Strength
in turbulent times
annual report
corporate profile
financial overview
NW Natural (nyse: nwn) is a 151-year-old
natural gas local distribution and storage
company headquartered in Portland,
Oregon. NW Natural serves about 668,000
customers in Oregon and Southwest Wash-
ington. In keeping with its steady growth,
the company has increased dividends paid to
shareholders for 54 consecutive years, a feat
matched by few publicly traded companies.
NW Natural operates gas storage facilities in
its service territory and provides gas storage
services to other companies in the Northwest.
NW Natural is developing the Gill Ranch
Storage facility near Fresno, California,
and plans to develop a new gas transmis-
sion pipeline in Oregon called Palomar to
provide enhanced gas deliverability and
reliability for the region.
service territory
and infrastructure projects
ASTORIA
washington
MIST STORAGE
GASCO LNG
VANCOUVER
earnings
Financial facts ($000):
Gross operating revenues
Net operating revenues
Net income
Financial ratios (%):
Return on average common equity
Capital structure at year-end:
Long-term debt
Common stock equity
common stock
Shareholder data (000):
Average shares outstanding
Year-end shares outstanding
Per share data ($):
Basic earnings
Diluted earnings
Dividends paid
Dividend rate at year-end
Book value at year-end
Market value at year-end
operating highlights
2009
2008
percent
increase
(decrease )
1,012,711
376,887
75,122
1,037,855
356,215
69,525
11.7
47.7
52.3
11.4
44.9
55.1
26,511
26,533
26,438
26,501
2.83
2.83
1.60
1.66
24.88
45.04
2.63
2.61
1.52
1.58
23.71
44.23
(2 )
6
8
3
6
(5 )
0
0
8
8
5
5
5
2
Gas sales and transportation deliveries (000 therms) 1,131,365
4,383
Degree days
667,794
Customers at year-end
1,061
Employees at year-end
1,260,751
4,576
662,341
1,133
(10 )
(4 )
1
(6 )
PORTLAND
THE DALLES
MOLALLA
PALOMAR
EAST
MADRAS
dividends paid on common stock (per share)
payment date
February 15
May 15
August 15
November 15
oregon
Total dividends paid
$ 0.395
0.395
0.395
0.415
$ 1.600
$ 0.375
0.375
0.375
0.395
$ 1.520
PALOMAR
WEST
LINCOLN CITY
NEWPORT LNG
COOS BAY
SALEM
ALBANY
EUGENE
KEY
NW NATURAL SERVICE TERRITORY
REGIONAL RESOURCE CENTER
LNG PLANT
UNDERGROUND STORAGE
GILL RANCH STORAGE
HEADQUARTERS
PROPOSED PALOMAR PIPELINE EAST
PROPOSED PALOMAR PIPELINE WEST
SACRAMENTO
northern california
SAN FRANCISCO
diluted earnings per share
(in dollars)
dividends paid per share
(in dollars)
$3.00
2.80
2.60
2.40
2.20
2.00
1.80
1.60
1.40
1.20
1.00
2005 2006 2007 2008 2009
$1.62
1.57
1.52
1.47
1.42
1.37
1.32
1.27
1.22
2005 2006 2007 2008 2009
GILL RANCH STORAGE
FRESNO
Diluted earnings per share were $2.83 in 2009 – up
8 percent over 2008.
Annual dividends paid per share in 2009 increased for the
54th consecutive year, including an average annual growth
rate of over 4 percent during the last 5 years.
table of contents
letter to shareholders ............................................................ 4
operations and infrastructure highlights ..................... 8
community and sustainability highlights ...................... 10
financial overview ..................................................................... 12
board of directors .................................................................... 18
corporate officers .................................................................... 19
quarterly financial information ........................................ 20
shareholder information ...................................................... 21
financial statements - form -k annual report
0534_narC3.indd 1
3
4/8/10 4:19:37 PM
letter to shareholders
In 2009, NW Natural celebrated its 150th anniversary.
It was an important milestone, one that reminded us of
the attributes that have helped our company fl ourish for
a century and a half – a deep commitment to service, an
ability to look ahead, a willingness to embrace change
and an unwavering focus on execution.
While these attributes have been a big part of our past,
they also defi ne us today. In 2009, they helped deliver
one of the company’s best fi nancial and operational
performances to date.
In fact, in a year marked by economic turbulence we:
• Earned $2.83 per share, the highest in the
company’s history;
• Returned nearly $36 million in bill credits to
customers;
• Reduced residential rates to customers by about
16 percent in Oregon and 22 percent in Washington;
Gregg Kantor,
President
and CEO
4
0534_narC3.indd 2
• Posted the second highest score in the
J.D. Power and Associates national
customer satisfaction survey;
• Negotiated a new fi ve-year contract
with our union;
• Deployed new technology that is driving
process improvements and effi ciencies;
• Completed a necessary workforce
reduction – primarily through attrition
and a voluntary severance program;
• Managed bad debt expense to 0.4 percent
of revenues;
• Advanced key gas infrastructure projects
that will grow and diversify the company;
• Raised the dividend rate by more than
5 percent, making it the 54th consecu-
tive year of increasing dividends paid
per share; and
• Maintained strong investment-grade
credit ratings.
In 2009, NW Natural built on its 150-year
legacy of success, delivering on its commitment
to customers and shareholders while setting the
stage for a strong future.
a win for customers
and shareholders
One of the few positive outcomes of last year’s
economic meltdown was lower wholesale natural
gas prices. NW Natural’s gas buyers captured
those savings for our customers and, as a result
of our unique gas cost-sharing mechanism in
Oregon, shareholders benefi ted as well.
Normally, gas-cost savings are returned to
customers in the form of lower rates during
the next heating season. Last year, to help
those feeling the pain of the economic down-
turn, we gave back as much as we could as
early as possible. Midyear we returned nearly
$36 million in gas-cost savings to customers
in the form of bill credits, rather than waiting
until the annual true-up. In addition to this
refund, in November we lowered residential
rates for the coming year substantially – by
about 16 percent in Oregon and 22 percent
in Washington.
For shareholders, the gas-cost savings trans-
lated into better-than-expected earnings. In
fact, we greatly exceeded our original earnings
guidance of $2.55 to $2.70, ending the year
at $2.83 per share. And despite the challenges
of the nation’s fi nancial markets last year,
NW Natural continued to successfully access
capital and our liquidity remained strong.
4/8/10 4:19:44 PM
While we delivered an excep-
tional fi nancial performance in
2009, it was also a remarkable
year for the progress we made
across our business.
a new accord:
a continued
commitment
In 2009, NW Natural’s
employees stepped up in
big ways. Th eir eff orts can
be seen in improved opera-
tions, the continued focus on
cost controls, the dedication
to customer service and a
commitment to ensuring the
company’s future success.
We began 2009 negotiating
a new employment contract
with our union, the Offi ce &
Professional Employees Inter-
national Union Local 11. For
over 20 years, NW Natural has
used an interest-based bargain-
ing approach that strives to
fi nd common ground and
avoid the hardened positions
that can lead to emotionally
charged deadlocks and
damaged relationships. Last
year’s negotiations required
compromises on both sides,
but in the end, it produced
an agreement that is fair to
employees and provides the
company what it needs to be
successful in today’s volatile
economic environment.
Th e new fi ve-year contract,
what we call the Joint Accord,
was ratifi ed by employees
in July. It strengthens our
company in many ways. For
example, by collapsing the
number of specialized job
descriptions into broader
job families, we set the stage
for a more versatile, effi cient
work force. And to help better
manage pension expenses,
we reached agreement to close
our defi ned benefi t plan to
new union employees – as
we had done in 2007 for
our nonunion employees.
In 2009, NW Natural
employees continued to
implement operational
improvements that we initiated
several years ago. We made
more progress streamlining
and standardizing our business
processes. And we continued
to harvest the benefi ts of
new technology.
Still, early last year it became
clear we were in no ordinary
recession. Th e homebuilding
sector had slowed substantially,
compared to what it had been
just a few years before. While
we were still growing, it was
at a far slower pace. We ended
the year with a customer
growth rate of 0.8 percent.
Between the end of 2005
and the beginning of 2010,
our eff orts to restructure the
company’s operations allowed
us to reduce our work force
by more than 20 percent.
Today, we are operating with
about 1,000 employees,
down from more than
1,300 in 2005.
We are appropriately staff ed
to do the work required of us.
We are also in a much stronger
position to weather future
housing market cycles without
needing to make signifi cant
adjustments to our work force.
Given this new economic
environment, we realized we
As the economy recovers
and the housing market
For the sixth consecutive
year, NW Natural ranked in
the top two in the West for
overall customer satisfaction.
In 2009, the company also
posted the second highest
score in the nation out of
75 gas utilities.
the promise
of natural gas
In our view, the future
for natural gas has never
been brighter. Natural gas
supplies are abundant and
prices are down. At the same
time, electric rates in the
Northwest are on the rise as
utilities add required renew-
able resources and address
In 2009, NW Natural’s employees continued to
implement operational improvements
that we had initiated several years ago.
We made more progress streamlining and
standardizing our business processes. And we continued
to harvest the benefi ts
of new technology.
needed to make adjustments
to our staffi ng levels, and
we needed to do it without
compromising safety, reli-
ability or customer service.
We completed a work force
assessment and identifi ed
potential position reductions
in areas primarily related to
adding new customers.
We talked to our employees
about the need to downsize;
we worked with the union
on how to go about it; and
by the end of the year, we
had reached our reduction
target. We are also proud to
report that we did it without
widespread layoff s – instead
using attrition and a voluntary
severance program.
picks up, we will rely more
on contract resources to add
new customers. Our employ-
ees will continue to focus on
higher-skilled tasks related
to engineering, specialty
construction, maintenance
and emergency response.
Th e work we completed last
year to improve our business
processes, resize ourselves
for a slower economy and
fi nalize a new labor agreement
wasn’t easy on employees.
But through it all, they stayed
focused on serving our
customers. Proof of that can
be seen once again in the
J.D. Power and Associates
Gas Utility Residential
Customer Satisfaction Survey.
the environmental issues
associated with coal.
Moreover, we believe policy-
makers at the local and
national level are coming
to understand the important
role natural gas will play in
the eff orts to address climate
change. We also believe any
national legislation passed
by Congress will refl ect
that fact.
Here at home, energy
customers in the Northwest
prefer natural gas. In fact, in
a study we commissioned last
year, respondents strongly
preferred gas to electricity
for home heating by a
three-to-one margin.
0534_narC3.indd 3
4/8/10 4:19:52 PM
While the housing sector remains sluggish, Oregon has the
advantage of innovative land-use policies that have worked
to limit overbuilding. We also continue to see in-migration
to the state. Together, these factors give us confi dence that
our service territory will work off existing housing inventories
more quickly than other areas around the country.
Th ere are many uncertainties ahead for the economy and the
energy landscape, but from our vantage point the product
advantages and public policy benefi ts of natural gas have
never been stronger.
total shareholder return
(annualized as a percent, including reinvestment of dividends)
one year
three years
five years
ten years
12%
10
8
6
4
2
0
2009
2006-2009 2004-2009 1999-2009
preparing for the future
Electric utilities are increasingly turning
to natural gas for generation to meet new
demand and to supplement intermittent
renewable resources. Th at is particularly true
on the West Coast where Washington, Oregon
and California have passed laws limiting carbon
emissions from new electric generation.
For example, the Northwest’s largest power
company predicts it will generate 66 percent
of its electricity from gas by 2029, compared
to 30 percent today. Oregon’s largest electric
utility also expects to increase its gas-fi red
electric generation by 15 percent in just the
next fi ve years.
All of this speaks to the importance of adding
new gas infrastructure in the West and why
NW Natural has chosen to use its storage and
pipeline expertise to grow and diversify. Last
year we made progress on these endeavors.
Gill Ranch Storage. In 2009, we hired Rick
Daniel, formerly president of EnCana Gas
Storage, to lead the completion and ongoing
operation of our Gill Ranch Storage facility
in California’s Central Valley.
Gill Ranch is a joint project with Pacifi c Gas
& Electric Company that includes an initial
6
0534_narC3.indd 4
4/8/10 4:19:52 PM
business in 2011 and beyond.
We are also optimistic about
making progress this year on
the permitting and commer-
cial arrangements necessary
to proceed with the Palomar
pipeline.
In 2009, as we celebrated our
150th anniversary, we pointed
with pride to the great legacy
of past NW Natural em-
ployees. I want to fi nish this
letter by pointing with pride
to the achievements of the
employees who serve your
company today. Last year
they demonstrated what a
talented and dedicated work
force can accomplish, even
in the face of very tough
economic conditions.
I am honored to work with
them. And I’m confi dent
they will continue to live up
to the highest expectations
of our customers, the com-
munities we serve and you,
our shareholders.
Th ank you once again
for your commitment to
NW Natural and the trust
you place in us.
Sincerely,
Gregg S. Kantor
President and
Chief Executive Offi cer
20 Bcf of underground
storage capacity and a 27-mile
pipeline. Last October the
project reached an important
milestone when the California
Public Utilities Commission
issued it a Certifi cate of Public
Convenience and Necessity.
Construction began in January
of this year, and we are target-
ing completion by the end of
the third quarter 2010.
Th e California Energy
Commission has stated that
development of gas infrastruc-
ture – including storage – is
one of its highest priorities.
We believe the timing and
location of the Gill Ranch
project position it well to
meet the growing needs of
the California energy market.
Storage Expansion at Mist.
NW Natural’s fi rst under-
ground storage project was
built over two decades ago
using depleted gas fi elds
near Mist, Ore., west of the
Portland area. Th is 16 Bcf
facility helps NW Natural
manage utility customer rates
by holding down transporta-
tion costs and allowing us to
secure gas purchases at the
lowest prices possible.
In addition to lower costs for
utility customers, expansions
at Mist have provided signifi -
cant contributions to earnings
over the last several years.
In fact, last year the nonutility
gas storage business segment
produced a net income of
$9 million.
In the latter part of 2009,
we completed 3D seismic
surveys and started the
engineering design work
for a potential expansion at
Mist. Th is new phase could
be an important step forward
because it would include a sec-
ond compressor station that
could serve future expansions.
Over the next year, we will
continue to evaluate the
appropriate timeline of
this expansion.
Palomar Pipeline. During
2009, we continued to work
with TransCanada on the
permitting of Palomar – a
217-mile, 36-inch pipeline.
Th e eastern portion of
Palomar – from Madras in
Central Oregon to Molalla
in the Willamette Valley –
presents a unique and
important opportunity. It
will strengthen our system’s
reliability by providing a
second interstate pipeline
to serve our customers. At
the same time, it will allow
us to access additional gas
supplies from the U.S.
Rocky Mountains.
If a liquefi ed natural gas
terminal is built on the
Columbia River, Palomar
could be extended west
to serve it. Palomar West
would provide another supply
option for customers, and
further enhance our ability
to buy gas at the lowest
possible price.
At this point, whether an
LNG terminal gets built
is uncertain. In either case,
we believe the east side of
Palomar is essential to serve
the growing gas supply and
pipeline capacity needs of
our region. We are currently
working with other energy
companies throughout
the Northwest to further
broaden shipper support
for Palomar East.
During 2009, we contin-
ued to work with property
owners, elected offi cials and
state and federal agencies on
permitting issues to refi ne the
proposed route for Palomar.
We hope to receive approval
for the project from the
Federal Energy Regulatory
Commission by the end
of 2010.
a look ahead
In 2009, we successfully navi-
gated the challenges created by
the worst economic downturn
since the Great Depression.
And I believe our decisive
response has helped us emerge
stronger than ever.
In 2010, the focus will
remain, as it has for many
years, on managing costs
and enhancing productivity.
We will continue to harvest
the effi ciency benefi ts
from our new technology
investments while pursuing
additional process improve-
ments with a leaner and
more fl exible work force.
High-effi ciency gas furnaces
and water heaters, gas cook
tops and hearth products
remain as popular as ever.
And a new generation of
combined heat and power
products promise new roles
for natural gas in the com-
mercial and industrial sectors.
We are going to work with
our customers and trade allies
to make sure these products
are as accessible and aff ord-
able as possible.
In addition, as we’ve done
throughout our company’s
history, we will search for
unique solutions that benefi t
our customers and the
communities we serve. For
example, we’ll be exploring
the resource potential for
biogas. First, we’ll support
pilot biogas production
projects through our volun-
tary customer carbon off set
program, Smart Energy. And
then we’ll be analyzing the
feasibility of using biogas in
our pipeline system. Frankly,
we believe the prospects
for energy solutions that
are both economically
smart and environmentally
responsible have never
been greater.
2010 will also be a pivotal
year for the growth and
diversifi cation of our non-
utility storage business.
Successfully completing
Gill Ranch is a top priority
for NW Natural this year.
We expect it to become an
important contributor to our
0534_narC3.indd 5
7
4/8/10 4:19:55 PM
operations and infrastructure highlights
operating efficiently today,
preparing for tomorrow
Off ering what customers want.
Northwest customers are wired.
Last year, 172,000 customers – about
26 percent of all accounts – completed
more than 700,000 transactions
using NW Natural’s Web site. Almost
87,000 customers, about 13 percent
of all customers, prefer email to paper
bills. And 16 percent of our customers
have payments deducted from their
bank accounts, rather than writing
out a check. Th ese are options our
customers want – they save paper
and postage costs, staff time and
increase customer satisfaction.
Getting it done right. In 2009, we
installed about 380,000 metering
devices, completing our Automated
Meter Reading project. It was an
example of doing things well from
start to fi nish. Working with proven
contractors and establishing a seven-
tiered quality assurance process, the
project was completed early and
came in 9 percent under budget.
Providing good service during tough times. Last year, in the midst of a diffi cult
work force reduction, our employees stayed focused on providing exceptional
service – and our customers appreciated it. For the sixth consecutive year, NW
Natural ranked in the top two in the West for overall customer satisfaction in
the J.D. Power and Associates Gas Utility Residential Customer Satisfaction
Survey. Th e company also posted the second highest score in the nation among
75 participating gas utilities.
customers served by each operating employee
Th e number of
customers served by
operating employees
continued to increase in
2009, as we improved
operational eff ectiveness.
1,000
900
800
700
600
500
400
‘05
‘06
‘07
‘08
‘09
8
0534_narC3.indd 6
4/8/10 4:19:56 PM
building gill ranch storage
With the necessary permits in hand, construction began
in January on the Gill Ranch Storage facility – a joint
development project with Pacifi c Gas & Electric Com-
pany. In addition to providing much-needed gas storage
for California, the project will have another major
benefi t – jobs. We expect construction of the storage
facility and related infrastructure to employ about 350
people during construction, providing a major boost
to a community experiencing an unemployment rate
greater than 40 percent.
expanding
mist storage
Since NW Natural
began making storage
services available to large
gas users throughout the
Northwest, the Mist
underground storage
facilities have added
increasing value to the
company. With greater
demand for natural gas predicted across the
West, we expect demand for storage to grow
as well. Our next expansion will help meet
the needs of other utilities and businesses.
Mist continues to be an invaluable resource to
core utility customers as well. During the 2009
December cold snap, we came close to a record
daily withdrawal of stored gas at Mist – which
allowed us to keep gas fl owing to Portland-area
customers despite an interruption on the
interstate pipeline system.
historic mist integrated development
(maximum daily deliverability in Dtherms)
600,000
500,000
400,000
300,000
200,000
100,000
0
‘00 ‘01 ‘02 ‘03 ‘04 ‘05 ‘06 ‘07 ‘08 ‘09
utility
interstate
Over the last nine years, Mist storage deliverability
has grown at a signifi cant pace.
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0534_narC3.indd 7
P l
Palomar
Mist Expansion
h
Gill Ranch
Gill R
planning palomar pipeline
As NW Natural and its partner,
TransCanada, prepare for a decision
from the Federal Energy Regulatory
Commission, the two companies are
working vigorously to reach out to
communities. During 2009, represen-
tatives of the companies held more
than 110 meetings with local govern-
ments; tribal offi cers; civic, business
and agricultural groups; and public
agencies. In addition, the team
continued meeting with landowners
along the proposed route to answer
questions and resolve potential
problems – well before the fi rst
shovel strikes the soil.
9
4/8/10 4:20:00 PM
community and sustainability highlights
supporting healthy
communities and
a healthy planet
Celebrating with compassion. In
2009, we celebrated 150 years of
operating in the Pacifi c Northwest.
We also refl ected on the interdepen-
dence between successful utilities and
healthy communities. So we felt it
fi tting to mark our anniversary with a
$150,000 contribution to the Oregon
Food Bank network. In addition, we
supported more than 270 Northwest
nonprofi t organizations.
Educating a safe generation. In 2009,
thousands of children heard NW
Natural’s message about natural gas
safety. Our Safe at Home program
provides free educational materials to
teachers in grades three through six.
Last year, participation increased
by 18 percent, with nearly 12,000
students in 322 schools studying a
week’s worth of classroom curricula
about natural gas safety. In addition, more than 42,000 people of all ages learned
about gas safety from the folks who best know how to engage kids – the Disney
organization. Portland’s Radio Disney created activities to help children under-
stand and remember safety facts at 32 events throughout our service territory.
Getting cash for getting healthy. At year-end, more than 42 percent of our work
force was signed up for the innovative Virgin HealthMiles program. Th e program
off ers cash incentives for healthy practices.
Employees earned nearly $90,000 last year
by getting more active and by monitoring
their weight and blood pressure regularly.
Th e program satisfi ed NW Natural’s desire
to help employees get healthier and to instill
a wellness orientation into our corporate
culture. In September, Virgin HealthMiles
awarded NW Natural one of its fi rst “Eye
on Fitness” awards, noting that the company
was “tackling rising health care costs head-on
through prevention.”
percent
of NW Natural employees
who participated in the
wellness program lost
or maintained their weight.
Participating employees
lost over 800 pounds
in 18 months.
10
0534_narC3.indd 8
4/8/10 4:20:08 PM
NW NATURAL’S CORE PURPOSE
We provide safe, reliable
and aff ordable energy
in an environmentally responsible way
to better the lives
of the public we serve.
getting smart
Smart Energy, the fi rst voluntary carbon off set program off ered to customers
by a stand-alone gas utility, helped build an innovative biodigester that could
become a model for the region. Th e project, located on a large dairy farm in
Central Oregon, uses tires as a medium for biogas-producing bacteria. Th e
sponsors hope this pilot project will give dairy farmers a low-cost solution to
their manure management challenges and lead to a practical source of biogas.
Smart Energy also is investing in a Washington state biodigester projected to
off set the equivalent of 60,000 metric tons of carbon dioxide over 10 years.
getting green
NW Natural’s Green Team, representing
various operational departments, took on the
challenge of reducing annual carbon emissions.
For example, modifi cations to air compressors
at one facility will save 192,000 kWh – and
about $13,000 – a year. Th ey also estimate
a 4.5 year payback period for proposed
improvements to lighting and heating
equipment. Another team is focused on
carbon reductions from the company’s
vehicle fl eet. Th ey are studying compressed
natural gas options and looking at ways to
reduce idling – and fuel use – in company
trucks. Th e review is highlighting small
ways to gather big savings.
smart energy customers
have offset
44,000 TONS
of carbon dioxide, which is
equivalent to reducing gasoline use
by 4.5 million gallons.
Safety
Integrity
Service Ethic
Caring
helping customers save
Clean Energy Works, a unique project in the test
phase, is helping Portland residents save energy
and money. Banks, utilities – including NW Natural
– and local governments created a low-interest loan
program for major energy-effi ciency upgrade projects.
As envisioned, energy-effi ciency retrofi ts would be
fi nanced over the long term and the loan repayment
included on a homeowner’s monthly utility bill.
