rates are drawn from the Citigroup Above Median
Curve, which consists of high quality bonds rated AA- or
higher by S&P or Aa3 or higher by Moody’s;
our expected annual rate of future compensation
increases, which remained unchanged at a range of
3.25% to 4.5% at December 31, 2017;
our expected long-term return on qualified defined
benefit plan assets, which remained unchanged at a
rate of 7.50%;
our mortality rate assumptions were updated from
RP-2006 mortality tables for employees and healthy
annuitants with a fully generational projection using
scale MP-2016 to corresponding RP-2006 mortality
tables using scale MP-2017, which partially offset
increases of our projected benefit obligation;
other key assumptions, which were based on actual
plan experience and actuarial recommendations.
•
•
•
•
At December 31, 2017, our net pension liability (benefit
obligations less market value of plan assets) for the qualified
defined benefit plan decreased $4.1 million compared to
2016. The decrease in our net pension liability is primarily
due to the $26.2 million increase in our pension benefit
obligation, offset by an increase of $30.2 million in plan
assets. The liability for non-qualified plans increased $2.3
million, and the liability for other postretirement benefits
decreased $0.5 million in 2017.
We determine the expected long-term rate of return on plan
assets by averaging the expected earnings for the target
asset portfolio. In developing our expected return, we
analyze historical actual performance and long-term return
projections, which gives consideration to the current asset
mix and our target asset allocation.
49
Change in
Assumption
(0.25)%
Dollars in millions
Discount rate:
Qualified defined
benefit plans
Non-qualified plans
Other
postretirement
benefits
Expected long-term
return on plan assets:
(0.25)
Qualified defined
benefit plans
Impact on
2017
Retirement
Benefit
Costs
Impact on
Retirement
Benefit
Obligations
at Dec. 31,
2017
$
1.4
$
—
—
15.2
0.9
0.8
0.7
N/A
In July 2012, President Obama signed into law the MAP-21
Act. This legislation changed several provisions affecting
pension plans, including temporary funding relief and
Pension Benefit Guaranty Corporation (PBGC) premium
increases, which reduces the level of minimum required
contributions in the near-term but generally increases
contributions in the long-run as well as increasing the
operational costs of running a pension plan. Prior to the
MAP-21 Act, we were using interest rates based on a 24-
month average yield of investment grade corporate bonds
(also referred to as "segment rate") to calculate minimum
contribution requirements. MAP-21 Act established a new
minimum and maximum corridor for segment rates based on
a 25-year average of bond yields, which is to be used in
calculating contribution requirements. In August 2014,
HATFA was signed and extends certain aspects of MAP-21
as well as modifies the phase-out periods for the limitations.
As a result we anticipate lower contributions over the next
five years with contributions increasing thereafter.
Income Taxes
Valuation Allowances
We recognize deferred tax assets to the extent that we
believe these assets are more likely than not to be realized.
In making such a determination, we consider the available
positive and negative evidence, including future reversals of
existing taxable temporary differences, projected future
taxable income, tax-planning strategies, and results of
recent operations. We have determined that we are more
likely than not to realize all recorded deferred tax assets as
of December 31, 2017. See Note 9.
Uncertain Tax Benefits
The calculation of our tax liabilities involves dealing with
uncertainties in the application of complex tax laws and
regulations in the jurisdictions in which we operate. A tax
benefit from a material uncertain tax position will only be
recognized when it is more likely than not that the position,
or some portion thereof, will be sustained upon examination,
including resolution of any related appeals or litigation
processes, on the basis of the technical merits. We
participate in the Compliance Assurance Process (CAP)
with the Internal Revenue Service (IRS). Under the CAP
program the Company works with the IRS to identify and
resolve material tax matters before the federal income tax
return is filed each year. No reserves for uncertain tax
benefits were recorded during 2017, 2016, or 2015. See
Note 9.
Tax Legislation
When significant proposed or enacted changes in income
tax rules occur we consider whether there may be a material
impact to our financial position, results of operations, cash
flows, or whether the changes could materially affect
existing assumptions used in making estimates of tax
related balances.
On December 22, 2017, H.R.1 - An Act to provide for
reconciliation pursuant to titles II and V of the concurrent
resolution on the budget for fiscal year 2018, also known as
the Tax Cuts and Jobs Act (TCJA), was enacted. The TCJA
permanently lowers the U.S. federal corporate income tax
rate to 21% from the existing maximum rate of 35%,
effective for our tax year beginning January 1, 2018. The
TCJA includes specific provisions related to regulated public
utilities that generally provide for the continued deductibility
of interest expense and the elimination of bonus
depreciation for property acquired after September 27,
2017. Certain rate normalization requirements for
accelerated cost recovery benefits related to regulated plant
balances also continue.
The reduced U.S. corporate income tax rate had a material
impact on our financial statements in 2017. As a result of the
reduction of the U.S. corporate income tax rate to 21%, U.S.
GAAP require deferred tax assets and liabilities be revalued
as of the date of enactment, with resulting tax effects
accounted for in the reporting period of enactment. We
recorded a net revaluation of deferred tax asset and liability
balances of $196.4 million as of December 31, 2017,
utilizing the reduced federal rate of 21% expected to apply
when these temporary differences are realized or settled,
based upon balances in existence at the date of enactment.
This revaluation had no impact on our 2017 cash flows. See
Note 9 for more information on how we are impacted by the
TCJA.
With respect to other tax legislation, the final tangible
property regulations applicable to all taxpayers were issued
on September 13, 2013 and were generally effective for
taxable years beginning on or after January 1, 2014. In
addition, procedural guidance related to the regulations was
issued under which taxpayers may make accounting
method changes to comply with the regulations. We have
evaluated the regulations and do not anticipate any material
impact. However, unit-of-property guidance applicable to
natural gas distribution networks has not yet been issued
and is expected in the near future. We will further evaluate
the effect of these regulations after this guidance is issued,
but believe our current method is materially consistent with
the new regulations and do not expect this additional
guidance to have a material effect on our financial
statements.
Regulatory Matters
Regulatory tax assets and liabilities are recorded to the
extent it is probable they will be recoverable from, or
50
refunded to, customers in future. At December 31, 2017 and
2016, we had net regulatory income tax assets of $21.3
million and $43.0 million, respectively, representing flow-
through future rate recovery of deferred tax liabilities
resulting from differences in utility plant financial statement
and tax basis and utility plant removal costs. These deferred
tax liabilities, and the associated regulatory income tax
assets, are currently being recovered through customer
rates and were reduced by $17.4 million as a result of the
TCJA. At December 31, 2017, we had a regulatory income
tax asset of $0.9 million representing probable future rate
recovery of deferred tax liabilities resulting from the equity
portion of AFUDC. This regulatory asset was reduced by
$0.8 million as a result of the TCJA.
On December 29, 2017, we filed applications with OPUC
and WUTC seeking authorization to defer the overall net
benefits of the utility resulting from the TCJA. On the same
day, Staff of the OPUC filed an application seeking deferral
of changes in our federal tax obligations resulting from the
TCJA. On January 8, 2018, the WUTC issued a statement
acknowledging receipt of our application and indicating their
intention to incorporate the impact into future rate case
proceedings.
We have recorded an estimated regulatory liability of $213.7
million as of December 31, 2017, which includes a gross up
for income taxes of $56.6 million, for the change in
regulated utility deferred taxes as a result of the TCJA. The
TCJA includes specific guidance for determining the
shortest time period over which the portion of this regulatory
liability resulting from accelerated cost recovery of utility
plant may accrue to the benefit of customers to avoid
incurring federal normalization penalties. However, it is
anticipated that until such time that customers receive the
direct benefit of this regulatory liability, the balance, net of
the additional gross up for income taxes, will continue to
provide an indirect benefit to customers by reducing the
utility rate base which determines customer rates for
service. It is not possible at this time to determine when the
final resolution of these regulatory proceedings will occur,
and as result, this regulatory liability is classified as non-
current.
Utility rates in effect include an allowance to provide for the
recovery of the anticipated provision for income taxes
incurred as a result of providing regulated services. The
provision for income taxes allowance currently in rates
includes an allowance for federal income taxes determined
by utilizing the pre-TCJA federal corporate income tax rate
of 35%. Beginning in 2018, we anticipate that an additional
regulatory liability will be recorded reflecting the deferral of a
reduction in our provision for income taxes, incurred as a
result of providing regulated utility services, due to the newly
enacted 21% federal corporate income tax rate.
Environmental Contingencies
We account for environmental liabilities in accordance with
accounting standards under the loss contingency guidance
when it is probable that a liability has been incurred and the
amount of the loss is reasonably estimable. Amounts
recorded for environmental contingencies take numerous
factors into consideration, including, among other variables,
changes in enacted laws, regulatory orders, estimated
remediation costs, interest rates, insurance proceeds,
the strategic evaluation, which included a potential sale in
the fourth quarter of 2017, we have lowered our views of a
near-term market recovery and have decreased the
likelihood associated with contracting with higher-value
customers. These changes were the most significant
estimates that caused our cash flow projections to decrease
to a point where they are no longer sufficient to cover the
carrying value of the asset. The current assumptions used in
our fair value model include a significant amount of
uncertainty in the estimate of future storage values.
Although we have not seen the rebound in storage prices
that we originally anticipated, we have worked diligently to
operate the Gill Ranch Facility efficiently and will continue to
evaluate all strategic options for the Gill Ranch Facility. Our
assumptions assume a recovery of the storage market in
California and an ability to identify and contract with higher-
value customers over the next 5 years, however not to the
extent previously forecasted.
While many expense assumptions are included in our
projected cash flows, the most significant assumption is our
estimated cost and timing of complying with the proposed
new safety regulations by DOGGR. Although significant,
these estimates were not considered to be as impactful to
the fair value of the assets as our estimates of the storage
revenues referenced above, but are the most significant
capital expense assumptions.
Going forward, the two key estimates that could change and
negatively impact the value of this asset are changes to the
estimated storage revenues and the cost and timing of
complying with the new DOGGR regulations. We currently
assume some recovery of storage prices and assume that
we will be required to comply with the new DOGGR
regulations over the next seven years. Additionally, a sale of
the asset could have an impact on fair value, should one
occur.
participation by other parties, timing of payments, and the
input of legal counsel and third-party experts. Accordingly,
changes in any of these variables or other factual
circumstances could have a material impact on the amounts
recorded for our environmental liabilities. For a complete
discussion of our environmental policy refer to Note 2. For a
discussion of our current environmental sites and liabilities
refer to Note 15 and "Contingent Liabilities" above. In
addition, for information regarding the regulatory treatment
of these costs and our regulatory recovery mechanism, see
"Results of Operations—Regulatory Matters—Rate
Mechanisms—Environmental Costs" above.
Impairment of Long-Lived Assets
We review the carrying value of long-lived assets whenever
events or changes in circumstances indicate the carrying
amount of the assets might not be recoverable. Factors that
would necessitate an impairment assessment of long-lived
assets include a significant adverse change in the extent or
manner in which the asset is used, a significant adverse
change in legal factors or business climate that could affect
the value of the asset, or a significant decline in the
observable market value or expected future cash flows of
the asset, among others.
When such factors are present, we assess the recoverability
by determining whether the carrying value of the asset will
be recovered through expected future cash flows. An asset
is determined to be impaired when the carrying value of the
asset exceeds the expected undiscounted future cash flows
from the use and eventual disposition of the asset. If an
impairment is indicated, we record an impairment loss for
the difference between the carrying value and the fair value
of the long-lived assets. Fair value is estimated using
appropriate valuation methodologies, which may include an
estimate of discounted cash flows.
In the fourth quarter of 2017, we recognized a non-cash pre-
tax impairment of long-lived assets at the Gill Ranch Facility
of $192.5 million, which is included in our gas storage
segment. We determined circumstances existed that
indicated the carrying value of the assets may not be
recoverable. Those circumstances included the completion
of a comprehensive strategic review process that evaluated
various alternatives including a potential sale, as well as
contracting for available storage at lower than anticipated
values for the coming storage year. Given these
considerations, management was required to re-evaluate
the estimated cash flows from our interests in the Gill Ranch
Facility, and has determined that those estimated cash flows
are no longer sufficient to cover the carrying value of the
assets.
We used the income approach to estimate fair value, using
the estimated future net cash flows. We also compared the
results of the income approach to our own recent sale
experience and recent market comparable transactions in
order to estimate fair value. Many factors and assumptions
impact the net cash flows used. The most significant and
uncertain estimates included our forecast of gas storage
pricing, our ability to successfully identify and contract with
higher-value customers in and/or near the northern
California market that Gill Ranch serves, and exploring the
possibility of providing energy storage services such as
compressed gas energy storage (CGES). After completing
51
ITEM 7A. QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK
We are exposed to various forms of market risk including
commodity supply risk, commodity price risk, interest rate
risk, foreign currency risk, credit risk and weather risk. The
following describes our exposure to these risks.
Commodity Supply Risk
We enter into spot, short-term, and long-term natural gas
supply contracts, along with associated pipeline
transportation contracts, to manage our commodity supply
risk. Historically, we have arranged for physical delivery of
an adequate supply of gas, including gas in our Mist storage
and off-system storage facilities, to meet expected
requirements of our core utility customers. Our long-term
gas supply contracts are primarily index-based and subject
to monthly re-pricing, a strategy that is intended to
substantially mitigate credit exposure to our physical gas
counterparties. Absolute notional amounts under physical
gas contracts related to open positions on our derivative
instruments were 520.3 million therms and 535.5 million
therms as of December 31, 2017 and 2016, respectively.
Commodity Price Risk
Natural gas commodity prices are subject to market
fluctuations due to unpredictable factors including weather,
pipeline transportation congestion, drilling technologies,
market speculation, and other factors that affect supply and
demand. We manage commodity price risk with financial
swaps and physical gas reserves from a long-term
investment in working interests in gas leases operated by
Jonah Energy. These financial hedge contracts and gas
reserves volumes are generally included in our annual PGA
filing for recovery, subject to a regulatory prudence review.
Notional amounts under financial derivative contracts were
$108.1 million and $123.6 million as of December 31, 2017
and 2016, respectively. The fair value of financial swaps as
of December 31, 2017 was an unrealized loss of $22.3
million with future cash outflows of $14.9 million in 2018,
$6.0 million in 2019, and $1.4 million in 2020.
Interest Rate Risk
We are exposed to interest rate risk primarily associated
with new debt financing needed to fund capital
requirements, including future contractual obligations and
maturities of long-term and short-term debt. Interest rate risk
is primarily managed through the issuance of fixed-rate debt
with varying maturities. We may also enter into financial
derivative instruments, including interest rate swaps, options
and other hedging instruments, to manage and mitigate
interest rate exposure. We did not have any interest rate
swaps outstanding as of December 31, 2017 or 2016.
Foreign Currency Risk
The costs of certain pipeline and off-system storage
services purchased from Canadian suppliers are subject to
changes in the value of the Canadian currency in relation to
the U.S. currency. Foreign currency forward contracts are
used to hedge against fluctuations in exchange rates for our
commodity-related demand and reservation charges paid in
Canadian dollars. Notional amounts under foreign currency
forward contracts were $7.7 million and $7.5 million as of
December 31, 2017 and 2016, respectively. If all of the
52
foreign currency forward contracts had been settled on
December 31, 2017, a gain of $0.1 million would have been
realized. See Note 13.
Credit Risk
Credit Exposure to Natural Gas Suppliers
Certain gas suppliers have either relatively low credit ratings
or are not rated by major credit rating agencies. To manage
this supply risk, we purchase gas from a number of different
suppliers at liquid exchange points. We evaluate and
monitor suppliers’ creditworthiness and maintain the ability
to require additional financial assurances, including
deposits, letters of credit, or surety bonds, in case a supplier
defaults. In the event of a supplier’s failure to deliver
contracted volumes of gas, the regulated utility would need
to replace those volumes at prevailing market prices, which
may be higher or lower than the original transaction prices.
We expect these costs would be subject to our PGA sharing
mechanism discussed above. Since most of our commodity
supply contracts are priced at the daily or monthly market
index price tied to liquid exchange points, and we have
adequate storage flexibility, we believe it is unlikely a
supplier default would have a material adverse effect on our
financial condition or results of operations.
Credit Exposure to Financial Derivative Counterparties
Based on estimated fair value at December 31, 2017, our
overall credit exposure relating to commodity contracts is
considered immaterial as it reflects amounts owed to
financial derivative counterparties (see table below).
However, changes in natural gas prices could result in
counterparties owing us money. Therefore, our financial
derivatives policy requires counterparties to have at least an
investment-grade credit rating at the time the derivative
instrument is entered into and specific limits on the contract
amount and duration based on each counterparty’s credit
rating. Due to potential changes in market conditions and
credit concerns, we continue to enforce strong credit
requirements. We actively monitor and manage our
derivative credit exposure and place counterparties on hold
for trading purposes or require cash collateral, letters of
credit, or guarantees as circumstances warrant.
The following table summarizes our overall financial swap
and option credit exposure, based on estimated fair value,
and the corresponding counterparty credit ratings. The table
uses credit ratings from S&P and Moody’s, reflecting the
higher of the S&P or Moody’s rating or a middle rating if the
entity is split-rated with more than one rating level
difference:
In millions
AA/Aa
A/A
Total
Financial Derivative Position by Credit Rating
Unrealized Fair Value Gain (Loss)
2017
2016
$
$
(9.0) $
(13.3)
(22.3) $
13.7
1.7
15.4
In most cases, we also mitigate the credit risk of financial
derivatives by having master netting arrangements with our
counterparties which provide for making or receiving net
cash settlements. Generally, transactions of the same type
in the same currency that have settlement on the same day
with a single counterparty are netted and a single payment
is delivered or received depending on which party is due
funds.
Additionally, we have master contracts in place with each
of our derivative counterparties that include provisions for
posting or calling for collateral. Generally, we can obtain
cash or marketable securities as collateral with one day’s
notice. We use various collateral management strategies to
reduce liquidity risk. The collateral provisions vary by
counterparty but are not expected to result in the significant
posting of collateral, if any. We have performed stress tests
on the portfolio and concluded the liquidity risk from
collateral calls is not material. Our derivative credit exposure
is primarily with investment grade counterparties rated AA-/
Aa3 or higher. Contracts are diversified across
counterparties to reduce credit and liquidity risk.
At December 31, 2017, our financial derivative credit risk on
a volumetric basis was geographically concentrated 36% in
the United States and 64% in Canada, based on our
counterparties' location. At December 31, 2016, our
financial derivative credit risk on a volumetric basis was
geographically concentrated 29% in the United States and
71% in Canada with our counterparties.
Credit Exposure to Insurance Companies
Our credit exposure to insurance companies for loss or
damage claims could be material. We regularly monitor the
financial condition of insurance companies who provide
general liability insurance policy coverage to NW Natural
and its predecessors.
Weather Risk
We have a weather normalization mechanism in Oregon;
however, we are exposed to weather risk primarily from our
regulated utility business. A large percentage of our utility
margin is volume driven, and current rates are based on an
assumption of average weather. Our weather normalization
mechanism in Oregon is for residential and commercial
customers, which is intended to stabilize the recovery of our
utility’s fixed costs and reduce fluctuations in customers’ bills
due to colder or warmer than average weather. Customers
in Oregon are allowed to opt out of the weather
normalization mechanism. As of December 31, 2017,
approximately 9% of our Oregon customers had opted out.
In addition to the Oregon customers opting out, our
Washington residential and commercial customers account
for approximately 11% of our total customer base and are
not covered by weather normalization. The combination of
Oregon and Washington customers not covered by a
weather normalization mechanism is 20% of all residential
and commercial customers. See "Results of Operations—
Regulatory Matters—Rate Mechanisms—WARM" above.
53
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TABLE OF CONTENTS
1.
2.
3.
4.
5.
Management's Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements:
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2017, 2016, and
2015
Consolidated Balance Sheets at December 31, 2017 and 2016
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2017, 2016, and 2015
Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 2016, and 2015
Notes to Consolidated Financial Statements
Quarterly Financial Information
Supplementary Data for the Years Ended December 31, 2017, 2016, and 2015:
Financial Statement Schedule
Schedule II – Valuation and Qualifying Accounts and Reserves
Supplemental Schedules Omitted
Page
55
56
57
58
60
61
62
90
90
All other schedules are omitted because of the absence of the conditions under which they are required or because the required
information is included elsewhere in the financial statements.
54
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in
Rules 13a-15(f) or 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial
reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles in the United States of
America (GAAP). Our internal control over financial reporting includes those policies and procedures that:
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
involving company assets;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit the preparation of financial statements in
accordance with GAAP, and that receipts and expenditures are being made only in accordance with authorizations of
management and the Board of Directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of the unauthorized acquisition, use, or disposition of
our assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements or fraud.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017. In making this
assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) in Internal Control-Integrated Framework (2013).
Based on our assessment and those criteria, management has concluded that we maintained effective internal control over
financial reporting as of December 31, 2017.
The effectiveness of internal control over financial reporting as of December 31, 2017 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears in this
annual report.
/s/ David H. Anderson
David H. Anderson
President and Chief Executive Officer
/s/ Frank H. Burkhartsmeyer
Frank H. Burkhartsmeyer
Senior Vice President and Chief Financial Officer
February 23, 2018
55
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Northwest Natural Gas Company:
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Northwest Natural Gas Company and its subsidiaries as of
December 31, 2017 and 2016, and the related consolidated statements of comprehensive income (loss), shareholders’ equity,
and cash flows for each of the three years in the period ended December 31, 2017 including the related notes and financial
statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also
have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in
Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position
of the Company as of December 31, 2017 and 2016, and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of
America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting
as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control
over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on
the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our
audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement,
whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material
respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement
of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks.
Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control
over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a
material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We
believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 23, 2018
We have served as the Company’s auditor since 1997.