Th e aim is to test the program with several hundred
Portland homeowners, installing a basic package of
insulation, and air and duct sealing. Th e resulting
energy savings should nearly or completely off set
the fi nanced cost of the improvements – meaning
little or no extra monthly costs for consumers. If the
pilot is successful, the approach may be a new model
for eff ectively expanding energy effi ciency in the
residential sector.
l
a
t
n
e
m
n
o
r
i
v
n
E
p
i
h
s
d
r
a
w
e
t
S
0534_narC3.indd 9
11
4/8/10 4:20:17 PM
comparative consolidated income statements
Th ousands, except per share amounts (year ended December 31)
2009
2008
2007
2006
2005
Operating revenues:
Gross operating revenues
Cost of sales
Revenue taxes
Net operating revenues
Operating expenses:
Operations and maintenance
General taxes
Depreciation and amortization
Total operating expenses
$ 1,012,711
611,168
24,656
$ 1,037,855
656,568
25,072
$ 1,033,193
639,150
25,001
$ 1,013,172
648,156
24,840
$ 910,486
563,860
21,633
376,887
356,215
369,042
340,176
324,993
127,104
28,253
62,814
218,171
113,360
26,660
72,159
212,179
120,488
25,288
68,343
214,119
114,560
24,419
64,435
203,414
113,216
23,185
61,645
198,046
Income from operations
158,716
144,036
154,923
136,762
126,947
Other income and expense - net
3,714
3,746
1,445
2,134
1,205
Interest charges - net
40,637
37,579
37,811
39,247
37,283
Income before income taxes
121,793
110,203
118,557
99,649
90,869
Income taxes
Net income
46,671
40,678
44,060
36,234
32,720
$ 75,122
$ 69,525
$ 74,497
$ 63,415
$ 58,149
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
26,511
26,576
26,438
26,594
26,821
26,995
27,540
27,657
27,564
27,621
$ 2.83
$ 2.83
$ 2.63
$ 2.61
$ 2.78
$ 2.76
$ 2.30
$ 2.29
$ 2.11
$ 2.11
Dividends per share of common stock
$ 1.60
$ 1.52
$ 1.44
$ 1.39
$ 1.32
Th ese Financial Statements are condensed. See full Financial Statements and Notes to Consolidated Financial Statements in the company’s Annual Report on Form 10-K.
net income
(in millions)
total plant and property
(in millions)
$90
80
70
60
50
40
30
20
10
0
2005
2006
2007
2008
2009
$1,750
1,500
1,250
1,000
750
500
250
0
Net Income in 2009 was $75 million, a company record.
12
0534_narC3.indd 10
2005
2006
2007
2008
2009
At the end of 2009, Total Plant and Property was
$1.7 billion, an 8 percent increase from 2008.
4/8/10 4:20:27 PM
comparative consolidated balance sheets
Th ousands (December 31)
2009
2008
2007
2006
2005
Assets
Plant and property:
Utility plant
Less accumulated depreciation
Utility plant - net
Non-utility property
Less accumulated depreciation and amortization
Non-utility property - net
Total plant and property
$ 2,216,112 $ 2,142,988
659,123
682,060
1,483,865
1,534,052
74,506
146,622
9,314
10,540
65,192
136,082
1,549,057
1,670,134
$ 2,052,161
615,533
1,436,628
67,149
7,904
59,245
1,495,873
$ 1,963,498
574,093
1,389,405
42,652
6,916
35,736
1,425,141
$ 1,875,444
536,867
1,338,577
40,836
5,990
34,846
1,373,423
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Inventories of gas, materials and supplies
Prepayments and other current assets
Total current assets 1
Regulatory assets 1
Fair value of non-trading derivatives 1
Other investments
Other assets
Total assets
Capitalization and liabilities
Capitalization:
Common stock equity
Long-term debt
Total capitalization
Current liabilities:
Notes payable
Accounts payable
Long-term debt due within one year
Taxes accrued
Interest accrued
Other current and accrued liabilities
Total current liabilities 1
8,432
35,543
77,438
71,230
(3,125 )
80,957
21,302
291,777
6,916
4,118
81,288
102,688
(2,927 )
96,067
40,909
329,059
6,107
–
69,442
78,004
(2,890 )
79,944
25,569
256,176
5,767
–
82,070
87,548
(3,033 )
78,128
21,695
272,175
7,143
–
84,418
81,512
(3,067 )
86,161
67,543
323,710
346,490
7,347
67,365
16,139
$ 2,399,252
435,789
4,738
54,132
5,377
$ 2,378,152
193,536
3,227
54,070
11,179
$ 2,014,061
196,280
6,557
47,985
8,718
98,851
178,653
58,451
9,216
$ 1,956,856 $ 2,042,304
$ 660,105
601,700
1,261,805
$ 628,373
512,000
1,140,373
$ 594,751
512,000
1,106,751
$ 599,545
517,000
1,116,545
$ 586,931
521,500
1,108,431
102,000
123,729
35,000
21,037
5,435
39,097
326,298
248,000
94,422
–
12,455
2,785
36,467
394,129
143,100
119,731
5,000
13,137
2,827
29,794
313,589
100,100
113,579
29,500
21,230
2,924
21,455
288,788
126,700
135,287
8,000
12,725
2,918
29,916
315,546
Regulatory liabilities 1
Deferred income taxes and investment tax credits
Fair value of non-trading derivatives 1
Other liabilities
Total capitalization and liabilities
248,613
295,250
257,831
300,898
158,381
22,836
192,165
178,825
$ 2,399,252 $ 2,378,152
275,090
206,340
18,587
93,704
$ 2,014,061
214,901
210,084
49,803
76,735
$ 1,956,856
344,487
227,400
6,876
39,564
$ 2,042,304
1 Current and long-term portions of regulatory assets, regulatory liabilities and fair value of non-trading derivatives are combined for presentation above.
Th ese Financial Statements are condensed. See full Financial Statements and Notes to Consolidated Financial Statements in the company’s Annual Report on Form 10-K.
0534_narC3.indd 11
13
4/8/10 4:20:29 PM
comparative financial statistics
market price & book value per share
(in dollars)
comparison of five-year cumulative total return
(based on $100 invested on 12/31/04)
$60
50
40
30
20
10
0
2005
2006
2007
2008
2009
$200
175
150
125
100
75
50
2004
2005
2006
2007
2008
2009
year-end book value
year-end market price
high /low market price
Th e year-end market-to-book ratio was 1.8 in 2009.
nwn
s&p utilities index
s&p small cap
Total shareholder return (annualized) over the fi ve years ending
December 31, 2009 was 9.77 percent, compared to the Standard &
Poor’s (S&P) Electric & Gas Utilities Index rate of 2.2 percent and
the S&P Small Cap 600 Index rate of 0.2 percent.
capital and project expenditures
(in millions)
year-end capital structure
(in millions)
$180
160
140
120
100
80
60
40
20
0
2005
2006
2007
2008
2009
customer growth
system maintenance
gas storage
system integrity
palomar pipeline
gill ranch
Total capital expenditures in 2009 were $170 million, of which $100
million was utility related.
$1,500
1,200
900
600
300
0
2005
2006
2007
2008
2009
common equity
long-term debt
short-term debt
At the end of 2009 total capitalization, including short-term debt, grew to
$1.4 billion, of which 47 percent was common equity.
14
0534_narC3.indd 12
4/8/10 4:20:31 PM
comparative financial statistics
Common stock
Ratios at year-end:
Price/earnings ratio
Dividend yield at year-end rate - %
Dividend payout - %
Consolidated return on average common equity - %
Per share data ($):
Basic earnings
Diluted earnings
Dividends paid
Dividend rate at year-end
Book value at year-end
Market price:
High
Low
Year-end
Average
2009
2008
2007
2006
2005
15.9
3.7
56.5
11.7
2.83
2.83
1.60
1.66
24.88
46.47
37.71
45.04
42.93
16.8
3.6
57.8
11.4
2.63
2.61
1.52
1.58
23.71
55.23
36.61
44.23
46.38
17.5
3.1
51.8
12.5
2.78
2.76
1.44
1.50
22.52
52.85
39.79
48.66
46.20
18.5
3.3
60.4
10.7
2.30
2.29
1.39
1.42
21.97
43.69
32.83
42.44
36.98
16.2
4.0
62.6
10.1
2.11
2.11
1.32
1.38
21.28
39.63
32.42
34.18
35.92
Number of shares of common stock outstanding (000):
Year-end
Average
26,533
26,511
26,501
26,438
26,407
26,821
27,284
27,540
27,579
27,564
Coverage data
Ratio of earnings to fi xed charges
(Securities and Exchange Commission method)
Cash fl ow data ($000)
Cash provided by operating activities
Cash used in investing activities
Utility plant
3.86
3.76
3.92
3.40
3.32
240,335
(162,141 )
34,721
(109,825 )
183,640
(117,479 )
148,566
(90,567 )
79,066
(92,008 )
Capital expenditures ($000)
Depreciation - % of average depreciable utility plant
Accumulated depreciation† - % of depreciable utility plant
91,201
2.9
42.8
96,582
3.4
42.2
93,785
3.4
40.8
95,307
3.4
39.6
89,259
3.4
38.4
Capital structure at year-end (%)
(Exclusive of current portion of long-term debt)
First mortgage bonds
Common stock equity
Total capital structure
Eff ective tax rate
47.7
52.3
100.0
44.9
55.1
100.0
46.3
53.7
100.0
46.3
53.7
100.0
47.0
53.0
100.0
Eff ective tax rate - % of pretax income
38
37
37
36
36
† Includes regulatory liability for accrued asset removal costs.
0534_narC3.indd 13
15
4/8/10 4:20:33 PM
comparative operating statistics
utility customers at year-end
(in thousands)
utility gas sales and transportation deliveries
(in millions of therms)
680
660
640
620
600
580
560
540
520
500
2005
2006
2007
2008
2009
1,400
1,200
1,000
800
600
400
200
0
2005
2006
2007
2008
2009
We added 5,453 new customers in 2009, expanding our customer base
by 0.8 percent. In the past fi ve years, the utility has added over 71,000
new customers.
firm sales
interruptible sales
transportation
Gas sales and transportation deliveries in 2009 decreased 10 percent from
2008, due primarily to warmer weather and the economic downturn.
utility gas revenues
(by class)
1%
3%
6%
4%
30%
56%
utility net operating revenues (margin)
(in millions)
$400
350
300
250
200
150
100
50
0
2005
2006
2007
2008
2009
residential
commercial
industrial firm sales
industrial interruptible sales
transportation
other
residential
commercial
industrial
other
Revenues from residential, commercial and industrial fi rm sales were
90 percent of total gas revenues.
Utility margin increased 6 percent over 2008, due primarily to gas cost –
sharing gains in 2009, and increased 13 percent since 2005.
16
14
0534_narC3.indd 14
4/8/10 4:20:36 PM
comparative operating statistics
Selected Utility Data
2009
2008
2007
2006
2005
Gas sales and transportation deliveries (000 therms):
Residential
Commercial
Industrial fi rm
Industrial interruptible
Total gas sales
Transportation
Total volumes delivered
412,867
255,593
39,447
72,525
780,432
350,933
1,131,365
428,787
265,531
47,340
87,484
829,142
431,609
1,260,751
398,960
249,659
52,340
89,128
790,087
424,882
1,214,969
382,665
242,683
66,971
112,736
805,055
387,594
1,192,649
371,538
233,987
74,880
149,106
829,511
328,056
1,157,567
Operating revenues and cost of sales ($000):
Utility operating revenues:
Residential
Commercial
Industrial fi rm
Industrial interruptible
Total gas sales revenues
Transportation
Regulatory adjustment for income taxes paid
Other
Total utility operating revenues
Cost of gas sold
Revenue taxes
Utility net operating revenues
Customer and weather data:
Total customers
Actual degree days
Percent colder (warmer) than average
Average use per customer (therms):
Residential
Commercial
Gas purchases (000 therms)
Gas purchased cost per therm - net (cents)
Average sendout cost of gas (cents)
Maximum day fi rm sendout (000 therms)
Maximum day total sendout (000 therms)
$ 555,844
292,697
41,407
62,116
952,064
13,635
5,884
21,166
992,749
611,088
24,656
$ 357,005
$ 566,840
298,943
46,579
68,978
981,340
14,288
1,760
21,784
1,019,172
656,504
25,072
$ 337,596
$ 555,312
298,800
54,567
74,876
983,555
14,191
5,996
12,228
1,015,970
639,094
25,001
$ 351,875
$ 536,468
290,666
66,986
93,107
987,227
12,800
–
161
1,000,188
648,081
24,840
$ 327,267
$ 471,502
250,287
64,507
100,740
887,036
10,755
–
2,862
900,653
563,772
21,633
$ 315,248
667,794
4,383
3%
686
4,113
784,982
71.96
78.40
6,980
8,339
662,341
4,576
7%
721
4,300
829,989
86.56
79.21
6,609
8,363
1,133
932
652,012
4,374
3%
687
4,110
806,905
75.00
80.89
5,845
7,344
1,141
924
636,584
4,089
(4)%
678
4,052
820,542
75.37
80.50
5,672
7,401
1,211
845
617,163
4,178
(2)%
682
3,972
815,334
71.42
67.96
5,649
6,966
1,305
738
Total employees at year-end
Number of customers served by each operating employee
1,061
979
0534_narC3.indd 15
17
15
4/8/10 4:20:38 PM
board of directors
MARTHA L. “STORMY”
BYORUM, 61
2004 2 6
Senior Managing Director
Stephens Cori Capital Advisors
New York, New York
TIMOTHY P. BOYLE, 60
2003 4 5
President and
Chief Executive Offi cer
Columbia Sportswear Company
Portland, Oregon
KEY: [Year elected to the board],
(1) Governance Committee, (2)
Audit Committee, (3) Organization
and Executive Compensation
Committee, (4) Public Aff airs and
Environmental Policy Committee,
(5) Strategic Planning Committee,
(6) Finance Committee
GREGG S. KANTOR, 52
2008
President and
Chief Executive Offi cer
NW Natural
Portland, Oregon
Front row
TOD R. HAMACHEK, 64
1986 1 2 5
Former Chairman and
Chief Executive Offi cer
Penwest Pharmaceuticals Company
Seattle, Washington
RUSSELL F. TROMLEY, 70
1994 1 2 3
Chairman of the Board
Tromley Industrial Holdings, Inc.
Tualatin, Oregon and
Chairman of the Board NW Natural
Portland, Oregon
Back row
JANE L. PEVERETT, 51
2007 2 3 5
Former President and
Chief Executive Offi cer
British Columbia
Transmission Corporation
Vancouver, British Columbia
KENNETH THRASHER, 60
2005 2 3 4
Chairman of the Board
Compli Corporation
Portland, Oregon
C. SCOTT GIBSON, 57
2002 1 3 4
President
Gibson Enterprises
Portland, Oregon
JOHN D. CARTER, 64
2002 1 2 6
Chairman of the Board
Schnitzer Steel Industries, Inc.
Portland, Oregon
MARK S. DODSON, 65
2003 4 5
Former Chief Executive Offi cer
NW Natural
Portland, Oregon
GEORGE J. PUENTES, 62
2007 4 6
Former President
Don Pancho Authentic
Mexican Foods, Inc.
Salem, Oregon
18
0534_narC3.indd 16
4/8/10 4:20:42 PM
corporate officers
J. KEITH WHITE, 57
[1996]
vice president business development
and energy supply and chief strategic
officer (-present)
Managing Director, Gas Operations
and Wholesale Services (-)
Managing Director and Chief Strategic Offi cer
(-)
STEPHEN P. FELTZ, 54
[1982]
treasurer and controller
(-present)
Assistant Treasurer and Manager
General Accounting (-)
Front row
MARGARET D. KIRKPATRICK, 55
[2005]
vice president and general counsel
(-present)
Partner, Stoel Rives LLP (-)
Back row
GRANT M. YOSHIHARA, 55
[1991]
vice president utility operations
(-present)
Managing Director, Utility Services (-)
Director, Utility Services (-)
General Manager, Consumer Services (-)
MARDILYN SAATHOFF, 53
[2008]
chief governance officer and
corporate secretary (-present)
Chief Compliance Offi cer and Assistant General
Counsel, Tektronix, Inc. (-)
General Counsel to Oregon Governor Kulongoski
and Business and Economic Development Advisor
(-)
C. ALEX MILLER, 52
2002
vice president finance and regulation
(- present)
Director, Rates and Regulatory Aff airs (-)
DAVID R. WILLIAMS, 57
[1978]
vice president utility services
(-present)
Director, Utility Operations (-)
Director, Districts and Labor Relations (-)
General Manager, Utility Operations (-)
0534_narC3.indd 17
DAVID H. ANDERSON, 48
2004
senior vice president and chief
financial officer (-present)
Senior VP and CFO, TXU Gas ()
Senior VP, Corporate Controller and Principal
Accounting Offi cer, TXU Corp. (-)
VP, Investor Relations and Shareholder
Services, TXU Corp. (-)
GREGG S. KANTOR, 52
[1996]
president and chief executive officer
(-present)
President and Chief Operating Offi cer (-)
Executive Vice President (-)
Senior Vice President, Public and Regulatory Aff airs
(-)
Vice President, Public Aff airs and Communications
(-)
LEA ANNE DOOLITTLE, 55
2000
senior vice president (-present)
Vice President, Human Resources (-)
Director of Compensation, Pacifi Corp (-)
19
17
4/8/10 4:20:47 PM
quarterly financial information
Quarterly Financial Information (unaudited)
(thousands except per share amounts)
March 31
June 30
Sept. 30
Dec. 31
Total
2009
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2008
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$437,355
142,639
47,363
1.79
1.78
$149,060
65,919
3,086
0.12
0.12
$116,854
48,626
(6,733)
(0.25)
(0.25)
$309,442
119,703
31,406
1.19
1.18
$1,012,711
376,887
75,122
2.83 *
2.83 *
$387,694
132,423
43,168
1.63
1.63
$191,254
62,572
3,297
0.12
0.12
$109,702
43,549
(10,120 )
(0.38 )
(0.38 )
$349,205
117,671
33,180
1.25
1.25
$1,037,855
356,215
69,525
2.63 *
2.61 *
* Quarterly earnings (loss) per share are based upon the average number of common shares outstanding during each quarter. Because the average number of shares outstanding has
changed in each quarter shown, the sum of quarterly earnings may not equal earnings per share for the year. Variations in earnings between quarterly periods are due primarily
to the seasonal nature of our business.
Common Stock Prices
NW Natural’s common stock is listed and trades on the New York Stock Exchange under the symbol “NWN.”
Th e quarterly high and low trading range during 2009 and 2008 was:
2009
Quarter Ended
March 31
June 30
September 30
December 31
2008
Quarter Ended
March 31
June 30
September 30
December 31
High
$45.66
46.07
46.00
46.47
High
$50.74
48.22
55.23
53.71
Low
$37.71
39.58
41.12
40.83
Low
$41.07
43.08
43.66
36.61
Th e closing quotations for the common stock on December 31, 2009 and 2008 were $45.04 and $44.23, respectively.
20
18
0534_narC3.indd 18
4/8/10 4:20:52 PM
shareholder information
notice of annual meeting
Th e 2010 Annual Meeting will be held at 2 p.m., Th ursday, May 27, at the Oregon Convention Center, 777 NE Martin
Luther King Jr. Blvd., Portland, Oregon 97232. A meeting notice and proxy statement will be sent to all shareholders
in April. If you plan to attend the annual meeting, you will need to detach and retain the admission ticket attached to
your proxy card mailed 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
evidence to the meeting that you owned NW Natural Common Stock as of the record date, and we will provide you with
an admission ticket. A form of government-issued photograph identifi cation will be required to enter the meeting.
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
market to fulfi ll purchases under the plan.
A prospectus will be sent upon request.
scheduled payment dates
February 15, 2010
May 14, 2010
August 13, 2010
November 15, 2010
certifications
Th e Chief Executive Offi cer certifi ed to
the NYSE on June 29, 2009 that, as of
that date, he was not aware of any viola-
tion by the company of NYSE’s corporate
governance listing standards, and the
company had fi led with the Securities
and Exchange Commission (SEC), as
exhibits 31.1 and 31.2 to its Annual Report
on Form 10-K for the year ended Decem-
ber 31, 2008, the certifi cates of the Chief
Executive Offi cer and the Chief Financial
Offi cer of the company certifying the
quality of the company’s public disclosure.
For the year ended December 31, 2009,
the certifi cates of the Chief Executive
Offi cer and Chief Financial Offi cer are
attached as exhibits 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 non-
management directors by writing to
NW Natural Board of Directors,
c/o Corporate Secretary.
forward-looking statements
Th e statements made in this Annual Report
that are not purely historical, including
statements regarding growth, future
demand for gas, and gas supplies, returns,
business development, project timelines,
job creation, operational changes, cost
management, strategy, governmental
policy and regulatory actions, economic
factors and the competitive environment
are forward-looking statements within
the “safe harbor” provisions of the Private
Securities Litigation Reform Act of 1995.
NW Natural’s actual results could diff er
materially from those anticipated in these
forward-looking statements as a result of
risks and uncertainties, including those
described in the attached report on Form
10-K. For a more complete description
of these risks and uncertainties, please
refer to our fi lings with the SEC on
Forms 10-K and 10-Q.
shareholder information
Robert S. Hess
Investor Relations
(800) 422-4012, Ext. 2388
rsh@nwnatural.com
Kimberlee V. Anderson
Shareholder Services
(800) 422-4012, Ext. 3412
kva@nwnatural.com
request for publications
Th e following publications may be ob-
tained without charge by contacting the
Corporate Secretary at NW Natural’s
address: Annual Report; Form 10-K;
Form 10-Q; Corporate Governance
Standards; Director Independence
Standards; Code of Ethics; and Board
Committee Charters.
Th ese publications, as well as other fi lings
made with the SEC, also are available on
NW Natural’s Web site at nwnatural.com.
Our SEC fi lings are also available in the
public reference room of the SEC at 100
F Street NE, Washington, DC 20549, by
calling (800) 732-0330 or by accessing the
SEC Web site at sec.gov.
stock transfer agent and registrar
For the common stock:
American Stock Transfer & Trust Company
59 Maiden Lane, Plaza Level
New York, NY 10038
(888) 777-0321
Web: amstock.com
email: info@amstock.com
trustee and bond paying agent
For all bond issues:
Deutsche Bank Trust Company Americas
60 Wall Street
27th Floor
New York, NY 10005
(800) 735-7777
220 NW Second Avenue, Portland, OR 97209
(503) 226-4211 or toll-free (800) 422-4012
nwnatural.com
NYSE: NWN
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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, 2009
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
Common Stock
Securities registered pursuant to Section 12(g) of the Act: None.
Name of each exchange on which registered
New York Stock Exchange
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 [
] 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, or
a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer [ X ]
Non-accelerated filer [
Accelerated Filer [
Smaller Reporting Company [
]
]
]
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, 2009, the registrant had 26,513,188 shares of its Common Stock outstanding. The aggregate market
value of these 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 $1,162,927,287.
At February 23, 2010, 26,533,028 shares of the registrant’s Common Stock (the only class of Common Stock) were
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of the registrant, to be filed in connection with the 2010 Annual Meeting of Shareholders,
are incorporated by reference in Part III.
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission
on Form 10-K
For the Fiscal Year Ended December 31, 2009
Table of Contents
PART I
Item 1.
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Forward-Looking Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Local Gas Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Utility Gas Supply, Storage and Transportation Capacity . . . . . . . . . . . . . . . . . . . . . . . .
Competition and Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation and Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions to Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Officers of the Registrant
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 3.
Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 4.
PART II
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Management’s Discussion and Analysis of Financial Condition and Results of Operations . . .
Item 7.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . .
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . .
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Certain Relationships and Related Transactions and Director Independence . . . . . . . . . . . . . . .
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Item 15.
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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GLOSSARY OF TERMS
Average weather: equal to the 25-year average
degree days based on temperatures established
in our 2003 Oregon general rate case.
Bcf: one billion cubic feet, a volumetric measure
of natural gas, roughly equal to 10 million
therms.
Btu: British thermal unit, a basic unit of thermal
energy measurement. One Btu equals the energy
required to raise one pound of water one degree
Fahrenheit at atmospheric pressure and 60
degrees Fahrenheit. One hundred thousand Btu’s
equal one therm.
Core utility customers: residential, commercial
and industrial customers on firm service from
the utility.
Cost of gas: the delivered cost of gas
commodity sold to customers, including the cost
of gas purchases, gas withdrawn from storage
inventory, gains and losses from commodity
hedges, pipeline demand charges, seasonal
demand cost balancing adjustments, regulatory
gas cost deferrals and company gas use.
Decoupling: a rate mechanism, also referred to
as our conservation tariff, which is designed to
break the link between earnings and the quantity
of natural gas consumed by customers. The
design is intended to allow the utility to
encourage customers to conserve energy while
not adversely affecting its earnings due to
reductions in sales volumes.
Degree days: units of measure that reflect
temperature-sensitive consumption of natural
gas, calculated by subtracting the average of a
day’s high and low temperatures from 65
degrees Fahrenheit.
Demand charge: a component in all core utility
customer rates that covers the cost of securing
firm pipeline capacity to meet peak demand,
whether that capacity is used or not.
Firm service: natural gas service offered to
customers under contracts or rate schedules that
will not be disrupted to meet the needs of other
customers, particularly during cold weather.
General rate case: a periodic filing with state or
federal regulators to establish equitable rates and
balance the interests of all classes of customers
and our shareholders.
Interruptible service: natural gas service
offered to customers (usually large commercial
or industrial users) under contracts or rate
schedules that allow for temporary interruptions
to meet the needs of firm service customers.
Liquefied natural gas (LNG): the cryogenic
liquid form of natural gas. To reach a liquid
form at atmospheric pressure, natural gas must
be cooled to approximately -260 degrees
Fahrenheit.
Purchased Gas Adjustment (PGA): a
regulatory mechanism for adjusting customer
rates due to changes in the cost to acquire and
deliver commodity supplies.
Return on equity (ROE): a measure of
corporate profitability, calculated as net income
divided by average common stock equity.
Authorized ROE refers to the equity rate
approved by a regulatory agency for utility
investments funded by common stock equity.
Sales service: service provided to a customer
that receives both natural gas supply and
transportation of that gas from the utility.
Therm: the basic unit of natural gas
measurement, equal to 100,000 Btu’s. An
average residential customer in our service area
uses about 700 therms in an average weather
year.
Transportation service: service provided to a
customer that secures its own natural gas supply
and pays the utility only for use of the
distribution system to transport it.
Utility margin: utility gross revenues less the
associated cost of gas and applicable revenue
taxes. Also referred to as utility net operating
revenues.
Weather normalization: a rate mechanism that
allows the utility to adjust customers’ bills
during the winter heating season to reduce
variations in margin recovery due to fluctuations
from average temperatures.
1
Forward-Looking Statements
This report contains “forward-looking statements” within the meaning of the U.S. Private
Securities Litigation Reform Act of 1995. Forward-looking statements can be identified by words such
as “anticipates,” “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:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
plans;
objectives;
goals;
strategies;
future events or performance;
trends;
cyclicality;
growth;
development of projects;
competition;
exploration of new gas supplies;
the benefits of liquefied natural gas;
estimated expenditures;
costs of compliance;
potential efficiencies;
impacts of new laws and regulations;
projected obligations under retirement plans;
adequacy of and shift in mix of gas supplies;
adequacy of regulatory deferrals; and
environmental, regulatory and insurance recovery.
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 uncer-tainties, 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 caution you therefore 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.
2
NORTHWEST NATURAL GAS COMPANY
PART I
ITEM 1. BUSINESS
General
Northwest Natural Gas Company (NW Natural) 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 September 1997. We maintain operations in Oregon,
Washington and California and conduct business through NW Natural, wholly-owned subsidiaries and
a joint venture. A reference to NW Natural (“we,” “us” or “our”) in this report means NW Natural and
its subsidiaries and joint venture unless otherwise noted.
Business Segments
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 that we aggregate and report as Other.
Local Gas Distribution
We are principally engaged in the distribution of natural gas in Oregon and southwest
Washington. We refer to this business segment as our local gas distribution segment or utility. Our
local gas distribution segment involves building and maintaining a safe and reliable pipeline
distribution system, purchasing gas from producers and marketers, contracting for the transportation of
gas over pipelines from regional supply basins to our service territory, and reselling the gas to
customers subject to rates and terms approved by the Oregon Public Utility Commission (OPUC) or by
the Washington Utilities and Transportation Commission (WUTC). Gas distribution also includes
transporting gas owned by large customers from the interstate pipeline connection, or city gate, to the
customers’ facilities for a fee, also approved by the OPUC or WUTC. Approximately 92 percent of our
consolidated assets at December 31, 2009, and 88 percent of our consolidated net income in 2009,
were related to the local gas distribution segment. The OPUC has allocated to us as our exclusive
service area a major portion of western Oregon, including the Portland metropolitan area, most of the
Willamette Valley and the coastal area from Astoria to Coos Bay. We also hold certificates from the
WUTC granting us exclusive rights to serve portions of three southwest Washington counties
bordering the Columbia River. We provide gas service in 124 cities and neighboring communities in
15 Oregon counties, as well as in 16 cities and neighboring communities in three Washington
counties. The city of Portland is the principal retail and manufacturing center in the Columbia River
Basin, and is a major port for trade with Asia.
At year-end 2009, we had approximately 668,000 total utility customers, consisting of
approximately 605,000 residential, 62,000 commercial and 1,000 industrial sales and transportation
customers. Approximately 90 percent of our utility customers are located in Oregon and 10 percent are
in Washington. Industries 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. No individual
utility customer or industry accounts for a significant portion of our revenues.
3
See Note 2 for further information on total assets and results of operations for the years ended
December 31, 2009, 2008 and 2007.
Utility Gas Supply, Storage and Transportation Capacity
We meet the expected needs of our core utility customers through natural gas purchases from a
variety of suppliers. Our supply and capacity plan is based on forecasted customer requirements and
takes into account estimated load growth by type of customer, attrition, conservation, distribution
system constraints, interstate pipeline capacity and contractual limitations and the forecasted transfer of
large customers between sales service and transportation-only service. We perform sensitivity analyses
based on factors such as weather variations and price elasticity effects. We have a diverse portfolio of
short-, medium- and long-term firm gas supply contracts that are supplemented during periods of peak
demand with gas from storage facilities either owned by or contractually committed to us.
Gas Acquisition Strategy
Our goals in purchasing gas for our core utility customers are:
• Reliability—Ensuring a gas resource portfolio that is sufficient to satisfy core utility
customer requirements under extremely cold weather conditions as described below in
“Source of Supply—Design Year and Design Day Sendout”;
• Lowest reasonable cost—Applying strategies to acquire gas supplies at the lowest
reasonable cost for utility customers;
• Price stability—Making use of physical assets (e.g. gas storage and long-term gas reserves)
and financial instruments (e.g. financial hedge contracts such as price swaps) to manage
commodity price variability; and
• Cost recovery—Managing gas purchase costs prudently to minimize the risks associated
with regulatory review and recovery of gas acquisition costs.
To achieve our gas acquisition strategy, we employ a gas purchasing strategy that emphasizes a
diversity of supply, liquid trading points, price risk management strategies, asset optimization and
regulatory alignment as described below.
Diversity of supply. There are three primary means by which we diversify our gas supply
acquisitions: regional supply basins; contract types; and contract durations.
Our utility obtains its gas supplies from three key regional supply basins. They are the Alberta
and British Columbia regions in Canada, and the Rocky Mountain region in the United States. We
believe that gas supplies available in the western United States and Canada are adequate to serve our
core utility requirements for the foreseeable future, but we are considering shifting more of our supply
mix to the U.S. Rocky Mountains based on projections of declining gas imports from western Canada
and increased gas production in the U.S. Rocky Mountains. We believe that the cost of natural gas
coming from these regions will continue to track respective market prices. Several projects have been
built and more are proposed to increase pipeline capacity out of the U.S. Rocky Mountain region,
while new technology to extract shale gas resources in recent years continues to increase the
availability of gas supply throughout North America. In addition, we also believe the potential
development of a liquefied natural gas (LNG) import terminal would benefit the Pacific Northwest. If
constructed, an LNG import terminal would introduce a new source of gas supply to our utility
customers and the region, thereby increasing the diversity of available sources of energy and increasing
the overall supply of natural gas available to meet future demand growth in the region.
4
We typically enter into gas purchase contracts for:
year-round baseload supply;
additional baseload supply for the winter heating season;
•
•
• winter heating season contracts where we have the option to call on all or some of the
•
supplies on a daily basis; and
spot purchases, taking into account forecasted customer requirements, storage injections
and withdrawals and seasonal weather fluctuations.
Other less frequent types of contracts include non-heating season baseload supplies,
non-heating season contracts where the supplier has the option to supply gas to us on a daily basis, and
seasonal exchange purchase and sale contracts. We try to maintain a diversified portfolio of purchase
arrangements.
We also use a variety of multi-year contract durations to avoid having to re-contract a
significant portion of our supplies every year. See “Core Utility Market Basic Supply,” below.
Liquid trading points. We purchase our gas supplies at liquid trading points to facilitate
competition and price transparency. These trading points include the NOVA Inventory Transfer (NIT)
point in Alberta (also referred to as AECO), Huntingdon/Sumas and Station 2 in British Columbia, and
various receipt points in the U.S. Rocky Mountains.
Price risk management strategies. Our four primary strategies for managing gas commodity
price risk are:
•
•
•
•
negotiating fixed prices directly with gas suppliers;
negotiating financial derivative instruments that effectively convert the floating price in a
physical supply contract to a fixed price (referred to as price swaps);
negotiating financial derivative instruments that effectively set a ceiling or floor price, or
both, on a floating price physical supply contract (referred to as calls, puts, and collars); and
buying gas and injecting it into storage or buying gas reserves for longer term supply
deliveries. See “Cost of Gas,” below.
Asset optimization. We use our gas supply, storage and transportation flexibility to capture
opportunities that emerge during the course of the year for gas purchases, sales, exchanges or other
means to manage net gas costs. In particular, our Mist underground storage facility provides flexibility
in this regard. In addition, in an effort to maximize the value of our gas storage and pipeline capacity,
we contract with an independent energy marketing company that optimizes our unused capacity when
those assets are not serving the needs of our core utility customers. This asset optimization service
performed by the independent energy marketing company produces cost savings that reduces our
utility’s cost of gas, as well as generates incremental revenues from a regulatory incentive sharing
mechanism that are included in our gas storage business segment. See Note 2.
Regulatory alignment. Mechanisms for gas cost recovery are designed to be fair and to balance
the interests of customers and shareholders. In general, utility rates are designed to recover the cost of,
but not earn a return on, the gas commodity purchased, and we attempt to minimize risks associated
with gas cost recovery through:
•
re-setting customer rates annually for changes in forecasted purchased gas costs and
recovery of customer deferrals of prior year’s actual versus forecasted gas purchase costs.
5
(see Part II, Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—
Purchased Gas Adjustment”);
aligning customer and shareholder interests, such as through the use of our Purchased Gas
Adjustment (PGA) incentive sharing mechanism, weather normalization, conservation, and
gas storage sharing mechanisms (see Part II, Item 7., “Results of Operations—Regulatory
Matters”); and
periodic review of regulatory deferrals with state regulatory commissions and key customer
groups.
•
•
Cost of Gas
The cost of gas to supply our core utility customers primarily consists of the purchase price
paid to suppliers, charges paid to pipeline companies to store and transport gas to our distribution
system and gains or losses related to gas commodity hedge contracts entered into in connection with
the purchase of gas for core utility customers.
Supply cost. Volatility in natural gas commodity prices has been dramatic over the last several
years primarily due to shifts in the balance of supply and demand, which has been affected by a variety
of factors, including weather, changes in demand, the level of production and availability of natural
gas, imports of natural gas, transportation constraints, availability of pipeline capacity, transportation
capacity cost increases, federal and state energy and environmental regulation and legislation, the
degree of market liquidity, supply disruptions, national and worldwide economic and political
conditions, and the price and availability of alternative fuels. We are in a favorable position with
respect to gas production because of the proximity of our service territory to supply basins in western
Canada and the U.S. Rocky Mountains, where some growth in gas production is expected to continue
for the foreseeable future.
Transportation cost. Pipeline transportation rates charged by our pipeline suppliers have been
relatively stable over the last several years. These rates periodically change when pipeline suppliers get
approval from the Federal Energy Regulatory Commission (FERC). Pipeline transportation rate
increases or decreases are generally passed on to our customers through annual PGA mechanisms.
Gas price hedging. We seek to mitigate the effects of higher gas commodity prices and price
volatility on core utility customers by using our underground storage facilities strategically and by
entering into financial hedge contracts in an attempt to fix or limit the price of gas commodity
purchases. Realized gains or losses from financial commodity hedge contracts are treated as reductions
or increases to the cost of gas.
Managing the Cost of Gas
We manage natural gas commodity price risk through active physical and financial hedging
programs. Our financial hedge contracts make up a majority of our commodity price hedging activity,
and these contracts are with a variety of investment-grade credit counterparties, typically with credit
ratings of AA- or higher. See Part II, Item 7A., “Quantitative and Qualitative Disclosures About
Market Risk—Credit Risk—Credit exposure to financial derivative counterparties.” Under our
financial hedge program, we are allowed to enter into commodity swaps, puts, calls and collars with
terms generally ranging anywhere from one month to five years.
6
In addition to the prices that are hedged through financial contracts, we also own physical gas
supplies in storage. We purchase and inject from 5 to 15 percent of our annual gas supply requirements
into storage during the summer when demand and gas prices are generally lower. About 15 percent of
our annual gas supply requirements is stored for withdrawal during the winter months in five different
storage facilities. We own and operate three of these storage facilities located within our service
territory, which reduces the need for additional upstream pipeline capacity and provides significant
cost savings. The other two storage facilities are owned and operated by our primary pipeline supplier.
The intended effect of our physical and financial hedging programs is to manage the price
exposure for a majority of our gas supply portfolio for the following gas contract year, which begins
November 1st of each year, with prices normally hedged for between 50 and 75 percent of year round
supplies, including more than 80 percent of our expected winter-heating season supplies based on
forecasted customer requirements. We are authorized by our Board of Directors to hedge up to 100
percent of our gas requirements for the next gas contract year.
Source of Supply—Design Year and Design Day Sendout
The effectiveness of our gas supply program ultimately rests on whether we provide reliable
service at a reasonable cost to our core utility customers. For this purpose, we develop a composite
design year and design day that is based on the coldest weather experienced over the last 20 years in
our service territory. We also assume that all usage by interruptible customers will be curtailed on the
design day. Our projected sources of delivery for design day firm utility customer sendout total
approximately 9 million therms. We are currently capable of meeting over 60 percent of our firm
customer maximum design day requirements with storage and peaking supply sources located within
or adjacent to our service territory, while the remaining gas supply requirements would be met by gas
purchases under firm contracts. Optimal utilization of storage and peaking facilities on our design day
reduces the cost and dependency on firm interstate pipeline transportation. On January 5, 2004, we
experienced our current record firm customer sendout of 7.2 million therms, and a total sendout of
8.9 million therms, on a day that was approximately 9 degrees Fahrenheit warmer than the design day
temperature. That January 2004 cold weather event lasted about 10 days, and the actual firm customer
sendout each day provided data indicating that load forecasting models required very little
re-calibration. Similar cold temperatures experienced in December 2008 and December 2009 produced
very high sendout days but firm sendout in December 2009 was still about 3 percent below our 2004
record. This primarily reflects a decline in average customer usage. Accordingly, we believe that our
supplies would be sufficient to meet firm customer demand if we were to experience design day
conditions. We will continue to evaluate and update our forecasts of design day requirements in
connection with our integrated resource plan (IRP) process (see “Integrated Resource Plan,” below).
The following table shows the sources of supply that are projected to be used to satisfy the
design day sendout for the 2009-2010 winter heating season:
Projected Sources of Supply for Design Day Sendout
Sources of Supply
Firm supply purchases
Mist underground storage (utility only)
Company-owned LNG storage
Off-system firm storage contracts
Recall agreements
Total
7
Therms
(in millions)
Percent
3.3
2.4
1.8
1.1
0.4
9.0
37
27
20
12
4
100
We believe the combination of the natural gas supply purchases under contract, our peaking
supplies and the transportation capacity held under contract on the interstate pipelines sufficiently
satisfies the needs of existing core utility customers and positions the utility to meet future
requirements.
Core Utility Market Basic Supply
We purchase gas for our core utility customers from a variety of suppliers located in western
Canada and the U.S. Rocky Mountain area. Currently, about 60 to 70 percent of our supply comes
from Canada, with the balance coming primarily from the U.S. Rocky Mountain region. We are
considering shifting more of our supply mix to the U.S. Rocky Mountains based on projections of
declining gas imports from western Canada and increased gas production in the U.S. Rocky
Mountains. At December 31, 2009, we had 29 firm contracts with 20 suppliers and remaining terms
ranging from five months to five years, which provide for a maximum of 1.55 million therms of firm
gas per day during the peak winter heating season and 0.8 million therms per day during the entire
year. These contracts have a variety of pricing structures and purchase obligations. In addition, we
have another 0.95 million therms of firm gas capacity whereby we can purchase contract or spot gas
supplies for delivery to our system during the peak winter heating season. During 2009, we purchased
783 million therms of gas under contracts with the following durations:
Contract Duration (primary terms)
Percent of Purchases
Long-term (one year or longer)
Short-term (more than one month, less than one year)
Spot (one month or less)
Total
49
18
33
100
We regularly renew or replace our gas supply contracts with new agreements with a variety of
existing and new suppliers. Aside from the optimization of our core utility gas supplies by the
independent energy marketing company (see “Gas Acquisition Strategy—Asset optimization,” above),
our daily contract requirements are provided by multiple sources with no more than three suppliers
providing between 5 and 10 percent of our average daily contract volumes. Firm year-round supply
contracts have remaining terms ranging from one to five years. Currently, all term gas supply contracts
use price formulas tied to monthly index prices. We hedge a majority of these contracts each year
using financial instruments as part of our gas purchasing strategy (see “Managing the Cost of Gas,”
above).
In addition to the year-round contracts, we continue to contract in advance for firm gas supplies
to be delivered only during the winter heating season primarily under short-term contracts. During
2009, new short-term purchase agreements were entered into with between 15 and 20 suppliers. These
agreements provide for a total of up to 1.1 million therms per day during the 2009-2010 heating
season. We intend to enter into new purchase agreements in 2010 for equivalent volumes of gas with
existing or new suppliers, as needed, to replace contracts that will expire during 2010.
We also buy gas on the spot market as needed to meet core utility customer demand. We have
flexibility under the terms of some of our firm supply contracts, which enables us to purchase spot gas
in lieu of the firm contract volumes thereby allowing us to take advantage of more favorable pricing on
the spot market from time to time.
8
We continue to purchase a small amount of gas from a non-affiliated producer in the Mist gas
field in Oregon. The production area is situated near our underground gas storage facilities. Current
production supplies are less than 1 percent of our total annual purchase requirements. Production from
these wells varies as existing wells are depleted and new wells are drilled.
Core Utility Market Peaking Supply and Storage
We supplement our firm gas supplies with gas from storage facilities we own or that are
contractually committed to us. Gas is generally purchased and stored during periods of low demand for
use at a later time during periods of peak demand. In addition to enabling us to meet our peak demand,
these facilities make it possible to lower the annual average cost of gas by allowing us to minimize our
pipeline capacity demand costs and to purchase gas for storage during the summer months when gas
prices are generally lower.
Underground storage. We provide daily and seasonal peaking gas supplies to our Oregon core
utility customers from our underground gas storage facility in the Mist gas storage field. Including the
latest expansions in 2008, this facility has a maximum daily deliverability of 5.1 million therms and a
total working gas capacity of about 16 Bcf. In May 2008, a total of 100,000 therms per day of Mist
storage capacity that had previously been available for storage services was recalled and committed to
use for core utility customers. This was the first recalled capacity since 2004. In May 2009, another
100,000 therms per day of Mist storage withdrawal capacity that had previously been available for
interstate storage services was recalled by the utility and committed to use for its core customers.
Under our regulatory agreement with the OPUC, non-utility gas storage at Mist has been developed in
advance of core utility customer needs for interstate storage services and can be recalled by the utility
to serve utility customers. Storage capacity recalled by the utility is added to utility rate base at net
book value and tracked into utility rates in the annual PGA filing immediately following the recall, so
there is minimal regulatory lag in cost recovery. The core utility market now has 2.5 million therms per
day of deliverability and approximately 9.4 Bcf of working gas committed from the Mist storage
facility.
We also have contracts with the Williams Companies’ Northwest Pipeline (Northwest Pipeline)
for firm gas storage services from an underground storage facility in Jackson Prairie near Chehalis,
Washington, and an LNG facility in Plymouth, Washington. Together, these two facilities provide us
with daily firm deliverability of about 1.1 million therms and total seasonal capacity of about
16 million therms. Separate contracts with Northwest Pipeline provide for the transportation of these
storage supplies to our service territory. All of these contracts have reached the end of their primary
terms, but we have exercised our renewal rights that allow for annual extensions at our option.
Company-owned LNG storage. We own and operate two LNG storage facilities in our Oregon
service territory that liquefy gas for storage during the summer months so that it is available for
withdrawal during the peak winter heating season. These two facilities provide a maximum combined
daily deliverability of 1.8 million therms and a total seasonal capacity of 17 million therms.
Recallable capacity from transportation customers. We also have contracts with one electric
generator and two industrial customers that together provide 390,000 therms per day of recallable
pipeline capacity and supply. Another contract for 52,000 therms per day of year-round pipeline
capacity expired on June 30, 2009, and the capacity reverted back to the industrial customer. A
replacement agreement to reacquire the expired capacity was completed later in 2009 (see
“Transportation—Transportation agreements,” below).
9
Transportation
Single transportation pipeline. Our distribution system is directly connected to a single
interstate pipeline, Northwest Pipeline. Although we are dependent on a single pipeline, the pipeline’s
gas flows are bi-directional and, as such, transports gas into the Portland metropolitan market from two
directions: (1) the north, which brings supplies from 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. In
2003 a federal order requiring Northwest Pipeline to replace its 26-inch mainline from the Canadian
border to our service territory underscored the need for pipeline transportation diversity. That
replacement project was completed by Northwest Pipeline in November 2006. We are pursuing options
to further diversify our pipeline transportation paths. Specifically, we are jointly developing plans to
build a pipeline (Palomar) that would connect TransCanada Pipelines Limited’s (TransCanada) Gas
Transmission Northwest (GTN) interstate transmission line to our gas distribution system. In August
2007, we entered into an agreement with GTN for the purpose of jointly developing, owning and
operating this proposed pipeline. Additionally, we entered into precedent agreements to become a
shipper on the Palomar Pipeline. If constructed, this pipeline would provide an alternate transportation
path for gas purchases from Alberta and the U.S. Rocky Mountains that currently move through the
Northwest Pipeline system (See Part II, Item 7., “2010 Outlook—Strategic Opportunities—Pipeline
diversification”).
Transportation agreements. The largest of our transportation agreements with Northwest
Pipeline extends through September 2013 and provides for firm transportation capacity of up to
2.1 million therms per day. This agreement provides access to natural gas supplies in British Columbia
and the U.S. Rocky Mountains.
Our second largest transportation agreement with Northwest Pipeline extends through
November 2011. It provides up to 1.0 million therms per day of firm transportation capacity from the
point of interconnection of the Northwest Pipeline and GTN systems in eastern Oregon to our service
territory. GTN’s pipeline runs from the U.S./Canadian border through northern Idaho, southeastern
Washington and central Oregon to the California/Oregon border. We have firm long-term capacity on
GTN’s pipeline and two upstream pipelines in Canada, which match the amount of Northwest Pipeline
capacity northward into Alberta, Canada.
We also have an agreement with Northwest Pipeline that extends into 2044 for approximately
350,000 therms per day of firm transportation capacity from the U.S. Rocky Mountain region.
Additionally, in 2008 we executed an agreement with a third party to take assignment of their firm gas
supply transportation contract starting no earlier than 2012 nor later than 2017, with the term extending
through 2046. This contract consists of 120,000 therms per day on Northwest Pipeline from the U.S.
Rocky Mountain region.
Beginning in December 2009, we took assignment of a long-term firm transportation contract
from an industrial customer for approximately 40,000 therms of Northwest Pipeline capacity to serve
our utility customers.
In addition, we have firm long-term pipeline transportation contracts with two other major
transporters located in Canada. One contract extends through October 2014 and provides
approximately 600,000 therms per day of firm gas transportation from Station 2 in northern British
Columbia to the Huntingdon/Sumas connection with Northwest Pipeline at the U.S./Canadian
border. Another contract extends through October 2020 and provides approximately 470,000 therms
10
per day of firm gas transportation from southeastern British Columbia to the same Huntingdon/Sumas
connection with Northwest Pipeline. Our capacity on this second contract is matched with companion
contracts for pipeline capacity on the TransCanada BC system and NIT system in British Columbia
and Alberta, allowing purchases to be made from the gas fields of Alberta, Canada.
Rates. FERC establishes rates for interstate pipeline transportation service under long-term
transportation agreements within the U.S., and Canadian federal or provincial authorities establish rates
for service under agreements with the Canadian pipelines over which we ship gas.
Integrated Resource Plan
The OPUC and WUTC have implemented integrated resource planning processes under which
utilities develop plans defining alternative growth scenarios and resource acquisition strategies. These
plans are consistent with state and energy policy and include:
•
•
•
an evaluation of supply and demand resources;
the consideration of uncertainties in the planning process and the need for flexibility to
respond to changes; and
a primary goal of “least cost” service.
In January 2009, the OPUC acknowledged our 2008 IRP. Although the OPUC
acknowledgment of the IRP does not constitute ratemaking approval of any specific resource
acquisition strategy or expenditure, the OPUC generally indicates that it would give considerable
weight in prudency reviews to utility actions that are consistent with acknowledged plans. We filed our
2009 IRP with the WUTC in March 2009. In July 2009, the WUTC provided notice that our 2009 IRP
met the requirements of the Washington Administrative Code. The WUTC has indicated that the IRP
process is one factor it will consider in a prudency review.