56
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
In thousands, except per share data
Operating revenues
Operating expenses:
Cost of gas
Operations and maintenance
Environmental remediation
General taxes
Depreciation and amortization
Impairment expense
Total operating expenses
Income (loss) from operations
Other income (expense), net
Interest expense, net
Income (loss) before income taxes
Income tax expense (benefit)
Net income (loss)
Other comprehensive income (loss):
Change in employee benefit plan liability, net of taxes of $735 for 2017, $452 for
2016, and ($988) for 2015
Amortization of non-qualified employee benefit plan liability, net of taxes of ($374)
for 2017, ($624) for 2016, and ($883) for 2015
Comprehensive income (loss)
Average common shares outstanding:
Basic
Diluted
Earnings (loss) per share of common stock:
Basic
Diluted
Dividends declared per share of common stock
See Notes to Consolidated Financial Statements
Year Ended December 31,
2017
2016
2015
$ 762,173
$ 675,967
$ 723,791
324,795
165,246
15,291
32,012
85,578
192,478
815,400
(53,227)
5,348
38,501
(86,380)
(30,757)
(55,623)
260,588
149,974
13,298
30,538
82,289
—
536,687
139,280
(543)
39,128
99,609
40,714
58,895
327,305
157,521
3,513
30,281
80,923
—
599,543
124,248
7,747
42,539
89,456
35,753
53,703
(2,059)
(744)
1,561
572
955
1,353
$ (57,110) $
59,106
$
56,617
28,669
28,669
27,647
27,779
27,347
27,417
$
(1.94) $
(1.94)
1.88
$
2.13
2.12
1.87
1.96
1.96
1.86
57
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands
Assets:
Current assets:
Cash and cash equivalents
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Regulatory assets
Derivative instruments
Inventories
Gas reserves
Other current assets
Total current assets
Non-current assets:
Property, plant, and equipment
Less: Accumulated depreciation
Total property, plant, and equipment, net
Gas reserves
Regulatory assets
Derivative instruments
Other investments
Other non-current assets
Total non-current assets
Total assets
As of December 31,
2017
2016
$
3,472
$
68,362
62,381
(956)
45,781
1,735
47,973
15,704
25,484
3,521
66,700
64,946
(1,290)
42,362
17,031
54,129
15,926
24,728
269,936
288,053
3,215,451
3,208,816
960,477
947,916
2,254,974
2,260,900
84,053
356,608
1,306
66,363
6,506
100,184
357,530
3,265
68,376
1,493
2,769,810
2,791,748
$
3,039,746
$
3,079,801
See Notes to Consolidated Financial Statements
58
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands
Liabilities and equity:
Current liabilities:
Short-term debt
Current maturities of long-term debt
Accounts payable
Taxes accrued
Interest accrued
Regulatory liabilities
Derivative instruments
Other current liabilities
Total current liabilities
Long-term debt
Deferred credits and other non-current liabilities:
Deferred tax liabilities
Regulatory liabilities
Pension and other postretirement benefit liabilities
Derivative instruments
Other non-current liabilities
Total deferred credits and other non-current liabilities
Commitments and contingencies (see Note 14 and Note 15)
Equity:
Common stock - no par value; authorized 100,000 shares; issued and outstanding 28,736
and 28,630 at December 31, 2017 and 2016, respectively
Retained earnings
Accumulated other comprehensive loss
Total equity
Total liabilities and equity
See Notes to Consolidated Financial Statements
As of December 31,
2017
2016
$
54,200
$
96,703
112,308
18,883
6,773
34,013
18,722
40,248
381,850
683,184
270,526
586,093
223,333
4,649
147,335
53,300
39,989
85,664
12,149
5,966
40,290
1,315
35,844
274,517
679,334
557,085
349,319
225,725
913
142,411
1,231,936
1,275,453
448,865
302,349
(8,438)
742,776
445,187
412,261
(6,951)
850,497
$
3,039,746
$
3,079,801
59
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
In thousands
Balance at December 31, 2014
Comprehensive income
Dividends on common stock
Tax expense from employee stock plans
Stock-based compensation
Shares issued pursuant to equity based plans
Balance at December 31, 2015
Comprehensive income
Dividends on common stock
Stock-based compensation
Shares issued pursuant to equity based plans
Issuance of common stock, net of issuance costs
Balance at December 31, 2016
Comprehensive income (loss)
Dividends on common stock
Stock-based compensation
Shares issued pursuant to equity based plans
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income (Loss)
Total
Equity
$
375,117
$
402,280
$
(10,076) $
767,321
—
—
(118)
3,277
4,868
383,144
—
—
2,924
6,358
52,761
445,187
—
—
2,882
796
53,703
(50,993)
—
—
—
404,990
58,895
(51,624)
—
—
—
412,261
(55,623)
(54,289)
—
—
2,914
—
—
—
—
(7,162)
211
—
—
—
—
(6,951)
(1,487)
—
—
—
56,617
(50,993)
(118)
3,277
4,868
780,972
59,106
(51,624)
2,924
6,358
52,761
850,497
(57,110)
(54,289)
2,882
796
Balance at December 31, 2017
$
448,865
$
302,349
$
(8,438) $
742,776
See Notes to Consolidated Financial Statements
60
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands
Operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to cash provided by operations:
Depreciation and amortization
Regulatory amortization of gas reserves
Deferred income taxes
Qualified defined benefit pension plan expense
Contributions to qualified defined benefit pension plans
Deferred environmental expenditures, net
Regulatory disallowance of prior environmental cost deferrals
Amortization of environmental remediation
Impairment of long-lived assets
Other
Changes in assets and liabilities:
Receivables, net
Inventories
Income taxes
Accounts payable
Interest accrued
Deferred gas costs
Other, net
Cash provided by operating activities
Investing activities:
Capital expenditures
Other
Cash used in investing activities
Financing activities:
Repurchases related to stock-based compensation
Proceeds from stock options exercised
Proceeds from common stock issued
Long-term debt issued
Long-term debt retired
Change in short-term debt
Cash dividend payments on common stock
Other
Cash provided by (used in) financing activities
(Decrease) increase in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental disclosure of cash flow information:
Interest paid, net of capitalization
Income taxes paid (refunded)
See Notes to Consolidated Financial Statements
61
Year Ended December 31,
2017
2016
2015
$ (55,623) $ 58,895
$ 53,703
85,578
16,353
(52,414)
5,364
82,289
15,525
32,056
5,274
80,923
17,991
26,972
5,697
(19,430)
(14,470)
(14,120)
(13,716)
(10,469)
(10,568)
—
15,291
192,478
3,287
13,298
—
15,000
3,513
—
2,127
3,225
(1,613)
3,099
5,571
6,734
1,424
807
(7,484)
16,620
9,467
12,380
93
2,373
6,964
(6,541)
(17,175)
(206)
17,122
(10,204)
31,918
(4,061)
12,365
(10,143)
206,704
222,147
184,688
(213,595)
(139,511)
(118,320)
(577)
2,882
3,022
(214,172)
(136,629)
(115,298)
(2,034)
(1,042)
4,819
—
8,404
52,760
100,000
150,000
—
3,875
—
—
(40,000)
(25,000)
(60,000)
900
(216,735)
35,335
(53,957)
(51,508)
(49,243)
(2,309)
(3,087)
(4,680)
7,419
(86,208)
(74,713)
(49)
3,521
(690)
4,211
$
3,472
$
3,521
$
(5,323)
9,534
4,211
$ 34,787
$ 36,023
$ 39,634
14,780
(7,157)
17,306
NORTHWEST NATURAL GAS
COMPANY
NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS
1. ORGANIZATION AND PRINCIPLES OF
CONSOLIDATION
The accompanying consolidated financial statements
represent the consolidated results of Northwest Natural Gas
Company (NW Natural or the Company) and all companies
we directly or indirectly control, either through majority
ownership or otherwise. We have two core businesses: our
regulated local gas distribution business, referred to as the
utility segment, which serves residential, commercial, and
industrial customers in Oregon and southwest Washington;
and our gas storage businesses, referred to as the gas
storage segment, which provides storage services for
utilities, gas marketers, electric generators, and large
industrial users from facilities located in Oregon and
California. In addition, we have investments and other non-
utility activities we aggregate and report as other.
Our core utility business assets and operating activities are
largely included in the parent company, NW Natural. Our
direct and indirect wholly-owned subsidiaries include NW
Natural Energy, LLC (NWN Energy), NW Natural Gas
Storage, LLC (NWN Gas Storage), Gill Ranch Storage, LLC
(Gill Ranch), NNG Financial Corporation (NNG Financial),
Northwest Energy Corporation (Energy Corp), Northwest
Natural Water Company (NWN Water), FWC Merger Sub,
Inc., and NWN Gas Reserves LLC (NWN Gas Reserves).
Investments in corporate joint ventures and partnerships we
do not directly or indirectly control, and for which we are not
the primary beneficiary, include NWN Financial's investment
in Kelso-Beaver Pipeline and NWN Energy's investment in
Trail West Holdings, LLC (TWH), which is accounted for
under the equity method. NW Natural and its affiliated
companies are collectively referred to herein as NW Natural.
The consolidated financial statements are presented after
elimination of all intercompany balances and transactions.
In this report, the term “utility” is used to describe our
regulated gas distribution business, and the term “non-
utility” is used to describe our gas storage businesses and
other non-utility investments and business activities.
Certain prior year balances in our consolidated financial
statements and notes have been reclassified to conform
with the current presentation. These reclassifications had no
effect on our prior year’s consolidated results of operations,
financial condition, or cash flows.
2. SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles in the United
States of America (GAAP) requires management to make
estimates and assumptions that affect reported amounts in
the consolidated financial statements and accompanying
notes. Actual amounts could differ from those estimates, and
changes would most likely be reported in future periods.
Management believes the estimates and assumptions used
are reasonable.
Industry Regulation
Our principal businesses are the distribution of natural gas,
which is regulated by the OPUC and WUTC, and natural gas
storage services, which are regulated by either the FERC or
the CPUC, and to a certain extent by the OPUC and WUTC.
Accounting records and practices of our regulated
businesses conform to the requirements and uniform system
of accounts prescribed by these regulatory authorities in
accordance with U.S. GAAP. Our businesses regulated by
the OPUC, WUTC, and FERC earn a reasonable return on
invested capital from approved cost-based rates, while our
business regulated by the CPUC earns a return to the extent
we are able to charge competitive prices above our costs
(i.e. market-based rates).
In applying regulatory accounting principles, we capitalize or
defer certain costs and revenues as regulatory assets and
liabilities pursuant to orders of the OPUC or WUTC, which
provide for the recovery of revenues or expenses from, or
refunds to, utility customers in future periods, including a
return or a carrying charge in certain cases.
At December 31, the amounts deferred as regulatory assets
and liabilities were as follows:
In thousands
Current:
Regulatory Assets
2017
2016
Unrealized loss on derivatives(1)
$ 18,712
$
Gas costs
Environmental costs(2)
Decoupling(3)
Income taxes
Other(4)
Total current
Non-current:
Unrealized loss on derivatives(1)
Pension balancing(5)
Income taxes
Pension and other postretirement
benefit liabilities
Environmental costs(2)
Gas costs
Decoupling(3)
Other(4)
154
6,198
1,315
6,830
9,989
11,227
13,067
2,218
7,272
4,378
6,783
$ 45,781
$ 42,362
$
4,649
$
913
60,383
19,991
50,863
38,670
179,824
183,035
72,128
63,970
84
3,970
15,579
89
5,860
14,130
Total non-current
$ 356,608
$ 357,530
62
In thousands
Current:
Gas costs
Unrealized gain on derivatives(1)
Decoupling(3)
Other(4)
Total current
Non-current:
Gas costs
Unrealized gain on derivatives(1)
Decoupling(3)
Income taxes
Accrued asset removal costs(6)
Other(4)
Total non-current
Regulatory Liabilities
2017
2016
$ 14,886
$
8,054
1,674
322
16,624
—
17,131
15,612
$ 34,013
$ 40,290
$
4,630
$
1,021
1,306
957
213,306
3,265
—
—
360,929
341,107
4,965
3,926
$ 586,093
$ 349,319
(1) Unrealized gains or losses on derivatives are non-cash items
and, therefore, do not earn a rate of return or a carrying
charge. These amounts are recoverable through utility rates as
part of the annual Purchased Gas Adjustment (PGA)
mechanism when realized at settlement.
(2) Refer to footnote (3) per the Deferred Regulatory Asset table in
(3)
(4)
Note 15 for a description of environmental costs.
This deferral represents the margin adjustment resulting from
differences between actual and expected volumes.
These balances primarily consist of deferrals and amortizations
under approved regulatory mechanisms. The accounts being
amortized typically earn a rate of return or carrying charge.
(5) Refer to footnote (1) of the Net Periodic Benefit Cost table per
Note 8 for information regarding the deferral of pension
expenses.
(6) Estimated costs of removal on certain regulated properties are
collected through rates. See "Accounting Policies—Plant,
Property, and Accrued Asset Removal Costs" below.
The amortization period for our regulatory assets and
liabilities ranges from less than one year to an
indeterminable period. Our regulatory deferrals for gas costs
payable are generally amortized over 12 months beginning
each November 1 following the gas contract year during
which the deferred gas costs are recorded. Similarly, most of
our other regulatory deferred accounts are amortized over
12 months. However, certain regulatory account balances,
such as income taxes, environmental costs, pension
liabilities, and accrued asset removal costs, are large and
tend to be amortized over longer periods once we have
agreed upon an amortization period with the respective
regulatory agency.
We believe all costs incurred and deferred at December 31,
2017 are prudent. We annually review all regulatory assets
and liabilities for recoverability and more often if
circumstances warrant. If we should determine that all or a
portion of these regulatory assets or liabilities no longer meet
the criteria for continued application of regulatory
accounting, we would be required to write-off the net
unrecoverable balances in the period such determination is
made.
Environmental Regulatory Accounting
See Note 15 for information about our SRRM and OPUC
63
orders regarding implementation.
New Accounting Standards
We consider the applicability and impact of all accounting
standards updates (ASUs) issued by the Financial
Accounting Standards Board (FASB). Accounting standards
updates not listed below were assessed and determined to
be either not applicable or are expected to have minimal
impact on our consolidated financial position or results of
operations.
Recently Issued Accounting Pronouncements
DERIVATIVES AND HEDGING. On August 28, 2017, the
FASB issued ASU 2017-12, "Derivatives and Hedging:
Targeted Improvements to Accounting for Hedging
Activities." The purpose of the amendment is to more closely
align hedge accounting with companies’ risk management
strategies. The ASU amends the accounting for risk
component hedging, the hedged item in fair value hedges of
interest rate risk, and amounts excluded from the
assessment of hedge effectiveness. The guidance also
amends the recognition and presentation of the effect of
hedging instruments and includes other simplifications of
hedge accounting. The amendments in this update are
effective for us beginning January 1, 2019. Early adoption is
permitted. The amended presentation and disclosure
guidance is required prospectively. We are currently
assessing the effect of this standard on our financial
statements and disclosures.
STOCK COMPENSATION. On May 10, 2017, the FASB
issued ASU 2017-09, "Stock Compensation - Scope of
Modification Accounting." The purpose of the amendment is
to provide clarity, reduce diversity in practice and reduce the
cost and complexity when applying the guidance in ASC
718, related to a change to the terms or conditions of a
share-based payment award. The ASU amends the scope of
modification accounting for share-based payment
arrangements and provides guidance on the types of
changes to the terms or conditions of share-based payment
awards to which an entity would be required to apply
modification accounting under ASC 718. Specifically, an
entity would not apply modification accounting if the fair
value, vesting conditions, and classification of the awards
are the same immediately before and after the modification.
The amendments in this update are effective for us
beginning January 1, 2018. The amendments in this update
should be applied prospectively to an award modified on or
after the adoption date. We do not expect this standard to
materially affect our financial statements and disclosures.
RETIREMENT BENEFITS. On March 10, 2017, the FASB
issued ASU 2017-07, "Improving the Presentation of Net
Periodic Pension Cost and Net Periodic Post Retirement
Benefit Cost." The ASU requires entities to disaggregate
current service cost from the other components of net
periodic benefit cost and present it with other current
compensation costs for related employees in the income
statement and to present the other components elsewhere in
the income statement and outside of income from operations
if that subtotal is presented. Only the service cost
component of the net periodic benefit cost is eligible for
capitalization. The amendments in this update are effective
for us beginning January 1, 2018. Upon adoption, the ASU
requires that changes to the income statement presentation
of net periodic benefit cost be applied retrospectively, while
changes to amounts capitalized must be applied
prospectively. On December 28, 2017, the FERC issued
Docket AI18-1-000 stating that it will allow entities to change
their capitalization policy for regulatory accounting and
reporting purposes to be consistent with the new US GAAP
requirements. This change will be allowed as a one-time
policy election upon adoption of the guidance. We have
elected to adopt the new ASU for FERC regulatory
accounting and reporting purposes. We anticipate that this
adoption will reduce amounts capitalized to plant. However,
this reduction will be largely offset by deferrals to our
pension regulatory balancing mechanism, and therefore, we
do not expect this standard to materially affect our financial
position.
STATEMENT OF CASH FLOWS. On August 26, 2016, the
FASB issued ASU 2016-15, "Classification of Certain Cash
Receipts and Cash Payments." The ASU adds guidance
pertaining to the classification of certain cash receipts and
payments on the statement of cash flows. The purpose of
the amendment is to clarify issues that have been creating
diversity in practice, including the classification of proceeds
from the settlement of insurance claims and proceeds from
the settlement of corporate-owned life insurance policies.
The amendments in this standard are effective for us
beginning January 1, 2018. We do not expect this standard
to materially affect our financial statements and disclosures.
LEASES. On February 25, 2016, the FASB issued ASU
2016-02, "Leases," which revises the existing lease
accounting guidance. Pursuant to the new standard, lessees
will be required to recognize all leases, including operating
leases that are greater than 12 months at lease
commencement, on the balance sheet and record
corresponding right-of-use assets and lease liabilities.
Lessor accounting will remain substantially the same under
the new standard. Quantitative and qualitative disclosures
are also required for users of the financial statements to
have a clear understanding of the nature of our leasing
activities. The standard is effective for us beginning January
1, 2019. The new standard must be adopted using a
modified retrospective transition and provides for certain
practical expedients. On November 29, 2017, the FASB
proposed an additional practical expedient that would allow
entities to apply the transition requirements on the effective
date of the standard.
On January 25, 2018, the FASB issued ASU 2018-01, "Land
Easement Practical Expedient for Transition to Topic 842", to
address the costs and complexity of applying the transition
provisions of the new lease standard to land easements.
This ASU provides an optional practical expedient to not
evaluate existing or expired land easements that were not
previously accounted for as leases under the current lease
guidance.
We are evaluating additional amendments reached by the
FASB, and we are currently assessing our lease population
and material contracts to determine the effect of this
standard on our financial statements and disclosures. Refer
to Note 14 for our current lease commitments.
64
FINANCIAL INSTRUMENTS. On January 5, 2016, the FASB
issued ASU 2016-01, "Financial Instruments - Overall:
Recognition and Measurement of Financial Assets and
Financial Liabilities." The ASU enhances the reporting model
for financial instruments, which includes amendments to
address aspects of recognition, measurement, presentation,
and disclosure. The new standard is effective for us
beginning January 1, 2018. Any impacts as a result of the
implementation of this ASU will be made through a
cumulative-effect adjustment to the consolidated balance
sheet in the first quarter of 2018. We do not expect this
standard to have a material impact to our financial
statements and disclosures.
REVENUE RECOGNITION. On May 28, 2014, the FASB
issued ASU 2014-09 "Revenue From Contracts with
Customers." Subsequently, the FASB issued additional,
clarifying amendments to address issues and questions
regarding implementation of the new revenue recognition
standard. The underlying principle of the guidance requires
entities to recognize revenue depicting the transfer of goods
or services to customers at amounts the entity is expected to
be entitled to in exchange for those goods or services. The
ASU also prescribes a five-step approach to revenue
recognition: (1) identify the contract(s) with the customer; (2)
identify the separate performance obligations in the
contract(s); (3) determine the transaction price; (4) allocate
the transaction price to separate performance obligations;
and (5) recognize revenue when, or as, each performance
obligation is satisfied. The guidance also requires additional
disclosures, both qualitative and quantitative, regarding the
nature, amount, timing and uncertainty of revenue and cash
flows. The new requirements prescribe either a full
retrospective or modified retrospective adoption method. The
new standard is effective for us beginning January 1, 2018,
and we have elected to adopt the standard using the
modified retrospective approach. We are in the process of
updating our accounting policies, processes, systems, and
internal controls as a result of implementing the new
standard. We have analyzed our revenue streams, material
contracts with customers, and the expanded disclosure
requirements under the new standard and determined that
the standard will not have a material impact on our financial
position, net income, or cash flows.
Accounting Policies
Plant, Property, and Accrued Asset Removal Costs
Plant and property are stated at cost, including capitalized
labor, materials, and overhead. In accordance with
regulatory accounting standards, the cost of acquiring and
constructing long-lived plant and property generally includes
an allowance for funds used during construction (AFUDC) or
capitalized interest. AFUDC represents the regulatory
financing cost incurred when debt and equity funds are used
for construction (see “AFUDC” below). When constructed
assets are subject to market-based rates rather than cost-
based rates, the financing costs incurred during construction
are included in capitalized interest in accordance with U.S.
GAAP, not as regulatory financing costs under AFUDC.
In accordance with long-standing regulatory treatment, our
depreciation rates consist of three components: one based
on the average service life of the asset, a second based on
the estimated salvage value of the asset, and a third based
on the asset’s estimated cost of removal. We collect, through
rates, the estimated cost of removal on certain regulated
properties through depreciation expense, with a
corresponding offset to accumulated depreciation. These
removal costs are non-legal obligations as defined by
regulatory accounting guidance. Therefore, we have
included these costs as non-current regulatory liabilities
rather than as accumulated depreciation on our consolidated
balance sheets. In the rate setting process, the liability for
removal costs is treated as a reduction to the net rate base
on which the regulated utility has the opportunity to earn its
allowed rate of return.
The costs of utility plant retired or otherwise disposed of are
removed from utility plant and charged to accumulated
depreciation for recovery or refund through future rates.
Gains from the sale of regulated assets are generally
deferred and refunded to customers. For non-utility assets,
we record a gain or loss upon the disposal of the property,
and the gain or loss is recorded in operating income or loss
in the consolidated statements of comprehensive income or
loss.
Our provision for depreciation of utility property, plant, and
equipment is recorded under the group method on a straight-
line basis with rates computed in accordance with
depreciation studies approved by regulatory authorities. The
weighted-average depreciation rate for utility assets in
service was approximately 2.8% for 2017, 2016, and 2015,
reflecting the approximate weighted-average economic life of
the property. This includes 2017 weighted-average
depreciation rates for the following asset categories: 2.7%
for transmission and distribution plant, 2.3% for gas storage
facilities, 4.4% for general plant, and 2.7% for intangible and
other fixed assets.
AFUDC. Certain additions to utility plant include AFUDC,
which represents the net cost of debt and equity funds used
during construction. AFUDC is calculated using actual
interest rates for debt and authorized rates for ROE, if
applicable. If short-term debt balances are less than the total
balance of construction work in progress, then a composite
AFUDC rate is used to represent interest on all debt funds,
shown as a reduction to interest charges, and on ROE
funds, shown as other income. While cash is not
immediately recognized from recording AFUDC, it is realized
in future years through rate recovery resulting from the
higher utility cost of service. Our composite AFUDC rate was
5.5% in 2017, 0.7% in 2016, and 0.4% in 2015.
IMPAIRMENT OF LONG-LIVED ASSETS. We review the
carrying value of long-lived assets whenever events or
changes in circumstances indicate the carrying amount of
the assets may not be recoverable. Factors that would
necessitate an impairment assessment of long-lived assets
include a significant adverse change in the extent or manner
in which the asset is used, a significant adverse change in
legal factors or business climate that could affect the value of
the asset, or a significant decline in the observable market
value or expected future cash flows of the asset, among
others.
When such factors are present, we assess the recoverability
by determining whether the carrying value of the asset will
65
be recovered through expected future cash flows. An asset
is determined to be impaired when the carrying value of the
asset exceeds the expected undiscounted future cash flows
from the use and eventual disposition of the asset. If an
impairment is indicated, we record an impairment loss for the
difference between the carrying value and the fair value of
the long-lived assets. Fair value is estimated using
appropriate valuation methodologies, which may include an
estimate of discounted cash flows.
In the fourth quarter of 2017, we recognized a non-cash pre-
tax impairment of long-lived assets at the Gill Ranch Facility
of $192.5 million, which is included in our gas storage
segment. We determined circumstances existed that
indicated the carrying value of the assets may not be
recoverable. Those circumstances included the completion
of a comprehensive strategic review process that evaluated
various alternatives including a potential sale, as well as
contracting for available storage at lower than anticipated
values for the coming storage year. Given these
considerations, management was required to re-evaluate the
estimated cash flows from our interests in the Gill Ranch
Facility, and has determined that those estimated cash flows
are no longer sufficient to cover the carrying value of the
assets. We did not recognize any impairments in 2016 or
2015.