Competition and Marketing
Competition with Other Energy Products
We have no direct competition in our service area from other natural gas distributors. However,
for residential customers, we compete primarily with electricity, fuel oil and propane. We also compete
with electricity and fuel oil for commercial applications. In the industrial market, we compete with all
forms of energy, including competition from third-party sellers of natural gas commodity. Competition
among gas suppliers is based on price, perceived environmental impact, sustainability, reliability,
efficiency and performance, market conditions, technology and legislative policy. Whether or not we
provide the gas supplies to serve our transportation-eligible customers, our net margins are not
materially affected because we generally do not make any margin on the commodity sales to our utility
customers (see “Industrial Markets,” below).
Residential and Commercial Markets
The relatively low market saturation of natural gas in residential single-family dwellings in our
service territory, estimated at approximately 55 percent, and our operating convenience and
environmental advantage over fuel oil, provides the potential for continuing growth from residential
and commercial conversions. In 2009, 5,407 net new residential customers were added, primarily from
single- and multi-family new construction, but also from the conversion of existing homes from oil,
11
electric or propane appliances to natural gas. The net increase of all new customers added in 2009 was
5,453. This represents a 12-month growth rate of 0.8 percent. On an annual basis, residential and
commercial customers typically account for about 55 to 60 percent of our utility’s total volumes
delivered and about 85 percent of gross operating revenues, while industrial customers account for
about 40 to 45 percent of volumes and about 12 percent of gross revenues. The remaining 3 percent of
gross operating revenues is derived from miscellaneous services and other regulatory charges.
Industrial Markets
Competition to serve the industrial and large commercial market in the Pacific Northwest has
been relatively unchanged since the early 1990s in terms of numbers and types of competitors.
Competitors consist of gas marketers, oil/propane sellers and electric utilities.
Industrial customer businesses 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. No
individual customer or industry group accounts for a significant portion of our revenues or margins.
The OPUC and WUTC have approved transportation tariffs under which we may contract with
customers to deliver customer-owned gas. Transportation tariffs available to industrial customers are
priced at our sales service rate less the commodity cost included in that rate. Therefore, our
transportation margins (i.e. sales minus the cost of gas sold) are unaffected financially if industrial
customers buy commodity supplies directly from marketers rather than purchasing gas from us, as long
as they remain on a tariff or contract with the same level of service. We do not generally make any
margin on the sale of the gas commodity. However, industrial customers may select between firm and
interruptible service, among other levels of service, and these choices can positively or negatively
affect margin as firm service has a higher margin than interruptible service. The relative level and
volatility of prices in the natural gas commodity markets, along with the availability of pipeline
capacity to ship customer-owned gas, are among the primary factors that have caused some industrial
customers to alternate between sales and transportation service or between higher and lower levels of
service.
Our industrial tariffs include terms which are intended to give us more certainty in the level of
gas supplies we will need to purchase in order to serve this customer group. The terms include an
annual election cycle period, special pricing provisions for out-of-cycle changes and the requirement
that industrial customers on our annual weighted average cost of gas tariff complete the agreed upon
term of their service. In the case of customers switching out-of-cycle from transportation to sales
service, the customer will be charged the cost of incremental gas supply in accordance with our
regulatory tariff.
We have designed custom transportation service agreements with several of our largest
industrial customers. These agreements are designed to provide transportation rates that are
competitive with the customer’s alternative capital and operating costs of installing direct connections
to Northwest Pipeline’s interstate pipeline system, which would allow them to bypass our gas
distribution system. These agreements generally prohibit bypass during their terms. Due to the cost
pressures that confront 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
12
customers to bypass our system in the foreseeable future, we may experience further deterioration of
margin associated with customers transferring to special contracts where pricing is specifically
designed to be competitive with their bypass alternative.
Gas Storage
Our gas storage business segment includes natural gas storage services provided to interstate
and intrastate customers in the Pacific Northwest using underground gas storage and pipeline facilities
we own and operate. We also use an independent energy marketing company to provide asset
optimization services for the utility under a contractual arrangement, the results of which are included
in this business segment.
Approximately 7 percent of our consolidated assets at December 31, 2009, and 12 percent of
our consolidated net income in 2009, are related to the gas storage business segment. For each of the
years ended December 31, 2009, 2008 and 2007, this business segment derived its revenues from asset
optimization services performed by an independent energy marketing company and from multi-year
gas storage contracts with less than 10 customers who contract for service at our Mist storage facility.
The total working gas capacity at our Mist gas storage facility is approximately 16 Bcf. Of this
capacity, approximately 9.4 Bcf, or 59 percent of storage capacity, is currently used by our utility, and
the remaining 6.6 Bcf, or 41 percent, is committed to gas storage customers primarily under firm
storage contracts. See Note 2 for more information on total assets and results of operations for the
years ended December 31, 2009, 2008 and 2007.
Pre-tax income from gas storage at Mist and third-party optimization services using our utility’s
storage or transportation capacity is subject to revenue sharing with core utility customers. In Oregon,
80 percent of the pre-tax income is retained by the gas storage segment when the costs of the capacity
used have not been included in utility rates, or 33 percent of the pre-tax income is retained when the
capacity costs have been included in utility rates. The remaining 20 percent and 67 percent of pre-tax
income in each case are credited to a deferred regulatory account for refund to our core utility
customers. We have a similar sharing mechanism in Washington for pre-tax income derived from gas
storage services and third-party optimization activities.
We are currently in the process of developing a second underground gas storage facility and
related pipeline in the Fresno, California area. This project is expected to serve the California
market. All permits were obtained to begin construction in 2010 (see “Gas storage development,”
below).
Asset optimization. We contract with an independent energy marketing company to optimize
the value of our unused storage and pipeline transportation assets, primarily through the use of
commodity transactions and pipeline capacity release transactions.
Seasonality of business. Generally, gas storage revenues do not follow seasonal patterns
similar to those experienced by the utility because rates for firm storage contracts are primarily in the
form of fixed monthly reservation charges and are not affected by customer usage. However, there is
some seasonal variation from the optimization of available utility storage capacity and related
transportation capacity. Temporary surplus capacity is usually available during the spring and summer
months when the demand for gas by utility customers is low.
13
Gas storage customers. Our gas storage business segment generally enters into contracts with
customers for firm storage capacity with terms ranging from one to 10 years. Currently, our gas storage
revenues are primarily derived from a few large storage customers who provide energy related
services, including natural gas distribution, electric generation and energy marketing companies. Five
storage customers currently account for over 90 percent of our existing gas storage capacity, with the
largest customer accounting for about half of total capacity. These five customers have contracts that
expire at various dates between March 2010 and April 2017.
Competitive conditions. Our Mist gas storage facility faces limited competition from other west
coast storage projects primarily because of its geographic location. In the future, we could face
increased competition from new or expanded natural gas storage facilities as well as from natural gas
pipelines, marketers and alternative energy sources.
Interstate gas storage. This part of the business segment currently provides firm and
interruptible gas storage services at Mist with related transportation services on the utility’s system to
and from Mist to interstate pipeline interconnections. The interstate storage services, and maximum
rates for these services, are authorized by the FERC. The storage capacity used by this business
segment has been developed as a non-utility investment by NW Natural in advance of core utility
customers’ requirements.
Intrastate gas storage. We provide intrastate gas storage services under an OPUC-approved
rate schedule that includes service and site-specific qualifications. The firm storage service terms and
conditions mirror the firm interstate storage service regulated by the FERC, except that these
customers are located and served in Oregon.
Gas storage development. In September 2007, we entered into a joint project agreement with
Pacific Gas & Electric Company (PG&E) to develop an underground natural gas storage facility near
Fresno, California. At that time, we formed a wholly-owned subsidiary, Gill Ranch Storage, LLC (Gill
Ranch), to plan and develop the project and to operate the facility. In July 2008, Gill Ranch filed an
application with the California Public Utilities Commission (CPUC) for a Certificate of Public
Convenience and Necessity (CPCN). In October 2009, we received an order from the CPUC approving
our CPCN. Gill Ranch’s provision of market-based rate storage services in California will be subject to
CPUC regulation including, but not limited to, service terms and conditions, tariff compliance, systems
of accounts, securities issuances, lien grants and sales of property. Our share of the total project cost is
estimated to be between $160 million and $180 million, representing 75 percent of the total cost of the
initial development, which includes our share of an estimated total 20 Bcf of gas storage capacity and
approximately 27 miles of gas transmission pipeline. We are currently in the process of hiring key staff
for our gas storage business. In January 2010, we began construction of the Gill Ranch facility. The
initial development of the gas storage facility at Gill Ranch is currently targeted to be in-service by the
end of the third quarter of 2010.
While our primary focus for growing the gas storage business is on the development at Gill
Ranch, we also plan to continue expanding our interstate storage facilities at Mist, Oregon. This past
year, we completed three-dimensional seismic surveys and initiated engineering work for a new 3 to 4
Bcf expansion at Mist. Pending confirmation of customer interest in contracting for the additional
capacity, we expect to move forward with the project next year and would target a 2011 in-service
date. The total project cost estimates are between $45 million and $55 million. This estimated cost
range includes the development of a second compression station and a pipeline gathering system at
Mist that will enable future storage expansions.
14
Other
We have non-utility investments and other business activities which are aggregated and
reported as a business segment called “Other.” Although in the aggregate these investments and
activities are not material, we identify and report them as a stand-alone segment based on our current
organization structure and decision-making process and because these business investments and
activities are not specifically related to our utility or gas storage segments. This segment primarily
consists of an equity method investment in a joint venture to build and operate an interstate gas
transmission pipeline in Oregon (see Part II, Item 7., “2010 Outlook—Strategic Opportunities—
Pipeline diversification,” below) and pipeline assets in our wholly-owned NNG Financial Corporation,
as well as some operating and non-operating expenses of the parent company that cannot be charged to
utility operations. Approximately 1 percent of our consolidated assets and consolidated net income are
related to activities in the “Other” business segment. See Note 2 for more information on total assets
and results of operations for the three years ended December 31, 2009.
Regulation and Rates
We are subject to regulation with respect to, among other matters, rates, terms of services, and
systems of accounts established by the OPUC, the WUTC, the FERC and, with respect to Gill Ranch,
the CPUC. The OPUC and WUTC also regulate our issuance of securities, as will the CPUC with
respect to Gill Ranch. Approximately 90 percent of our utility operating revenues are derived from
Oregon customers, and the balance is derived from Washington customers.
We file general rate case and rate tariff requests with the OPUC, WUTC and FERC to
periodically change the rates we charge our utility and storage customers. Later this year, we expect to
file a storage service tariff with the CPUC with respect to Gill Ranch. With certain exceptions, our
most recent agreement with the OPUC precludes us from filing a general rate case request before
September 2011, but does not preclude us from filing other types of rate adjustment requests. In 2008,
we filed a general rate case in Washington that was approved in December 2008 with the resulting
changes to rates effective on January 1, 2009 (see Part II, Item 7., “Results of Operations—Regulatory
Matters—General Rate Cases,” below). We are required under our Mist interstate storage certificate
authority and rate approval orders to file every three years either a petition for rate approval or a cost
and revenue study to change or justify maintaining the existing rates for the interstate storage service.
For further information, see Part II, Item 7., “Results of Operations—Regulatory Matters,” below and
“Business Segments—Gas Storage,” above.
Environmental Issues
Properties and Facilities
We have properties and facilities that are subject to federal, state and local laws and regulations
related to environmental matters. These laws and regulations may require expenditures over a long
timeframe to control environmental effects. Estimates of liabilities for environmental response 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;
15
•
•
•
•
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; and
variations between the estimated and actual period of time that must be dedicated to
respond to an environmentally-contaminated site.
We own, or previously owned, properties currently being investigated that may require
environmental response, including: a property in Multnomah County, Oregon that is the site of a
former gas manufacturing plant that was closed in 1956 (Gasco site); a property adjacent to the Gasco
site that is now the location of a manufacturing plant owned by Siltronic Corporation (Siltronic site);
an area adjacent to the Gasco and the Siltronic sites in the Willamette River that has been listed by the
U.S. Environmental Protection Agency as a Superfund site for which we have been identified as one of
a number of potentially responsible parties (Portland Harbor site); the former location of a gas
manufacturing plant operated by our predecessor that is outside the geographic scope of the current
Portland Harbor site (Front Street site); and the former site of three manufactured gas holding tanks
(Central Service Center site). Based on our current assessment of regulatory and insurance recovery of
environmental costs, we do not expect that the ultimate resolution of these matters will have a material
adverse effect on our financial condition, results of operations or cash flows; however, if it is
determined that both the insurance recovery and future rate recovery of such costs are not probable,
then the costs not expected to be recovered will be charged to expense in the period such determination
is made and could have a material impact on our financial condition or results of operations. See Note
11, for a further discussion of potential environmental responses, related costs and regulatory and
insurance recovery.
Future Environmental Issues
We recognize that our businesses are likely to be impacted by future carbon constraints. A
variety of legislative and regulatory measures to address greenhouse gas emissions are in various
phases of discussion or implementation. These include proposed international standards, proposed
federal legislation and proposed or enacted state actions to develop statewide or regional programs,
each of which have imposed or would impose measures to achieve reductions in greenhouse gas
emissions. For example, in December 2009, the U.S. Environmental Protection Agency (EPA)
officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases
present an endangerment to human health and the environment because emissions of such gases are,
according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.
These findings by the EPA allow the agency to proceed with the adoption and implementation of
regulations that would restrict emissions of greenhouse gases under existing provisions of the federal
Clean Air Act. In late September 2009, the EPA proposed two sets of regulations in anticipation of
finalizing its findings that would require a reduction in emissions of greenhouse gases from motor
vehicles and that could also lead to the imposition of greenhouse gas emission limitations in Clean Air
Act permits for certain stationary sources. Additionally, in September 2009, the EPA issued a final rule
requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission
sources in the United States beginning in 2011 for emissions occurring on or after January 1,
2010. This new rule also requires certain facilities that emit 25,000 metric tons or more of CO2
equivalents per year and certain industries to report certain greenhouse gas emissions data from that
facility or industry to the EPA on an annual basis. As we are part of the natural gas distribution
industry required to report these emissions, we are evaluating our obligations under this new rule in
light of additional guidance to be released by the EPA.
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The outcome of other international, federal and state climate change initiatives cannot be
determined at this time, but these initiatives could produce a number of results including potential new
regulations, legal actions, additional charges to fund energy efficiency activities, or other regulatory
actions. The adoption and implementation of any regulations imposing reporting obligations on, or
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 fossil fuel with a relatively low carbon content, it is also possible that future carbon
constraints could create additional demand for natural gas for electric production, direct use in homes
and businesses and as a reliable and relatively low-emission back-up fuel source for alternative energy
sources.
We continue to take steps to address future greenhouse gas emission issues, including actively
participating in policy development through the Oregon Governor’s Task Force on Climate Change
and leading efforts within the American Gas Association to promote the enactment of fair federal
climate change legislation. Our President and CEO is a commissioner on the Oregon Global Warming
Commission. We continue to engage in policy development and in identifying ways to reduce
greenhouse gas emissions associated with our operations and our customers’ gas use, including the
introduction of the Smart Energy program, which allows customers to contribute funds to projects that
offset greenhouse gases produced from their natural gas use.
Employees
At December 31, 2009, our workforce consisted of 646 members of the Office and Professional
Employees International Union (OPEIU), Local No. 11, AFL-CIO, and 415 management level and
other non-union employees (see Part II, Item 7., “2010 Outlook—Strategic Opportunities—Business
process improvements”). Our labor agreement with members of OPEIU that covers wages, benefits
and working conditions extends to May 31, 2014, and thereafter from year to year unless either party
serves notice of its intent to negotiate modifications to the collective union agreement.
Additions to Infrastructure
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,
technology, distribution system enhancements and the development of additional gas storage
facilities. In 2010, utility capital expenditures are estimated to be between $80 and $90 million, and
non-utility capital investments are estimated to be between $120 and $145 million for development
projects that are currently in process, including our storage expansion at Mist. For the years 2010-2014,
capital expenditures for the utility are estimated to be between $400 and $500 million, while the
amount for gas storage and other investments after 2010 will depend largely on future decisions about
potential opportunities in gas storage and pipeline projects.
Executive Officers of the Registrant
For information concerning our executive officers, see Part III, Item 10.
Available Information
We file annual, quarterly and special reports and other information with the Securities and
Exchange Commission (SEC). Reports, proxy statements and other information filed by us can be read
and copied at the Public Reference Room of the SEC, 100 F Street, N.E., Washington, D.C. 20549.
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You can obtain additional information about the Public Reference Room by calling the SEC at
1-800-SEC-0330. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy
statements and other information that 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, as well as proxy materials, filed
or furnished pursuant to Section 13(a) or 15(d) and 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 adopted a Code of Ethics for all employees and a Financial Code of Ethics that applies
to senior financial employees, both of which are available on our website. We intend to disclose
amendments to, and any waivers from, such codes of ethics 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 us 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.
ITEM 1A. RISK FACTORS
Our business and financial results are subject to a number of risks and uncertainties. When
considering any investment in our securities, investors should 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. Additional risks and uncertainties not presently known or currently
deemed immaterial also may impair our business operations. This list is not exhaustive and the order of
presentation does not reflect management’s determination of priority or likelihood.
Economic risk. Changes in the economy and in the financial markets may have a negative
impact on our financial condition and results of operations.
Changes in economic activity in our markets and in global financial markets can result in a
decline in customer additions and energy consumption, which could have a negative effect on our
financial condition and results of operations. In recent years, the U.S. and world economies have
slowed, unemployment rates and mortgage defaults have risen, and the value of homes and investment
assets have declined, which has adversely affected the income and financial resources of many
domestic households and businesses. It is unclear whether the federal responses to these conditions will
lessen the severity or duration of this economic downturn. Our operations and financial results are
affected by these economic conditions. Less new housing construction, fewer conversions to natural
gas, higher levels of residential foreclosures and vacancies, and personal and business bankruptcies or
reduced spending could all result in a decline in energy consumption and customer growth, a slowing
of collections from our customers, and a higher than normal level of accounts receivable and bad debts,
all of which could have a negative effect on our financial condition and results of operations.
Regulatory risk. Regulation of our business, including changes in the regulatory environment
in general, and failure of regulatory authorities to approve rates which provide for timely recovery of
our costs and an adequate return on invested capital in particular, 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
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capital invested, the amounts and types of securities we may issue, services we provide, facilities we
own or operate, terms of customer services, system of accounts, the nature of investments we may
make, safety standards, deferral and recovery of various expenses, including, but not limited to,
pipeline replacement and environmental remediation costs, transactions with affiliated interests,
actions investors may take with respect to our company and other matters. Similarly, FERC has
regulatory authority over our interstate gas storage services, and the CPUC has regulatory authority
over our Gill Ranch gas storage operations.
The rates we charge to customers must be approved by the applicable regulatory agencies. Our
rates are generally designed to allow us to recover the costs of providing such services and to earn an
adequate return on our capital investment. However, we expect the rates charged to customers of Gill
Ranch for gas storage services will be based on what customers are willing to pay (i.e. market-based
rates) rather than on our recovery of costs plus a reasonable return on our investment (i.e. cost-based
rates). We also expect to continue to make expenditures to expand, improve and operate our
distribution and storage systems. Regulators can deny recovery of expenditures we make if they find
that such expenditures were not prudently incurred according to their regulatory standards.
In addition, in the normal course of our 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.
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.
In recent years, we have seen a significant increase in the volatility of natural gas commodity
prices, primarily due to shifts in the balance of supply and demand. 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, imports of natural gas, including LNG, transportation constraints, availability of
pipeline capacity, transportation capacity cost increases, federal and state energy and environmental
regulation and legislation, the degree of market liquidity, supply disruption, natural disasters, wars and
other catastrophic events, national and worldwide economic and political conditions, and the price and
availability of alternative fuels. The cost we pay for natural gas is generally passed through to our
customers through an annual PGA rate adjustment in Oregon and Washington (see below). Significant
increases in the commodity price of natural gas raises the cost of energy to our existing customers,
thereby causing those customers to conserve or potentially switch to alternate sources of energy.
Significant price increases could also cause new home builders and commercial developers to select
heating systems other than natural gas. Decreases in the volume of gas we sell could reduce our
earnings in the absence of decoupled rate structures, and a decline in customers could slow growth in
our future earnings.
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
several months or even a year 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. This could contribute to higher short-term debt levels, greater expense associated with
collection efforts and increased bad debt expense.
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In Oregon and Washington, our utility has PGA tariffs which provide for annual revisions in
rates resulting from changes in the cost of purchased gas including the expected impact on bad debt
expense. In Oregon, we also have a price-elasticity adjustment that adjusts rates through the annual
PGA for expected increases or decreases in customer usage due to higher or lower gas prices. The
Oregon PGA tariff also provides an incentive to the Company to achieve lower gas costs such that a
percentage, set annually, of any difference between the estimated average PGA gas cost in rates and
the actual average gas cost incurred be recognized as current income or expense (see Part II, Item 7.,
“Results of Operations—Regulatory Matters—Rate Mechanisms”). Accordingly, higher average gas
costs than those assumed in setting rates can adversely affect our operating cash flows, liquidity and
results of operations. 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.
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 markets, including commercial paper, debt capital
markets 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 the capital markets could adversely affect our ability to access short-term and long-term
financing. Our access to funds under committed short-term 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/or 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 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.
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.
We attempt to manage these exposures and mitigate our risks through adherence to established risk
limits and risk management procedures, including hedging activities that are in accordance with our
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derivatives policy guidelines. These risk limits and risk management procedures 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 which could adversely impact our financial
condition, results of operations, and cash flows.
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, thereby limiting our exposure to earnings volatility on a year-to-year basis. However, the hedge
transactions we enter into for the utility are subject to a prudency review by the OPUC and WUTC,
and, if deemed imprudent, those expenses may be disallowed, which could have an adverse effect on
our financial condition and results of operations. In addition, 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 hedge accounting under generally accepted
accounting standards, our hedges may not be effective and our results of operations and financial
condition could be adversely affected.
We also have credit-related exposure to derivative counterparties. In general, we require our
counterparties to have an investment-grade credit rating at the time the derivative instrument is entered
into, and we specify limits on the contract amount and duration based on each counterparty’s credit
rating. Nevertheless, 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. In that event, our financial results could be adversely affected.
Although our valuations take into account the expected probability of default and the potential loss due
to a default by our counterparties, an actual default by a particular counterparty could have a greater
impact than we estimate. 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.
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 fuel sources and growing commercial use of natural
gas. Continued weakness in the residential new construction and conversion market and continued
decline in average use of natural gas by our residential and commercial customers, could result in an
adverse long-term impact on our utility margin, earnings and cash flows.
Risk of competition. Our gas distribution and storage businesses are subject to increased
competition which could negatively affect our results of operations.
In the residential market, our gas distribution business competes primarily with suppliers of
electricity, fuel oil, propane, and renewable energy providers. We also compete with suppliers of
electricity, fuel oil and renewable energy providers for commercial applications. In the industrial
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market, we compete with suppliers of all forms of energy, including oil, electricity, renewable energy
providers and, as it relates to sources of energy for electric power plants, coal and hydro. Competition
among these forms of energy is based on price, reliability, efficiency and performance.
Higher natural gas prices have at times eroded, or in some cases eliminated, the competitive
price advantage of natural gas over other energy sources. Technological improvements in other energy
sources could also erode our competitive advantage. If natural gas prices rise relative to other energy
sources, 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.
Our existing gas storage segment currently faces limited competition from other west coast
storage projects primarily because of its geographic location. In the future, we could face increased
competition from new or expanded natural gas storage facilities, interstate pipelines and gas marketers
seeking to provide or arrange transportation, storage and other services for customers.
Reliance on third parties to supply natural gas risk. We rely on third parties to supply
substantially all of the natural gas we store and deliver, and limitations on our ability to obtain
supplies 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 deliver supplies of natural gas from third parties, as well as our ability to acquire supplies
directly from new sources. Certain factors including the following may affect our ability to acquire and
deliver natural gas to our current and future customers: suppliers or other third parties’ control over
drilling of new wells and operating facilities to transport natural gas to our distribution system;
competition for the acquisition of natural gas; priority allocations on transmission pipelines; impact of
severe weather disruptions to natural gas supplies such as occurred with Hurricane Katrina in 2005; the
regulatory and pricing policies of federal, state and local government agencies; and the availability of
Canadian reserves for export to the United States. If we are unable to obtain or are limited in our ability
to obtain natural gas from our current suppliers or new sources, our financial results could be adversely
impacted.