We used the income approach to estimate fair value, using
the estimated future net cash flows of the Gill Ranch Facility.
We also compared the results of the income approach to our
own recent sale process experience and recent market
comparable transactions in order to estimate fair value.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash
equivalents include cash on hand plus highly liquid
investment accounts with original maturity dates of three
months or less. At December 31, 2017 and 2016,
outstanding checks of approximately $4.8 million and $2.9
million, respectively, were included in accounts payable.
Revenue Recognition and Accrued Unbilled Revenue
Utility revenues, derived primarily from the sale and
transportation of natural gas, are recognized upon delivery of
the gas commodity or service to customers. Revenues
include accruals for gas delivered but not yet billed to
customers based on estimates of deliveries from meter
reading dates to month end (accrued unbilled revenue).
Accrued unbilled revenue is dependent upon a number of
factors that require management’s judgment, including total
gas receipts and deliveries, customer use by billing cycle,
and weather factors. Accrued unbilled revenue is reversed
the following month when actual billings occur. Our accrued
unbilled revenue at December 31, 2017 and 2016 was $62.4
million and $64.9 million, respectively.
Non-utility revenues are derived primarily from the gas
storage segment. At our Mist underground storage facility,
revenues are primarily firm service revenues in the form of
fixed monthly reservation charges. At the Gill Ranch Facility,
firm storage services resulting from short-term and long-term
contracts are typically recognized in revenue ratably over the
term of the contract regardless of the actual storage capacity
utilized. In addition, we also have asset management service
revenue from an independent energy marketing company
that optimizes commodity, storage, and pipeline capacity
release transactions. Under this agreement, guaranteed
asset management revenue is recognized using a straight-
line, pro-rata methodology over the term of each contract.
Revenues earned above the guaranteed amount are
recognized as they are earned.
Revenue Taxes
Revenue-based taxes are primarily franchise taxes, which
are collected from customers and remitted to taxing
authorities. Revenue taxes are included in operating
revenues in the statement of comprehensive income or loss.
Revenue taxes were $19.1 million, $17.1 million, and $18.0
million for 2017, 2016, and 2015, respectively.
Accounts Receivable and Allowance for Uncollectible
Accounts
Accounts receivable consist primarily of amounts due for
natural gas sales and transportation services to utility
customers, plus amounts due for gas storage services. We
establish an allowance for uncollectible accounts (allowance)
for trade receivables, including accrued unbilled revenue,
based on the aging of receivables, collection experience of
past due account balances including payment plans, and
historical trends of write-offs as a percent of revenues. A
specific allowance is established and recorded for large
individual customer receivables when amounts are identified
as unlikely to be partially or fully recovered. Inactive
accounts are written-off against the allowance after they are
120 days past due or when deemed uncollectible.
Differences between our estimated allowance and actual
write-offs will occur based on a number of factors, including
changes in economic conditions, customer creditworthiness,
and natural gas prices. The allowance for uncollectible
accounts is adjusted quarterly, as necessary, based on
information currently available.
Inventories
Utility gas inventories, which consist of natural gas in storage
for the utility, are stated at the lower of average cost or net
realizable value. The regulatory treatment of utility gas
inventories provides for cost recovery in customer rates.
Utility gas inventories injected into storage are priced in
inventory based on actual purchase costs. Utility gas
inventories withdrawn from storage are charged to cost of
gas during the current period they are withdrawn at the
weighted-average inventory cost.
Gas storage inventories, which primarily represent
inventories at the Gill Ranch Facility, mainly consist of
natural gas received as fuel-in-kind from storage customers.
Gas storage inventories are valued at the lower of average
cost or net realizable value. Cushion gas is not included in
our inventory balances, is recorded at original cost, and is
classified as a long-term plant asset.
Materials and supplies inventories consist of both utility and
non-utility inventories and are stated at the lower of average
cost or net realizable value.
Our utility and gas storage inventories totaled $36.7 million
and $42.7 million at December 31, 2017 and 2016,
respectively. At December 31, 2017 and 2016, our materials
66
and supplies inventories totaled $11.3 million and $11.4
million, respectively.
Gas Reserves
Gas reserves are payments to acquire and produce natural
gas reserves. Gas reserves are stated at cost, adjusted for
regulatory amortization, with the associated deferred tax
benefits recorded as liabilities on the balance sheet. The
current portion is calculated based on expected gas
deliveries within the next fiscal year. We recognize regulatory
amortization of this asset on a volumetric basis calculated
using the estimated gas reserves and the estimated therms
extracted and sold each month. The amortization of gas
reserves is recorded to cost of gas along with gas production
revenues and production costs. See Note 11.
Derivatives
Derivatives are measured at fair value and recognized as
either assets or liabilities on the balance sheet. Changes in
the fair value of the derivatives are recognized currently in
earnings unless specific regulatory or hedge accounting
criteria are met. Accounting for derivatives and hedges
provides an exception for contracts intended for normal
purchases and normal sales for which physical delivery is
probable. In addition, certain derivative contracts are
approved by regulatory authorities for recovery or refund
through customer rates. Accordingly, the changes in fair
value of these approved contracts are deferred as regulatory
assets or liabilities pursuant to regulatory accounting
principles. Our financial derivatives generally qualify for
deferral under regulatory accounting. Our index-priced
physical derivative contracts also qualify for regulatory
deferral accounting treatment.
Derivative contracts entered into for utility requirements after
the annual PGA rate has been set and maturing during the
PGA year are subject to the PGA incentive sharing
mechanism. In Oregon we participate in a PGA sharing
mechanism under which we are required to select either an
80% or 90% deferral of higher or lower gas costs such that
the impact on current earnings from the gas cost sharing is
either 20% or 10% of gas cost differences compared to PGA
prices, respectively. For the PGA years in Oregon beginning
November 1, 2017, 2016, and 2015, we selected the 90%,
90%, and 80% deferral of gas cost differences, respectively.
In Washington, 100% of the differences between the PGA
prices and actual gas costs are deferred. See Note 13.
Our financial derivatives policy sets forth the guidelines for
using selected derivative products to support prudent risk
management strategies within designated parameters. Our
objective for using derivatives is to decrease the volatility of
gas prices, earnings, and cash flows without speculative risk.
The use of derivatives is permitted only after the risk
exposures have been identified, are determined not to
exceed acceptable tolerance levels, and are determined
necessary to support normal business activities. We do not
enter into derivative instruments for trading purposes.
Fair Value
In accordance with fair value accounting, we use the
following fair value hierarchy for determining inputs for our
debt, pension plan assets, and our derivative fair value
measurements:
•
•
•
Level 1: Valuation is based on quoted prices for identical
instruments traded in active markets;
Level 2: Valuation is based on quoted prices for similar
instruments in active markets, quoted prices for identical
or similar instruments in markets that are not active, and
model-based valuation techniques for which all
significant assumptions are observable in the market;
and
Level 3: Valuation is generated from model-based
techniques that use significant assumptions not
observable in the market. These unobservable
assumptions reflect our own estimates of assumptions
market participants would use in valuing the asset or
liability.
When developing fair value measurements, it is our policy to
use quoted market prices whenever available or to maximize
the use of observable inputs and minimize the use of
unobservable inputs when quoted market prices are not
available. Fair values are primarily developed using industry-
standard models that consider various inputs including: (a)
quoted future prices for commodities; (b) forward currency
prices; (c) time value; (d) volatility factors; (e) current market
and contractual prices for underlying instruments; (f) market
interest rates and yield curves; (g) credit spreads; and (h)
other relevant economic measures. The Company considers
liquid points for its natural gas hedging to be those points for
which there are regularly published prices in a nationally
recognized publication or where the instruments are traded
on an exchange.
Income Taxes
We account for income taxes under the asset and liability
method, which requires the recognition of deferred tax
assets and liabilities for the expected future tax
consequences of events that have been included in the
financial statements. Under this method, deferred tax assets
and liabilities are determined on the basis of the differences
between the financial statement and tax basis of assets and
liabilities using enacted tax rates in effect for the year in
which the differences are expected to reverse. The effect of
a change in tax rates on deferred tax assets and liabilities is
recognized in income in the enactment date period unless a
regulatory Order specifies deferral of the effect of the change
in tax rates over a longer period of time.
Deferred income tax assets and liabilities are also
recognized for temporary differences where the deferred
income tax benefits or expenses have previously been
flowed through in the ratemaking process of the regulated
utility. Regulatory tax assets and liabilities are recorded on
these deferred tax assets and liabilities to the extent we
believe they will be recoverable from or refunded to
customers in future rates.
Deferred investment tax credits on utility plant additions,
which reduce income taxes payable, are deferred for
financial statement purposes and amortized over the life of
the related plant.
We recognize interest and penalties related to unrecognized
tax benefits, if any, within income tax expense and accrued
interest and penalties within the related tax liability line in the
consolidated balance sheets. No accrued interest or
penalties for uncertain tax benefits have been recorded. See
Note 9.
Environmental Contingencies
Loss contingencies are recorded as liabilities when it is
probable a liability has been incurred and the amount of the
loss is reasonably estimable in accordance with accounting
standards for contingencies. Estimating probable losses
requires an analysis of uncertainties that often depend upon
judgments about potential actions by third parties. Accruals
for loss contingencies are recorded based on an analysis of
potential results.
With respect to environmental liabilities and related costs,
we develop estimates based on a review of information
available from numerous sources, including completed
studies and site specific negotiations. It is our policy to
accrue the full amount of such liability when information is
sufficient to reasonably estimate the amount of probable
liability. When information is not available to reasonably
estimate the probable liability, or when only the range of
probable liabilities can be estimated and no amount within
the range is more likely than another, it is our policy to
accrue at the low end of the range. Accordingly, due to
numerous uncertainties surrounding the course of
environmental remediation and the preliminary nature of
several site investigations, in some cases, we may not be
able to reasonably estimate the high end of the range of
possible loss. In those cases, we have disclosed the nature
of the potential loss and the fact that the high end of the
range cannot be reasonably estimated. See Note 15.
Subsequent Events
We monitor significant events occurring after the balance
sheet date and prior to the issuance of the financial
statements to determine the impacts, if any, of events on the
financial statements to be issued. We do not have any
subsequent events to report.
67
3. EARNINGS PER SHARE
Basic earnings or loss per share are computed using net
income or loss and the weighted average number of
common shares outstanding for each period presented.
Diluted earnings per share are computed in the same
manner, except it uses the weighted average number of
common shares outstanding plus the effects of the
assumed exercise of stock options and the payment of
estimated stock awards from other stock-based
compensation plans that are outstanding at the end of each
period presented.
Antidilutive stock awards are excluded from the calculation of diluted earnings or loss per common share. Diluted earnings or
loss per share are calculated as follows:
In thousands, except per share data
Net income (loss)
Average common shares outstanding - basic
Additional shares for stock-based compensation plans (See Note 6)
Average common shares outstanding - diluted
Earnings (loss) per share of common stock - basic
Earnings (loss) per share of common stock - diluted
Additional information:
Antidilutive shares
4. SEGMENT INFORMATION
We primarily operate in two reportable business segments:
local gas distribution and gas storage. We also have other
investments and business activities not specifically related
to one of these two reporting segments, which are
aggregated and reported as other. We refer to our local gas
distribution business as the utility, and our gas storage
segment and other as non-utility. Our utility segment also
includes the utility portion of our Mist underground storage
facility and our North Mist gas storage expansion in Oregon
and NWN Gas Reserves, which is a wholly-owned
subsidiary of Energy Corp. Our gas storage segment
includes NWN Gas Storage, which is a wholly-owned
subsidiary of NWN Energy, Gill Ranch, which is a wholly-
owned subsidiary of NWN Gas Storage, the non-utility
portion of Mist, and all third-party asset management
services. Other includes NNG Financial, non-utility
appliance retail center operations, NWN Water, which is
pursuing investments in the water sector itself and through
its wholly-owned subsidiary FWC Merger Sub, Inc., and
NWN Energy's equity investment in TWH, which is pursuing
development of a cross-Cascades transmission pipeline
project. No individual customer accounts for over 10% of
our operating revenues.
Local Gas Distribution
Our local gas distribution segment is a regulated utility
principally engaged in the purchase, sale, and delivery of
natural gas and related services to customers in Oregon
and southwest Washington. As a regulated utility, we are
responsible for building and maintaining a safe and reliable
pipeline distribution system, purchasing sufficient gas
supplies from producers and marketers, contracting for firm
and interruptible transportation of gas over interstate
pipelines to bring gas from the supply basins into our
service territory, and re-selling the gas to customers subject
to rates, terms, and conditions approved by the OPUC or
WUTC. Gas distribution also includes taking customer-
owned gas and transporting it from interstate pipeline
connections, or city gates, to the customers’ end-use
facilities for a fee, which is approved by the OPUC or
2017
2016
2015
$
(55,623) $
58,895
$
28,669
—
28,669
27,647
132
27,779
$
$
(1.94) $
(1.94) $
2.13
2.12
$
$
53,703
27,347
70
27,417
1.96
1.96
97
5
12
WUTC. Approximately 89% of our customers are located in
Oregon and 11% in Washington. On an annual basis,
residential and commercial customers typically account for
around 60% of our utility’s total volumes delivered and 90%
of our utility’s margin. Industrial customers largely account
for the remaining volumes and utility margin. A small
amount of utility margin is also derived from miscellaneous
services, gains or losses from an incentive gas cost sharing
mechanism, and other service fees.
Industrial sectors we serve include: pulp, paper, and other
forest products; the manufacture of electronic,
electrochemical and electrometallurgical products; the
processing of farm and food products; the production of
various mineral products; metal fabrication and casting; the
production of machine tools, machinery, and textiles; the
manufacture of asphalt, concrete, and rubber; printing and
publishing; nurseries; government and educational
institutions; and electric generation.
Gas Storage
Our gas storage segment includes natural gas storage
services provided to customers primarily from two
underground natural gas storage facilities: the Gill Ranch
Facility and the non-utility portion of our Mist gas storage
facility. In addition to earning revenue from customer
storage contracts, we also use an independent energy
marketing company to provide asset management services
for utility and non-utility capacity, the results of which are
included in this business segment.
Mist Gas Storage Facility
Earnings from non-utility assets at our Mist facility in
Oregon are primarily related to firm storage capacity
revenues. Earnings for the Mist facility also include
revenue, net of amounts shared with utility customers, from
management of utility assets at Mist and upstream pipeline
capacity when not needed to serve utility customers. We
retain 80% of the pre-tax income from these services when
the costs of the capacity have not been included in utility
rates, or 33% of the pre-tax income when the costs have
been included in utility rates. The remaining 20% and 67%,
68
respectively, are recorded to a deferred regulatory account
for crediting back to utility customers.
Gill Ranch Gas Storage Facility
Gill Ranch has a joint project agreement with Pacific
Gas and Electric Company (PG&E) to own and operate the
Gill Ranch Facility, an underground natural gas storage
facility near Fresno, California. Gill Ranch has a 75%
undivided ownership interest in the facility and is also the
operator of the facility, which offers storage services to the
California market at market-based rates, subject to CPUC
regulation including, but not limited to, service terms and
conditions and tariff regulations. Although this is a jointly-
owned property, each owner is independently responsible
for financing its share of the Gill Ranch Facility. As such, the
impairment of long-lived assets at the Gill Ranch Facility
recognized in 2017 reflects our ownership interest.
Revenues are primarily related to firm storage capacity as
well as asset management revenues.
Other
We have non-utility investments and other business
activities, which are aggregated and reported as other.
Other primarily consists of an equity method investment in
TWH, which was formed to build and operate an interstate
gas transmission pipeline in Oregon (TWP), other pipeline
assets in NNG Financial, and non-utility appliance retail
center operations. For more information on TWP, see Note
12. Other also includes some corporate operating and non-
operating revenues and expenses that cannot be allocated
to utility operations. Upon closing agreements to purchase
two water utilities, we expect them to be accounted for as
other.
NNG Financial's assets primarily consist of an active,
wholly-owned subsidiary which owns a 10% interest in an
18-mile interstate natural gas pipeline. NNG Financial’s
total assets were $0.4 million and $0.5 million at December
31, 2017 and 2016, respectively.
Segment Information Summary
Inter-segment transactions were immaterial for the periods presented. The following table presents summary financial
information concerning the reportable segments:
In thousands
2017
Utility
Gas Storage
Other
Total
Operating revenues
$
732,942
$
23,620
$
5,611
$
Depreciation and amortization
Income (loss) from operations (1)
Net income (loss) (2)
Capital expenditures
Total assets at December 31, 2017
2016
79,734
132,807
60,509
211,672
2,961,326
5,844
(185,074)
(116,209)
1,923
59,583
—
(960)
77
—
762,173
85,578
(53,227)
(55,623)
213,595
18,837
3,039,746
Operating revenues
$
650,477
$
25,266
$
224
$
Depreciation and amortization
Income (loss) from operations
Net income (loss) (3)
Capital expenditures
76,289
130,570
54,567
138,074
6,000
9,136
4,303
1,437
—
(426)
25
—
675,967
82,289
139,280
58,895
139,511
Total assets at December 31, 2016
2,806,627
256,333
16,841
3,079,801
2015
Operating revenues
$
702,210
$
21,356
$
225
$
Depreciation and amortization
Income (loss) from operations
Net income (loss) (3)
Capital expenditures
74,410
119,215
53,391
115,272
6,513
5,032
174
3,048
—
1
138
—
723,791
80,923
124,248
53,703
118,320
Total assets at December 31, 2015
2,791,623
261,750
16,037
3,069,410
(1)
(2)
(3)
Includes $192.5 million for an impairment of long-lived assets at the Gill Ranch Facility in Gas Storage.
Includes $21.9 million and $0.6 million of tax benefit in Gas Storage and Other, respectively, and $1.0 million of tax expense in Utility from
the enactment of TCJA. Gas Storage also includes an after-tax impairment of long-lived assets at the Gill Ranch Facility of $141.5 million.
The TCJA was enacted December 22, 2017 and resulted in the federal tax rate changing from 35% to 21%. The after-tax impairment
charge is calculated using our new combined federal and state statutory rate of 26.5%.
Includes $2.0 million in 2016 and $9.1 million in 2015 of after-tax regulatory environmental disallowance charges in Utility.
Utility Margin
Utility margin is a financial measure consisting of utility
operating revenues, which are reduced by revenue taxes,
the associated cost of gas, and environmental recovery
revenues. The cost of gas purchased for utility customers is
generally a pass-through cost in the amount of revenues
billed to regulated utility customers. Environmental recovery
revenues represent collections received from customers
through our environmental recovery mechanism in Oregon.
These collections are offset by the amortization of
environmental liabilities, which is presented as
environmental remediation expense in our operating
expenses. By subtracting cost of gas and environmental
remediation expense from utility operating revenues, utility
margin provides a key metric used by our chief operating
decision maker in assessing the performance of the utility
69
segment. The gas storage segment and other emphasize
growth in operating revenues as opposed to margin
because they do not incur a product cost (i.e. cost of gas
sold) like the utility and, therefore, use operating revenues
and net income to assess performance.
The following table presents additional segment information concerning utility margin:
In thousands
Utility margin calculation:
Utility operating revenues
Less: Utility cost of gas
Environmental remediation expense
Utility margin
5. COMMON STOCK
Common Stock
As of December 31, 2017 and 2016, we had 100 million
shares of common stock authorized. As of December 31,
2017, we had reserved 43,058 shares for issuance of
common stock under the Employee Stock Purchase Plan
(ESPP) and 155,086 shares under our Dividend
Reinvestment and Direct Stock Purchase Plan (DRPP). At
our election, shares sold through our DRPP may be
purchased in the open market or through original issuance
of shares reserved for issuance under the DRPP.
The Restated Stock Option Plan (SOP) was terminated with
respect to new grants in 2012; however, options granted
before the Restated SOP was terminated will remain
outstanding until the earlier of their expiration, forfeiture, or
exercise. There were 91,688 options outstanding at
December 31, 2017, which were granted prior to termination
of the plan.
During November 2016, we completed an equity issuance
consisting of an offering of 880,000 shares of its common
stock along with a 30-day option for the underwriters to
purchase an additional 132,000 shares. The offering closed
on November 16, 2016 and resulted in a total issuance of
1,012,000 shares as both the initial offering and the
underwriter option were fully executed. All shares were
issued on November 16, 2016 at an offering price of $54.63
per share and resulted in total net proceeds of $52.8 million.
Stock Repurchase Program
We have a share repurchase program under which we may
purchase our common shares on the open market or
through privately negotiated transactions. We currently have
Board authorization through May 2018 to repurchase up to
an aggregate of the greater of 2.8 million shares or $100
million. No shares of common stock were repurchased
pursuant to this program during the year ended December
31, 2017. Since the plan’s inception in 2000, a total of 2.1
million shares have been repurchased at a total cost of
$83.3 million.
2017
2016
2015
$
$
732,942
$
650,477
$
325,019
15,291
260,588
13,298
702,210
327,305
3,513
392,632
$
376,591
$
371,392
Summary of Changes in Common Stock
The following table shows the changes in the number of
shares of our common stock issued and outstanding:
In thousands
Balance, December 31, 2014
Sales to employees under ESPP
Stock-based compensation
Sales to shareholders under DRPP
Balance, December 31, 2015
Sales to employees under ESPP
Stock-based compensation
Equity Issuance
Balance, December 31, 2016
Sales to employees under ESPP
Stock-based compensation
Balance, December 31, 2017
Shares
27,284
19
78
46
27,427
18
173
1,012
28,630
18
88
28,736
6. STOCK-BASED COMPENSATION
Our stock-based compensation plans are designed to
promote stock ownership in NW Natural by employees and
officers. These compensation plans include a Long Term
Incentive Plan (LTIP), an ESPP, and a Restated SOP.
Long Term Incentive Plan
The LTIP is intended to provide a flexible, competitive
compensation program for eligible officers and key
employees. Under the LTIP, shares of common stock are
authorized for equity incentive grants in the form of stock,
restricted stock, restricted stock units, stock options, or
performance shares. An aggregate of 1,100,000 shares
were authorized for issuance as of December 31, 2017.
Shares awarded under the LTIP may be purchased on the
open market or issued as original shares.
Of the 1,100,000 shares of common stock authorized for
LTIP awards at December 31, 2017, there were 626,960
shares available for issuance under any type of award. This
assumes market, performance, and service-based grants
currently outstanding are awarded at the target level. There
were no outstanding grants of restricted stock or stock
options under the LTIP at December 31, 2017 or 2016. The
LTIP stock awards are compensatory awards for which
compensation expense is based on the fair value of stock
awards, with expense being recognized over the
70
performance and vesting period of the outstanding awards.
Forfeitures are recognized as they occur.
Performance Shares
Since the LTIP’s inception in 2001, performance shares,
which incorporate market, performance, and service-based
factors, have been granted annually with three-year
performance periods. The following table summarizes
performance share expense information:
Dollars in thousands
Estimated award:
2015-2017 grant(3)
Actual award:
2014-2016 grant
2013-2015 grant
Shares(1)
Expense
During Award
Year(2)
Total
Expense
for Award
18,300
$
(346) $
1,169
31,388
8,914
168
312
1,685
1,240
(1)
In addition to common stock shares, a participant also
receives a dividend equivalent cash payment equal to the
number of shares of common stock received on the award
payout multiplied by the aggregate cash dividends paid per
share during the performance period.