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, 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 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. 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 would negatively impact our results of operations
Business development risk. The development, construction, startup and operation of our
business development projects may involve unanticipated changes or delays that could negatively
impact our costs as well as our financial condition, results of operations and cash flows.
Business development projects involve many risks. We are currently engaged in several
business development projects. We are in the early development stage on the Palomar gas transmission
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pipeline in Oregon, and we have begun construction of Gill Ranch gas storage facility in California.
We may also engage in other business development projects in the future, including expansion of our
storage facility at Mist. With respect to these projects, we may not be able to obtain required
governmental permits and approvals, or financing, to complete our projects in a cost-efficient or timely
manner. If we do not obtain the necessary regulatory approvals in a timely manner, development
projects may be delayed or abandoned. There also may be startup and construction delays, construction
cost overruns, inability to negotiate acceptable agreements such as rights-of-way, easements,
construction, gas supply or other material contracts, changes in customer demand, changes in market
prices, and operating cost increases. Additionally, natural gas storage and transportation markets are
intensely competitive, both within the natural gas industry and with alternative sources of energy. To
complete our business development projects, we will need to secure financing from willing investors at
reasonable cost. If credit markets are inaccessible, we may be unable fund our business development
projects at acceptable interest rates within a timeframe favorable for completing the project. Similarly,
an inability to obtain the necessary state permits, or arrange for sufficient supplier commitments could
impact the viability of an LNG terminal on the Columbia river and may mean that we would not
proceed with the western portion of Palomar. One or more of these events may mean that our equity
investments could become 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 decreases 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 non-utility development projects, including Palomar and Gill Ranch, and we may acquire
interests in other similar types of projects in the future. Under these types of business 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. In addition, other
participants may withdraw from the project, become financially distressed or bankrupt, or have
economic or other business interests or goals that are inconsistent with ours. Although we have
contractual and other legal remedies to enforce our interests, if a participant in one of these business
arrangements acts contrary to our interests, it could adversely impact the project as well as our
financial condition, results of operations and cash flows.
Environmental risk. Certain of our properties and facilities may pose environmental risks
requiring remediation, the cost of 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, but our results of operations
may be adversely affected to the extent that estimates of the probable costs increase significantly as
additional information becomes available and to the extent we are not able to recover the incremental cost
from insurance or through customer rates. A regulatory asset has already been recorded for estimated
costs pursuant to a deferral order from the OPUC. To the extent we are unable to recover these deferred
costs in rates or through insurance, we would be required to reduce our regulatory asset which would
adversely affect our results of operations and financial condition. In addition, disputes may arise between
potentially responsible parties and regulators as to the severity of particular environmental matters and
what remediation efforts are appropriate. These disputes could lead to adversarial administrative
proceedings or litigation, with associated costs and uncertain outcomes.
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We cannot predict with certainty the amount or timing of future expenditures related to
environmental investigation and remediation that may be required, or disputes arising in relation
thereto, because of the difficulty of estimating such costs. There is also uncertainty in quantifying
liabilities under environmental laws that impose joint and several liability on all potentially responsible
parties. Moreover, there are no assurances that existing environmental regulations will not be revised
or that new stricter regulations seeking to protect the environment will not be adopted or become
applicable to us. Revised environmental regulations which result in increased compliance costs or
additional operating restrictions could have an adverse effect on our financial condition and results of
operations, particularly if those costs are not fully recoverable from insurance or through customer
rates.
Global climate change risk. Management expects that future legislation may impose carbon
constraints to address global climate change exposing us to regulatory and financial risk. Additionally,
certain properties and facilities may be subject to physical risks associated with climate change.
There are a number of new 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 overall climate change, including greenhouse gas emissions such as carbon dioxide. The adoption
of current or future proposed legislation by U.S. Congress or similar legislation by states, or the
adoption of related regulations by federal or state regulatory bodies such as the EPA, imposing
reporting obligations on, or limiting emissions of greenhouse gases from our equipment or operations
could have far-reaching and significant impacts on our business as well as the broader energy
industry. Such current or future legislation or regulation could impose on us reporting requirements,
operational requirements or restrictions, or additional charges to fund energy efficiency initiatives.
Such initiatives could result in us 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, and could impact the prices we charge our
customers, 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 changes in customer demand, increased costs
associated with repairing and maintaining distribution systems resulting in increased maintenance and
capital costs (and potential increased financing needs), limits on our ability to meet peak customer
demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that
climate change adversely impacts the economic health of a region, it may adversely impact customer
demand and revenues. Such physical risks could have an adverse effect on our financial condition,
results of operations, and cash flows.
Weather risk. Our results of operations may be negatively affected by warmer than average or
colder than average weather.
We are exposed to weather risk primarily in our utility business segment. A majority of our
volume is driven from gas sales made to space heating residential and commercial customers during
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each winter heating season. Current utility rates are based on an assumption of average weather.
Weather that is warmer than average typically results in lower gas sales. Sustained colder weather
typically results in higher gas sales. Although the effects of warmer or colder weather on utility margin
in Oregon are intended to be largely mitigated through the operation of our weather normalization
mechanism, colder weather could adversely affect utility margin so we may be required to purchase
gas at spot rates in a rising price market to secure sufficient volumes to meet customer requirements.
Approximately 9 percent of our Oregon residential and commercial customers have opted out of the
weather normalization mechanism and another 10 percent are in Washington where we do not have a
weather normalization mechanism. Furthermore, continuation of the weather normalization mechanism
in Oregon after October 2012 is subject to regulatory approval. As a result, we may not be fully
protected against warmer than average or colder than average weather, both of which may have an
adverse affect 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, which can
decrease our sales of natural gas and adversely affect our results of operations. In Oregon, we have a
conservation tariff which is designed to recover lost margin due to declines in residential and
commercial customers’ consumption. The conservation tariff is scheduled to expire in October
2012. The failure of the OPUC to extend the conservation tariff in the future could adversely affect our
financial condition, results of operations and cash flows. We do not have a conservation tariff in
Washington.
Operating risk. Transporting and storing natural gas involves numerous risks that may result
in accidents and other operating risks and costs.
Our gas distribution activities are subject to a variety of operating hazards and risks that cannot
be completely avoided, such as leaks, accidents, mechanical problems, fires, explosions, earthquakes,
floods, storms, landslides and other adverse weather conditions and hazards, which could cause
substantial financial losses. In addition, our distribution facilities and equipment are subject to third
party damage from construction activities and vandalism. These risks could result in loss of human life,
significant damage to property, environmental pollution and disruption of our operations, which in turn
could lead to financial losses. The occurrence of any of these events may not be fully covered by our
insurance policies or be recoverable through rates, which could adversely affect our financial condition
and results of operations.
Business continuity risk. We may be adversely impacted by local or national disasters,
pandemic illness, terrorist activities and other extreme events to which we may not able to promptly
respond.
Local or national disasters, pandemic illness, terrorist activities and other extreme events are a
threat to our assets and operations. Companies in our industry may face a heightened risk due to
exposure to actual acts of terrorism that could target or impact our natural gas distribution,
transmission and storage facilities and result in a disruption in our operations and ability 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 that could affect our operations. Threatened or
actual national disasters or terrorist activities may also disrupt capital markets and our ability to raise
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capital, 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. We maintain emergency planning and training programs to
remain ready to respond to events that could cause business interruption. However, a slow or
inadequate response to events may have an adverse impact on operations and earnings. We may not be
able to obtain sufficient insurance to cover all risks associated with local and national disasters,
pandemic illness, terrorist activities and other events, which could increase the risk that an event could
adversely affect our operations or financial results.
Employee benefit risk. The cost of providing pension and postretirement healthcare benefits is
subject to changes in pension asset values, changing employee demographics and actuarial
assumptions, which may have an adverse effect on our financial results.
We provide pension plans and postretirement healthcare benefits to eligible full-time
employees. Our cost of providing such benefits is subject to changes in the market value of our pension
assets, changing employee demographics, including longer life expectancies of beneficiaries, 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 expense or other postretirement benefit costs recorded in
future periods. Sustained declines in equity markets and reductions in bond prices may have a material
adverse effect on the value of our pension fund assets. 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 financial condition, results of operations and cash flows.
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 in our gas distribution
business 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 aging employees retire. Without an appropriately skilled workforce, our
ability to provide quality service to our customers and meet our regulatory requirements will be
challenged and this could negatively impact our earnings. Additionally, a majority of our workers are
represented by Office and Professional Employees International Union Local No.11 AFL-CIO (the
Union) and are covered by a collective union agreement that will expire May 31, 2014. Disputes with
the Union over terms and conditions of the collective union agreement could result in instability in our
labor relationship and work stoppages that could impact the timely delivery of our product and
services, which could strain relationships with customers and state regulators and cause a loss of
revenues which could adversely affect our results of operations. The collective union agreement may
also increase the cost of employing our workforce, affect our ability to continue offering market-based
salaries and employee benefits, limit our flexibility in dealing with our workforce, and limit our ability
to change work rules and practices and implement other efficiency-related improvements to
successfully compete in today’s challenging marketplace.
26
Legislative and taxing authority risk. We are subject to governmental regulation, and our
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. 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 applicable to them. Changes in regulations or
the imposition of additional regulations could negatively influence our operating environment and
results of operations. For example, Oregon legislation that became effective in 2006 requires that
utilities not collect in rates more income taxes than they actually pay to taxing authorities. If amounts
paid differ from amounts collected by more than $100,000, then we are required to implement a rate
schedule with an automatic adjustment to refund or collect the difference, which could be material.
Additionally, changes in federal, state or local tax laws and their related regulations, or
differing interpretation 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. Unforeseen changes in laws, regulations
or adverse judgments may negatively affect our financial condition and results of operations.
Business improvements risk. Our efforts to integrate, consolidate and streamline our
operations have resulted in increased reliance on technology and third party vendors, the failure 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, which provides an integrated suite
of business application software; an automated dispatch system, which provides integrated planning,
scheduling and dispatching; an automated meter reading system, which allows for electronic reading of
customers meters; 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. Although we
have, when possible, developed alternative sources of technology and built redundancy into our
computer networks and tools, there can be no assurance that these efforts to date would protect us
against all potential issues or disaster occurrences related to the loss of any such technologies or their
use.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments.
27
ITEM 2. PROPERTIES
Utility Properties
Our natural gas distribution system consists of approximately 13,800 miles of distribution and
transmission mains located in our service territory in Oregon and Washington. In addition, the
distribution system includes service pipes, meters and regulators, and gas regulating and metering
stations. The mains are located in municipal streets or alleys pursuant to valid franchise or occupation
ordinances, in county roads or state highways pursuant to valid agreements or permits granted pursuant
to statute, or on lands of others pursuant to valid easements obtained from the owners of such lands.
We also hold all necessary permits for the crossing of the Willamette River and a number of smaller
rivers by our mains.
We own service facilities in Portland, as well as various satellite service centers, garages,
warehouses and other buildings necessary and useful in the conduct of our business. We lease office
space in Portland for our corporate headquarters, which expires on May 31, 2018. 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 own LNG storage facilities in Portland and near
Newport, Oregon.
In order to reduce risks associated with gas leakage in older parts of our system, we undertook
an accelerated pipe replacement program under which we removed or replaced 100 percent of our cast
iron mains by October 2000. In 2001, we initiated an accelerated pipe replacement program under
which we expect to eliminate all bare steel mains and services in the system by 2021.
Gas Storage Properties
We hold interests in approximately 8,500 net acres of underground natural gas storage in
Oregon and approximately 1,900 net acres of underground natural gas storage in California. We also
hold interests in approximately 1,600 net acres of oil and gas leases in Oregon. 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 an option to purchase future storage rights in certain
other areas of the Mist gas field in Oregon, as well as in California related to the Gill Ranch storage
project.
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 is a first mortgage lien on substantially all of the property
constituting our utility plant.
ITEM 3. LEGAL PROCEEDINGS
Other than the proceedings disclosed in Note 11, we have only routine nonmaterial litigation in
the ordinary course of business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders, through the solicitation of
proxies or otherwise, during the quarter ended December 31, 2009.
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29
PART II
ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
(A) 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
2009
High
Low
$45.66
46.07
46.00
46.47
$37.71
39.58
41.12
40.83
2008
High
Low
$50.74
48.22
55.23
53.71
$41.07
43.08
43.66
36.61
The closing quotations for our common stock on December 31, 2009 and 2008 were $45.04 and
$44.23, respectively.
(B) As of December 31, 2009, there were 7,418 holders of record of our common stock.
(C) We have paid quarterly dividends on our common stock in each year since the stock first
was issued to the public in 1951. Annual common dividend payments per share, adjusted for stock
splits, have increased each year since 1956. Dividends per share paid during the past two years were as
follows:
Payment Date
February 15
May 15
August 15
November 15
Total per share
2009
$0.395
0.395
0.395
0.415
$1.600
2008
$0.375
0.375
0.375
0.395
$1.520
The amount and timing of dividends payable on our common stock are within the sole
discretion of our Board of Directors. Our Board of Directors expects to continue paying cash dividends
on our common stock on a quarterly basis. However, the declaration and amount of future dividends
depend upon our earnings, cash flows, financial condition and other factors.
30
(D) 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, 2009:
ISSUER PURCHASES OF EQUITY SECURITIES
(a)
(b)
Total Number
of Shares
Purchased (1)
Average
Price Paid
per Share
(c)
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs (2)
(d)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the
Plans or Programs (2)
2,285
24,416
1,805
28,506
$43.19
$42.96
$45.00
$43.11
2,124,528
-
-
-
2,124,528
$16,732,648
-
-
-
$16,732,648
Period
Balance forward
10/01/09-10/31/09
11/01/09-11/30/09
12/01/09-12/31/09
Total
(1) During the quarter ended December 31, 2009, 25,126 shares of our common stock were purchased on the
open market to meet the requirements of our Dividend Reinvestment and Direct Stock Purchase Plan. In
addition, 3,380 shares of our common stock were purchased on the open market during the quarter under
equity-based programs. During the three months ended December 31, 2009, no shares of our common stock
were accepted as payment for stock option exercises pursuant to our Restated Stock Option Plan.
(2) We have a share repurchase program for our common stock under which we purchase shares on the open
market or through privately negotiated transactions. We have Board authorization through May 31, 2010 to
repurchase up to an aggregate of 2.8 million shares or up to an aggregate of $100 million. For the year
ended December 31, 2009, no shares of our common stock were purchased pursuant to this program. Since
the program’s inception in 2000 we have repurchased 2.1 million shares of common stock at a total cost of
$83.3 million.
31
ITEM 6. SELECTED FINANCIAL DATA
Thousands, except per share amounts and
ratio of earnings to fixed charges
2009
For the year ended December 31,
2007
2006
2008
2005
Utility operating revenues:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - interruptible sales
Total gas sales revenues
Transportation
Regulatory adjustment for income taxes paid (1)
Other
Total gross utility operating revenues
Cost of gas sold
Revenue taxes
Utility net operating revenues
Non-utility net operating revenues
$ 555,844 $ 566,840 $ 555,312 $ 536,468 $ 471,502
250,287
64,507
100,740
298,943
46,579
68,978
290,666
66,986
93,107
298,800
54,567
74,876
292,697
41,407
62,116
952,064
13,635
5,884
21,166
992,749
611,088
24,656
357,005
19,882
981,340
14,288
1,760
21,784
983,555
14,191
5,996
12,228
987,227
12,800
-
161
1,019,172
656,504
25,072
1,015,970
639,094
25,001
1,000,188
648,081
24,840
337,596
18,619
351,875
17,167
327,267
12,909
887,036
10,755
-
2,862
900,653
563,772
21,633
315,248
9,745
Net operating revenues
$ 376,887 $ 356,215 $ 369,042 $ 340,176 $ 324,993
Net income
$
75,122 $
69,525 $
74,497 $
63,415 $
58,149
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
26,511
26,576
26,438
26,594
26,821
26,995
27,540
27,657
27,564
27,621
$
$
$
2.83 $
2.83 $
2.63 $
2.61 $
2.78 $
2.76 $
2.30 $
2.29 $
2.11
2.11
1.60 $
1.52 $
1.44 $
1.39 $
1.32
Total assets - at end of period
$2,399,252 $2,378,152 $2,014,061 $1,956,856 $2,042,304
Long-term debt
Ratio of earnings to fixed charges
$ 601,700 $ 512,000 $ 512,000 $ 517,000 $ 521,500
3.32
3.92
3.76
3.40
3.86
(1) Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation in
2007 (see Part II, Item 7., “Business Segments – Utility Operations—Regulatory Adjustment for Income
Taxes Paid.”)
32
SELECTED FINANCIAL DATA (continued)
Thousands, except customer and gas cost per
therm data
Capitalization - at end of period
Common stock equity
Long-term debt
Total capitalization
Gas sales and transportation deliveries
(therms):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Total gas sales
Transportation
For the year ended December 31,
2009
2008
2007
2006
2005
$ 660,105 $ 628,373 $ 594,751 $ 599,545
517,000
512,000
601,700
512,000
$ 586,931
521,500
$1,261,805 $1,140,373 $1,106,751 $1,116,545
$1,108,431
412,867
255,593
39,447
72,525
780,432
350,933
428,787
265,531
47,340
87,484
829,142
431,609
398,960
249,659
52,340
89,128
790,087
424,882
382,665
242,683
66,971
112,736
805,055
387,594
371,538
233,987
74,880
149,106
829,511
328,056
Total volumes delivered
1,131,365
1,260,751
1,214,969
1,192,649
1,157,567
Customers (average for period):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Transportation
Total customers
Customer statistics:
Heat requirements:
Actual degree days
Percent colder (warmer) than average
Average annual use per customer in therms:
Residential
Commercial
Gas purchased cost per therm - net (cents)
601,989
62,142
610
169
158
594,481
61,756
625
180
136
580,346
60,749
634
189
128
564,700
59,889
650
197
99
665,068
657,178
642,046
625,535
545,163
58,914
666
201
78
605,022
4,383
3%
686
4,113
71.96
4,576
7%
721
4,300
86.56
4,374
3%
687
4,110
75.00
4,089
(4%)
678
4,052
75.37
4,178
(2%)
682
3,972
71.42
33
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) financial condition, including the principal factors that affect results of operations. The
discussion refers to our consolidated activities for the years ended December 31, 2009, 2008, and 2007.
Unless otherwise indicated, references in this discussion to “Notes” are to the Notes to Consolidated
Financial Statements in this report.
The consolidated financial statements principally consist of the accounts of NW Natural and its
wholly-owned subsidiaries, NNG Financial Corporation (Financial Corporation) and Gill Ranch
Storage, LLC (Gill Ranch), and an equity investment in a proposed natural gas pipeline. These
accounts include our regulated local gas distribution business, our regulated gas storage business, and
other regulated and non-regulated investments primarily in energy-related businesses. In this report, the
term “utility” is used to describe our regulated local gas distribution segment, and the term “non-
utility” is used to describe our gas storage segment (gas storage) as well as our other regulated and
non-regulated investments and business activities (other segment) (see “2010 Outlook—Strategic
Opportunities,” below, and Note 2).
In addition to presenting results of operations and earnings amounts in total, certain measures
are expressed in cents per share. These amounts reflect factors that directly impact earnings. We
believe this per share information is useful because it enables readers to better understand the impact of
these factors on earnings. All references in this section to earnings per share are on the basis of diluted
shares (see Note 1). We also show operating revenues and margins excluding the refund of gas cost
savings to customers in June and July 2009 because we believe it provides a more meaningful
comparison of operating revenues and margins between 2008 and 2009. We use such non-GAAP (i.e.
non-generally accepted accounting principles) measures in analyzing our financial performance and
believe that they provide useful information to our investors and creditors in evaluating our financial
condition and results of operations.
Executive Summary
Highlights of 2009:
• Consolidated net income and earnings per share increased 8 percent to all time record highs
of $75.1 million and $2.83 per share, respectively;
• Net operating revenues increased 6 percent to $376.9 million;
• Operations and maintenance expense increased 12 percent to $127.1 million;
• Cash flow from operations increased $205.6 million to $240.3 million;
• Permits were approved to proceed with the development at Gill Ranch, and construction
began in January 2010;
• A new five-year contract was executed with our union employees, effective in July 2009;
and
• The quarterly common stock dividend was increased 5 percent to 41.5 cents per share in the
fourth quarter of 2009, making this the 54th consecutive year of increasing dividends paid
to shareholders.
Our primary businesses consist of regulated utility and gas storage operations. Factors critical
to the success of the regulated utility include: maintaining a safe and reliable distribution system;
34
acquiring an adequate supply of natural gas; providing distribution services at competitive prices; and
being able to recover our operating and capital costs in the rates charged to customers in a reasonable
and timely manner. Our utility business is regulated by two state commissions, the Oregon Public
Utility Commission (OPUC) and the Washington Utilities and Transportation Commission (WUTC).
Factors critical to the success of our regulated gas storage business include: developing and operating
storage capacity at competitive market prices; retaining existing customers and successfully marketing
available storage capacity to new customers; planning for the replacement of capacity that is expected
to be recalled by the utility to serve growing demands of its customers; obtaining timely approval of
reasonable rate increases; and with respect to future development of gas storage projects, being able to
obtain financing to fund future development. Our existing gas storage business rates are approved by
the Federal Energy Regulatory Commission (FERC) for interstate customers or the OPUC for
intrastate customers. The Gill Ranch gas storage project currently under development is subject to
regulation by the California Public Utilities Commission (CPUC) (see “2010 Outlook—Strategic
Opportunities—Gas Storage Development,” below).
2010 Outlook
In 2010, we intend to remain focused on improving our core businesses, enhancing our strategic
position, advancing business development projects related to our primary businesses, and strengthening
our organizational effectiveness. The following is a brief summary of management’s plans and
objectives in these four areas. For a detailed discussion of these areas, see “Issues, Challenges and
Performance Measures,” and “Strategic Opportunities,” below.
Business improvements. We continue to integrate, consolidate and streamline operations using
recently implemented new technology improvements, which include an enterprise resource planning
system, an automated dispatching system and an automated meter reading system. These and other
new technologies support our operating model.
Strategic position. We remain committed to creating shareholder value while balancing the
interests of our customers, employees and the communities we serve. To create value, we will respond
to business challenges and opportunities that lie ahead, including finding innovative solutions to
economic and environmental challenges as well as regulatory, business development and workforce
challenges and opportunities.
Business development. In addition to exploring new growth opportunities, we intend to
continue advancing key natural gas infrastructure investments during 2010, including our gas storage
project in California and our gas transmission pipeline project in Oregon.
Organizational effectiveness. Our employees are our most valued resource. We intend to
support our employees with a positive work environment, on-going training opportunities, continued
refinement of our organizational structure and new technologies to achieve our goals and facilitate
improvements to our operating model.
Issues, Challenges and Performance Measures
Economic weakness. Continued weakness in local and U.S. economies have resulted in
reduced consumer demand and business spending. These conditions may continue to have a negative
impact on our financial results, reflecting slower customer growth, reduced industrial margins,
increased bad debt expense, and higher pension costs. Most recently, our annual customer growth rate
35
slowed to 0.8 percent in 2009 compared to 1.6 percent in 2008. We expect our customer growth rate in
2010 to stabilize near 2009 levels, unless economic conditions deteriorate further. Despite challenging
market conditions, we believe we are well positioned to continue adding customers due to our
relatively low market penetration, our efforts to convert homes to natural gas, and the potential for
environmental initiatives that could favor natural gas use in our region.
Managing gas prices and supplies. Our gas acquisition strategy is designed to secure sufficient
supplies of natural gas to meet the needs of our utility customers and to hedge gas prices to effectively
manage costs, reduce price volatility and maintain a competitive advantage. We entered the 2009-10
gas year, that began November 1, 2009, hedged at a targeted level of approximately 75 percent of our
estimated gas purchase volumes for the gas contract year, and we believe we have sufficient contracted
supplies to meet the needs of our core utility customers. In addition, we are currently hedged on gas
prices for between 10 and 15 percent of our forecasted purchase volumes for the two gas contract years
after October 31, 2010. We have Board authorization to hedge up to 100 percent of our gas supply
requirements for the next gas contract year. Our Purchased Gas Adjustment (PGA) mechanism, along
with gas price hedging strategies and gas supplies in storage, enables us to reduce earnings risk
exposure to higher gas costs. In addition to hedging gas prices over the next three years, we are also
evaluating and developing other gas acquisition strategies to potentially manage gas price volatility for
customers beyond three years.
Environmental investigation and remediation costs. We accrue all material environmental loss
contingencies related to our properties that require environmental investigation or remediation. Due to
numerous uncertainties surrounding the preliminary nature of investigations or the developing nature
of remediation requirements, actual costs could vary significantly from our loss estimates. As a
regulated utility, we are required to defer certain costs pursuant to regulatory decisions by the OPUC or
WUTC, including environmental costs, and to seek recovery of these amounts in future rates to
customers. However, before we can seek recovery from customers, we must pursue recovery from
insurance policies. Ultimate recovery of environmental costs, either from regulated utility rates or from
insurance, will depend on our ability to effectively manage costs and demonstrate that costs were
prudently incurred. Recovery may vary significantly from amounts currently recorded as regulatory
assets, and amounts not recovered would be required to be charged to income in the period they were
deemed to be unrecoverable. See Note 11.
Climate change. We recognize that our businesses are likely to be impacted by future carbon
constraints. The outcome of federal, state, local and international climate change initiatives cannot be
determined at this time, but these initiatives could produce a number of results including potential new
regulations, additional charges to fund energy efficiency activities, or other regulatory actions. While
our CO2 equivalent emission levels are relatively small, the adoption and implementation of any
regulations imposing reporting obligations, or limiting emissions of greenhouse gases associated with
our operations, 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 fossil fuel with a relatively low
carbon content, it is also possible that future carbon constraints could create additional demand for
natural gas for electric production, direct use in homes and businesses and as a reliable and relatively
low-emission back-up fuel source for alternative energy sources.
Strategies and performance measures. In order to deal with the challenges affecting our
business, we annually review and update our strategic plan to map our course over the next several
years. Our plan includes strategies for: improving our utility gas distribution business; growing our
36
non-utility gas storage business; investing in new natural gas infrastructure in the region; and
maintaining a leadership role within the natural gas industry by addressing long-term energy policies
and pursuing business opportunities that support new clean energy technologies. We intend to measure
our performance and monitor progress of certain metrics including, but not limited to: earnings per
share growth; total shareholder return; return on invested capital; utility return on equity; utility
customer satisfaction ratings; utility margin; capital, operations and maintenance expense per
customer; and non-utility earnings before interest, taxes, depreciation and amortization (non-utility
EBITDA).
Strategic Opportunities
Business process improvements. To address the current economic and competitive challenges,
we continue to evaluate and implement business strategies to improve efficiencies. Our goal is to
integrate, consolidate and streamline operations and support our employees with new technology tools.
In 2009, we completed the implementation of our new enterprise resource planning (ERP)
system, which is designed to reduce the number of technology platforms and improve overall operating
efficiencies by:
•
•
•
integrating systems and data;
automating control procedures and workflows; and
improving management decision-making and financial reporting processes.
In 2009, we also completed our project to automate the reading of gas meters (AMR). Meters
equipped with this new technology electronically transmit usage data to receiving devices located in
our vehicles as they drive in the area, substantially reducing the labor costs associated with reading
meters. The total capital cost of this project was approximately $25 million (see “Results of
Operations—Regulatory Matters—Rate Mechanisms—AMR Deferral,” below).
In 2008 and 2009, we deployed an automated dispatching system, which provides integrated
planning and scheduling with global positioning system capabilities to more effectively collect and
distribute data. We will continue to deploy this new technology in the field during 2010.
In 2009, we announced a voluntary severance program to reduce staffing levels in response to
work load declines related to slower customer growth and efficiency improvements. Severance
programs and normal attrition resulted in reductions of full-time positions from 1,133 at December 31,
2008 to approximately 1,020 in early 2010. We incurred severance charges in the fourth quarter of
approximately $1.5 million, which were partially offset by savings from vacated positions prior to the
end of the year. We also expect some additional position reductions in 2010, but those reductions will
most likely come from normal attrition.
Technology investments, workforce reductions and the other initiatives discussed above are
expected to facilitate process improvements, contribute to long-term operational efficiencies and
reduce operating expenses throughout NW Natural.
Gas storage development. In 2007, we entered into a joint project agreement with Pacific
Gas & Electric Company (PG&E) to develop an underground natural gas storage facility near Fresno,
California. At that time, we formed a wholly-owned subsidiary, Gill Ranch, to plan and develop the
project and to operate the facility. In July 2008, Gill Ranch filed an application with the CPUC for a
37
Certificate of Public Convenience and Necessity (CPCN). In October 2009, we received an order from
the CPUC approving our CPCN. Gill Ranch’s provision of market-based rates for storage services in
California will be subject to CPUC regulation including, but not limited to, service terms and
conditions, tariff compliance, securities issuances, lien grants and sales of property. Our share of the
total project development cost is estimated to be between $160 million and $180 million, representing
75 percent of the total cost of the initial development, which includes an estimated total 20 Bcf of gas
storage capacity and approximately 27 miles of gas transmission pipeline. In January 2010, we began
construction on the Gill Ranch facility. The initial development of the gas storage facility at Gill Ranch
is currently targeted to be in-service by the end of the third quarter of 2010.
We are currently in the process of hiring key staff for our non-utility gas storage businesses.
While our primary focus for growing the gas storage business is on the current development at Gill
Ranch, we also plan to continue expanding our interstate storage facilities at Mist, Oregon. In 2009, we
completed three-dimensional seismic surveys and initiated engineering work for a new 3 to 4 Bcf
expansion at Mist. Pending successful marketing efforts, we expect to move forward with the project
and would target a 2011 in-service date. Currently, our total cost estimates are between $45 million and
$55 million for this expansion project. This estimated cost range includes the development of a second
compression station and a pipeline gathering system that will also enable future storage expansions at
Mist.
Pipeline diversification. Currently, we depend on a single bi-directional interstate pipeline to
ship gas supplies to our utility distribution system. Palomar Gas Transmission, LLC, a wholly-owned
subsidiary of Palomar Gas Holdings, LLC, (PGH), is seeking to build a new gas transmission pipeline
that would provide a new interconnection with our utility distribution system. PGH is owned 50
percent by NW Natural and 50 percent by Gas Transmission Corporation (GTN), an indirect wholly-
owned subsidiary of TransCanada Corporation. The proposed Palomar pipeline is a 217-mile natural
gas transmission pipeline in Oregon designed to serve our utility and the growing markets in Oregon
and other parts of the western United States. The Palomar pipeline would be regulated by the FERC. In
December 2008, Palomar filed for a CPCN with the FERC.
The Palomar project includes an east and west segment. The east segment would extend
approximately 111 miles west from an interconnection with GTN’s existing interstate transmission
mainline near Maupin, Oregon to an interconnection with NW Natural’s gas distribution system near
Molalla, Oregon. The west segment would then extend approximately 106 miles further west to other
potential additional interconnections including a possible connection to one of the two liquefied natural
gas (LNG) terminals proposed to be built on the Columbia River. The east segment would not only
diversify NW Natural’s gas delivery options and enhance the reliability of service to our utility
customers by providing an alternate transportation path for gas purchases from different regions in
western Canada and the U.S. Rocky Mountains, but also provide potential access to other shippers in
the region. The west segment of Palomar would provide the region, as well as our utility customers
with potential access to a new source of gas supply if an LNG terminal is built on the Columbia
River. Palomar will continue to focus on permitting activities during 2010, and we believe the FERC
will issue a draft Environmental Impact Statement during the first quarter of 2010. The date for when
Palomar is expected to go into service will be impacted by the timing of our final FERC permit and the
needs of shippers. In addition, the development of LNG terminals along the Columbia River may or
may not proceed, which may affect the development of the west segment of Palomar. See “Financial
Condition—Cash Flows—Investing Activities,” below for further discussion on the status of Palomar.
38
Consolidated Earnings and Dividends
Net income was $75.1 million, or $2.83 per share, for the year ended December 31, 2009,
compared to $69.5 million, or $2.61 per share, and $74.5 million, or $2.76 per share, for the years
ended December 31, 2008 and 2007, respectively. Consolidated returns on average common equity for
these three years were 11.7 percent, 11.4 percent and 12.5 percent, respectively.
2009 compared to 2008:
Factors contributing to increased earnings were:
•
•
•
a $20.6 million increase in utility net operating revenue (margin) from our regulatory share
of gas cost savings, reflecting a contribution to margin of $15.1 million in 2009 compared
to a reduction to margin of $5.5 million in 2008;
a $4.1 million increase in utility margin from the regulatory adjustment for income taxes
paid; and
a $1.3 million increase in margin from gas storage operations.
Partially offsetting the above factors were:
•
•
•
a $13.7 million increase in operations and maintenance expense primarily due to higher
expenses for pensions, bonuses, health care benefits and employee severance;
a $6.0 million increase in income tax expense related to higher taxable income and a higher
state income tax rate; and
a $2.1 million decrease in utility margin from industrial customers, reflecting weak
economic conditions and a decrease in depreciation rates.
2008 compared to 2007:
Factors contributing to decreased earnings were:
•
•
•
•
•
a $5.5 million loss in utility margin from our regulatory share of gas cost increases in 2008
compared to a margin gain of $12.1 million in 2007 from gas cost decreases;
a $4.2 million decrease in utility margin from a lower customer surcharge related to
regulatory adjustments for income taxes paid;
a $3.8 million increase in depreciation expense primarily due to increased utility plant in
service;
a $2.9 million decrease in margin due to a temporary mark-to-market gain in 2007; and
a $1.6 million decrease in utility margin from industrial customers due to weaker economic
conditions.
Partially offsetting the above factors were:
•
•
a $7.1 million increase in utility margin from higher sales volumes to residential and
commercial customers due to colder weather and customer growth, after decoupling and
weather mechanism adjustments;
a $7.1 million decrease in operation and maintenance expense, partially due to higher costs
in 2007 for strategic initiatives, and partially due to lower bonuses and employee benefit
costs in 2008;
39
•
•
•
a $3.4 million decrease in income tax expense due to lower taxable income;
a $1.1 million after-tax gain from the sale of our investment in an aircraft leased to a
commercial airline; and
a $0.8 million increase in utility margin due to curtailment charges for use by a small
number of industrial customers during cold weather.
Dividends paid on our common stock were $1.60 per share in 2009, compared to $1.52 per
share in 2008. In October 2009, the Board of Directors declared a quarterly dividend on our common
stock of 41.5 cents per share, payable on November 13, 2009, increasing the indicated annual dividend
rate to $1.66 per share.
Application of Critical Accounting Policies and Estimates
In preparing our financial statements using generally accepted accounting principles in the
United States of America (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 cost recovery and amortizations;
revenue recognition;
derivative instruments and hedging activities;
pensions and postretirement benefits;
income taxes; and
environmental contingencies.
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 1.
Regulatory Accounting
We are regulated by the OPUC and WUTC, which establish our utility rates and rules
governing utility services provided to customers, and, to a certain extent, set forth the 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) require 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,” below). There are other expenses or
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
40
revenues) as regulatory assets (or regulatory liabilities) on the balance sheet. When we are allowed to
recover these expenses from, or required to refund them 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, which are applicable to regulated companies, 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 we meet all three conditions, we continue to apply regulatory accounting principles for
our regulated 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, regulatory and competitive conditions, we believe that it is reasonable to expect continued
application of regulatory accounting for our regulated activities, and that all of our regulatory assets
and liabilities at December 31, 2009 and 2008 are recoverable or refundable through future customer
rates. See Note 1, “Industry Regulation.”
Revenue Recognition
Utility revenues, derived primarily from the sale and transportation of natural gas, are
recognized when gas is delivered to and received by the customer. Revenues are accrued for gas
delivered to customers, but not yet billed, based on estimates of gas deliveries from the last meter
reading date to month end (accrued unbilled revenues). Accrued unbilled revenues are primarily based
on a percentage estimate of our unbilled gas deliveries each month, which is dependent upon a number
of factors, some of which require management’s judgment. These factors include total gas receipts and
deliveries, customer meter reading dates, customer usage patterns and weather. Accrued unbilled
revenue estimates are reversed the following month when actual billings occur. Estimated unbilled
revenues at December 31, 2009 and 2008 were $71.2 million and $102.7 million, respectively. The
decrease in accrued unbilled revenues at year-end 2009 was primarily due to lower volumes in 2009
reflecting warmer weather in late December 2009 and lower customer rates. If the estimated
percentage of unbilled volume at December 31, 2009 was adjusted up or down by 1 percent, then our
unbilled revenues, net operating revenues and net income would have increased or decreased by an
estimated $2.3 million, $0.1 million and $0.6 million, respectively.
Utility revenues may also include the recognition of a regulatory adjustment for income taxes
paid. This revenue reflects an OPUC rule whereby we are required to automatically implement a rate
refund or a rate surcharge to utility customers. This refund or surcharge is accrued based on the
estimated difference between income taxes paid and income taxes authorized to be collected in rates
(for further discussion, see “Results of Operations—Business Segments – Utility Operations—
Regulatory Adjustment for Income Taxes Paid,” below).
41
Non-utility revenues, derived primarily from our gas storage business segment, are recognized
upon delivery of service to customers. Revenues from our asset optimization partner are recognized
over the life of the optimization contract for the guaranteed amount, and recognized as earned for
amounts above the guaranteed amount.
Accounting for Derivative Instruments and Hedging Activities
Our gas acquisition 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. The accounting rules for determining whether a contract meets the
definition of a derivative instrument or qualifies for hedge accounting treatment are complex. The
contracts that meet the definition of a derivative instrument are recorded on our balance sheet at fair
value. If certain regulatory conditions are met, then the fair value is recorded together with an
offsetting entry to a regulatory asset or liability account pursuant to regulatory accounting (see Note 1,
“Industry Regulation”), and no unrealized gain or loss is recognized in current income. 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 (see “Regulatory Accounting,” above). 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 (see
Note 1, “Derivatives” and “Industry Regulation”). Our derivative contracts outstanding at
December 31, 2009 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 derivatives activities being subject to regulatory deferral treatment. For estimated fair
values on unrealized gains and losses at December 31, 2009 and 2008, see Note 10.
Commodity-based derivative contracts entered into by the utility after our annual PGA filing
for the current gas contract period are subject to a regulatory incentive sharing mechanism in Oregon
(see “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,”
below). The portion not deferred to a regulatory account pursuant to that sharing agreement is
recognized either in current income for contracts not qualifying for hedge accounting or in other
comprehensive income for contracts qualifying for hedge accounting.
Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial
statement treatment of each specific derivative. As of December 31, 2009, all of our derivatives were
effective economic hedges and either qualified or were expected to qualify for regulatory deferral or
hedge accounting treatment. We use the hypothetical derivative method under accounting standards for
derivatives and hedging to determine the hedge effectiveness for our interest rate swaps and the dollar
offset method for other derivative contracts under accounting standards for derivatives and hedging.
The effectiveness test applied to financial derivatives is dependent on the type of derivative and its use.
42
The following table summarizes the amount of realized gains and losses from commodity price
and currency hedge transactions for the last three years:
Thousands
Net gain (loss) on commodity-price swaps— utility
Net gain (loss) on commodity-price options—utility
Net gain (loss) on interest rate swap—utility
Subtotal on commodity—utility
Net gain (loss) on foreign currency forward purchases—utility
Total realized net gain (loss)
2009
2008
2007
$(172,089) $34,256
1,527
-
(5,809)
(10,096)
$(41,954)
(662)
-
(187,994)
88
35,783
(728)
(42,616)
662
$(187,906) $35,055
$(41,954)
Realized gains (losses) from commodity hedges and foreign currency forward purchase
contracts are recorded as reductions (increases) to the cost of gas and are included in the calculation of
annual PGA rate changes. Realized gains (losses) from interest rate hedges are recorded as reductions
(increases) to interest charges over the term of the underlying debt issuances. Unrealized gains and
losses from commodity hedges, foreign currency hedges and interest rate hedges, which reflect
quarterly mark-to-market valuations, are generally not recognized in current income or other
comprehensive income, but are recorded as regulatory liabilities or regulatory assets, and are offset by
a corresponding balance in non-trading derivative assets or liabilities (see Note 10).
Accounting for Pensions and Postretirement Benefits
We maintain two qualified non-contributory defined benefit pension plans covering a majority
of our regular employees with more than one year of service, several non-qualified supplemental
pension plans for eligible executive officers and certain key employees and other postretirement
employee benefit plans. Only the two qualified defined benefit pension plans have plan assets, which
are held in a qualified trust to fund retirement benefits. Effective January 1, 2007 and 2010, the
qualified defined benefit retirement plans for non-union employees and for union employees,
respectively, were closed to new participants. Instead, non-union and union employees hired or
re-hired after December 31, 2006 and 2009, respectively, are provided an enhanced Retirement K
Savings Plan benefit. Also, effective January 1, 2007, the postretirement Welfare Benefit Plan for
Non-Bargaining Unit Employees was closed to new participants.
Net periodic pension and postretirement benefit costs (retirement benefit costs) and projected
benefit obligations (benefit obligations) are determined in accordance with accounting standards for
compensation and retirement benefits 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 7). These key assumptions have a significant impact on the pension amounts recorded
and disclosed. Retirement benefit costs consist of service costs, interest costs, the amortization of
actuarial gains, losses and prior service costs, the expected returns on plan assets and, in part, on a
market-related valuation of assets, if applicable. The market-related asset valuation reflects differences
between expected returns and actual investment returns, which we recognize over a three-year period
or less from the year in which they occur, thereby reducing year-to-year volatility in retirement benefit
costs.
Accounting standards also require balance sheet recognition of the overfunded or underfunded
status of pension and postretirement benefit plans in accumulated other comprehensive income
(AOCI), net of tax, based on the fair value of plan assets compared to the actuarial value of future
43
benefit obligations. However, the retirement benefit costs relating to our qualified defined benefit
pension and postretirement benefit plans are recovered in utility rates which are set based on
accounting standards for pensions and postretirement benefits, and as such we received approval from
the OPUC pursuant to regulatory accounting 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 under common equity (see “Regulatory Accounting”, above, and Note 1, “Industry
Regulation”).
A number of factors are considered in developing pension and postretirement assumptions,
including evaluations of relevant discount rates, an evaluation of expected long-term investment
returns based on asset classes and target asset allocations, expected changes in salaries and wages,
analyses of past retirement plan experience and current market conditions and input from actuaries and
other consultants. For the December 31, 2009 measurement date, we reviewed and updated:
•
•
•
•
our pension and postretirement weighted-average discount rate assumptions from 6.60
percent to 6.01 percent and from 7.12 percent to 5.78 percent, respectively. The new rate
assumptions were determined for each plan based on a matching of the estimated cash flow,
which reflects the timing and amount of future benefit payments, to the Citigroup Above
Median Curve, which consists of high quality bonds rated AA- or higher by Standard &
Poor’s (S&P) or Aa3 or higher by Moody’s Investors Service (Moody’s);
our expected annual rate of future compensation increases changed from a range of 3.5 to
5.0 percent to a range of 3.25 to 5.0 percent;
our expected long-term return on qualified defined benefit plan assets remained unchanged
at 8.25 percent; and
other key assumptions as needed based on actual experience and actuarial
recommendations.
At December 31, 2009, our net pension liability (benefit obligations less market value of plan
assets) for the two qualified defined benefit plans decreased by $10.5 million compared to 2008. Better
than expected investment performance plus a cash contribution of $25 million more than offset the
$19.0 million increase in benefit obligations due to lower discount rates and $4.2 million increase due
to updating other assumptions, thereby resulting in the net decrease to our unfunded pension liability.
The liability for non-qualified plans increased $3.1 million and the liability for other postretirement
benefits increased $1.8 million in 2009.
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 evaluate an analysis of
historical actual performance and long-term return projections, which gives consideration to the current
asset mix and our target asset allocation. As of December 31, 2009, the actual annualized returns on
plan assets, net of management fees, for the past one-year, five-years, 10-years and since December
1980 were 15.79 percent, 2.23 percent, 2.96 percent and 10.29 percent, respectively.
44
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 future changes in certain actuarial assumptions:
Change in
Assumption
Impact on 2009
Retirement Benefit Costs
Impact on Retirement
Benefit Obligations
at Dec. 31, 2009
(0.25%)
Thousands, except percent
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
$862
7
100
550
$8,604
3,212
558
N/A
The impact of a change in retirement benefit costs on operating results would be less than the
amounts shown above because only between 60 and 70 percent of our pension costs is charged to
operations and maintenance expense. The remaining 30 to 40 percent is capitalized to construction
accounts as payroll overhead and included in utility plant, which is amortized to expense over the
useful life of the asset placed into service.
Accounting for Income Taxes
We account for income taxes in accordance with accounting standards that require the
recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary
differences between financial statement carrying amount and tax basis of assets and liabilities.
Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable
income in the years in which those temporary differences are expected to be recovered or settled. At
December 31, 2009 and 2008, our net long-term deferred tax liability totaled $300.9 million and
$257.8 million, respectively. After application of the federal statutory tax rate to book income,
judgment is required with respect to the timing and deductibility of expense in our tax returns. For state
income tax and local income taxes, judgment is also required with respect to the apportionment among
the various jurisdictions. A valuation allowance is recorded if we expect that it is “more likely than
not” that our deferred tax assets will not be realized. At December 31, 2009, we did not have a
valuation allowance due to our expectation that all of these assets will be realized.
These accounting standards also require the recognition of deferred income tax assets and
liabilities for temporary differences where regulators require us to flow through deferred income tax
benefits or expenses in the ratemaking process of the regulated utility (regulatory tax assets and
liabilities). This is consistent with the ratemaking policies of the OPUC and WUTC. Regulatory tax
assets and liabilities are recorded to the extent we believe they will be recoverable from, or refunded
to, customers in future rates. At December 31, 2009 and 2008, we had regulatory assets representing
differences between book and tax basis related to pre-1981 property of $76.2 million and $69.9
million, respectively, and recorded an offsetting deferred tax liability (see Note 1, “Income Tax
Expense”). We received authorization from the OPUC and WUTC in 2008 to accelerate the recovery
of these pre-1981 regulatory assets through future utility rates (see “Regulatory Accounting,” above,
and Notes 1 and 8).
Uncertain tax positions are accounted for in accordance with accounting standards that require
management’s assessment of the expected treatment of a tax position taken in a filed tax return, or
45
planned to be taken in a future tax return, that has not been reflected in measuring income tax expense
for financial reporting purposes. Until such positions are sustained by the taxing authorities, we would
not recognize the tax benefits resulting from such positions and would report the tax effect as a liability
in the Company’s consolidated balance sheet. As of December 31, 2009, we had no uncertain tax
positions.
The Internal Revenue Service (IRS) is currently examining our 2006 through 2008 consolidated
federal income tax returns. The IRS completed its last examination of the 2002 through 2004 audit
cycle in the second quarter of 2006. Completion of the 2006 through 2008 federal income tax returns is
expected during 2010.
Interest and penalties, if any, related to any future income tax deficiencies will be recorded
within income tax expense in the consolidated statements of income.
Contingencies
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. Estimates of loss contingencies, including estimates of legal defense costs when
such costs are probable of being incurred and are reasonably estimable, and related disclosures are
updated when new information becomes available. 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. When information is
sufficient to estimate only a range of potential liabilities, and no point within the range is more likely
than any other, we recognize an accrued liability at the low end of the range and disclose the range (see
“Contingent Liabilities,” below). It is possible, however, that the range of potential liabilities could be
significantly different than amounts currently accrued and disclosed, with the result that our financial
condition and results of operations could be materially affected by changes in the assumptions or
estimates related to these contingencies.
With respect to environmental liabilities and related costs we develop estimates based on a
review of information available from recently completed studies and negotiations involving several
sites. Using sampling data, feasibility studies, existing technology and enacted laws and regulations,
we estimate that the total future expenditures for environmental investigation, monitoring and
remediation are $65.3 million as of December 31, 2009. 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,
then it is our policy to accrue at the lower end of the range. Accordingly, due to numerous uncertainties
surrounding the course of environmental remediation and the preliminary nature of several site
investigations, the range of potential loss beyond the amounts currently accrued, and the probabilities
thereof, cannot be reasonably estimated. Therefore, we have recorded the liabilities at an amount that
reflects the most likely estimate or the low end of the range.
We will continue to seek recovery of such costs through insurance and through customer rates,
and we believe recovery of these costs is probable. If it is determined that both the insurance recovery
and future rate recovery of such costs are not probable, the costs will be charged to expense in the
period such determination is made (see Note 11).
46
Results of Operations
Regulatory Matters
Regulation and Rates
We are subject to regulation with respect to, among other matters, rates and systems of
accounts by the OPUC, the WUTC, FERC, and with respect to Gill Ranch, the CPUC. The OPUC and
WUTC and, with respect to Gill Ranch, the CPUC, also regulate our issuance of securities. In 2009,
approximately 90 percent of our utility gas volumes were delivered to, and utility operating revenues
were derived from, Oregon customers and the balance from Washington customers. Future earnings
and cash flows from utility operations will be determined largely by the Oregon and Washington
economies in general, and by the pace of growth in the residential and commercial markets in
particular, and by our ability to remain price competitive, control expenses, and obtain reasonable and
timely regulatory recovery for our utility gas costs, operating and maintenance costs and investments
made in utility plant.