(2) Amount represents the expense recognized in the third year of
(3)
the vesting period noted above. For the 2015-2017 grant, we
did not meet targets and reversed expense during 2017 that
had been previously recognized.
This represents the estimated number of shares to be
awarded as of December 31, 2017 as certain performance
share measures had been achieved. Amounts are subject to
change with final payout amounts authorized by the Board of
Directors in February 2018.
The aggregate number of performance shares granted and
outstanding at the target and maximum levels were as
follows:
Dollars in
thousands
Performance
Period
Performance Share
Awards Outstanding
2017
Cumulative
Expense
Target
Maximum
Expense/
(Reversal)
December
31, 2017
59,934
$
(346) $
1,169
2015-17
2016-18
2017-19
Total
29,967
24,826
32,680
49,652
65,360
87,473
174,946
$
337
942
933
815
942
For the 2015-2017 and 2016-2018 plan years, performance
share awards are based on EPS and Return on Invested
Capital (ROIC) factors and a total shareholder return (TSR
factor) relative to the Dow Jones U.S. Gas Distribution peer
group over the three-year performance period. Additionally,
these plans are based on performance results achieved
relative to specific core and non-core strategies (strategic
factor). For the 2017-2019 plan year, performance share
awards are based on the achievement of EPS and ROIC
factors, which can be modified by a TSR factor relative to
the performance of the Russell 2500 Utilities Index over the
three-year performance period and a growth modifier based
on accumulative EBITA measure.
Compensation expense is recognized in accordance with
accounting standards for stock-based compensation and
calculated based on performance levels achieved and an
71
estimated fair value using the Monte-Carlo method. The
weighted-average grant date fair value of nonvested shares
at December 31, 2017 and 2016 was $56.40 and $50.83 per
share, respectively. The weighted-average grant date fair
value of shares granted during the year was $57.05 per
share and for shares vested during the year was $52.02 per
share. As of December 31, 2017, there was $2.8 million of
unrecognized compensation expense related to the
nonvested portion of performance awards expected to be
recognized through 2019.
Restricted Stock Units
In 2012, we began granting RSUs under the LTIP instead of
stock options under the Restated SOP. Generally, the RSUs
awarded are forfeitable and include a performance-based
threshold as well as a vesting period of four years from the
grant date. Upon vesting, the RSU holder is issued one
share of common stock plus a cash payment equal to the
total amount of dividends paid per share between the grant
date and vesting date of that portion of the RSU. The fair
value of an RSU is equal to the closing market price of the
Company's common stock on the grant date. During 2017,
total RSU expense was $1.6 million compared to $1.5
million in 2016 and $1.3 million in 2015. As of December 31,
2017, there was $3.1 million of unrecognized compensation
cost from grants of RSUs, which is expected to be
recognized over a period extending through 2022.
Information regarding the RSU activity is summarized as
follows:
Number
of
RSUs
Weighted -
Average
Price Per
RSU
Nonvested, December 31, 2014
70,794
$
Granted
Vested
Forfeited
Nonvested, December 31, 2015
Granted
Vested
Forfeited
Nonvested, December 31, 2016
Granted
Vested
Forfeited
Nonvested, December 31, 2017
37,264
(19,003)
(468)
88,587
40,271
(29,488)
(9,397)
89,973
32,168
(35,341)
(2,278)
84,522
44.00
46.29
44.81
44.99
44.78
54.36
45.56
44.59
48.85
60.51
47.07
53.78
53.90
Restated Stock Option Plan
The Restated SOP was terminated for new option grants in
2012; however, options granted before the plan terminated
will remain outstanding until the earlier of their expiration,
forfeiture, or exercise. Any new grants of stock options
would be made under the LTIP, however, no option grants
have been awarded since 2012 and all stock options were
vested as of December 31, 2015.
Options under the Restated SOP were granted to officers
and key employees designated by a committee of our Board
of Directors. All options were granted at an option price
equal to the closing market price on the date of grant and
may be exercised for a period of up to 10 years and seven
days from the date of grant. Option holders may exchange
shares they have owned for at least six months, valued at
the current market price, to purchase shares at the option
price.
Information regarding the Restated SOP activity is
summarized as follows:
Weighted -
Average
Price Per
Share
Intrinsic
Value
(In millions)
Option
Shares
Balance outstanding,
December 31, 2014
416,088
$
43.40
$
Exercised
Forfeited
Balance outstanding,
December 31, 2015
Exercised
Forfeited
Balance outstanding,
December 31, 2016
Exercised
Forfeited
Balance outstanding
and exercisable,
December 31, 2017
(62,900)
(500)
352,688
(172,525)
—
180,163
(88,275)
(200)
39.96
45.74
44.00
43.61
n/a
44.38
44.33
41.15
91,688
44.43
2.7
0.5
n/a
2.3
2.0
n/a
2.8
1.8
n/a
1.4
During 2017, cash of $3.9 million was received for stock
options exercised and $0.5 million related tax expense was
recognized. The weighted-average remaining life of options
exercisable and outstanding at December 31, 2017 was
2.47 years.
Employee Stock Purchase Plan
The ESPP allows employees to purchase common stock at
85% of the closing price on the trading day immediately
preceding the initial offering date, which is set annually.
Each eligible employee may purchase up to $21,199 worth
of stock through payroll deductions over a period defined by
the Board of Directors, which is currently a 12-month period,
with shares issued at the end of the 12-month subscription
period.
Stock-Based Compensation Expense
Stock-based compensation expense is recognized as
operations and maintenance expense or is capitalized as
part of construction overhead. The following table
summarizes the financial statement impact of stock-based
compensation under our LTIP, Restated SOP and ESPP:
In thousands
2017
2016
2015
Operations and maintenance
expense, for stock-based
compensation
$ 2,354 $ 2,370 $ 2,673
Income tax benefit
(930)
(924)
(1,012)
Net stock-based compensation
effect on net income (loss)
$ 1,424 $ 1,446 $ 1,661
Amounts capitalized for stock-based
compensation
$
528 $
554 $
661
7. DEBT
Short-Term Debt
Our primary source of short-term funds is from the sale of
commercial paper and bank loans. In addition to issuing
commercial paper or bank loans to meet seasonal working
capital requirements, short-term debt is used temporarily to
fund capital requirements. Commercial paper and bank
loans are periodically refinanced through the sale of long-
term debt or equity securities. Our commercial paper
program is supported by one or more committed credit
facilities.
At December 31, 2017 and 2016, total short-term debt
outstanding was $54.2 million and $53.3 million,
respectively, which was comprised entirely of commercial
paper. The weighted average interest rate at December 31,
2017 and 2016 was 1.9% and 0.8%, respectively.
The carrying cost of our commercial paper approximates fair
value using Level 2 inputs, due to the short-term nature of
the notes. See Note 2 for a description of the fair value
hierarchy. At December 31, 2017, our commercial paper had
a maximum remaining maturity of 11 days and an average
remaining maturity of 6 days.
We have a $300.0 million credit agreement, with a feature
that allows us to request increases in the total commitment
amount up to a maximum amount of $450.0 million. The
maturity of the agreement is December 20, 2019. We have
a letter of credit of $100.0 million. Any principal and unpaid
interest owed on borrowings under the agreement is due
and payable on or before the expiration date. There were no
outstanding balances under the agreement and no letters of
credit issued or outstanding at December 31, 2017 and
2016.
The credit agreement requires that we maintain credit
ratings with Standard & Poor’s (S&P) and Moody’s Investors
Service, Inc. (Moody’s) and notify the lenders of any change
in our senior unsecured debt ratings or senior secured debt
ratings, as applicable, by such rating agencies. A change in
our debt ratings is not an event of default, nor is the
maintenance of a specific minimum level of debt rating a
condition of drawing upon the credit facility. However,
interest rates on any loans outstanding under the credit
facility are tied to debt ratings, which would increase or
decrease the cost of any loans under the credit facility when
ratings are changed.
The credit agreement also requires us to maintain a
consolidated indebtedness to total capitalization ratio of
70% or less. Failure to comply with this covenant would
entitle the lenders to terminate their lending commitments
and accelerate the maturity of all amounts outstanding. We
were in compliance with this covenant at December 31,
2017 and 2016.
Long-Term Debt
The issuance of FMBs, which includes our medium-term
notes, under the Mortgage and Deed of Trust (Mortgage) is
limited by eligible property, adjusted net earnings, and other
provisions of the Mortgage. The Mortgage constitutes a first
mortgage lien on substantially all of our utility property.
72
Maturities and Outstanding Long-Term Debt
Retirement of long-term debt for each of the 12-month
periods through December 31, 2022 and thereafter are as
follows:
In thousands
Year
2018
2019
2020
2021
2022
$
97,000
30,000
75,000
60,000
—
Fair Value of Long-Term Debt
Our outstanding debt does not trade in active markets. We
estimate the fair value of our debt using utility companies
with similar credit ratings, terms, and remaining maturities to
our debt that actively trade in public markets. These
valuations are based on Level 2 inputs as defined in the fair
value hierarchy. See Note 2.
The following table provides an estimate of the fair value of
our long-term debt, including current maturities of long-term
debt, using market prices in effect on the valuation date:
Thereafter
524,700
In thousands
The following table presents our debt outstanding as of
December 31:
In thousands
First Mortgage Bonds
2017
2016
Gross long-term debt
Unamortized debt
issuance costs
Carrying amount
Estimated fair value
$
$
$
December 31,
2017
2016
786,700
$
726,700
(6,813)
779,887
853,339
$
$
(7,377)
719,323
793,339
8. PENSION AND OTHER POSTRETIREMENT
BENEFIT COSTS
We maintain a qualified non-contributory defined benefit
pension plan, non-qualified supplemental pension plans for
eligible executive officers and other key employees, and
other postretirement employee benefit plans. We also have
a qualified defined contribution plan (Retirement K Savings
Plan) for all eligible employees. The qualified defined benefit
pension plan and Retirement K Savings Plan have plan
assets, which are held in qualified trusts to fund retirement
benefits.
Effective January 1, 2007 and 2010, the qualified defined
benefit pension plans and postretirement benefits for non-
union employees and union employees, respectively, were
closed to new participants.
These plans were not available to employees of our non-
utility subsidiaries. Non-union and union employees hired or
re-hired after December 31, 2006 and 2009, respectively,
and employees of NW Natural subsidiaries are provided an
enhanced Retirement K Savings Plan benefit.
Effective December 31, 2012, the qualified defined benefit
pension plans for non-union and union employees were
merged into a single plan.
7.000 % Series B due 2017
1.545 % Series B due 2018
6.600 % Series B due 2018
8.310 % Series B due 2019
7.630 % Series B due 2019
5.370 % Series B due 2020
9.050 % Series A due 2021
3.176 % Series B due 2021
3.542 % Series B due 2023
5.620 % Series B due 2023
7.720 % Series B due 2025
6.520 % Series B due 2025
7.050 % Series B due 2026
3.211 % Series B due 2026
7.000 % Series B due 2027
2.822 % Series B due 2027
6.650 % Series B due 2027
6.650 % Series B due 2028
7.740 % Series B due 2030
7.850 % Series B due 2030
5.820 % Series B due 2032
5.660 % Series B due 2033
5.250 % Series B due 2035
4.000 % Series B due 2042
4.136 % Series B due 2046
3.685 % Series B due 2047
Less: Current maturities
$
— $
75,000
22,000
10,000
20,000
75,000
10,000
50,000
50,000
40,000
20,000
10,000
20,000
35,000
20,000
25,000
19,700
10,000
20,000
10,000
30,000
40,000
10,000
50,000
40,000
75,000
786,700
97,000
40,000
75,000
22,000
10,000
20,000
75,000
10,000
50,000
50,000
40,000
20,000
10,000
20,000
35,000
20,000
—
19,700
10,000
20,000
10,000
30,000
40,000
10,000
50,000
40,000
—
726,700
40,000
Total long-term debt
$ 689,700
$ 686,700
First Mortgage Bonds
We issued $100.0 million of FMBs in September 2017
consisting of $25.0 million with a coupon rate of 2.822% and
maturity date in 2027 and $75 million with a coupon rate of
3.685% and maturity date in 2047.
Retirements of Long-Term Debt
We redeemed $40.0 million of FMBs with a coupon rate of
7.000% in August 2017.
73
The following table provides a reconciliation of the changes in benefit obligations and fair value of plan assets, as applicable, for
the pension and other postretirement benefit plans, excluding the Retirement K Savings Plan, and a summary of the funded
status and amounts recognized in the consolidated balance sheets as of December 31:
In thousands
Reconciliation of change in benefit obligation:
Obligation at January 1
Service cost
Interest cost
Net actuarial (gain) loss
Benefits paid(1)
Obligation at December 31
Reconciliation of change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Benefits paid(1)
Fair value of plan assets at December 31
Funded status at December 31
Postretirement Benefit Plans
Pension Benefits
Other Benefits
2017
2016
2017
2016
$
457,839
$
445,628
$
29,395
$
31,049
7,090
18,111
34,829
7,083
18,399
7,688
(31,580)
(20,959)
341
1,141
(213)
(1,737)
391
1,175
(1,488)
(1,732)
$
486,289
$
457,839
$
28,927
$
29,395
$
257,714
$
249,338
$
40,308
21,483
12,593
16,742
(31,580)
(20,959)
— $
—
1,737
(1,737)
287,925
$
257,714
$
— $
—
—
1,732
(1,732)
—
(198,364) $
(200,125) $
(28,927) $
(29,395)
$
$
(1)
In 2017, we completed a partial buy-out of our qualified defined benefit pension plan in which $9.3 million of plan assets and $8.7 million
liabilities were transferred to an insurer to provide annuities for buy-out plan participants.
Our qualified defined benefit pension plan has an aggregate benefit obligation of $449.7 million and $423.5 million at December
31, 2017 and 2016, respectively, and fair values of plan assets of $287.9 million and $257.7 million, respectively. The following
table presents amounts realized through regulatory assets or in other comprehensive loss (income) for the years ended
December 31:
Regulatory Assets
Other Comprehensive Loss (Income)
Pension Benefits
Other Postretirement Benefits
Pension Benefits
In thousands
2017
2016
2015
2017
2016
2015
2017
2016
2015
Net actuarial loss (gain)
$ 12,177
$ 14,005
$
419
$
(214) $ (1,488) $
2,724
$
2,777
$
(1,196) $
(2,549)
Settlement Loss
Amortization of:
Prior service cost
Actuarial loss
—
—
—
—
—
—
(127)
(230)
(230)
(14,802)
(13,238)
(16,372)
468
(696)
468
(705)
(197)
(554)
—
—
(946)
193
—
1,386
—
—
(2,236)
Total
$ (2,752) $
537
$ (16,183) $
(442) $ (1,725) $
1,973
$
1,831
$
383
$
(4,785)
The following table presents amounts recognized in regulatory assets and accumulated other comprehensive loss (AOCL) at
December 31:
In thousands
Prior service cost (credit)
Net actuarial loss
Total
Regulatory Assets
AOCL
Pension Benefits
Other Postretirement Benefits
Pension Benefits
2017
2016
2017
2016
2017
2016
$
$
49
$
176
$
(2,206) $
(2,675) $
— $
175,035
177,660
6,964
7,874
13,266
175,084
$
177,836
$
4,758
$
5,199
$
13,266
$
1
11,434
11,435
74
The following table presents amounts recognized in AOCL and the changes in AOCL related to our non-qualified employee
benefit plans:
In thousands
Beginning balance
Amounts reclassified to AOCL
Amounts reclassified from AOCL:
Amortization of actuarial losses
Loss from plan settlement
Total reclassifications before tax
Tax expense (benefit)
Total reclassifications for the period
Ending balance
In 2018, an estimated $17.3 million will be amortized from
regulatory assets to net periodic benefit costs, consisting of
$17.7 million of actuarial losses, and $0.4 million of prior
service credits. A total of $0.8 million will be amortized from
AOCL to earnings related to actuarial losses in 2018.
Our assumed discount rate for the pension plan and other
postretirement benefit plans was determined independently
based on the Citigroup Above Median Curve (discount rate
curve), which uses high quality corporate bonds rated AA- or
higher by S&P or Aa3 or higher by Moody’s. The discount
rate curve was applied to match the estimated cash flows in
each of our plans to reflect the timing and amount of
expected future benefit payments for these plans.
Our assumed expected long-term rate of return on plan
assets for the qualified pension plan was developed using a
weighted-average of the expected returns for the target
asset portfolio. In developing the expected long-term rate of
return assumption, consideration was given to the historical
performance of each asset class in which the plan’s assets
are invested and the target asset allocation for plan assets.
Our investment strategy and policies for qualified pension
plan assets held in the retirement trust fund were approved
by our Retirement Committee, which is composed of senior
management with the assistance of an outside investment
consultant. The policies set forth the guidelines and
objectives governing the investment of plan assets. Plan
assets are invested for total return with appropriate
consideration for liquidity, portfolio risk, and return
expectations. All investments are expected to satisfy the
prudent investments rule under the Employee Retirement
Income Security Act of 1974. The approved asset classes
may include cash and short-term investments, fixed income,
common stock and convertible securities, absolute and real
return strategies, real estate, and investments in NW
Natural securities. Plan assets may be invested in
separately managed accounts or in commingled or mutual
funds. Investment re-balancing takes place periodically as
needed, or when significant cash flows occur, in order to
maintain the allocation of assets within the stated target
ranges. The retirement trust fund is not currently invested in
Year Ended December 31,
2017
2016
(6,951) $
(2,794)
946
—
(1,848)
361
(1,487)
(8,438) $
(7,162)
(1,196)
1,386
193
383
(172)
211
(6,951)
$
$
NW Natural securities.
The following table presents the pension plan asset target
allocation at December 31, 2017:
Asset Category
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Long government/credit
High yield bonds
Emerging market debt
Real estate funds
Target Allocation
29.3%
6.9
28.0
11.8
17.5
2.0
3.5
1.0
Our non-qualified supplemental defined benefit plan
obligations were $36.6 million and $34.3 million at
December 31, 2017 and 2016, respectively. These plans are
not subject to regulatory deferral, and the changes in
actuarial gains and losses, prior service costs, and transition
assets or obligations are recognized in AOCL, net of tax
until they are amortized as a component of net periodic
benefit cost. These are unfunded, non-qualified plans with
no plan assets; however, we indirectly fund a significant
portion of our obligations with company and trust-owned life
insurance and other assets.
Our other postretirement benefit plans are unfunded plans
but are subject to regulatory deferral. The actuarial gains
and losses, prior service costs, and transition assets or
obligations for these plans are recognized as a regulatory
asset.
Net periodic benefit costs consist of service costs, interest
costs, the amortization of actuarial gains and losses, and
the expected returns on plan assets, which are based in part
on a market-related valuation of assets. The market-related
valuation reflects differences between expected returns and
actual investment returns with the differences recognized
over a three-year or less period from the year in which they
occur, thereby reducing year-to-year net periodic benefit
cost volatility.
75
The following table provides the components of net periodic benefit cost for our pension and other postretirement benefit plans
for the years ended December 31:
In thousands
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service costs
Amortization of net actuarial loss
Settlement expense
Net periodic benefit cost
Amount allocated to construction
Amount deferred to regulatory balancing account(1)
Pension Benefits
Other Postretirement Benefits
2017
2016
2015
2017
2016
2015
$
7,090
$
7,083
$
8,267
$
341
$
391
$
18,111
(20,433)
127
15,748
—
20,643
(6,597)
(6,542)
18,399
18,360
1,141
1,175
(20,054)
(20,676)
231
14,624
193
20,476
(5,746)
(6,252)
231
18,609
—
24,791
(6,834)
(8,241)
—
(468)
696
—
1,710
(587)
—
—
(468)
705
—
1,803
(600)
—
527
1,179
—
197
554
—
2,457
(808)
—
Net amount charged to expense
$
7,504
$
8,478
$
9,716
$
1,123
$
1,203
$
1,649
(1) The deferral of defined benefit pension plan expenses above or below the amount set in rates was approved by the OPUC, with recovery of
these deferred amounts through the implementation of a balancing account. The balancing account includes the expectation of higher net
periodic benefit costs than costs recovered in rates in the near-term with lower net periodic benefit costs than costs recovered in rates
expected in future years. Deferred pension expense balances include accrued interest at the utility’s authorized rate of return, with the
equity portion of the interest recognized when amounts are collected in rates.
Net periodic benefit costs are reduced by amounts
capitalized to utility plant based on approximately 25% to
35% payroll overhead charge. In addition, a certain amount
of net periodic benefit costs are recorded to the regulatory
balancing account for pensions.
Net periodic pension cost less amounts charged to capital
accounts and regulatory balancing accounts are expenses
recognized in earnings.
The following table provides the assumptions used in measuring periodic benefit costs and benefit obligations for the years
ended December 31:
Pension Benefits
Other Postretirement Benefits
2017
2016
2015
2017
2016
2015
Assumptions for net periodic benefit cost:
Weighted-average discount rate
3.99%
4.17%
3.82%
3.85%
4.00%
3.74%
Rate of increase in compensation
3.25-4.5%
3.25-4.5%
3.25-5.0%
Expected long-term rate of return
7.50%
7.50%
7.50%
n/a
n/a
n/a
n/a
n/a
n/a
Assumptions for year-end funded status:
Weighted-average discount rate
3.52%
4.00%
4.21%
3.44%
3.85%
4.00%
Rate of increase in compensation
3.25-4.5%
3.25-4.5%
3.25-4.5%
Expected long-term rate of return
7.50%
7.50%
7.50%
n/a
n/a
n/a
n/a
n/a
n/a
The assumed annual increase in health care cost trend
rates used in measuring other postretirement benefits as of
December 31, 2017 was 7.50%. These trend rates apply to
both medical and prescription drugs. Medical costs and
prescription drugs are assumed to decrease gradually each
year to a rate of 4.75% by 2026.
Assumed health care cost trend rates can have a significant
effect on the amounts reported for the health care plans;
however, other postretirement benefit plans have a cap on
the amount of costs reimbursable by us.
A one percentage point change in assumed health care cost
trend rates would have the following effects:
In thousands
1% Increase
1% Decrease
Effect on net periodic
postretirement health care
benefit cost
Effect on the accumulated
postretirement benefit obligation
$
44
$
(39)
478
(428)
We review mortality assumptions annually and will update
for material changes as necessary. In 2017, our mortality
rate assumptions were updated from RP-2006 mortality
tables for employees and healthy annuitants with a fully
generational projection using scale MP-2016 to
corresponding RP-2006 mortality tables using scale
MP-2017, which partially offset increases of our projected
benefit obligation.
76
The following table provides information regarding employer
contributions and benefit payments for the qualified pension
plan, non-qualified pension plans, and other postretirement
benefit plans for the years ended December 31, and
estimated future contributions and payments:
In thousands
Pension Benefits
Other Benefits
$
16,742
$
Employer Contributions:
2016
2017
2018 (estimated)
Benefit Payments:
2015
2016
2017
Estimated Future Benefit Payments:
2018
2019
2020
2021
2022
2023-2027
21,483
17,710
35,923
20,959
31,580
22,679
23,546
24,542
25,471
26,095
145,065
1,732
1,737
1,835
2,018
1,732
1,737
1,835
1,871
1,861
1,904
1,886
9,261
Employer Contributions to Company-Sponsored
Defined Benefit Pension Plans
We make contributions to our qualified defined benefit
pension plans based on actuarial assumptions and
estimates, tax regulations, and funding requirements under
federal law. The Pension Protection Act of 2006 (the Act)
established funding requirements for defined benefit plans.
The Act establishes a 100% funding target over seven years
for plan years beginning after December 31, 2008. In 2012
the Moving Ahead for Progress in the 21st Century Act
(MAP-21) legislation changed several provisions affecting
pension plans, including temporary funding relief and
Pension Benefit Guaranty Corporation (PBGC) premium
increases, which reduces the level of minimum required
contributions in the near-term but generally increases
contributions in the long-run and increases the operational
costs of running a pension plan. In 2014, the Highway and
Transportation Funding Act (HATFA) was signed and
extends certain aspects of MAP-21 as well as modifies the
phase-out periods for the limitations.
Our qualified defined benefit pension plan is currently
underfunded by $161.7 million at December 31, 2017.
Including the impacts of MAP-21 and HATFA, we made
cash contributions totaling $19.4 million to our qualified
defined benefit pension plan for 2017. During 2018, we
expect to make contributions of approximately $15.5 million
to this plan.
Multiemployer Pension Plan
In addition to the Company-sponsored defined benefit plans
presented above, prior to 2014 we contributed to a
multiemployer pension plan for our utility's union employees
known as the Western States Office and Professional
Employees International Union Pension Fund (Western
States Plan). The plan's employer identification number is
94-6076144. Effective December 22, 2013, we withdrew
77
from the plan, which was a noncash transaction. Vested
participants will receive all benefits accrued through the date
of withdrawal. As the plan was underfunded at the time of
withdrawal, we were assessed a withdrawal liability of $8.3
million, plus interest, which requires NW Natural to pay $0.6
million each year to the plan for 20 years beginning in July
2014. The cost of the withdrawal liability was deferred to a
regulatory account on the balance sheet.
We made payments of $0.6 million for 2017, and as of
December 31, 2017 the liability balance was $7.1 million.
For 2016 and 2015, contributions to the plan were $0.6
million and $0.6 million, respectively, which was
approximately 4% to 5% of the total contributions to the plan
by all employer participants in those years.
Defined Contribution Plan
The Retirement K Savings Plan is a qualified defined
contribution plan under Internal Revenue Code Sections
401(a) and 401(k). Employer contributions totaled $5.4
million, $4.6 million, and $3.7 million for 2017, 2016, and
2015, respectively. The Retirement K Savings Plan includes
an Employee Stock Ownership Plan.
Deferred Compensation Plans
The supplemental deferred compensation plans for eligible
officers and senior managers are non-qualified plans. These
plans are designed to enhance the retirement savings of
employees and to assist them in strengthening their
financial security by providing an incentive to save and
invest regularly.
Fair Value
Below is a description of the valuation methodologies used
for assets measured at fair value. In cases where the
pension plan is invested through a collective trust fund or
mutual fund, the fund's market value is utilized. Market
values for investments directly owned are also utilized.
U.S. LARGE CAP EQUITY and U.S. SMALL/MID CAP
EQUITY. These are Level 1 and non-published net asset
value (NAV) assets. The Level 1 assets consist of directly
held stocks and mutual funds with a readily determinable
fair value, including a published NAV. The non-published
NAV assets consist of commingled trusts where NAV is not
published but the investment can be readily disposed of at
NAV or market value. Directly held stocks are valued at the
closing price reported in the active market on which the
individual security is traded. Mutual funds and commingled
trusts are valued at NAV and the unit price, respectively.
This asset class includes investments primarily in U.S.
common stocks.
NON-U.S. EQUITY. These are Level 1 and non-published NAV
assets. The Level 1 assets consist of directly held stocks,
and the non-published NAV assets consist of commingled
trusts where the NAV/unit price is not published but the
investment can be readily disposed of at the NAV/unit price.
Directly held stocks are valued at the closing price reported
in the active market on which the individual security is
traded, and the commingled trusts are valued at unit price.
This asset class includes investments primarily in foreign
equity common stocks.
EMERGING MARKETS EQUITY. These are non-published
NAV assets consisting of an open-end mutual fund where
the NAV price is not published but the investment can be
readily disposed of at the NAV, and a commingled trust
where the investment can be readily disposed of at unit
price. This asset class includes investments primarily in
common stocks in emerging markets.
FIXED INCOME. These are non-published NAV assets
consisting of a commingled trust, valued at unit price, where
unit price is not published, but the investment can be readily
disposed of at the unit price. This asset class includes
investments primarily in investment grade debt and fixed
income securities.
LONG GOVERNMENT/CREDIT. These are non-published NAV
and Level 2 assets. The non-published NAV assets include
commingled trusts, valued at unit price, where unit price is
not published, but the investment can be readily disposed of
at the unit price. The Level 2 assets consist of directly held
fixed-income securities, with readily determinable fair
values, whose values are determined by closing prices if
available and by matrix prices for illiquid securities. This
asset class includes long duration fixed income investments
primarily in U.S. treasuries, U.S. government agencies,
municipal securities, mortgage-backed securities, asset-
backed securities, as well as U.S. and international
investment-grade corporate bonds.
HIGH YIELD BONDS. These are non-published NAV assets,
consisting of a limited partnership and a commingled trust
where the valuation is not published but the investment can
be readily disposed of at market value, valued at NAV or
unit price, respectively. This asset class includes
investments primarily in high yield bonds.
EMERGING MARKET DEBT. This is a non-published NAV
asset consisting of a commingled trust with a readily
determinable fair value, where unit price is not published,
but the investment can be readily disposed of at the unit
price. This asset class includes investments primarily in
emerging market debt.
REAL ESTATE. These are Level 1 and non-published NAV
assets. The Level 1 asset is a mutual fund with a readily
determinable fair value, including a published NAV. The non-
published NAV asset is a commingled trust with a readily
determinable fair value, where unit price is not published,
but the investment can be readily disposed of at the unit
price. This asset class includes investments primarily in real
estate investment trust (REIT) equity securities globally.
ABSOLUTE RETURN STRATEGY. This is a non-published
NAV asset consisting of a hedge fund of funds where the
valuation is not published. This hedge fund of funds is
winding down. Based on recent dispositions, we believe the
remaining investment is fairly valued. The hedge fund of
funds is valued at the weighted average value of
investments in various hedge funds, which in turn are
valued at the closing price of the underlying securities. This
asset class primarily includes investments in common
stocks and fixed income securities.
CASH AND CASH EQUIVALENTS. These are Level 1 and non-
published NAV assets. The Level 1 assets consist of cash in
U.S. dollars, which can be readily disposed of at face value.
The non-published NAV assets represent mutual funds
without published NAV's but the investment can be readily
disposed of at the NAV. The mutual funds are valued at the
NAV of the shares held by the plan at the valuation date.
The preceding valuation methods may produce a fair value
calculation that is not indicative of net realizable value or
reflective of future fair values. Although we believe these
valuation methods are appropriate and consistent with other
market participants, the use of different methodologies or
assumptions to determine the fair value of certain
investments could result in a different fair value
measurement at the reporting date.
Investment securities are exposed to various financial risks
including interest rate, market, and credit risks. Due to the
level of risk associated with certain investment securities, it
is reasonably possible that changes in the values of our
investment securities will occur in the near term and such
changes could materially affect our investment account
balances and the amounts reported as plan assets available
for benefit payments.
78
The following table presents the fair value of plan assets, including outstanding receivables and liabilities, of the retirement trust
fund:
In thousands
Investments
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Long government/credit
High yield bonds
Emerging market debt
Real estate
Absolute return strategy
Cash and cash equivalents
Total investments
Investments
U.S. large cap equity
U.S. small/mid cap equity
Non-U.S. equity
Emerging markets equity
Fixed income
Long government/credit
High yield bonds
Emerging market debt
Real estate
Absolute return strategy
Cash and cash equivalents
Total investments
Receivables:
Accrued interest and dividend income
Due from broker for securities sold
Total receivables
Liabilities:
Due to broker for securities purchased
December 31, 2017
Level 1
Level 2
Level 3
Non-Published
NAV(1)
Total
$
— $
—
21,211
—
—
—
—
—
—
—
82
— $
— $
102,851
$
102,851
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
16,423
56,075
28,743
2,781
33,081
2,777
12,605
5,544
189
5,533
16,423
77,286
28,743
2,781
33,081
2,777
12,605
5,544
189
5,615
$
21,293
$
— $
— $
266,602
$
287,895
December 31, 2016
Level 1
Level 2
Level 3
Non-Published
NAV(1)
Total
$
49,841
$
— $
— $
5,655
$
18,629
22,404
—
—
—
—
—
17,857
—
9
108,740
$
$
—
—
—
—
34,955
—
—
—
—
—
—
—
—
—
—
—
—
—
$
$
— $
34,955
$
— $
— $
10,232
25,346
13,457
6,719
17,960
14,072
8,504
882
3,111
2,482
108,420
$
$
55,496
28,861
47,750
13,457
6,719
52,915
14,072
8,504
18,739
3,111
2,491
252,115
December 31,
2017
2016
$
$
$
30
—
30
$
$
451
5,170
5,621
— $
22
Total investment in retirement trust
257,714
(1) The fair value for these investments is determined using Net Asset Value per share (NAV) as of December 31, as a practical expedient, and
287,925
$
$
therefore they are not classified within the fair value hierarchy. These investments primarily consist of institutional investment products, for
which the NAV is generally not publicly available.
79
9. INCOME TAX
The following table provides a reconciliation between
income taxes calculated at the statutory federal tax rate and
the provision for income taxes reflected in the consolidated
statements of comprehensive income or loss for December
31:
Dollars in thousands
2017
2016
2015
Income taxes (benefits) at
federal statutory rate
Increase (decrease):
State income tax, net of
federal
Amortization of
investment tax credits
Differences required to be
flowed-through by
regulatory commissions
Gains on company and
trust-owned life insurance
Effect of TCJA
Deferred Tax Rate
Differential Post-TCJA
Other, net
Total provision for income
taxes (benefits)
$(30,233)
$ 34,863
$ 31,310
(5,784)
4,582
4,195
(4)
(41)
(118)
2,357
2,357
2,357
(872)
(594)
(766)
(21,429)
26,947
(1,739)
—
—
—
—
(453)
(1,225)
$(30,757)
$ 40,714
$ 35,753
Effective tax rate
35.6%
40.9%
40.0%
The effective income tax rate for 2017 compared to 2016
changed primarily as a result of the TCJA, the equity portion
of AFUDC and excess tax benefits related to stock-based
compensation. The effective income tax rate increase from
2016 compared to 2015 was primarily the result of lower
depletion deductions from gas reserves activity in 2016.
The provision for current and deferred income taxes
consists of the following at December 31:
In thousands
Current
Federal
State
Deferred
Federal
State
2017
2016
2015
$ 16,403
$
7,402
$ 10,558
4,892
21,295
2,042
9,444
(41,134)
26,219
(10,918)
5,051
(52,052)
31,270
61
10,619
18,729
6,405
25,134
Total provision for income
taxes (loss benefits)
$ (30,757) $ 40,714
$ 35,753
At December 31, 2017 and 2016, regulatory income tax
assets of $21.3 million and $43.0 million, respectively, were
recorded, a portion of which is recorded in current assets.
These regulatory income tax assets primarily represent
future rate recovery of deferred tax liabilities, resulting from
differences in utility plant financial statement and tax bases
and utility plant removal costs, which were previously flowed
through for rate making purposes and to take into account
the additional future taxes, which will be generated by that
recovery. These deferred tax liabilities, and the associated
regulatory income tax assets, are currently being recovered
80
through customer rates. At December 31, 2017, we had a
regulatory income tax asset of $0.9 million representing
probable future rate recovery of deferred tax liabilities
resulting from the equity portion of AFUDC.
The following table summarizes the total provision (benefit)
for income taxes for the utility and non-utility business
segments for December 31:
In thousands
Utility:
Current
Deferred
Deferred investment tax
credits
Non-utility business segments:
Current
Deferred
2017
2016
2015
$ 21,453
$ 10,300
$ 15,890
19,479
28,749
20,834
(4)
(41)
(118)
40,928
39,008
36,606
(158)
(856)
(5,271)
(71,527)
(71,685)
2,562
1,706
4,418
(853)
Total provision for income taxes
$(30,757) $ 40,714
$ 35,753
The following table summarizes the tax effect of significant
items comprising our deferred income tax accounts at
December 31:
In thousands
Deferred tax liabilities:
Plant and property
Regulatory income tax assets
Regulatory liabilities
Non-regulated deferred tax liabilities
Total
Deferred tax assets:
2017
2016
$ 296,114
$ 428,642
22,209
29,114
933
43,048
48,291
51,446
$ 348,370
$ 571,427
Regulatory income tax liabilities
$ 56,470
$
Non-regulated deferred tax assets
17,796
—
—
Pension and postretirement
obligations
Alternative minimum tax credit
carryforward
Total
3,512
4,493
66
9,853
$ 77,844
$ 14,346
Deferred income tax liabilities, net
$ 270,526
$ 557,081
Deferred investment tax credits
—
4
Deferred income taxes and investment
tax credits
$ 270,526
$ 557,085
Management assesses the available positive and negative
evidence to estimate if sufficient taxable income will be
generated to utilize the existing deferred tax assets. Based
upon this assessment, we have determined we are more
likely than not to realize all deferred tax assets recorded as
of December 31, 2017.
As a result of certain realization requirements prescribed in
the accounting guidance for income taxes, the tax benefit of
statutory depletion is recognized no earlier than the year in
which the depletion is deductible on our federal income tax
return. Income tax expense decreased by $0.9 million in
2015 as a result of realizing deferred depletion benefit from
2013 and 2014. This benefit is included in Other, net in the
statutory rate reconciliation table.
Uncertain tax positions are accounted for in accordance with
accounting standards that require management’s
assessment of the anticipated settlement outcome of
material uncertain tax positions taken in a prior year, or
planned to be taken in the current year. Until such positions
are sustained, we would not recognize the uncertain tax
benefits resulting from such positions. No reserves for
uncertain tax positions were recorded as of December 31,
2017, 2016, or 2015.
Our federal income tax returns for tax years 2013 and
earlier are closed by statute. The IRS Compliance
Assurance Process (CAP) examination of the 2013, 2014,
and 2015 tax years have been completed. There were no
material changes to these returns as filed. The 2016 and
2017 tax years are currently under IRS CAP examination.
Our 2018 CAP application has been accepted by the IRS.
Under the CAP program, we work with the IRS to identify
and resolve material tax matters before the tax return is filed
each year. As of December 31, 2017, income tax years
2014 through 2016 remain open for state examination.
U.S. Federal TCJA Matters
On December 22, 2017, the TCJA was enacted and
permanently lowers the U.S. federal corporate income tax
rate to 21% from the existing maximum rate of 35%,
effective for our tax year beginning January 1, 2018. The
TCJA includes specific provisions related to regulated public
utilities that provide for the continued deductibility of interest
expense and the elimination of bonus depreciation for
property acquired after September 27, 2017.
As a result of the reduction of the U.S. corporate income tax
rate to 21%, U.S. GAAP requires deferred tax assets and
liabilities be revalued as of the date of enactment, with
resulting tax effects accounted for in the reporting period of
enactment. We recorded a net revaluation of deferred tax
asset and liability balances of $196.4 million as of
December 31, 2017. This revaluation had no impact on our
2017 cash flows.
The net change in our utility deferred taxes, that were
determined to have previously been included in ratemaking
activities by the OPUC and WUTC, was recorded as a net
regulatory liability that is expected to accrue to the future
benefit of customers. It is possible that this estimated
regulatory liability balance of $213.3 million, which includes
a gross up for income taxes of $56.5 million, may increase
or decrease as a result of future regulatory guidance by the
OPUC and WUTC or as additional authoritative
interpretation of the TCJA becomes available.
The change in our utility deferred taxes of $18.2 million,
associated with tax benefits that have previously been
flowed through to customers or for the equity portion of
AFUDC, resulted in an identical reduction in the associated
regulatory assets. This change had no impact on our
income tax expense. The net change in our utility deferred
taxes, that were determined to have been previously
excluded from ratemaking activities by the OPUC and
WUTC, and the change in deferred taxes associated with
the gas storage segment and other non-regulated
operations, was recorded as a net reduction of income tax
expense of $21.4 million.
Under pre-TCJA law, business interest is generally
deductible in the determination of taxable income. The TCJA
imposes a new limitation on the deductibility of net business
interest expense in excess of approximately 30% of
adjusted taxable income. Taxpayers operating in the trade
or business of public regulated utilities are excluded from
these new interest expense limitations.
There is uncertainty whether the new interest expense
limitation may apply to our non-regulated operations. The
legislative history indicates that all members of a
consolidated or affiliated group are treated as a single
taxpayer with respect to applying business interest
limitations. Future authoritative guidance may indicate that
net interest expense must be allocated between regulated
and non-regulated activities within the consolidated group.
Until such time that additional guidance is available that
eliminates this uncertainty, we are unable to estimate
whether the new interest limitation rules will impact our
future operating results. The new interest limitation rules are
effective for taxable years beginning after December 31,
2017. There is no grandfathering for debt instruments
outstanding prior to such date. Net business interest
expense amounts disallowed may be carried forward
indefinitely and treated as interest in succeeding taxable
years.
The TCJA generally provides for immediate full expensing
for qualified property acquired and placed in service after
September 27, 2017 and before January 1, 2023. This
would generally provide for accelerated cost recovery for
capital investments. However, the definition of qualified
property excludes property used in the trade or business of
a public regulated utility. The definition of utility trade or
business is the same as that used by the TCJA with respect
to the imposition of the net interest expense limitation
discussed above. As a result, a similar uncertainty exists
with respect to whether the exclusion from full expensing will
apply to our full consolidated group, which primarily
operates as a regulated public utility, or whether full
expensing will be available to our non-regulated activities.
An additional uncertainty exists with respect to whether 50%
bonus depreciation, which was in effect prior to the TCJA,
will apply to property for which a contract was entered into
or significant construction had occurred prior to September
27, 2017, but that was not placed in service until after that
date. We excluded all assets placed in service by the
consolidated group after September 27, 2017 from bonus
depreciation. If future authoritative guidance indicates that
bonus depreciation is available to us for these capital
expenditures, this would primarily result in a decrease to our
current income taxes payable and an increase in regulatory
liability.
The SEC staff issued Staff Accounting Bulletin 118, which
provides guidance on accounting for the tax effects of the
TCJA. SAB 118 provides a measurement period that should
not extend beyond one year from the TCJA enactment date
for companies to complete the accounting under ASC 740.
To the extent that a company’s accounting for certain
income tax effects of the TCJA is incomplete but it is able to
determine a reasonable estimate, it must record a
provisional estimate in the financial statements. Consistent
with SAB 118, the determination to exclude all assets placed
81
respectively. These accrued asset removal costs are
reflected on the balance sheet as regulatory liabilities. See
Note 2. During 2017 and 2016, we did not acquire any
equipment under capital leases.
11. GAS RESERVES
We have invested $188 million through our gas reserves
program in the Jonah Field located in Wyoming as of
December 31, 2017. Gas reserves are stated at cost, net of
regulatory amortization, with the associated deferred tax
benefits recorded as liabilities on the consolidated balance
sheets. Our investment in gas reserves provides long-term
price protection for utility customers through the original
agreement with Encana Oil & Gas (USA) Inc. under which
we invested $178 million and the amended agreement with
Jonah Energy LLC under which an additional $10 million
was invested.
We entered into our original agreements with Encana in
2011 under which we hold working interests in certain
sections of the Jonah Field. Gas produced in these sections
is sold at prevailing market prices, and revenues from such
sales, net of associated operating and production costs and
amortization, are credited to the utility's cost of gas. The
cost of gas, including a carrying cost for the rate base
investment, is included in our annual Oregon PGA filing,
which allows us to recover these costs through customer
rates. Our investment under the original agreement, less
accumulated amortization and deferred taxes, earns a rate
of return.
In March 2014, we amended the original gas reserves
agreement in order to facilitate Encana's proposed sale of
its interest in the Jonah field to Jonah Energy. Under the
amendment, we ended the drilling program with Encana,
but increased our working interests in our assigned
sections of the Jonah field. We also retained the right to
invest in new wells with Jonah Energy. Under the amended
agreement we still have the option to invest in additional
wells on a well-by-well basis with drilling costs and resulting
gas volumes shared at our amended proportionate working
interest for each well in which we invest. We elected to
participate in some of the additional wells drilled in 2014,
but have not had the opportunity to participate in additional
wells since 2014. However, we may have the opportunity to
participate in more wells in the future.
Gas produced from the additional wells is included in our
Oregon PGA at a fixed rate of $0.4725 per therm, which
approximates the 10-year hedge rate plus financing costs
at the inception of the investment.
Gas reserves acted to hedge the cost of gas
for approximately 6%, 8% and 11% of our utility's gas
supplies for the years ended December 31, 2017, 2016,
and 2015 respectively.
in service after September 27, 2017 from bonus
depreciation is provisional.
We primarily operate in the States of Oregon and
Washington. The extent to which a particular state adopts
the U.S. Internal Revenue Code directly affects the
application of the enacted federal changes of the TCJA to its
taxable income computation. To varying degrees, Oregon
and Washington corporate business tax approaches rely on
federal income tax law, including the Internal Revenue Code
and the associated Treasury regulations. It is possible that
the federal changes resulting from the TCJA will cause
states to reassess their future conformity, however, we have
evaluated the state impacts of the TCJA under current law.
Oregon automatically adopts changes to the U.S. Internal
Revenue Code related to the calculation of consolidated
corporate taxable income. By both State statute and
administrative rule, Oregon corporation excise tax law, as
related to the definition of taxable income, is tied to federal
tax law as applicable to our tax year. Changes enacted to
the definition of federal taxable income by the TCJA are
effective for Oregon tax purposes in the same manner as for
federal tax purposes. As a result, the net interest limitation
and full expensing exclusions, discussed above, apply to
Oregon as well.
Washington State does not have a corporate income tax,
but rather imposes a tax on our gross receipts. The TCJA
does not include a change to the definition of gross receipts,
or the timing of their recognition, that is currently anticipated
to impact us. As a result, no change to Washington State
reporting is anticipated.
10. PROPERTY, PLANT, AND EQUIPMENT
The following table sets forth the major classifications of our
property, plant, and equipment and accumulated
depreciation at December 31:
In thousands
2017
2016
Utility plant in service
$2,975,217
$2,843,243
Utility construction work in progress
Less: Accumulated depreciation
Utility plant, net
Non-utility plant in service
Non-utility construction work in
progress
Less: Accumulated depreciation
Non-utility plant, net
159,924
942,879
62,264
903,096
2,192,262
2,002,411
75,639
299,378
4,671
17,598
62,712
3,931
44,820
258,489
Total property, plant, and equipment
$2,254,974
$2,260,900
Capital expenditures in accrued
liabilities
$
34,976
$
9,547
The weighted average depreciation rate for utility assets
was 2.8% for utility assets during 2017, 2016, and 2015.
The weighted average depreciation rate for non-utility
assets was 1.9% in 2017, 2.0% in 2016, and 2.2% in 2015.