General Rate Cases
Oregon. In our most recent general rate increase in Oregon, which was effective in September
2003, the OPUC authorized rates to customers based on a return on common stock equity (ROE) of
10.2 percent. In 2007, in connection with the renewal of our conservation tariff and weather
normalization rate mechanism, the OPUC approved a stipulation that restricts us from filing a general
rate case with the OPUC prior to September 1, 2011, subject to certain exceptions. Under the
agreement, we would be allowed to file a general rate case if an extraordinary event occurs or
significant investments are required on behalf of our customers and we are unable to reach agreement
regarding alternative forms of cost recovery outside of a general rate case. These exceptions might
include additional investments in our pipeline integrity management program. This agreement does not
impact our ability to file annual rate adjustments to reflect changes in gas purchase costs under our
PGA mechanism or our ability to collect or refund prior year’s gas cost deferrals. See “Rate
Mechanisms—Purchased Gas Adjustment,” below.
Washington. In December 2008, an all-party stipulated agreement regarding our Washington
general rate case was approved by the WUTC. As part of the stipulation, the WUTC authorized rates to
our customers based on a ROE of 10.1 percent, which is included as part of an overall rate of return on
total invested capital of 8.4 percent. These new customer rates went into effect on January 1, 2009.
Under these rates, our annual revenue requirements increased by approximately $2.7 million, or 3
percent. We are reviewing recent decisions regarding decoupling mechanisms in Washington and
considering whether to request approval for a decoupling mechanism.
Federal. We are required under our Mist interstate storage certificate authority and rate
approval orders to file every three 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. We filed a cost
and revenue study and an associated petition for rate approval in April 2008. As a result of that
proceeding, the current maximum cost-based rates for our interstate gas storage services were
approved by FERC in August 2008, with our maximum rates unchanged from the levels approved by
FERC in 2005. The maximum cost-based rates are designed to reflect updated costs related to the
further development of the Mist gas storage facility from 2005 to 2008. Additionally, we made a filing
in December 2008 to obtain FERC approval to revise the depreciation rates associated with Mist assets
47
used to derive the cost-based interstate storage rates to match the depreciation rates for the same assets
that were recently adjusted under state regulation. We did not file to make any changes to the
previously approved maximum rates. FERC approved the depreciation rate filing in May 2009. We are
required to make our next cost and revenue study filing at FERC on or before December 11, 2011.
California. To date, we have not filed any rate cases or storage service tariffs with the
CPUC. Later in 2010, we expect to file a storage service tariff with the CPUC with respect to Gill
Ranch.
Rate Mechanisms
Purchased Gas Adjustment. Rate changes are established each year under PGA mechanisms in
Oregon and Washington to reflect changes in the expected cost of natural gas commodity purchases,
including gas storage, gas purchases hedged with financial derivatives, interstate pipeline demand
charges, the application of temporary rate adjustments to amortize balances in deferred regulatory
accounts and the removal of temporary rate adjustments effective for the previous year.
In October 2009, the OPUC and WUTC approved rate changes effective on November 1, 2009
under our PGA mechanisms. The effect of the rate changes was to decrease the average monthly bills
of Oregon residential customers by 18 percent, partially offset by an increase in the public purpose
charge, which resulted in a net decrease of 16 percent. The average monthly bills of Washington
residential customers decreased by 22 percent.
Under the current Oregon PGA incentive sharing mechanism, we are required to select by
August 1 of each year either an 80 percent deferral or 90 percent deferral of higher or lower actual gas
costs compared to PGA prices such that the impact on current earnings from the gas cost incentive
sharing is either 20 percent or 10 percent, respectively. In addition to the gas cost incentive sharing
mechanism, we are also subject to an annual earnings review to determine if the utility is earning over
an allowed threshold. If utility earnings exceed a specific earnings threshold level, then 33 percent of
the amount above the threshold will be deferred for refund to customers. Under this provision, if we
select the 80 percent deferral option, then we retain all of our earnings up to 150 basis points above the
currently authorized ROE. If we select the 90 percent deferral option, then we retain all of our earnings
up to 100 basis points above the currently authorized ROE. We selected the 80 percent deferral option
for the 2008-2009 PGA year. In August 2009, we selected 90 percent deferral for the 2009-2010 PGA
year. The earnings threshold is subject to adjustment up or down depending on movements in long-
term interest rates. In 2009 and 2008, the earnings threshold after adjustment for long-term interest
rates was 11.5 percent and 13.1 percent, respectively. No amounts were required to be refunded to
customers as a result of the 2008 utility earnings review, and we do not expect that any amounts will
be required to be refunded to customers as a result of the 2009 earnings review, which will be
approved by the OPUC during the second quarter of 2010.
There has been no change to the Washington PGA mechanism under which we defer 100
percent of the higher or lower actual purchased gas costs and pass that difference through to customers
as an adjustment to future rates. We do not have an earnings sharing mechanism in Washington.
Conservation Tariff. In October 2002, the OPUC authorized the implementation of a
“conservation tariff,” which is a rate mechanism designed to adjust margin for changes in consumption
patterns due to residential and commercial customers’ conservation efforts. The tariff is a decoupling
mechanism that is intended to break the link between utility earnings and the quantity of gas consumed
48
by customers, removing any financial incentive by the utility to discourage customers’ conservation
efforts. In Washington, customer use is not covered by a conservation tariff, and as such our utility
earnings are affected by increases and decreases in usage based on customers’ conservation
efforts. Washington customers account for about 10 percent of our utility revenues.
The Oregon conservation tariff includes two components: (1) a price elasticity adjustment,
which adjusts rates annually for increases or decreases from expected customer volumes due to annual
changes in commodity costs or periodic changes in our general rates; and (2) a conservation adjustment
calculated on a monthly basis to account for the difference between actual and expected customer
volumes (also referred to as the decoupling adjustment). 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 next year’s annual PGA filing. Baseline consumption was
determined by customer consumption data used in the 2003 Oregon general rate case and is adjusted
annually for customer growth and the effect of the price elasticity adjustment discussed above. See
“Results of Operations—Business Segments—Utility Operations,” below.
In 2005, an independent study to measure the effectiveness of Oregon’s conservation tariff
mechanism recommended continuation of the tariff with minor modifications, which the OPUC
approved. In September 2007, the OPUC extended our conservation tariff through October 2012.
Weather Normalization. In Oregon, the OPUC approved our use of a weather normalization
mechanism through October 2012. 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 our residential and commercial
customers’ bills between December 1 and May 15 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 (see “Business Segments—Utility Operations,”
below). We do not have a weather normalization mechanism approved for our Washington customers,
which account for about 10 percent of our utility revenues.
Regulatory and Insurance Recovery for Environmental Costs. The OPUC has authorized us
to defer environmental costs associated with certain named sites and to accrue interest on deferred
environmental cost balances, subject to an annual demonstration that we have maximized our
insurance recovery or made substantial progress in securing insurance recovery for unrecovered
environmental expenses. These authorizations have been extended through January 2010. We have
requested another extension through January 2011, and that request is currently pending. See Note 11.
Industrial Tariffs. The OPUC and WUTC have approved tariffs covering service to our major
industrial customers, including terms which are intended to give us certainty in the level of gas
supplies we will need to acquire to serve this customer group. The terms include an annual election
period, special pricing provisions for out-of-cycle changes and a requirement that industrial customers
under our annual PGA cost of gas tariff complete the term of their service election.
System Integrity Program. In 2004, the OPUC approved specific accounting treatment and cost
recovery for our transmission pipeline integrity management program, a program mandated by the
Pipeline Safety Improvement Act of 2002 and the related rules adopted by the U.S. Department of
49
Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). We record these
costs as either capital expenditures or regulatory assets, accumulate the costs over each 12-month
period ending September 30, and recover the revenue requirement associated with the costs, subject to
audit, through rate changes effective with the annual PGA in Oregon. The PHMSA also had proposed a
distribution integrity management program. In February 2009, the OPUC approved a stipulated
agreement to create a new, consolidated system integrity program (SIP). The SIP integrates the existing
transmission pipeline and proposed distribution pipeline integrity management programs into a single
program. In December 2009, the PHMSA issued the final rule for distribution integrity management
programs. Our SIP costs are tracked into rates annually, with rate recovery after the first $3.3 million
of capital costs. An annual cap for expenditures has been set at $12 million, but extraordinary costs
above the cap may be approved with written consent of the OPUC and other interested parties.
The SIP allows recovery of costs incurred, as discussed above, in Oregon during the period
from October 2008 through October 2011, or until the effective date of new rates adopted in our next
general rate case. We do not have any special accounting or rate treatment for SIP costs incurred in the
state of Washington.
AMR Deferral. In 2009, we completed a project to automate the reading of our Oregon
customers’ gas meters. The capital cost of this AMR project was approximately $25 million. In
February 2010, the OPUC approved a stipulation that allows us to defer the revenue requirement
associated with the AMR project and amortize that deferral subject to an annual earnings test. We are
permitted to recover the deferral amount as long as our ROE during the earnings review period does
not exceed our authorized ROE. Earnings or losses from our PGA gas cost incentive sharing
mechanism are not included for purposes of this earnings test. Recovery of any deferred amounts will
begin in November 2010 as part of our annual PGA rate adjustment.
Depreciation Study. The OPUC and WUTC approved our filed depreciation study and our
request to change the amortization of our regulatory tax asset account balance on pre-1981 plant. These
approvals specifically authorized the implementation of new depreciation rates in Oregon and
Washington, with a corresponding decrease to customer billing rates effective January 1, 2009 (see
“Consolidated Operations—Depreciation and Amortization,” below). The new regulatory tax
amortization schedule on pre-1981 assets, with a corresponding increase to customer rates, became
effective January 1, 2009 in Washington and November 1, 2009 in Oregon. The implementation of the
new rates decreases depreciation expense and increases income tax expense, both of which are offset
on an annualized basis by a corresponding change in utility operating revenues. FERC also approved
the application of these new depreciation rates for our interstate gas storage assets in May 2009, and
the new rates were made effective as of January 1, 2009.
Customer Refunds for Gas Cost Incentive Sharing. For the period between November 1, 2008
and March 31, 2009, our actual gas costs were significantly lower than the gas costs embedded in
customer rates. As a result, 80 percent of the gas cost savings attributed to Oregon and 100 percent of
the savings attributed to Washington were recorded to a regulatory account for refund to customers
(see “Purchased Gas Adjustment,” above). Ordinarily, these refunds would be included in customer
rates in the next year’s PGA filing, but in 2009 we received special regulatory approval to refund the
accumulated gas cost savings early to our Oregon and Washington customers. In June and July 2009,
we refunded a total of $31.5 million to our Oregon customers and $4.3 million to our Washington
customers through billing credits.
50
Pension Deferral. We are currently subject to a regulatory deferral order from the OPUC
whereby we must refund cost savings to customers when our annual pension expense is below the
amount set for rate recovery in our last general rate case. However, we are currently not authorized to
defer and recover any cost increases from customers when our annual pension expense is above the
amount set in rates. For 2010, our annual pension expense is expected to be significantly above the
amount set in rates, and we may seek some form of regulatory relief for pension expenses between
now and our next general rate case.
Business Segments - Utility Operations
Our utility margin results are affected by customer growth and to a certain extent by changes in
weather and customer consumption patterns, with a significant portion of our earnings being derived
from natural gas sales to residential and commercial customers. In Oregon, we have a conservation
tariff that adjusts revenues to offset changes in margin resulting from increases or decreases in
residential and commercial customer consumption. We also have a weather normalization mechanism
that adjusts customer bills up or down to offset changes in margin resulting from above- or below-
average temperatures during the winter heating season (see “Results of Operations—Regulatory
Matters—Rate Mechanisms,” above). Both mechanisms are designed to reduce the volatility of our
utility earnings.
2009 compared to 2008:
Our utility segment in 2009 earned $66.0 million, or $2.48 per share, compared to $58.7
million, or $2.21 per share in 2008. The major factor contributing to the increase in utility margin was
a $20.6 million increase in our gas cost incentive sharing from lower gas prices. Total utility volumes
sold and delivered in 2009 decreased by 10 percent over last year due to the effects of warmer weather
on residential and commercial use and the effects of a weak economy on commercial and industrial
use. Margin was reduced by $11.4 million in 2009 compared to 2008 due to a customer rate decrease
which corresponded to a decrease in depreciation rates and expense effective January 1, 2009.
Excluding the impact of lower depreciation rates on revenues, our margin from residential and
commercial customers increased by $5.2 million in 2009, including the effects of the weather
normalization and decoupling mechanisms. Industrial margin declined $2.1 million, but would have
decreased by $1.3 million if the depreciation rate impact was excluded. The regulatory adjustment for
income taxes paid also increased margin by $4.1 million compared to 2008, primarily due to the cost of
gas savings in 2009.
Our weather normalization mechanism reduced residential and commercial margin by $15.2
million for the year ended December 31, 2009 based on weather that was 3 percent colder than
average, compared to a reduction of $15.3 million for the year ended December 31, 2008 when
weather was 7 percent colder than average. Our decoupling mechanism increased residential and
commercial margin by $11.6 million in 2009, after adjusting for expected price elasticity impacts from
higher PGA prices effective November 1, 2008, compared to a margin increase of $4.9 million in 2008.
2008 compared to 2007:
Our utility segment in 2008 earned $58.7 million, or $2.21 per share, compared to $64.9
million, or $2.41 per share in 2007. This decrease is primarily due to a decrease in utility margin of
$14.3 million or 4 percent even though margins from residential and commercial customers contributed
an additional $7.1 million in 2008, including the effects of the weather normalization and decoupling
51
mechanisms while margin from industrial customers declined by $1.6 million. Total utility volumes
sold and delivered in 2008 increased by 4 percent over 2007 due to colder weather and 1.6 percent
customer growth. The major factors contributing to the decline in utility margin were the $17.6 million
decrease in our regulatory incentive sharing from higher gas costs, a $4.2 million decrease in the
regulatory adjustments for income taxes paid and a $1.6 million decrease in margin from industrial
customers due to weak economic conditions.
Our weather normalization mechanism offset residential and commercial margin gains by $15.3
million for the year ended December 31, 2008 based on weather that was 7 percent colder than
average, compared to an offset of $2.5 million for the year ended December 31, 2007, based on
weather that was 3 percent colder than average in 2007. Our decoupling mechanism recovered $4.9
million of residential and commercial margin losses in 2008, after adjusting for expected price
elasticity impacts from higher PGA prices effective November 1, 2007, compared to a margin recovery
of $0.5 million in 2008.
52
The following table summarizes the composition of gas utility volumes and revenues for the
years ended December 31, 2009, 2008 and 2007:
Thousands except degree day and
customer data
Utility volumes - therms:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
2009
2008
2007
Favorable/(Unfavorable)
2009
vs. 2008
2008
vs. 2007
412,867
255,593
39,447
124,218
72,525
226,715
428,787
265,531
47,340
184,832
87,484
246,777
398,960
249,659
52,340
161,790
89,128
263,092
(15,920)
(9,938)
(7,893)
(60,614)
(14,959)
(20,062)
29,827
15,872
(5,000)
23,042
(1,644)
(16,315)
Total utility volumes sold and delivered
1,131,365
1,260,751
1,214,969
(129,386)
45,782
$ 555,844
292,697
41,407
5,671
62,116
7,964
5,884
21,166
992,749
611,088
24,656
$ 566,840
298,943
46,579
6,370
68,978
7,918
1,760
21,784
1,019,172
656,504
25,072
$ 555,312
298,800
54,567
5,927
74,876
8,264
5,996
12,228
1,015,970
639,094
25,001
$ (10,996)
(6,246)
(5,172)
(699)
(6,862)
46
4,124
(618)
(26,423)
45,416
416
$ 11,528
143
(7,988)
443
(5,898)
(346)
(4,236)
9,556
3,202
(17,410)
(71)
$ 357,005
$ 337,596
$ 351,875
$ 19,409
$(14,279)
Utility operating revenues - dollars:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
Regulatory adjustment for income taxes paid (1)
Other revenues
Total utility operating revenues
Cost of gas sold
Revenue taxes
Utility net operating revenues (utility
margin)
Utility margin: (2)
Residential sales
Commercial sales
Industrial - sales and transportation
Miscellaneous revenues
Regulatory share of gas cost
Other margin adjustments
$ 217,124
85,850
27,713
6,670
15,064
2,308
$ 224,683
90,402
29,771
6,381
(5,505)
436
$ 213,698
85,960
31,333
4,966
12,135
(229)
$
(7,559)
(4,552)
(2,058)
289
20,569
1,872
8,561
30
6,694
4,124
$ 10,985
4,442
(1,562)
1,415
(17,640)
665
(1,695)
(12,770)
4,422
(4,236)
Margin before regulatory adjustments
Weather normalization mechanism
Decoupling mechanism
Regulatory adjustment for income taxes paid (1)
354,729
(15,236)
11,628
5,884
346,168
(15,266)
4,934
1,760
347,863
(2,496)
512
5,996
Utility margin
$ 357,005
$ 337,596
$ 351,875
$ 19,409
$(14,279)
Customers - end of period:
Residential customers
Commercial customers
Industrial customers
Total number of customers - end of period
Actual degree days
Percent colder (warmer) than average (3)
604,692
62,169
933
667,794
4,383
3%
599,285
62,115
941
662,341
4,576
7%
589,676
61,397
939
652,012
4,374
3%
5,407
54
(8)
5,453
9,609
718
2
10,329
See “Regulatory Adjustment for Income Taxes Paid,” below for further discussion.
(1)
(2) Amounts reported as margin for each category of customers are net of demand charges and revenue taxes.
(3) Average weather represents the 25-year average degree days, as determined in our last Oregon general rate case.
53
In June and July 2009, we refunded gas cost savings totaling $35.8 million to our Oregon and
Washington customers. The following non-GAAP table summarizes the impact of this refund on our
operating revenues, cost of gas sold and margin for the year ended December 31, 2009, along with a
comparison to the years ended December 31, 2008 and 2007. We believe this non-GAAP financial
calculation enables the reader of the financial statements to better understand our operating revenues,
cost of gas and utility margin performance from management’s perspective in addition to the
traditional GAAP presentation.
Thousands
Utility operating revenues:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - firm transportation
Industrial - interruptible sales
Industrial - interruptible transportation
Regulatory adjustment for income taxes paid
Other revenue
Total utility operating revenues
Cost of gas sold
Revenue taxes
Utility margin
2009
As Reported Refund
Excluding
Refund
(Non-
GAAP)
2008
2007
$555,844
292,697
41,407
5,671
62,116
7,964
5,884
21,166
992,749
611,088
24,656
$19,952 $575,796 $566,840 $555,312
298,800
11,579
54,567
1,585
5,927
-
74,876
2,673
8,264
-
5,996
-
12,228
-
298,943
46,579
6,370
68,978
7,918
1,760
21,784
304,276
42,992
5,671
64,789
7,964
5,884
21,166
35,789 1,028,538 1,019,172 1,015,970
639,094
34,691
25,001
898
645,779
25,554
656,504
25,072
$357,005
$200 $357,205 $337,596 $351,875
The non-GAAP information disclosed above reconciles to the preceding table summarizing
utility margin for the year ended December 31, 2009.
Residential and Commercial Sales
Residential and commercial sales are impacted by customer growth, seasonal weather patterns,
energy prices, competition from other energy sources and economic conditions in our service areas.
Typically, 80 percent or more of our annual utility operating revenues are derived from gas sales to
weather-sensitive residential and commercial customers. Although variations in temperatures between
periods will affect volumes of gas sold to these customers, the effect on margin and net income is
significantly reduced due to our weather normalization mechanism in Oregon where about 90 percent
of our customers are served. This mechanism is effective for the period from December 1 through
May 15 of each heating season. Approximately 9 percent of our eligible Oregon customers have opted
out of the mechanism. In Oregon, we also have a conservation decoupling mechanism that is intended
to break the link between our earnings and the quantity of gas consumed by customers, so that we do
not have an incentive to encourage greater consumption and undermine Oregon’s conservation policy
and efforts. In Washington, where the remaining 10 percent of our customers are served, we do not
have a weather normalization or a conservation decoupling mechanism. As a result, we are not fully
insulated from earnings volatility due to weather and conservation in Washington.
The primary factors that impact results of operations in the residential and commercial markets
are customer growth, seasonal weather patterns, competition from other energy sources, economic
conditions and to a certain extent the volatility of gas prices.
54
2009 compared to 2008:
•
•
•
operating revenues in 2009 decreased $17.2 million or 2 percent primarily due to $31.5
million in customer refunds for gas cost savings, partially offset by customer rate increases
of 14 and 21 percent in Oregon and Washington, respectively, effective November 1, 2008,
and customer growth of 0.8 percent;
volumes were 4 percent lower, primarily reflecting 4 percent warmer weather, customer
conservation and weak economic conditions; and
sales margin was 4 percent lower due to lower volumes and customer rate decreases related
to lower depreciation expense, but that was partially offset by the decoupling adjustment
that recovers margin from lower use per customer.
2008 compared to 2007:
•
•
operating revenues in 2008 increased 1 percent on a 7 percent increase in volumes due to 5
percent colder weather and 1.6 percent customer growth, partially offset by customer rate
decreases of 8 to 10 percent over the first 10 months of 2008; and
sales margin was 5 percent higher, reflecting increased volumes from customer growth and
from colder weather, but that was largely offset by the weather normalization adjustment
that credits customer bills when weather is colder than normal.
Industrial Sales and Transportation
Industrial operating revenues include the commodity cost component of gas sold under sales
service but not under transportation service. Therefore, industrial customer switching between sales
service and transportation service can cause swings in operating revenues but generally our margins
are unaffected because we do not mark up the cost of gas. As such, we believe margin is a better
measure of performance for the industrial sector. The primary factors that impact margin from
industrial sales and transportation markets are as follows:
2009 compared to 2008:
•
volumes delivered to industrial customers decreased 104 million therms, or 18 percent,
reflecting reduced usage likely due to weak economic conditions; and
• margin decreased $2.1 million, or 7 percent, reflecting a weak economy and customer rate
decreases related to lower depreciation expense and lower volumes, but that was partially
offset by fixed charges not affected by declining use.
2008 compared to 2007:
•
volumes delivered to industrial customers increased 0.1 million therms, or less than 1
percent, reflecting a reduction in sales volumes of 6.6 million therms offset by an increase
in transportation volumes of 6.7 million therms; and
• margin decreased $1.6 million, or 5 percent, reflecting a shift from higher margin to lower
margin rate schedules, but this decrease was partially offset by a margin gain of $0.8
million from curtailment charges assessed to a small number of customers who were out of
compliance during a cold weather episode in December 2008.
55
Several large industrial customers transferred from sales service to transportation service in
2009 and 2008. Changes in natural gas prices can result in a number of our large industrial customers
switching between transportation service, where they arrange for their own supplies through
independent third parties, to sales service, where we sell them the gas commodity under regulatory
tariffs. In such cases, our tariff requires us to charge the incremental cost of gas supply incurred, if any,
to serve those customers so that the cost does not adversely impact our margins or the prices our core
customers pay.
Regulatory Adjustment for Income Taxes Paid
Oregon law requires regulated natural gas and electric utilities to annually review the amount of
income taxes collected in rates from utility operation and compare it to the amount the utility actually
pays to taxing authorities. Under this law, if we pay less in income taxes than we collect from our
Oregon utility customers, or if our consolidated taxes paid are less than the taxes we collect from our
Oregon utility customers, then we are required to refund the excess to our Oregon utility
customers. Conversely, if we pay more income taxes than we actually collect from our Oregon utility
customers, as set forth under our most recent general rate case, then we are required to collect a
surcharge from our Oregon utility customers.
For the 2007 and 2008 tax years, the OPUC approved our tax filings to recover $6.4 million
and $0.2 million, respectively, through a surcharge to our Oregon utility customers. It was agreed that
the 2007 surcharge, plus accrued interest, would be collected in a one-time charge to customers in June
2009. It was also agreed that the 2008 surcharge, plus accrued interest, would be collected over a
one-year period beginning June 1, 2010. For the 2009 tax year, we anticipate that the difference
between income taxes paid and the amounts collected in rates will be greater than $100,000, and in
accordance with the rules, we have estimated a surcharge of $5.3 million (excluding interest). Both the
2007 and 2009 surcharges were primarily driven by higher income taxes paid on gains from gas cost
savings from our PGA incentive sharing mechanism. The following table summarizes the total
adjustment for income taxes paid as recognized in our results of operations for the year ended
December 31, 2009:
Thousands
Tax Year 2007
Tax Year 2008
Tax Year 2009
Total adjustment for income taxes paid
Other Revenues
Surcharge
Interest
Total
$
-
179
5,265
$5,444
$225
23
192
$ 225
202
5,457
$440
$5,884
Other revenues include miscellaneous fee income as well as revenue adjustments reflecting
deferrals to, or amortizations from, regulatory asset or liability accounts other than deferrals relating to
gas costs. Other revenues increased net operating revenues by $21.1 million in 2009, compared to
$21.8 million in 2008 and $12.2 million in 2007.