Accumulated depreciation does not include the accumulated
provision for asset removal costs of $360.9 million and
$341.1 million at December 31, 2017 and 2016,
82
The following table outlines our net gas reserves
investment at December 31:
In thousands
2017
2016
Gas reserves, current
$
15,704
$
15,926
Gas reserves, non-current
171,832
171,610
Less: Accumulated amortization
Total gas reserves(1)
Less: Deferred taxes on gas reserves
87,779
99,757
22,712
71,426
116,110
28,119
Net investment in gas reserves
$
77,045
$
87,991
(1) Our net investment in additional wells included in total gas
reserves was $5.8 million and $6.7 million at December 31,
2017 and 2016, respectively.
Our investment is included in our consolidated balance
sheets under gas reserves with our maximum loss
exposure limited to our investment balance.
12. INVESTMENTS
Investments include financial investments in life insurance
policies, and equity method investments in certain
partnerships and limited liability companies. The following
table summarizes our other investments at December 31:
In thousands
2017
2016
Investments in life insurance policies
$ 50,792
$ 52,719
Investments in gas pipeline
Other
13,669
13,767
1,902
1,890
Total other investments
$ 66,363
$ 68,376
Investment in Life Insurance Policies
We have invested in key person life insurance contracts to
provide an indirect funding vehicle for certain long-term
employee and director benefit plan liabilities. The amount in
the above table is reported at cash surrender value, net of
policy loans.
Investments in Gas Pipeline
TWP, a wholly-owned subsidiary of TWH, is pursuing the
development of a new gas transmission pipeline that would
provide an interconnection with our utility distribution
system. NWN Energy, a wholly-owned subsidiary of NW
Natural, owns 50% of TWH, and 50% is owned by
TransCanada American Investments Ltd., an indirect wholly-
owned subsidiary of TransCanada Corporation.
Variable Interest Entity (VIE) Analysis
TWH is a VIE, with our investment in TWP reported under
equity method accounting. We have determined we are not
the primary beneficiary of TWH’s activities as we only have
a 50% share of the entity, and there are no stipulations that
allow us a disproportionate influence over it. Our
investments in TWH and TWP are included in other
investments on our balance sheet. If we do not develop this
investment, then our maximum loss exposure related to
TWH is limited to our equity investment balance, less our
share of any cash or other assets available to us as a 50%
owner. Our investment balance in TWH was $13.4 million at
December 31, 2017 and 2016.
Impairment Analysis
Our investments in nonconsolidated entities accounted for
under the equity method are reviewed for impairment at
each reporting period and following updates to our corporate
planning assumptions. If it is determined a loss in value is
other than temporary, a charge is recognized for the
difference between the investment’s carrying value and its
estimated fair value. Fair value is based on quoted market
prices when available or on the present value of expected
future cash flows. Differing assumptions could affect the
timing and amount of a charge recorded in any period.
In 2011, TWP withdrew its original application with the
FERC for a proposed natural gas pipeline in Oregon and
informed FERC that it intended to re-file an application to
reflect changes in the project scope aligning the project with
the region’s current and future gas infrastructure needs.
TWP continues working with customers in the Pacific
Northwest to further understand their gas transportation
needs and determine the commercial support for a revised
pipeline proposal. A new FERC certificate application is
expected to be filed to reflect a revised scope based on
these regional needs.
Our equity investment was not impaired at December 31,
2017 as the fair value of expected cash flows from planned
development exceeded our remaining equity investment of
$13.4 million at December 31, 2017. However, if we learn
that the project is not viable or will not go forward, we could
be required to recognize a maximum charge of up to
approximately $13.4 million based on the current amount of
our equity investment, net of cash and working capital at
TWP. We will continue to monitor and update our
impairment analysis as required.
13. DERIVATIVE INSTRUMENTS
We enter into financial derivative contracts to hedge a
portion of our utility’s natural gas sales requirements. These
contracts include swaps, options, and combinations of
option contracts. We primarily use these derivative financial
instruments to manage commodity price variability. A small
portion of our derivative hedging strategy involves foreign
currency exchange contracts.
We enter into these financial derivatives, up to prescribed
limits, primarily to hedge price variability related to our
physical gas supply contracts as well as to hedge spot
purchases of natural gas. The foreign currency forward
contracts are used to hedge the fluctuation in foreign
currency exchange rates for pipeline demand charges paid
in Canadian dollars.
In the normal course of business, we also enter into
indexed-price physical forward natural gas commodity
purchase contracts and options to meet the requirements of
utility customers. These contracts qualify for regulatory
deferral accounting treatment.
We also enter into exchange contracts related to the third-
party asset management of our gas portfolio, some of which
are derivatives that do not qualify for hedge accounting or
regulatory deferral, but are subject to our regulatory sharing
agreement. These derivatives are recognized in operating
83
revenues in our gas storage segment, net of amounts
shared with utility customers.
Notional Amounts
The following table presents the absolute notional amounts
related to open positions on our derivative instruments:
In thousands
Natural gas (in therms):
Financial
Physical
Foreign exchange
At December 31,
2017
2016
429,100
477,430
520,268
535,450
$ 7,669
$ 7,497
Purchased Gas Adjustment (PGA)
Derivatives entered into by the utility for the procurement or
hedging of natural gas for future gas years generally receive
regulatory deferral accounting treatment. In general, our
commodity hedging for the current gas year is completed
prior to the start of the gas year, and hedge prices are
reflected in our weighted-average cost of gas in the PGA
filing. Hedge contracts entered into after the start of the PGA
period are subject to our PGA incentive sharing mechanism
in Oregon. We entered the 2017-18 and 2016-17 gas year
with our forecasted sales volumes hedged at 49% and 48%
in financial swap and option contracts, and 26% and 27% in
physical gas supplies, respectively. Hedge contracts entered
into prior to our PGA filing, in September 2017, were
included in the PGA for the 2017-18 gas year. Hedge
contracts entered into after our PGA filing, and related to
subsequent gas years, may be included in future PGA filings
and qualify for regulatory deferral.
Unrealized and Realized Gain/Loss
The following table reflects the income statement presentation for the unrealized gains and losses from our derivative
instruments:
In thousands
Benefit (expense) to cost of gas
Operating revenues
Amounts deferred to regulatory accounts on balance sheet
Total gain (loss) in pre-tax earnings
UNREALIZED GAIN/LOSS. Outstanding derivative
instruments related to regulated utility operations are
deferred in accordance with regulatory accounting
standards. The cost of foreign currency forward and natural
gas derivative contracts are recognized immediately in the
cost of gas; however, costs above or below the amount
embedded in the current year PGA are subject to a
regulatory deferral tariff and therefore, are recorded as a
regulatory asset or liability.
REALIZED GAIN/LOSS. We realized net losses of $7.8
million and $26.9 million for the years ended December 31,
2017 and 2016, respectively, from the settlement of natural
gas financial derivative contracts. Realized gains and losses
are recorded in cost of gas, deferred through our regulatory
accounts, and amortized through customer rates in the
following year.
Credit Risk Management of Financial Derivatives
Instruments
No collateral was posted with or by our counterparties as of
December 31, 2017 or 2016. We attempt to minimize the
potential exposure to collateral calls by counterparties
to manage our liquidity risk. Counterparties generally allow a
certain credit limit threshold before requiring us to post
collateral against loss positions. Given our counterparty
credit limits and portfolio diversification, we were not subject
to collateral calls in 2017 or 2016. Our collateral call
exposure is set forth under credit support agreements,
which generally contain credit limits. We could also be
subject to collateral call exposure where we have agreed to
December 31, 2017
December 31, 2016
Natural gas
commodity
Foreign
exchange
Natural gas
commodity
Foreign
exchange
$
$
(26,000) $
(1,021)
26,665
107
—
(107)
$
22,746
$
995
(23,394)
(356) $
— $
347
$
(130)
—
130
—
provide adequate assurance, which is not specific as to the
amount of credit limit allowed, but could potentially require
additional collateral in the event of a material adverse
change.
Based on current commodity financial swap and option
contracts outstanding, which reflect unrealized losses of
$22.3 million at December 31, 2017, we have estimated the
level of collateral demands, with and without potential
adequate assurance calls, using current gas prices and
various credit downgrade rating scenarios for NW Natural as
follows:
Credit Rating Downgrade Scenarios
(Current
Ratings)
A+/A3
BBB+/
Baa1
BBB/
Baa2
BBB-/
Baa3
Specul-
ative
$
— $ — $ — $ (5,428) $(15,422)
—
—
— (5,428)
(11,594)
In thousands
With
Adequate
Assurance
Calls
Without
Adequate
Assurance
Calls
Our financial derivative instruments are subject to master
netting arrangements; however, they are presented on a
gross basis in our consolidated balance sheets. We and our
counterparties have the ability to set-off obligations to each
other under specified circumstances. Such circumstances
may include a defaulting party, a credit change due to a
merger affecting either party, or any other termination event.
84
If netted by counterparty, our derivative position would result
in an asset of $2.9 million and a liability of $23.3 million as
of December 31, 2017. As of December 31, 2016, our
derivative position would have resulted in an asset of $18.8
million and a liability of $0.7 million.
We are exposed to derivative credit and liquidity risk
primarily through securing fixed price natural gas commodity
swaps to hedge the risk of price increases for our natural
gas purchases made on behalf of customers. We utilize
master netting arrangements through International Swaps
and Derivatives Association contracts to minimize this risk
along with collateral support agreements with counterparties
based on their credit ratings. In certain cases, we require
guarantees or letters of credit from counterparties to meet
our minimum credit requirement standards.
Our financial derivatives policy requires counterparties to
have a certain investment-grade credit rating at the time the
derivative instrument is entered into, and the policy specifies
limits on the contract amount and duration based on each
counterparty’s credit rating. We do not speculate with
derivatives; instead, we use derivatives to hedge our
exposure above risk tolerance limits. Any increase in market
risk created by the use of derivatives should be offset by the
exposures they modify.
We actively monitor our derivative credit exposure and place
counterparties on hold for trading purposes or require other
forms of credit assurance, such as letters of credit, cash
collateral, or guarantees as circumstances warrant. Our
ongoing assessment of counterparty credit risk includes
consideration of credit ratings, credit default swap spreads,
bond market credit spreads, financial condition, government
actions, and market news. We use a Monte-Carlo simulation
model to estimate the change in credit and liquidity risk from
the volatility of natural gas prices. The results of the model
are used to establish earnings-at-risk trading limits. Our
credit risk for all outstanding financial derivatives at
December 31, 2017 extends to March 2020.
We could become materially exposed to credit risk with one
or more of our counterparties if natural gas prices
experience a significant increase. If a counterparty were to
become insolvent or fail to perform on its obligations, we
could suffer a material loss; however, we would expect such
a loss to be eligible for regulatory deferral and rate recovery,
subject to a prudence review. All of our existing
counterparties currently have investment-grade credit
ratings.
Fair Value
In accordance with fair value accounting, we include non-
performance risk in calculating fair value adjustments. This
includes a credit risk adjustment based on the credit
spreads of our counterparties when we are in an unrealized
gain position, or on our own credit spread when we are in an
unrealized loss position. The inputs in our valuation models
include natural gas futures, volatility, credit default swap
spreads, and interest rates. Additionally, our assessment of
non-performance risk is generally derived from the credit
default swap market and from bond market credit spreads.
The impact of the credit risk adjustments for all outstanding
derivatives was immaterial to the fair value calculation at
December 31, 2017. As of December 31, 2017 and 2016,
the net fair value was a liability of $20.3 million and an asset
of $18.1 million, respectively, using significant other
observable, or Level 2, inputs. No Level 3 inputs were used
in our derivative valuations, and there were no transfers
between Level 1 or Level 2 during the years ended
December 31, 2017 and 2016.
14. COMMITMENTS AND CONTINGENCIES
Leases
We lease land, buildings, and equipment under agreements
that expire in various years, including a 99-year land lease
that extends through 2108. Rental costs were $7.5 million,
$6.2 million, and $5.5 million for the years ended December
31, 2017, 2016, and 2015, respectively, a portion of which is
capitalized. The following table reflects the future minimum
lease payments due under non-cancelable leases at
December 31, 2017. These commitments relate principally
to the lease of our office headquarters, underground gas
storage facilities, and computer equipment.
In thousands
Operating
leases
Capital
leases
$
5,378
$
3
$
5,379
6,945
7,482
7,629
169,411
—
—
—
—
—
Minimum
lease
payments
5,381
5,379
6,945
7,482
7,629
169,411
$
202,224
$
3
$
202,227
2018
2019
2020
2021
2022
Thereafter
Total
In October 2017, we entered into a 20-year operating lease
agreement for a new headquarters in Portland, Oregon in
anticipation of the expiration of our current lease in 2020.
Payments under the new lease are expected to commence
in 2020. Total estimated base rent payments over the life of
the lease are approximately $160 million and have been
included in the table above. We have the option to extend
the term of the lease for two additional seven-year periods.
Additionally, the lease was analyzed in consideration of
build-to-suit lease accounting guidance, and we concluded
that we are the accounting owner of the asset during
construction. As a result, we recognized $0.5 million in
Property, plant and equipment and an obligation in Other
non-current liabilities for the same amount on our
consolidated balance sheet at December 31, 2017.
Gas Purchase and Pipeline Capacity Purchase and
Release Commitments
We have signed agreements providing for the reservation of
firm pipeline capacity under which we are required to make
fixed monthly payments for contracted capacity. The pricing
component of the monthly payment is established, subject
to change, by U.S. or Canadian regulatory bodies. In
addition, we have entered into long-term sale agreements to
release firm pipeline capacity. We also enter into short-term
and long-term gas purchase agreements.
85
remediation costs and record a reasonable potential
remediation liability, or make an adjustment to our existing
liability. From this study, the regulatory agency selects a
remedy and issues a Record of Decision (ROD).
After a ROD is issued, we would seek to negotiate a
consent decree or consent judgment for designing and
implementing the remedy. We would have the ability to
further refine estimates of remediation liabilities at that time.
Remediation may include treatment of contaminated media
such as sediment, soil and groundwater, removal and
disposal of media, institutional controls such as legal
restrictions on future property use, or natural recovery.
Following construction of the remedy, the EPA and ODEQ
also have requirements for ongoing maintenance,
monitoring, and other post-remediation care that may
continue for many years. Where appropriate and reasonably
known, we will provide for these costs in our remediation
liabilities described below.
Due to the numerous uncertainties surrounding the course
of environmental remediation and the preliminary nature of
several site investigations, in some cases, we may not be
able to reasonably estimate the high end of the range of
possible loss. In those cases, we have disclosed the nature
of the possible loss and the fact that the high end of the
range cannot be reasonably estimated where a range of
potential loss is available. Unless there is an estimate within
the range of possible losses that is more likely than other
cost estimates within that range, we record the liability at the
low end of this range. It is likely changes in these estimates
and ranges will occur throughout the remediation process
for each of these sites due to our continued evaluation and
clarification concerning our responsibility, the complexity of
environmental laws and regulations, and the determination
by regulators of remediation alternatives. In addition to
remediation costs, we could also be subject to Natural
Resource Damages (NRD) claims from third-party tribal
entities. We will assess the likelihood and probability of each
claim and recognize a liability if deemed appropriate. Refer
to "Other Portland Harbor" below.
The aggregate amounts of these agreements were as
follows at December 31, 2017:
In thousands
2018
2019
2020
2021
2022
Thereafter
Total
Less: Amount
representing
interest
Total at present
value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$
63,944
$
79,891
$
3,581
2,729
2,729
2,273
—
—
71,675
82,129
77,028
65,630
60,050
601,844
966,572
—
—
—
—
—
3,581
601
174,542
24
$
71,074
$
792,030
$
3,557
Our total payments for fixed charges under capacity
purchase agreements were $85.3 million for 2017, $85.0
million for 2016, and $85.2 million for 2015. Included in the
amounts were reductions for capacity release sales of $4.5
million for 2017, $4.5 million for 2016, and $4.4 million for
2015. In addition, per-unit charges are required to be paid
based on the actual quantities shipped under the
agreements. In certain take-or-pay purchase commitments,
annual deficiencies may be offset by prepayments subject to
recovery over a longer term if future purchases exceed the
minimum annual requirements.
Environmental Matters
Refer to Note 15 for a discussion of environmental
commitments and contingencies.
15. ENVIRONMENTAL MATTERS
We own, or previously owned, properties that may require
environmental remediation or action. We estimate the range
of loss for environmental liabilities based on current
remediation technology, enacted laws and regulations,
industry experience gained at similar sites, and an
assessment of the probable level of involvement and
financial condition of other potentially responsible parties
(PRPs). When amounts are prudently expended related to
site remediation of those sites described herein, we have a
recovery mechanism in place to collect 96.68% of
remediation costs from Oregon customers, and we are
allowed to defer environmental remediation costs allocated
to customers in Washington annually until they are reviewed
for prudence at a subsequent proceeding.
Our sites are subject to the remediation process prescribed
by the Environmental Protection Agency (EPA) and the
Oregon Department of Environmental Quality (ODEQ). The
process begins with a remedial investigation (RI) to
determine the nature and extent of contamination and then
a risk assessment (RA) to establish whether the
contamination at the site poses unacceptable risks to
humans and the environment. Next, a feasibility study (FS)
or an engineering evaluation/cost analysis (EE/CA)
evaluates various remedial alternatives. It is at this point in
the process when we are able to estimate a range of
86
Environmental Sites
The following table summarizes information regarding liabilities related to environmental sites, which are recorded in other
current liabilities and other noncurrent liabilities on the balance sheet at December 31:
In thousands
Portland Harbor site:
Gasco/Siltronic Sediments
Other Portland Harbor
Gasco/Siltronic Upland site
Central Service Center site
Front Street site
Oregon Steel Mills
Total
PORTLAND HARBOR SITE. The Portland Harbor is an
EPA listed Superfund site that is approximately 10 miles
long on the Willamette River and is adjacent to NW
Natural's Gasco uplands sites. We are one of over one
hundred PRPs to the Superfund site. In January 2017, the
EPA issued its Record of Decision, which selects the
remedy fund for the clean-up of the Portland Harbor site
(Portland Harbor ROD). The Portland Harbor ROD
estimates the present value total cost at approximately
$1.05 billion with an accuracy between -30% and +50% of
actual costs.
Our potential liability is a portion of the costs of the remedy
for the entire Portland Harbor Superfund site. The cost of
that remedy is expected to be allocated among more than
100 PRPs. In addition, we are actively pursuing clarification
and flexibility under the ROD in order to better understand
our obligation under the clean-up. We are also participating
in a non-binding allocation process with the other PRPs in
an effort to resolve our potential liability. The Portland
Harbor ROD does not provide any additional clarification
around allocation of costs among PRPs and, as a result of
issuance of the Portland Harbor ROD, we have not modified
any of our recorded liabilities at this time.
We manage our liability related to the Superfund site as two
distinct remediation projects: the Gasco/Siltronic Sediments
and Other Portland Harbor projects.
Gasco/Siltronic Sediments. In 2009, NW Natural and Siltronic
Corporation entered into a separate Administrative Order on
Consent with the EPA to evaluate and design specific
remedies for sediments adjacent to the Gasco uplands and
Siltronic uplands sites. We submitted a draft EE/CA to the
EPA in May 2012 to provide the estimated cost of potential
remedial alternatives for this site. At this time, the estimated
costs for the various sediment remedy alternatives in the
draft EE/CA, for the additional studies and design work
needed before the cleanup can occur, and for regulatory
oversight throughout the clean-up range from $48.0 million
to $350 million. We have recorded a liability of $48.0 million
for the sediment clean-up, which reflects the low end of the
range. At this time, we believe sediments at this site
represent the largest portion of our liability related to the
Portland Harbor site discussed above.
87
Current Liabilities
Non-Current Liabilities
2017
2016
2017
2016
$
2,683
$
869
$
45,346
$
43,972
1,949
13,422
25
1,009
—
1,970
10,657
73
906
—
4,163
47,835
—
10,757
179
4,148
49,183
—
7,786
179
$
19,088
$
14,475
$
108,280
$
105,268
Other Portland Harbor. While we still believe liabilities
associated with the Gasco/Siltronic sediments site represent
our largest exposure, we do have other potential exposures
associated with the Portland Harbor ROD, including NRD
costs and harborwide clean-up costs (including downstream
petroleum contamination), for which allocations among the
PRPs have not yet been determined.
The Company and other parties have signed a cooperative
agreement with the Portland Harbor Natural Resource
Trustee council to participate in a phased NRD assessment
to estimate liabilities to support an early restoration-based
settlement of NRD claims. One member of this Trustee
council, the Yakama Nation, withdrew from the council in
2009, and in 2017, filed suit against the Company and 29
other parties seeking remedial costs and NRD assessment
costs associated with the Portland Harbor, set forth in the
complaint. The complaint seeks recovery of alleged costs
totaling $0.3 million in connection with the selection of a
remedial action for the Portland Harbor as well as
declaratory judgment for unspecified future remedial action
costs and for costs to assess the injury, loss, or destruction
of natural resources resulting from the release of hazardous
substances at and from the Portland Harbor site. The
Yakama Nation has filed two amended complaints
addressing certain pleading defects and dismissing the
State of Oregon. We have recorded a liability for NRD
claims which is at the low end of the range of the potential
liability; the high end of the range cannot be reasonably
estimated at this time. The NRD liability is not included in
the aforementioned range of costs provided in the Portland
Harbor ROD.
GASCO UPLANDS SITE. A predecessor of NW Natural,
Portland Gas and Coke Company, owned a former gas
manufacturing plant that was closed in 1958 (Gasco site)
and is adjacent to the Portland Harbor site described above.
The Gasco site has been under investigation by us for
environmental contamination under the ODEQ Voluntary
Clean-Up Program (VCP). It is not included in the range of
remedial costs for the Portland Harbor site noted above. We
manage the Gasco site in two parts: the uplands portion and
the groundwater source control action.
We submitted a revised Remedial Investigation Report for
the uplands to ODEQ in May 2007. In March 2015, ODEQ
approved the RA, enabling us to begin work on the FS in
2016. We have recognized a liability for the remediation of
the uplands portion of the site which is at the low end of the
range of potential liability; the high end of the range cannot
be reasonably estimated at this time.
In October 2016, ODEQ and NW Natural agreed to amend
their VCP agreement to incorporate a portion of the Siltronic
property adjacent to the Gasco site formerly owned by
Portland Gas & Coke between 1939 and 1960 into the
Gasco RA and FS, excluding the uplands for Siltronic.
Previously, we were conducting an investigation of
manufactured gas plant constituents on the entire Siltronic
uplands for ODEQ. Siltronic will be working with ODEQ
directly on environmental impacts to the remainder of its
property.
In September 2013, we completed construction of a
groundwater source control system, including a water
treatment station, at the Gasco site. We have estimated the
cost associated with the ongoing operation of the system
and have recognized a liability which is at the low end of the
range of potential cost. We cannot estimate the high end of
the range at this time due to the uncertainty associated with
the duration of running the water treatment station, which is
highly dependent on the remedy determined for both the
upland portion as well as the final remedy for our Gasco
sediment exposure.
OTHER SITES. In addition to those sites above, we have
environmental exposures at three other sites: Central
Service Center, Front Street, and Oregon Steel Mills. We
may have exposure at other sites that have not been
identified at this time. Due to the uncertainty of the design of
remediation, regulation, timing of the remediation, and in the
case of the Oregon Steel Mills site, pending litigation,
liabilities for each of these sites have been recognized at
their respective low end of the range of potential liability; the
high end of the range could not be reasonably estimated at
this time.
Central Service Center site. We are currently performing an
environmental investigation of the property under ODEQ's
Independent Cleanup Pathway. This site is on ODEQ's list
of sites with confirmed releases of hazardous substances,
and cleanup is necessary.
Front Street site. The Front Street site was the former
location of a gas manufacturing plant we operated (the
former Portland Gas Manufacturing site, or PGM). At
ODEQ’s request, we conducted a sediment and source
control investigation and provided findings to ODEQ. In
December 2015, we completed a FS on the former Portland
Gas Manufacturing site.
In July 2017, ODEQ issued the PGM ROD. The ROD
specifies the selected remedy, which requires a combination
of dredging, capping, treatment, and natural recovery. In
addition, the selected remedy also requires institutional
controls and long-term inspection and maintenance. We
revised the liability in the second quarter of 2017 to
incorporate the estimated undiscounted cost of
approximately $10.5 million for the selected remedy.
88
Further, we have recognized an additional liability of $1.3
million for additional studies and design costs as well as
regulatory oversight throughout the clean-up. We plan to
complete the remedial design in 2018 and expect to
construct the remedy details during 2019.
Oregon Steel Mills site. Refer to the “Legal Proceedings,”
below.
Site Remediation and Recovery Mechanism (SRRM)
We have an SRRM through which we track and have the
ability to recover past deferred and future prudently incurred
environmental remediation costs allocable to Oregon,
subject to an earnings test, for those sites identified therein.
In the February 2015 Order establishing the SRRM (2015
Order), the OPUC addressed outstanding issues related to
the SRRM, which required us to forego the collection of $15
million out of approximately $95 million in total
environmental remediation expenses and associated
carrying costs.
As a follow-up to the 2015 Order, the OPUC issued an
additional Order in January 2016 (2016 Order) regarding the
SRRM implementation in which the OPUC: (1) disallowed
the recovery of $2.8 million of interest earned on the
previously disallowed environmental expenditure amounts;
(2) clarified the state allocation of 96.68% of environmental
remediation costs for all environmental sites to Oregon; and
(3) confirmed our treatment of $13.8 million of expenses put
into the SRRM amortization account was correct and in
compliance with prior OPUC orders. As a result of the 2016
Order, we recognized a $3.3 million non-cash charge in the
first quarter, of which $2.8 million is reflected in other
income and expense, net and $0.5 million is included in
operations and maintenance expense.
COLLECTIONS FROM OREGON CUSTOMERS. Under the
SRRM collection process there are three types of deferred
environmental remediation expense:
• Pre-review - This class of costs represents remediation
spend that has not yet been deemed prudent by the
OPUC. Carrying costs on these remediation expenses are
recorded at our authorized cost of capital. The Company
anticipates the prudence review for annual costs and
approval of the earnings test prescribed by the OPUC to
occur by the third quarter of the following year.
• Post-review - This class of costs represents remediation
spend that has been deemed prudent and allowed after
applying the earnings test, but is not yet included in
amortization. We earn a carrying cost on these amounts
at a rate equal to the five-year treasury rate plus 100
basis points.
• Amortization - This class of costs represents amounts
included in current customer rates for collection and is
generally calculated as one-fifth of the post-review
deferred balance. We earn a carrying cost equal to the
amortization rate determined annually by the OPUC,
which approximates a short-term borrowing rate.
In addition to the collection amount noted above, the Order
also provides for the annual collection of $5.0 million from
Oregon customers through a tariff rider. As we collect
amounts from customers, we recognize these collections as
revenue and separately amortize an equal and offsetting
the original Order, or earlier if we gain greater certainty
about our future remediation costs, to consider whether
adjustments to the mechanism may be appropriate.
WASHINGTON DEFERRAL. In Washington, cost recovery
and carrying charges on amounts deferred for costs
associated with services provided to Washington customers
will be determined in a future proceeding.
Legal Proceedings
NW Natural is subject to claims and litigation arising in the
ordinary course of business. Although the final outcome of
any of these legal proceedings cannot be predicted with
certainty, including the matter described below, we do not
expect that the ultimate disposition of any of these matters
will have a material effect on our financial condition, results
of operations, or cash flows.
OREGON STEEL MILLS SITE. In 2004, NW Natural was
served with a third-party complaint by the Port of Portland
(the Port) in a Multnomah County Circuit Court case,
Oregon Steel Mills, Inc. v. The Port of Portland. The Port
alleges that in the 1940s and 1950s petroleum wastes
generated by our predecessor, Portland Gas & Coke
Company, and 10 other third-party defendants, were
disposed of in a waste oil disposal facility operated by the
United States or Shaver Transportation Company on
property then owned by the Port and now owned by Evraz
Oregon Steel Mills. The complaint seeks contribution for
unspecified past remedial action costs incurred by the Port
regarding the former waste oil disposal facility as well as a
declaratory judgment allocating liability for future remedial
action costs. No date has been set for trial. In August 2017,
the case was stayed pending outcome of the Portland
Harbor allocation process or other remediation. Although the
final outcome of this proceeding cannot be predicted with
certainty, we do not expect the ultimate disposition of this
matter will have a material effect on our financial condition,
results of operations, or cash flows.
For additional information regarding other commitments and
contingencies, see Note 14.
amount of our deferred regulatory asset balance through the
environmental remediation operating expense line shown
separately in the operating expense section of the income
statement.
We received total environmental insurance proceeds of
approximately $150.0 million as a result of settlements from
our litigation that was dismissed in July 2014. Under the
2015 OPUC Order, one-third of the Oregon allocated
proceeds were applied to costs deferred through 2012 with
the remaining two-thirds applied to costs at a rate of $5.0
million per year plus interest over the following 20 years. We
accrue interest on the insurance proceeds in the customer’s
favor at a rate equal to the five-year treasury rate plus 100
basis points. As of December 31, 2017, we have applied
$68.2 million of insurance proceeds to prudently incurred
remediation costs allocated to Oregon.
The following table presents information regarding the total
regulatory asset deferred as of December 31:
In thousands
Deferred costs and interest (1)
Accrued site liabilities (2)
2017
2016
$
45,546
$
53,039
126,950
119,443
Insurance proceeds and interest
(94,170)
(98,523)
Total regulatory asset deferral(1)
$
78,326
$
73,959
Current regulatory assets(3)
Long-term regulatory assets(3)
6,198
72,128
9,989
63,970
(1)
Includes pre-review and post-review deferred costs, amounts
currently in amortization, and interest, net of amounts collected
from customers.
(2) Excludes 3.32% of the Front Street site liability, or $0.4 million
in 2017 and $0.3 million in 2016, as the OPUC only allows
recovery of 96.68% of costs for those sites allocable to
Oregon, including those that historically served only Oregon
customers.
(3) Environmental costs relate to specific sites approved for
regulatory deferral by the OPUC and WUTC. In Oregon, we
earn a carrying charge on cash amounts paid, whereas
amounts accrued but not yet paid do not earn a carrying
charge until expended. We also accrue a carrying charge on
insurance proceeds for amounts owed to customers. In
Washington, a carrying charge related to deferred amounts will
be determined in a future proceeding. Current environmental
costs represent remediation costs management expects to
collect from customers in the next 12 months. Amounts
included in this estimate are still subject to a prudence and
earnings test review by the OPUC and do not include the $5
million tariff rider. The amounts allocable to Oregon are
recoverable through utility rates, subject to an earnings test.
ENVIRONMENTAL EARNINGS TEST. To the extent the
utility earns at or below its authorized Return of Equity
(ROE), remediation expenses and interest in excess of the
$5.0 million tariff rider and $5.0 million insurance proceeds
are recoverable through the SRRM. To the extent the utility
earns more than its authorized ROE in a year, the utility is
required to cover environmental expenses and interest on
expenses greater than the $10.0 million with those earnings
that exceed its authorized ROE.
Under the 2015 Order, the OPUC will revisit the deferral and
amortization of future remediation expenses, as well as the
treatment of remaining insurance proceeds three years from
89
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Quarter ended
In thousands, except per share data
March 31
June 30
September 30
December 31
2017
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
2016
Operating revenues
Net income (loss)
Basic earnings (loss) per share(1)
Diluted earnings (loss) per share(1)
$
297,323
$
136,238
$
88,190
$
240,422
40,310
1.41
1.40
2,729
0.10
0.10
(8,495)
(0.30)
(0.30)
$
255,529
$
99,183
$
87,727
$
36,641
1.33
1.33
2,019
0.07
0.07
(8,040)
(0.29)
(0.29)
(90,167)
(3.14)
(3.14)
233,528
28,275
1.01
1.00
(1) Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Variations in
earnings between quarterly periods are due primarily to the seasonal nature of our business.
NORTHWEST NATURAL GAS COMPANY
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A
COLUMN B
COLUMN C
Additions
COLUMN D
COLUMN E
Deductions
In thousands (year ended December 31)
2017
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
2016
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
2015
Reserves deducted in balance sheet from
assets to which they apply:
Allowance for uncollectible accounts
$
$
$
Balance at
beginning of
period
Charged to
costs and
expenses
Charged to
other accounts
Net write-offs
Balance at end
of period
1,290
$
865
$
— $
1,199
$
956
870
$
1,246
$
— $
826
$
1,290
969
$
760
$
— $
859
$
870
90
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
Our management, under the supervision and with the
participation of our Chief Executive Officer and Chief
Financial Officer, has completed an evaluation of the
effectiveness of the design and operation of our disclosure
controls and procedures (as defined in Rules 13a-15(e) and
15d-15(e) of the Securities Exchange Act of 1934, as
amended (the Exchange Act)). Based upon this evaluation,
our Chief Executive Officer and Chief Financial Officer have
concluded that, as of the end of the period covered by this
report, our disclosure controls and procedures were
effective to ensure that information required to be disclosed
by us and included in our reports filed or submitted under
the Exchange Act is recorded, processed, summarized, and
reported within the time periods specified in the
Securities and Exchange Commission (SEC) rules and
forms and that such information is accumulated and
communicated to management, including the Chief
Executive Officer and Chief Financial Officer, as appropriate
to allow timely decisions regarding required disclosure.
(b) Changes in Internal Control Over Financial Reporting
Our management is responsible for establishing and
maintaining adequate internal control over financial
reporting, as such term is defined in the Exchange Act Rule
13a-15(f). There have been no changes in our internal
control over financial reporting that occurred during the
quarter ended December 31, 2017 that have materially
affected, or are reasonably likely to materially affect, our
internal control over financial reporting.
The statements contained in Exhibit 31.1 and Exhibit 31.2
should be considered in light of, and read together with, the
information set forth in this Item 9(a).
ITEM 9B. OTHER INFORMATION
None.
91
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The "Information Concerning Nominees and Continuing Directors", "Corporate Governance", and "Section 16(a) Beneficial
Ownership Reporting Compliance" contained in our definitive Proxy Statement for the May 24, 2018 Annual Meeting of
Shareholders is hereby incorporated by reference.
PART III
Name
David H. Anderson
Age at
Dec. 31, 2017
56
Frank H. Burkhartsmeyer(1)
53
Brody J. Wilson(1)
Lea Anne Doolittle
James R.Downing
Kimberly A. Heiting(2)(3)
MardiLyn Saathoff
Grant M. Yoshihara(3)
Shawn M. Filippi
Thomas J. Imeson
Justin Palfreyman
Lori Russell
David A. Weber
38
62
48
48
61
62
45
67
39
58
58
Positions held during last five years
Chief Executive Officer and President (2016- ); Chief Operating Officer and
President (2015-2016); Executive Vice President and Chief Operating Officer
(2014-2015); Executive Vice President Operations and Regulation (2013-2014);
Senior Vice President and Chief Financial Officer (2004-2013).
Senior Vice President and Chief Financial Officer (2017- ); President and Chief
Executive Officer of Renewables, Avangrid Renewables (2015-2017); Senior
Vice President of Finance, Iberdrola Renewables Holdings, Inc. (2012-2015);
Vice President, Strategy, Planning & Market Fundamentals, Iberdrola
Renewables Holdings, Inc. (2005- 2012).
Vice President, Chief Accounting Officer, Controller and Treasurer (2017- ); Chief
Financial Officer (Interim), Treasurer, Chief Accounting Officer and Controller
(2016-2017); Chief Accounting Officer, Controller and Assistant Treasurer
(2016); Controller (2013-2015); Acting Controller (2013); Accounting Director
(2012-2013); Senior Manager, PriceWaterhouseCoopers LLP (2009-2012);
Manager, PriceWaterhouseCoopers LLP (2007-2009).
Senior Vice President and Chief Administrative Officer (2013- ); Senior Vice
President (2008-2013); Vice President, Human Resources (2000-2007).
Vice President and Chief Information Officer (2017- ); Chief Information Officer,
WorleyParsons (America's Division) (2016-2017); Executive Service Delivery
Manager for SAP, British Petroleum (2011-2015).
Vice President, Communications and Chief Marketing Officer (2015- ); Chief
Marketing & Communications Officer (2013-2014); Chief Corporate
Communications Officer (2011-2013); Communications Director (2005-2011).
Senior Vice President, Regulation and General Counsel (2016- ); Senior Vice
President and General Counsel (2015-2016); Vice President, Legal, Risk and
Compliance (2013-2014); Deputy General Counsel (2010-2013); Chief
Governance Officer and Corporate Secretary (2008-2014).
Senior Vice President, Utility Operations (2016- ); Vice President, Utility
Operations (2007-2016); Managing Director, Utility Services (2005-2006);
Director, Utility Services (2004-2005).
Vice President, Chief Compliance Officer and Corporate Secretary (2016- );
Vice President and Corporate Secretary (2015-2016); Senior Legal Counsel
(2011-2014); Assistant Corporate Secretary (2010-2014); Associate Legal
Counsel (2005-2010).
Vice President of Public Affairs (2014- ); Director of Public Affairs, Port of
Portland (2006-2014).
Vice President, Strategy and Business Development (2017- );Vice President,
Business Development (2016-2017); Director, Power, Energy and Infrastructure
Group, Lazard, Freres & Co. (2009-2016).
Vice President, Utility Services (2016- ); Utility Field Operations Director
(2013-2016); Serve Customer Process Director (2008-2013).
President and Chief Executive Officer, NW Natural Gas Storage, LLC and Gill
Ranch Storage, LLC (2012- ); Interim President and Chief Executive Officer, NW
Natural Gas Storage, LLC and Gill Ranch Storage, LLC (2011-2012); Chief
Operating Officer, NW Natural Gas Storage, LLC and Gill Ranch Storage, LLC
(2010-2011); Managing Director of Information Services and Chief Information
Officer (2005-2011); Director of Information Services and Chief Information
Officer (2001-2005).
(1) Frank H. Burkhartsmeyer was appointed Senior Vice President and Chief Financial Office effective May 17, 2017, replacing Brody J. Wilson, who had been serving
as Chief Financial Office on an interim basis. Effective May 17, 2017, Mr. Wilson was appointed Vice President, Chief Accounting Officer, Controller, and Treasurer.
(2) Kimberly A. Heiting was appointed Senior Vice President, Communications and Chief Marketing Officer effective January 1, 2018.
(3) Grant M. Yoshihara announced his intention to retire effective March 31, 2018. The Board of Directors appointed Kimberly A. Heiting as Senior Vice President,
Operations and Chief Marketing Officer and Jon Huddleston Vice President, Engineering and Utility Operations, effective March 31, 2018.
Each executive officer serves successive annual terms; present terms end on May 24, 2018. There are no family relationships
among our executive officers, directors or any person chosen to become one of our officers or directors. NW Natural has
adopted a Code of Ethics (Code) applicable to all employees and officers that is available on our website at www.nwnatural.com.
We intend to disclose on our website at www.nwnatural.com any amendments to the Code or waivers of the Code for executive
officers and directors.
92
ITEM 11. EXECUTIVE COMPENSATION
The information concerning "Executive Compensation",
"Report of the Organization and Executive Compensation
Committee", and "Compensation Committee Interlocks and
Insider Participation" contained in our definitive Proxy
Statement for the May 24, 2018 Annual Meeting of
Shareholders is hereby incorporated by reference.
Information related to Executive Officers as of December
31, 2017 is reflected in Part III, Item 10, above.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The following table sets forth information regarding compensation plans under which equity securities of NW Natural are
authorized for issuance as of December 31, 2017 (see Note 6 to the Consolidated Financial Statements):
Plan Category
Equity compensation plans approved by security holders:
LTIP (1)(2)
Restated Stock Option Plan
Employee Stock Purchase Plan
Equity compensation plans not approved by security holders:
Executive Deferred Compensation Plan (EDCP)(3)
Directors Deferred Compensation Plan (DDCP)(3)
Deferred Compensation Plan for Directors and Executives (DCP)(4)
Total
(a)
(b)
(c)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
171,995
91,688
$
22,804
1,132
42,936
176,265
506,820
n/a
44.43
56.53
n/a
n/a
n/a
626,960
—
37,857
n/a
n/a
n/a
664,817
(1) Awards may be granted under the LTIP as Performance Share Awards, Restricted Stock Units, or stock options. Shares issued pursuant to
Performance Share Awards and Restricted Stock Units under the LTIP do not include an exercise price, but are payable when the award
criteria are satisfied. The number of shares shown in column (a) include 84,522 Restricted Stock Units and 87,473 Performance Share
Awards, reflecting the number of shares to be issued as targeted performance share awards under outstanding Performance Share Awards.
If the maximum awards were paid pursuant to the Performance Share Awards outstanding at December 31, 2017, the number of shares
shown in column (a) would increase by 87,473 shares, reflecting the maximum share award of 200% of target, and the number of shares
shown in column (c) would decrease by the same amount of shares. No stock options or other types of award have been issued under the
LTIP.
The number of shares shown in column (c) includes shares that are available for future issuance under the LTIP as Restricted Stock Units,
Performance Share Awards, or stock options at December 31, 2017.
(2)
(3) Prior to January 1, 2005, deferred amounts were credited, at the participant’s election, to either a “cash account” or a “stock account.” If
deferred amounts were credited to stock accounts, such accounts were credited with a number of shares of NW Natural common stock
based on the purchase price of the common stock on the next purchase date under our Dividend Reinvestment and Direct Stock Purchase
Plan, and such accounts were credited with additional shares based on the deemed reinvestment of dividends. Cash accounts are credited
quarterly with interest at a rate equal to Moody’s Average Corporate Bond Yield plus two percentage points, subject to a 6% minimum rate.
At the election of the participant, deferred balances in the stock accounts are payable after termination of Board service or employment in a
lump sum, in installments over a period not to exceed 10 years in the case of the DDCP, or 15 years in the case of the EDCP, or in a
combination of lump sum and installments. Amounts credited to stock accounts are payable solely in shares of common stock and cash for
fractional shares, and amounts in the above table represent the aggregate number of shares credited to participants' stock accounts. We
have contributed common stock to the trustee of the Umbrella Trusts such that the Umbrella Trusts hold approximately the number of
shares of common stock equal to the number of shares credited to all participants’ stock accounts.
(4) Effective January 1, 2005, the EDCP and DDCP were closed to new participants and replaced with the DCP. The DCP continues the basic
provisions of the EDCP and DDCP under which deferred amounts are credited to either a “cash account” or a “stock account.” Stock
accounts represent a right to receive shares of NW Natural common stock on a deferred basis, and such accounts are credited with
additional shares based on the deemed reinvestment of dividends. Effective January 1, 2007, cash accounts are credited quarterly with
interest at a rate equal to Moody’s Average Corporate Bond Yield. Our obligation to pay deferred compensation in accordance with the
terms of the DCP will generally become due on retirement, death, or other termination of service, and will be paid in a lump sum or in
installments of five, 10, or 15 years as elected by the participant in accordance with the terms of the DCP. Amounts credited to stock
accounts are payable solely in shares of common stock and cash for fractional shares, and amounts in the above table represent the
aggregate number of shares credited to participants' stock accounts. We have contributed common stock to the trustee of the Supplemental
Trust such that this trust holds approximately the number of common shares equal to the number of shares credited to all participants' stock
accounts. The right of each participant in the DCP is that of a general, unsecured creditor of the Company.
The information captioned “Beneficial Ownership of Common Stock by Directors and Executive Officers” and "Security
Ownership of Common Stock of Certain Beneficial Owners" contained in our definitive Proxy Statement for the May 24, 2018
Annual Meeting of Shareholders is incorporated herein by reference.
93
ITEM 13. CERTAIN RELATIONSHIPS AND
RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
The information captioned "Transactions with Related
Persons" and "Corporate Governance" in the Company’s
definitive Proxy Statement for the May 24, 2018 Annual
Meeting of Shareholders is hereby incorporated by
reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND
SERVICES
The information captioned "2017 and 2016 Audit Firm Fees"
in the Company’s definitive Proxy Statement for the May 24,
2018 Annual Meeting of Shareholders is hereby
incorporated by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT
SCHEDULES
(a) The following documents are filed as part of this report:
1. A list of all Financial Statements and Supplemental
Schedules is incorporated by reference to Item 8.
2. List of Exhibits filed:
Reference is made to the Exhibit Index
commencing on page 95.
ITEM 16. FORM 10-K SUMMARY
None.
94
NORTHWEST NATURAL GAS COMPANY
Exhibit Index to Annual Report on Form 10-K
For the Fiscal Year Ended December 31, 2017
Exhibit Number Document
*3a.
*3b.
*4a.
*4b.
*4c.
*4d.
*4e.
*4f.
*4g.
12
21
Restated Articles of Incorporation, as filed and effective May 31, 2006 and amended June 3, 2008 (incorporated
herein by reference to Exhibit 3.1 to Form 10-Q for the quarter ended June 30, 2008, File No. 1-15973).
Bylaws as amended December 21, 2017 (incorporated herein by reference to Exhibit 3.1 to Form 8-K dated
December 21, 2017, File No. 1-15973).
Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers Trust (to whom Deutsche Bank Trust
Company Americas is now successor), Trustee (incorporated herein by reference to Exhibit 7(j) in File No. 2-6494);
and copies of Supplemental Indentures Nos. 1 through 14 to the Mortgage and Deed of Trust, dated respectively, as
of June 1, 1949, March 1, 1954, April 1, 1956, February 1, 1959, July 1, 1961, January 1, 1964, March 1, 1966,
December 1, 1969, April 1, 1971, January 1, 1975, December 1, 1975, July 1, 1981, June 1, 1985 and November 1,
1985 (incorporated herein by reference to Exhibit 4(d) in File No. 33-1929); Supplemental Indenture No. 15 to the
Mortgage and Deed of Trust, dated as of July 1, 1986 (filed as Exhibit 4(c) in File No. 33-24168); Supplemental
Indentures Nos. 16, 17 and 18 to the Mortgage and Deed of Trust, dated, respectively, as of November 1, 1988,
October 1, 1989 and July 1, 1990 (incorporated herein by reference to Exhibit 4(c) in File No. 33-40482);
Supplemental Indenture No. 19 to the Mortgage and Deed of Trust, dated as of June 1, 1991 (incorporated herein by
reference to Exhibit 4(c) in File No. 33-64014); Supplemental Indenture No. 20 to the Mortgage and Deed of Trust,
dated as of June 1, 1993 (incorporated herein by reference to Exhibit 4(c) in File No. 33-53795); Supplemental
Indenture No. 21 to the Mortgage and Deed of Trust, dated as of October 15, 2012 (incorporated herein by reference
to Exhibit 4.1 to Form 8-K dated October 26, 2012, File No. 1-15973); and Supplemental Indenture No. 22 to the
Mortgage and Deed of Trust, dated as of November 1, 2016 (incorporated herein by reference to Exhibit 4.1 to Form
10-Q for the quarter ended September 30, 2016, File No. 1-15973).
Form of Secured Medium-Term Notes, Series B (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated
October 4, 2004, File No. 1-15973).
Copy of Indenture, dated as of June 1, 1991, between the Company and Bankers Trust Company, Trustee, relating
to the Company’s Unsecured Medium-Term Notes (incorporated herein by reference to Exhibit 4(e) in File No.
33-64014).
Form of Credit Agreement among Northwest Natural Gas Company and the parties thereto, with JPMorgan
Chase Bank, N.A. as administrative agent and U.S. Bank, N.A. and Wells Fargo Bank, N.A. as co-syndication
agents, dated as of December 20, 2012 (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated
December 21, 2012, File No.1-15973).
Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America, N.A., Canadian
Imperial Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank, N.A., and Wells
Fargo Bank, N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, extending the maturity date of the
Credit Agreement between Northwest Natural Gas Company and each financial institution, effective as of
December 20, 2013 (incorporated herein by reference to Exhibit 4k to Form 10-K for 2013, File No. 1-15973).
Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A., Bank of America, N.A., Canadian
Imperial Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank, N.A., and Wells
Fargo Bank, N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, extending the maturity date of the
Credit Agreement between Northwest Natural Gas Company and each financial institution, effective as of
December 20, 2014 (incorporated herein by reference to Exhibit 4m to Form 10-K for 2014, File No. 1-15973).
First Amendment to Credit Agreement, between the Company JPMorgan Chase Bank, N.A., Bank of America,
N.A., Canadian Imperial Bank of Commerce, Royal Bank of Canada, TD Bank, N.A., Union Bank, N.A., US Bank,
N.A., and Wells Fargo Bank, N.A., with JPMorgan Chase Bank, N.A. as Administrative Agent, dated as of
December 20, 2014 (incorporated herein by reference to Exhibit 4n to Form 10-K for 2014, File No. 1-15973).
Statement re computation of ratios of earnings to fixed charges.
Subsidiaries of Northwest Natural Gas Company.
95
23
Consent of PricewaterhouseCoopers LLP.
31.1
31.2
Certification of Principal Executive Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-
Oxley Act of 2002.
Certification of Principal Financial Officer Pursuant to Rule 13a-14(a)/15-d-14(a), Section 302 of the Sarbanes-
Oxley Act of 2002.
**32.1
Certification of Principal Executive Officer and Principal Financial Officer Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
Executive Compensation Plans and Arrangements:
*10a.
*10b.
*10c.
*10d.
*10e.
*10f.
*10g.
*10h.
*10i.
*10j.
*10k.
*10l.
Executive Supplemental Retirement Income Plan 2010 Restatement (incorporated herein by reference to Exhibit
10b. to Form 10-K for 2009, File No. 1-15973).
Supplemental Executive Retirement Plan, 2011 Restatement (incorporated herein by reference to Exhibit 10.1 to
Form 10-Q for the quarter ended September 30, 2011, File No. 1-15973).
Northwest Natural Gas Company Supplemental Trust, effective January 1, 2005, restated as of December 15,
2005 (incorporated herein by reference to Exhibit 10.7 to Form 8-K dated December 16, 2005, File No. 1-15973).
Northwest Natural Gas Company Umbrella Trust for Directors, effective January 1, 1991, restated as of
December 15, 2005 (incorporated herein by reference to Exhibit 10.5 to Form 8-K dated December 16, 2005, File
No. 1-15973).
Northwest Natural Gas Company Umbrella Trust for Executives, effective January 1, 1988, restated as of
December 15, 2005 (incorporated herein by reference to Exhibit 10.6 to Form 8-K dated December 16, 2005, File
No. 1-15973).
Restated Stock Option Plan, as amended effective December 14, 2006 (incorporated herein by reference to
Exhibit 10c. to Form 10-K for 2006, File No. 1-15973).
Form of Restated Stock Option Plan Agreement (incorporated herein by reference to Exhibit 10h. to Form 10-K
for 2009, File No. 1-15973).
Executive Deferred Compensation Plan, effective as of January 1, 1987, restated as of February 26, 2009
(incorporated herein by reference to Exhibit 10e. to Form 10-K for 2008, File No. 1-15973).
Directors Deferred Compensation Plan, effective June 1, 1981, restated as of February 26, 2009 (incorporated
herein by reference to Exhibit 10f. to Form 10-K for 2008, File No. 1-15973).
Deferred Compensation Plan for Directors and Executives, effective January 1, 2005, restated as of July 28, 2016
(incorporated herein by reference to Exhibit 10.3 to Form 10-Q for the quarter ended June 30, 2016, File No.
1-15973).
Form of Indemnity Agreement as entered into between the Company and each director and certain executive
officers (incorporated herein by reference to Exhibit 10l. to Form 10-K for 2009, File No. 1-15973).
Form of Indemnity Agreement as entered into between the Company and certain executive officers (incorporated
herein by reference to Exhibit 10l.(1) to Form 10-K for 2009, File No. 1-15973).
*10m.
Non-Employee Directors Stock Compensation Plan, as amended effective December 15, 2005 (incorporated
herein by reference to Exhibit 10.2 to Form 8-K dated December 16, 2005, File No. 1-15973).
96
*10n.
Executive Annual Incentive Plan, effective February 23, 2012, as amended effective January 1, 2016
(incorporated herein by reference to Exhibit 10p. to Form 10-K for 2015, File No. 1-15973).
10o.
Executive Annual Incentive Plan, effective January 1, 2017 (incorporated herein by reference to Exhibit 10o. to
Form 10-K for 2016, File No. 1-15973).
10p.
Executive Annual Incentive Plan, effective January 1, 2018.
*10q.
Form of Change in Control Severance Agreement between the Company and each executive officer (incorporated
herein by reference to Exhibit 10o. to Form 10-K for 2008, File No. 1-15973).
*10r.
Northwest Natural Gas Company Long Term Incentive Plan, as amended and restated effective May 24, 2012
(incorporated herein by reference to Exhibit 10r to Form 10-K for 2012, File No. 1-15973).
10s.
Northwest Natural Gas Company Long Term Incentive Plan, as amended and restated effective May 25, 2017.
*10t.
*10u.
*10v.
*10w.
Form of Long Term Incentive Award Agreement under the Long Term Incentive Plan (2015-2017) (incorporated by
reference to Exhibit 10w. to Form 10-K for 2014, File No. 1-15973).
Form of Long Term Incentive Award Agreement under the Long Term Incentive Plan (2016-2018) (incorporated
herein by reference to Exhibit 10w. to Form 10-K for 2015, File No. 1-15973).
Form of Long Term Incentive Award Agreement under the Long Term Incentive Plan between the Company and
an Executive Officer (2016-2018) (incorporated herein by reference to Exhibit 10x. to Form 10-K for 2015, File
No. 1-15973).
Agreement to Amend the Long Term Incentive Award Agreement, under the Long Term Incentive Plan dated
February 25, 2016 by and between the Company and an executive officer (incorporated herein by reference to
Exhibit 10y. to Form 10-K for 2015, File No. 1-15973).
*10x.
Form of Long Term Incentive Award Agreement under Long Term Incentive Plan (2017-2019) (incorporated herein
by reference to Exhibit 10x. to Form 10-K for 2016, File No. 1-15973).
10y.
Form of Long Term Incentive Award Agreement under Long Term Incentive Plan (2018-2020).
*10z.
Form of Consent dated December 14, 2006 entered into by each executive officer with respect to amendments to
the Executive Supplemental Retirement Income Plan, the Supplemental Executive Retirement Plan and certain
change in control severance agreements (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated
December 19, 2006, File No. 1-15973).
*10aa.
Consent to Amendment of Deferred Compensation Plan for Directors and Executives, dated February 28, 2008
entered into by each executive officer (incorporated herein by reference to Exhibit 10bb to Form 10-K for 2007,
File No. 1-15973).
10bb.
Form of Restricted Stock Unit Award Agreement under Long Term Incentive Plan (2018).
*10cc.
Corrected Form of Restricted Stock Unit Award Agreement under Long Term Incentive Plan (2017)(incorporated
herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended March 31, 2017, File No. 1-15973).
*10dd.
Form of Restricted Stock Unit Award Agreement under Long Term Incentive Plan (2016) (incorporated herein by
reference to Exhibit 10bb. to Form 10-K for 2015, File No. 1-15973).
97
*10ee.
Form of Amendment to Restricted Stock Unit Award Agreements (2013, 2014 and 2015) (incorporated herein by
reference to Exhibit 10cc to Form 10-K for 2016, File No. 1-15973).
*10ff.
Form of Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (2013, 2014 and 2015)
(incorporated herein by reference to Exhibit 10aa. to Form 10-K for 2012, File No. 1-15973).
*10gg.
Form of Special Restricted Stock Unit Award Agreement under the Long Term Incentive Plan between the
Company and an executive officer (incorporated herein by reference to Exhibit 10a. to Form 10-Q for the quarter
ended March 31, 2014, File No. 1-15973).
*10hh.
Form of Director Restricted Stock Unit Award Agreement under the Long Term Incentive Plan (incorporated herein
by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2017, File No 1-15973).
*10ii.
*10jj.
*10kk.
*10ll.
Form of Director Restricted Stock Unit Award Agreement under Long Term Incentive Plan (incorporated herein by
reference to Exhibit 10a. to Form 10-Q for the quarter ended March 31, 2016, File No. 1-15973).
Severance Agreement between Northwest Natural Gas Company and an executive officer, dated August 1, 2016
(incorporated herein by reference to Exhibit 10.1 to Form 8-K dated July 29, 2016, File No. 1-15973).
Form of Restricted Stock Unit Award Agreement between the Company and an executive officer dated as of July
27, 2016 (incorporated herein by reference to Exhibit 10.1 to Form 10-Q for the quarter ended June 30, 2016, File
No. 1-15973).
Amended and Restated Cash Retention Agreement between the Company and an executive officer, dated as of
July 28, 2016 (incorporated herein by reference to Exhibit 10.2 to Form 10-Q for the quarter ended June 30,
2016, File No. 1-15973).
*10mm.
Form of Special Restricted Stock Unit Award Agreement under Long Term Incentive Plan between the Company
and an executive officer, dated as of September 30, 2016 (incorporated herein by reference to Exhibit 10.1 to
Form 10-Q for the quarter ended September 30, 2016, File No. 1-15973).
*10nn.
Form of Severance Agreement between the Company and an executive officer, dated May 17, 2017 (incorporated
herein by reference to Exhibit 10.1 to Form 8-K dated April 24, 2017, File No. 1-15973).
*10oo.
Form of Special Restricted Stock Unit Agreement between the Company and an executive officer, dated May 17,
2017 (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated April 24, 2017, File No. 1-15973).
*10pp.
Form of Hire-On Bonus Agreement between the Company and an executive officer, dated May 17, 2017
(incorporated herein by reference to Exhibit 10.3 to Form 8-K dated April 24, 2017, File No. 1-15973).
10qq.
10rr.
10ss.
*10tt.
Form of Special Restricted Stock Unit Agreement between the Company and an executive officer, dated
September 30, 2016.
Form of Hire-On Bonus Agreement between the Company and an executive officer, date September 30, 2016.
Cash Retention Agreement between the Company and an executive officer, dated as of March 1, 2018.
Annual Incentive Plan for NW Natural Gas Storage, LLC, as amended effective January 1, 2017 (incorporated
herein by reference to Exhibit 10oo. to Form 10-K for 2016, File No. 1-15973).
*10uu.
Long Term Incentive Plan for NW Natural Gas Storage, LLC, as amended effective January 1, 2016 (incorporated
herein by reference to Exhibit 10pp. to Form 10-K for 2016, File No. 1-15973).
98
101.
The following materials from Northwest Natural Gas Company's Annual Report on Form 10-K for the fiscal year
ended December 31, 2017, formatted in Extensible Business Reporting Language (XBRL):
(i) Consolidated Statements of Income;
(ii) Consolidated Balance Sheets;
(iii) Consolidated Statements of Cash Flows; and
(iv) Related notes.
*Incorporated herein by reference as indicated
**Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is not being "filed" for purposes of Section 18 of the Securities
Exchange Act of 1934, as amended.
99
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
NORTHWEST NATURAL GAS COMPANY
By: /s/ David H. Anderson
David H. Anderson
President and Chief Executive Officer
Date: February 23, 2018
100
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the registrant and in the capacities and on the date indicated.
Signature
Title
Date
/s/ David H. Anderson
David H. Anderson
President and Chief Executive Officer
Principal Executive Officer and Director
February 23, 2018
/s/ Frank H. Burkhartsmeyer
Principal Financial Officer
February 23, 2018
Frank H. Burkhartsmeyer
Senior Vice President and Chief Financial Officer
/s/ Brody J. Wilson
Principal Accounting Officer
February 23, 2018
Brody J. Wilson
Vice President, Treasurer, Chief Accounting Officer
and Controller
)
)
)
)
)
)
)
)
)
)
)
February 23, 2018
)
)
)
)
)
)
)
)
)
)
)
)
)
)
/s/ Timothy P. Boyle
Timothy P. Boyle
/s/ Martha L. Byorum
Martha L. Byorum
/s/ John D. Carter
John D. Carter
/s/ Mark S. Dodson
Mark S. Dodson
/s/ C. Scott Gibson
C. Scott Gibson
/s/ Tod R. Hamachek
Tod R. Hamachek
/s/ Jane L. Peverett
Jane L. Peverett
/s/ Kenneth Thrasher
Kenneth Thrasher
/s/ Malia H. Wasson
Malia H. Wasson
Director
Director
Director
Director
Director
Director
Director
Director
Director
101
NORTHWEST NATURAL GAS COMPANY
Ratios of Earnings to Fixed Charges
(Unaudited)
EXHIBIT 12
In thousands, except share data
Fixed Charges, as defined:
Interest on Long-Term Debt
Other Interest
Amortization of Debt Discount and Expense
Capitalized Interest
Interest Portion of Rentals
Total Fixed Charges, as defined
Earnings, as defined:
Net Income (Loss)
Taxes on Income
Fixed Charges, as above
Total Earnings (Losses), as defined
Ratios of Earnings to Fixed Charges
Year Ended December 31,
2017
2016
2015
2014
2013
$
$
$
36,809
2,274
2,017
2,598
2,574
46,272
$
34,508
3,404
1,671
—
2,048
41,631
$
37,918
3,173
1,760
—
1,976
44,827
$
40,066
2,718
1,963
—
2,302
47,049
40,825
2,709
1,877
—
1,910
47,321
(55,623 )
58,895
(30,757 )
40,714
41,631
46,272
(40,108 ) $ 141,240
3.39
*
53,703
35,753
44,827
$ 134,283
3.00
58,692
41,643
47,049
$ 147,384
3.13
60,538
41,705
47,321
$ 149,564
3.16
*
In 2017, earnings were insufficient to cover fixed charges by approximately $86.4 million primarily due to the impairment of long-
lived assets at the Gill Ranch Facility.
SUBSIDIARIES OF NORTHWEST NATURAL GAS COMPANY
an Oregon Corporation
EXHIBIT 21
Name of Subsidiary
Gill Ranch Storage, LLC
NW Natural Energy, LLC
NW Natural Gas Storage, LLC
NNG Financial Corporation
Trail West Holdings, LLC
Trail West Pipeline, LLC
BL Credit Holdings, LLC
Northwest Biogas, LLC
KB Pipeline Company
Northwest Energy Corporation
Northwest Energy Sub Corporation
NWN Gas Reserves LLC
NW Natural Water Company, LLC
FWC Merger Sub, Inc.
Jurisdiction Organized
Oregon
Oregon
Oregon
Oregon
Delaware
Delaware
Delaware
Oregon
Oregon
Oregon
Oregon
Oregon
Oregon
Idaho
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
EXHIBIT 23
We hereby consent to the incorporation by reference in the Registration Statements on Form S 8 (Nos. 333-70218,
333-100885, 333-120955, 333-134973, 333-139819, 333-180350, 333-187005, 333-214425, and 333-221347) and Form S-3
(No. 333-214496) of Northwest Natural Gas Company of our report dated February 23, 2018 relating to the financial statements,
financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10 K.
/s/ PricewaterhouseCoopers LLP
Portland, Oregon
February 23, 2018
CERTIFICATION
I, David H. Anderson, certify that:
EXHIBIT 31.1
1. I have reviewed this annual report on Form 10-K of Northwest Natural Gas Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date: February 23, 2018
/s/ David H. Anderson
David H. Anderson
President and Chief Executive Officer
CERTIFICATION
I, Frank H. Burkhartsmeyer, certify that:
EXHIBIT 31.2
1. I have reviewed this annual report on Form 10-K for Northwest Natural Gas Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material
fact necessary to make the statements made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present
in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined
in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report
based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons
performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Date:
February 23, 2018
/s/ Frank H. Burkhartsmeyer
Frank H. Burkhartsmeyer
Senior Vice President and Chief Financial Officer
NORTHWEST NATURAL GAS COMPANY
Certificate Pursuant to Section 906
of Sarbanes – Oxley Act of 2002
EXHIBIT 32.1
Each of the undersigned, DAVID H. ANDERSON, Chief Executive Officer, and FRANK H. BURKHARTSMEYER, Senior Vice
President and Chief Financial Officer of NORTHWEST NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY
that:
1. The Company’s Annual Report on Form 10-K for the year ended December 31, 2017 (the Report) fully complies with
the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
2. Information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed this 23th day of
February 2018.
/s/ David H. Anderson
David H. Anderson
Chief Executive Officer
/s/ Frank H. Burkhartsmeyer
Frank H. Burkhartsmeyer
Senior Vice President and Chief Financial Officer
A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to
Northwest Natural Gas Company and will be retained by Northwest Natural Gas Company and furnished to the Securities and
Exchange Commission or its staff upon request.
COMMUNITY & SUSTAINABILITY REPORT
Learn more about NW Natural’s community
involvement and philanthropic contributions,
environmental stewardship, employee safety
efforts and other company initiatives.
View the Community & Sustainability
Annual Report at:
nwnatural.com/aboutnwnatural/community
LOW-INCOME PROGRAMS
NW Natural helps low-income customers
manage their bills through a variety of
programs. Shareholders and customers
support the Gas Assistance Program, which
supplements federal and state assistance
(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:86)(cid:17)(cid:3)(cid:44)(cid:81)(cid:3)(cid:68)(cid:71)(cid:71)(cid:76)(cid:87)(cid:76)(cid:82)(cid:81)(cid:15)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:50)(cid:85)(cid:72)(cid:74)(cid:82)(cid:81)(cid:3)(cid:47)(cid:82)(cid:90)(cid:16)(cid:44)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)
Gas Assistance Program uses public purpose
fees to help low-income customers pay their
(cid:88)(cid:87)(cid:76)(cid:79)(cid:76)(cid:87)(cid:92)(cid:3)(cid:69)(cid:76)(cid:79)(cid:79)(cid:86)(cid:17)(cid:3)(cid:55)(cid:75)(cid:72)(cid:3)(cid:50)(cid:85)(cid:72)(cid:74)(cid:82)(cid:81)(cid:3)(cid:47)(cid:82)(cid:90)(cid:16)(cid:44)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:40)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:3)
(cid:40)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:70)(cid:92)(cid:3)(cid:51)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:15)(cid:3)(cid:68)(cid:79)(cid:86)(cid:82)(cid:3)(cid:83)(cid:68)(cid:76)(cid:71)(cid:3)(cid:73)(cid:82)(cid:85)(cid:3)(cid:69)(cid:92)(cid:3)(cid:83)(cid:88)(cid:69)(cid:79)(cid:76)(cid:70)(cid:3)
purpose charges, helps customers in need
(cid:68)(cid:70)(cid:84)(cid:88)(cid:76)(cid:85)(cid:72)(cid:3)(cid:75)(cid:76)(cid:74)(cid:75)(cid:16)(cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:70)(cid:92)(cid:3)(cid:72)(cid:84)(cid:88)(cid:76)(cid:83)(cid:80)(cid:72)(cid:81)(cid:87)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)
weatherization upgrades.
(cid:57)(cid:76)(cid:72)(cid:90)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:47)(cid:82)(cid:90)(cid:16)(cid:44)(cid:81)(cid:70)(cid:82)(cid:80)(cid:72)(cid:3)(cid:51)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:86)(cid:3)(cid:68)(cid:87)(cid:29)
nwnatural.com/residential
ENERGY-EFFICIENCY PROGRAMS
NW Natural partners with Energy Trust of
Oregon to offer our Oregon and Washington
(cid:70)(cid:88)(cid:86)(cid:87)(cid:82)(cid:80)(cid:72)(cid:85)(cid:86)(cid:3)(cid:72)(cid:81)(cid:72)(cid:85)(cid:74)(cid:92)(cid:16)(cid:72)(cid:73)(cid:403)(cid:70)(cid:76)(cid:72)(cid:81)(cid:70)(cid:92)(cid:3)(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)
services. Learn more about the results of these
(cid:83)(cid:85)(cid:82)(cid:74)(cid:85)(cid:68)(cid:80)(cid:86)(cid:3)(cid:68)(cid:81)(cid:71)(cid:3)(cid:87)(cid:75)(cid:72)(cid:3)(cid:69)(cid:72)(cid:81)(cid:72)(cid:403)(cid:87)(cid:86)(cid:3)(cid:87)(cid:82)(cid:3)(cid:82)(cid:88)(cid:85)(cid:3)(cid:70)(cid:88)(cid:86)(cid:87)(cid:82)(cid:80)(cid:72)(cid:85)(cid:86)(cid:17)
View the Energy Trust of Oregon
Annual Report at:
nwnatural.com/residential
INVESTOR AND SHAREHOLDER
INFORMATION
STOCK TRANSFER AGENT
AND REGISTRAR
For common stock:
American Stock Transfer
& Trust Company
6201 15th Avenue
Brooklyn, NY 11219
(888) 777-0321
web: astfinancial.com
email: info@(cid:68)(cid:86)(cid:87)(cid:403)(cid:81)(cid:68)(cid:81)(cid:70)(cid:76)(cid:68)(cid:79)(cid:17)(cid:70)(cid:82)(cid:80)
TRUSTEE AND
BOND PAYING AGENT
For bond issues:
Deutsche Bank
Trust Company Americas
60 Wall Street
New York, NY 10005
(800) 735-7777
NIKKI SPARLEY
(cid:39)(cid:76)(cid:85)(cid:72)(cid:70)(cid:87)(cid:82)(cid:85)(cid:15)(cid:3)(cid:44)(cid:81)(cid:89)(cid:72)(cid:86)(cid:87)(cid:82)(cid:85)(cid:3)(cid:53)(cid:72)(cid:79)(cid:68)(cid:87)(cid:76)(cid:82)(cid:81)(cid:86)
Toll free (800) 422-4012, Ext. 2530
Direct (503) 721-2530
nikki.sparley@nwnatural.com
CHU LEE
Manager, Shareholder Services
Toll free (800) 422-4012, Ext. 2402
Direct (503) 220-2402
chu.lee@nwnatural.com
220 NW SECOND AVENUE
PORTLAND, OREGON 97209
NWNATURAL.COM
NYSE: NWN