2009 compared to 2008:
Other revenues in 2009 were $0.7 million lower than in 2008 primarily reflecting a $6.3 million
surcharge for the rate adjustment from income taxes paid and $0.7 million decrease in curtailment
charges, partially offset by a $7.4 million refund to utility customers related to the gas storage
regulatory sharing mechanism.
56
2008 compared to 2007:
Other revenues in 2008 were $9.6 million higher than in 2007 primarily reflecting a $10.5
million refund to utility customers related to the gas storage regulatory sharing mechanism, partially
offset by a $1.9 million surcharge for the rate adjustment from income taxes paid.
Cost of Gas Sold
The cost of gas sold includes current gas purchases, gas drawn from storage inventory, gains
and losses from commodity hedges, pipeline demand charges, seasonal demand cost balancing
adjustments, regulatory gas cost deferrals and company gas use. Our regulated utility does not
generally earn a profit or incur a loss on gas commodity purchases. The OPUC and the WUTC require
the natural gas commodity cost to be billed to customers at the same cost incurred or expected to be
incurred by the utility. However, under the PGA mechanism in Oregon, our net income is affected by
differences between actual and expected purchased gas costs primarily due to market fluctuations and
volatility affecting unhedged purchases (see “Results of Operations—Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment,” above). We use natural gas derivatives, primarily fixed-
price commodity swaps, consistent with our financial derivatives policies to help manage our exposure
to rising gas prices. Gains and losses from financial hedge contracts are generally included in our PGA
prices and normally do not impact net income as the hedges are usually 100 percent passed through to
customers in annual rate changes, subject to a regulatory prudency review. However, utility gas hedges
entered into after the annual PGA filing in Oregon may impact net income to the extent of our share of
any gain or loss under the PGA. In Washington, 100 percent of the actual gas costs, including hedge
gains and losses, are passed through in customer rates (see “Application of Critical Accounting
Policies and Estimates—Accounting for Derivative Instruments and Hedging Activities,” and “Results
of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above, and
Note 11).
2009 compared to 2008:
•
•
•
total cost of gas sold decreased $45.4 million, or 7 percent, primarily due to reduced sales
volumes and credits for customer refunds;
the average gas cost collected through rates decreased 1 percent from 79 cents per therm in
2008 to 78 cents per therm in 2009, primarily reflecting the reduction to cost of gas sold
from our customer refund in 2009, partially offset by our 14 to 21 percent PGA rate
increases effective November 1, 2008; and
net losses totaling $187.9 million were realized from our financial hedges and included in
cost of gas sold, compared to $35.1 million of net hedge gains in 2008.
2008 compared to 2007:
•
•
•
total cost of gas sold increased $17.4 million or 3 percent, due to increased sales volumes;
the average cost of gas sold decreased 2 percent from 81 cents per therm in 2007 to 79 cents
in 2008, primarily reflecting our 8 to 10 percent PGA rate decreases effective November 1,
2007 and our 14 to 21 percent increases effective November 1, 2008; and
net gains of $35.1 million were realized from our financial hedges and included in cost of
gas sold, compared to $42.0 million of net losses in 2007.
57
In 2009 and 2007, our actual gas costs were significantly lower than gas costs embedded in
rates, but in 2008 our actual gas costs were higher than the gas costs embedded in rates. The effect on
shareholders from the gas cost incentive sharing mechanism was a margin gain of $15.1 million and
$12.1 million in 2009 and 2007, respectively, compared to a margin loss of $5.5 million in 2008. For a
discussion of our Oregon gas cost incentive sharing mechanism and the change effective November 1,
2009, see “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas
Adjustment,” above.
Gas Storage
Our gas storage segment primarily consists of the non-utility portion of our Mist underground
storage facility, utility and non-utility asset optimization and Gill Ranch. In 2009, we earned $8.9
million, or 34 cents per share, from our gas storage business segment, after regulatory sharing and
income taxes. This compares to net income of $8.4 million, or 31 cents per share, in 2008 and $8.5
million, or 32 cents per share, in 2007.
In Oregon, we retain 80 percent of the pre-tax income from gas storage services as well as from
optimization services when the costs of the capacity being used is not included in utility rates, or 33
percent of the pre-tax income from such storage and optimization services when the capacity being
used is included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a
deferred regulatory account for refund to our core utility customers. We have a similar sharing
mechanism in Washington for pre-tax income derived from gas storage and optimization services.
In 2007, we announced a joint project with PG&E to develop a new underground natural gas
storage facility at Gill Ranch near Fresno, California. We formed a subsidiary of NW Natural to
develop and operate the facility. Gill Ranch will initially own 75 percent of the project, and PG&E will
own 25 percent. As of December 31, 2009 and 2008, total assets at Gill Ranch were $116.3 million and
$13.2 million, respectively. See Note 2.
Other
Our other business segment consists of Financial Corporation, an equity investment in Palomar
and other non-utility investments and business activities. Financial Corporation had total assets at
December 31, 2009 and 2008 of $1.4 million and $1.3 million, respectively, and our investment
balance in Palomar was $14.1 million and $14.2 million, respectively. The asset balance at Financial
Corporation reflects a non-controlling interest in the Kelso Beaver pipeline. The balance in Palomar
reflects our equity investment to date in a proposed 217-mile transmission pipeline.
Net income from our other business segment for the years ended December 31, 2009, 2008 and
2007 was $0.2 million, $2.4 million and $1.1 million, respectively. In 2008, we sold the last of our
non-core assets, resulting in an after-tax gain of $1.1 million. See Note 2.
Consolidated Operations
Operations and Maintenance
Operations and maintenance expenses increased by $13.7 million in 2009, or 12 percent higher
than 2008, while 2008 was $7.1 million, or 6 percent lower than 2007. In 2009, operations and
58
maintenance expense included increased costs for pensions, health care, bonuses and a severance
program. The following summarizes the major factors that contributed to changes in operations and
maintenance expense:
2009 compared to 2008:
•
•
•
•
•
an $8.0 million increase in pension expense primarily due to lower assumed discount rates
and a decrease in our plans’ funded status, which resulted from a significant decline in the
market value of assets during 2008;
a $5.3 million increase in employee labor and benefit expense due to higher health care
premiums and higher bonuses related to above-target operating results, which affect annual
incentive payments and compensation;
a $1.1 million charge related to our voluntary severance program involving workforce
reductions during the third and fourth quarters of 2009;
a $1.1 million increase in strategic initiatives including performance improvement and
corporate tax projects; and
a $1.0 million increase in utility uncollectible expense (see discussion below).
Partially offsetting the above increases were:
•
•
a $2.1 million decrease in employee compensation expense related to reduced employee
count; and
a $0.6 million decrease in claims in 2009.
2008 compared to 2007:
•
•
a $4.3 million decrease due to additional costs incurred in 2007 for strategic initiatives
including maintenance projects, training and promotional and safety campaigns; and
a $5.6 million decrease in employee compensation and benefit expense, primarily due to
lower bonuses related to lower operating results which affected annual and long-term
incentives.
Partially offsetting the above decreases were:
•
•
a $2.0 million increase in costs related to serving a growing customer base and increased
operating expenses during the December cold weather episode; and
a $0.2 million, or 6 percent, increase in uncollectible expense reflecting higher revenues due
to rate increases and sales volume increases.
Our bad debt expense ratio as a percent of revenues was 0.42 percent for 2009, compared to
0.31 percent in 2008. Due to the weak economy and high unemployment rates, we were seeing a slight
increase in delinquent balances and customers on payment plans, partially offset by an increase in low
income energy assistance funds available for customers and refunds of gas cost savings in June and
July of 2009. Also, we have a rate mechanism that covers the increase in bad debt expense directly
related to increases in commodity costs. Under our PGA mechanism, billing rates are adjusted each
year to recover the expected increase (or decrease) in bad debt expense due to the higher cost of natural
gas. The revenue adjustment for bad debt expense is based on our average write-off rate over the last
three years multiplied by the estimated increase in commodity costs. In 2009, margin revenues
increased by approximately $0.6 million to partially offset the expected increase in bad debt expense.
59
General Taxes
General taxes, which are principally comprised of property and payroll taxes and regulatory
fees, increased $1.6 million, or 6 percent, in 2009 compared to 2008, and increased $1.4 million, or 5
percent, in 2008 compared to 2007. The major factors that contributed to changes in general taxes are:
2009 compared to 2008:
•
•
a $1.0 million, or 5 percent increase in property taxes related to a 3 percent increase in
utility plant balances; and
a $0.5 million increase in payroll taxes due to higher incentive compensation and employee
severance compensation in 2009.
2008 compared to 2007:
•
a $1.3 million increase in property taxes related to higher tax rates and increased utility
plant balances.
We have been involved in litigation with the Oregon Department of Revenue (ODOR) over
whether natural gas inventories and appliance inventories held for resale are required to be taxed as
personal property. This was appealed to and presented before the Oregon Supreme Court in 2009.
In January 2010, the Oregon Supreme Court unanimously ruled in our favor, stating that these
inventories were exempt from property tax. The ODOR has until March 11, 2010 to file a Motion for
Reconsideration with the Oregon Supreme Court. We are entitled to a refund of approximately $5.0
million, plus accrued interest, for property taxes paid on gas inventories beginning with the 2002-03
tax year and appliance inventories beginning with the 2005-06 tax year. We will recognize this gain as
income in 2010.
Depreciation and Amortization
The following table summarizes the increases in total plant and property and total depreciation
and amortization for the three years ended December 31:
Thousands, except percentages
Plant and property:
Utility plant:
Depreciable
Non-depreciable, including construction work in progress
Non-utility property:
Depreciable
Non-depreciable, including construction work in progress
Total plant and property
Depreciation and amortization:
Utility plant
Non-utility property
Total depreciation and amortization expense
Weighted average depreciation rate - utility
Weighted average depreciation rate - non-utility
60
2009
2008
2007
$2,169,922
46,190
$2,101,900
41,088
$2,013,191
38,970
2,216,112
2,142,988
2,052,161
63,564
83,058
146,622
62,882
11,624
74,506
56,444
10,705
67,149
$2,362,734
$2,217,494
$2,119,310
$
$
61,472
1,342
62,814
$
$
70,691
1,468
72,159
$
$
67,410
933
68,343
2.9%
2.2%
3.4%
2.5%
3.4%
2.1%
Total depreciation and amortization expense in 2009 decreased by $9.3 million, or 13 percent,
as compared to a $3.8 million or 6 percent increase, in 2008 over 2007. The decreased expense in 2009
was related to the adoption of the new depreciation rates, which were approved by the OPUC, WUTC
and FERC effective January 1, 2009 (see “Regulatory Matters—Rate Mechanisms—Depreciation
Study,” above). The increased expense in 2008 was primarily due to additional investments in utility
plant to meet continuing customer growth and to make system improvements (see “Financial
Condition—Cash Flows—Investing Activities,” below, and Note 9).
Other Income and Expense—Net
The following table provides details on other income and expense – net for the last three years:
Thousands
Gains from company-owned life insurance
Interest income
Income from equity investments
Net interest on deferred regulatory accounts
Gain on sale of investments
Other non-operating
Total other income and expense - net
2009 compared to 2008:
2009
2008
2007
$ 3,416
211
1,329
2,051
45
(3,338)
$ 2,190
250
667
552
1,737
(1,650)
$ 1,939
537
130
84
1,544
(2,789)
$ 3,714
$ 3,746
$ 1,445
Other income and expense—net decreased by less than $0.1 million in 2009 over 2008. The
decrease was primarily due to a net increase in other non-operating expense for higher business
development costs and other strategic initiatives expense in 2009, and from the gain on sale of the
aircraft in 2008. These were partially offset by increases in income from company-owned life
insurance, income from our equity investment in Palomar and interest income from deferred regulatory
account balances.
2008 compared to 2007:
Other income and expense–net increased by $2.3 million in 2008 over 2007. The increase was
primarily due to a decrease of $1.1 million in other non-operating expense, reflecting the additional
start-up expenses in 2007 for business development and other strategic initiatives, and by a $0.2
million increase from the gain on sale of investments, reflecting the gains on sales of the aircraft in
2008 and the two wind power electric generation projects in 2007, and a $0.5 million increase in
income from equity investments, primarily related to Palomar.
Interest Charges—Net of Amounts Capitalized
Interest charges-net of amounts capitalized in 2009 increased by $3.1 million, or 8 percent,
compared to 2008, reflecting the issuance of long-term debt to refinance short-term debt balances,
which included the issuance of $75 million of 5.37 percent medium-term notes (MTN’s) issued in
March 2009 and the $50 million of 3.95 percent MTN’s issued in July 2009. Interest charges-net of
amounts capitalized in 2008 decreased by $0.2 million, or less than 1 percent, compared to 2007,
reflecting lower balances on long-term debt outstanding due to the redemption of $5 million of MTN’s
in July 2008. The average interest crediting rate for the allowance for funds used during construction,
comprised of short-term and long-term borrowing rates, as appropriate, was 1.0 percent in 2009, 3.6
percent in 2008 and 5.4 percent in 2007.
61
Income Tax Expense
The increase in income tax expense of $6.0 million or 15 percent in 2009, compared to 2008
was primarily due to higher pre-tax consolidated earnings and a slightly higher effective tax rate of
38.3 percent in 2009 compared to 36.9 percent in 2008. Income tax expense decreased by $3.4 million
or 8 percent in 2008, as compared to total income tax expense of $44.1 million in 2007, and the
effective tax rate decreased slightly from an effective rate of 37.2 percent in 2007.
For the 2009 tax year, the higher effective tax rate was primarily the result of an increase in the
Oregon corporate income tax rate (see below for further discussion), an increased amortization of our
regulatory tax asset account on pre-1981 plant assets (see “Regulatory Matters—Rate Mechanisms—
Depreciation Study,” above), and an adjustment to deferred income taxes attributed to our
non-regulated business segments. For the 2008 tax year, the slightly lower effective tax rate was
primarily the result of a higher non-taxable gain on company-owned life insurance. For more
information on our income taxes, including a reconciliation between the statutory federal and state
income tax rates and the effective rate, see Note 1 and Note 8.
In July 2009, the governor of Oregon signed House Bill 3405 establishing increases in the state
income tax rate for corporations. By referendum, Oregon voters approved this legislation in January
2010. The corporate income tax rate in Oregon for 2009 and 2010 will increase from 6.6 percent to 7.9
percent for corporations with taxable income over $250,000. For tax years 2011 and 2012, the income
tax rate will decrease to 7.6 percent, and for years after 2012 the tax rate will return to the current 6.6
percent, except for corporations with taxable income over $10 million the tax rate will remain at 7.6
percent. The new tax rates are retroactive to January 1, 2009. Following existing guidance on income
taxes, we re-measured our deferred income tax assets and liabilities, resulting in an adjustment to
increase the balance by $3.6 million. Approximately $3.5 million of the adjustment was attributed to
our utility operations. As we anticipate future recovery in rates, we recorded a $5.8 million regulatory
asset for the grossed up revenue requirement. With respect to our non-utility business segments, a $0.1
million adjustment was charged to income tax expense.
Financial Condition
Capital Structure
Our goal is to maintain a strong consolidated capital structure, generally consisting of 45 to 50
percent common stock equity and 50 to 55 percent long-term and short-term debt. When additional
capital is required, debt or equity securities are issued depending upon both the target capital structure
and market conditions. These sources also are used to fund long-term debt redemption requirements
and short-term commercial paper maturities (see “Liquidity and Capital Resources,” below, and Notes
5 and 6). Achieving the target capital structure and maintaining sufficient liquidity to meet operating
requirements are necessary to maintain attractive credit ratings and have access to capital markets at
reasonable costs. Our consolidated capital structure was as follows for the years ended December 31,
2009 and 2008:
Common stock equity
Long-term debt
Short-term debt, including current maturities of long-term debt
Total
62
2009
47.2%
43.0%
9.8%
2008
45.3%
36.8%
17.9%
100.0%
100.0%
Liquidity and Capital Resources
At December 31, 2009, we had $8.4 million of cash and cash equivalents compared to $6.9
million at December 31, 2008. Short-term liquidity is provided by cash balances, internal cash flow
from operations, proceeds from the sale of commercial paper notes, unsecured credit facilities with
multi-year commitments, (see “Credit Agreement,” below), an ability to borrow from cash surrender
value in company-owned life insurance policies, and proceeds from the sale of long-term debt. We use
long-term debt proceeds primarily to finance capital expenditures and refinance maturing short-term
and long-term debt.
Our current senior secured long-term debt ratings are AA- from S&P and A1 from Moody’s.
Most recently, S&P downgraded our corporate credit rating to A+ from AA-, but at the same time
reaffirmed our senior secured long-term debt rating at AA- and our senior unsecured rating at
A+. Previously, Moody’s had upgraded our long-term senior secured debt rating from A2 to A1 in
August 2009. Our short-term debt ratings are A-1 from S&P and P-1 from Moody’s. Both S&P and
Moody’s have assigned a stable outlook to our debt ratings.
Over the last 18 months, the capital markets have experienced significant volatility and tight
credit conditions, but conditions have improved recently as reflected by tighter credit spreads and
increased access to new financing for investment grade issuers. With our current debt ratings, we have
been able to issue commercial paper and long term debt at attractive rates and have not needed to
borrow from our $250 million back-up facility. In the event that we are not able to issue new debt due
to market conditions, we expect that our near term liquidity needs can be met by using cash balances or
drawing upon our committed credit facility (see “Credit Agreement,” below). We also have a universal
shelf registration statement filed with the Securities and Exchange Commission for the issuance of
secured and unsecured debt or equity securities, subject to market conditions and regulatory
approvals. We have OPUC approval to issue up to $175 million of additional MTNs under our shelf
registration statement.
Our senior unsecured long-term debt ratings are A+ and A3 from S&P and Moody’s,
respectively. In the event that our senior unsecured long-term debt credit 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 form of collateral, which
could expose us to additional cash requirements and may trigger significant increases in short-term
borrowings. If the credit risk-related contingent features underlying these contracts were triggered on
December 31, 2009, we would be required to post approximately $7.8 million of collateral to our
counterparties, but that would assume our long-term debt ratings were at non-investment grade levels,
a level that is significantly lower than our current ratings.
Based on several factors, including our current credit ratings, our recent experience issuing
commercial paper, our current cash reserves, our committed credit facilities and other liquidity
resources, and our expected ability to issue long-term debt and equity securities under our universal
shelf registration statement, we believe our liquidity is sufficient to meet our anticipated near-term cash
requirements, including all contractual obligations and investing and financing activities discussed
below.
Dividend Policy
We have paid quarterly dividends on our common stock each year since the stock was first
issued to the public in 1951. Annual common dividend payments per share, adjusted for stock splits,
63
have increased each year since 1956. The amount and timing of dividends payable on our common
stock is within the sole discretion of our Board of Directors. Our Board of Directors expects to
continue paying cash dividends on common stock on a quarterly basis. However, the declarations and
amount of future dividends will be dependent upon our earnings, cash flows, financial condition and
other factors.
Off-Balance Sheet Arrangements
Except for certain lease and purchase commitments (see “Contractual Obligations,” below), we
have no material off-balance sheet financing arrangements.
Contractual Obligations
The following table shows our contractual obligations at December 31, 2009 by maturity and
type of obligation.
Thousands
Payments Due in Years Ending December 31,
2014
2012
2010
2011
2013
Thereafter
Total
Commercial paper
Long-term debt maturities
Interest on long-term debt
Postretirement benefit payments (1)
Capital leases
Operating leases
Gas purchase contracts (2)
Gas pipeline commitments
Other purchase commitments
$102,000 $
35,000
39,345
23,041
582
4,162
145,305
81,907
130,339
- $
- $
10,000
36,840
19,943
269
4,155
37,819
71,502
7,183
40,000
34,518
20,545
95
4,279
23,640
54,910
813
- $
-
33,607
20,985
16
4,317
16,741
47,425
-
- $
60,000
33,446
21,621
-
4,641
13,951
23,554
-
- $ 102,000
636,700
459,523
228,395
962
44,977
237,456
547,851
138,335
491,700
281,767
122,260
-
23,423
-
268,553
-
Total
$561,681 $187,711 $178,800 $123,091 $157,213 $1,187,703 $2,396,199
(1)
The majority of postretirement benefit payment obligations are related to our qualified defined benefit
pension plans, which are funded by plan assets and future cash contributions. See Note 7.
(2) All gas purchase contracts use price formulas tied to monthly index prices. Commitment amounts are based
on index prices at December 31, 2009.
Other purchase commitments primarily consist of remaining balances under existing purchase
orders. These and other contractual obligations are financed through cash from operations and from the
issuance of short-term debt, which is periodically refinanced through the sale of long-term debt or
equity securities.
At December 31, 2009, 646 of our utility employees were members of the Office and
Professional Employees International Union, Local No. 11. In July 2009, our union employees ratified
a new five-year labor agreement called the Joint Accord. The agreement included a 2.4 percent average
wage increase effective June 1, 2009, and a scheduled 1 percent wage increase each year thereafter
with the potential for up to an additional 2 percent per year based on wage inflation and other factors.
The Joint Accord also maintains competitive health benefits while limiting the cost increases for these
benefits to the same level as the annual wage increases, and provides increased job flexibility along
with the ability for the Company to use short-term unpaid leave to temporarily adjust the workforce
64
without layoffs. The Joint Accord continues our defined benefit retirement plan for existing employees,
but closes the plan to new employees hired after December 31, 2009. The term of the new Joint Accord
extends to May 31, 2014, and thereafter from year to year unless either party serves notice of its intent
to negotiate modifications to the collective bargaining agreement.
Short-term Debt
Our primary source of short-term liquidity is from internal cash flows and the sale of
commercial paper notes. In addition to issuing commercial paper to meet seasonal working capital
requirements, including the financing of gas inventories and accounts receivable, short-term debt may
be used to temporarily fund capital requirements. Commercial paper is periodically refinanced through
the sale of long-term debt or equity securities. Our outstanding commercial paper, which is sold
through two commercial banks under an issuing and paying agency agreement, is supported by one or
more unsecured revolving credit facilities (see “Credit Agreement,” below). Our commercial paper
program did not experience any liquidity disruptions as a result of the credit problems that affected
issuers of asset-backed commercial paper and certain other commercial paper programs in 2008 and
2009. At December 31, 2009 and 2008, our utility had commercial paper outstanding of $69.8 million
and $248.0 million, respectively. This year’s outstanding commercial paper balances were lower than
last year’s primarily due to the refinancing of short-term debt with long-term debt issuances.
In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40 million
that has been extended until September 30, 2010. As of December 31, 2009, Gill Ranch had $32.2
million of borrowings outstanding included under short-term debt on the balance sheet, with a
corresponding cash collateral amount included under restricted cash – current on the balance sheet. The
effective interest rate on Gill Ranch’s credit facility is 0.8 percent.
Credit Agreement
We have a syndicated multi-year credit agreement for unsecured revolving loans totaling $250
million, which may be extended for additional one-year periods subject to lender approval. All lenders
agreed to extend their obligations for an additional one-year period to May 31, 2013. All lenders under
our credit agreement are major financial institutions with committed balances and investment grade
credit ratings as of December 31, 2009 as follows:
Lender rating, by category
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Amount
Committed
(in thousands)
$
-
230,000
20,000
-
$250,000
Based on credit market conditions, it is possible that one or more lending commitments could
be unavailable to us if the lender defaulted due to lack of funds or insolvency. However, based on our
current assessment of our lenders’ creditworthiness, including a review of capital ratios, credit default
swap spreads and credit ratings, we believe the risk of lender default is minimal.
As discussed above, we extended commitments with all seven lenders under the syndicated
credit agreement, with commitments totaling $250 million, to May 31, 2013. The credit agreement also
65
allows us to request increases in the total commitment amount from time to time, up to a maximum
amount of $400 million, and to replace any lenders who decline to extend the maturity date of the
credit agreement. The credit agreement also permits the issuance of letters of credit in an aggregate
amount up to the applicable total borrowing commitment. Any principal and unpaid interest owed on
borrowings under the credit agreement is due and payable on or before the maturity date. There were
no outstanding balances under this credit agreement at December 31, 2009 and 2008. The credit
agreement also requires us to maintain a consolidated indebtedness to total capitalization ratio of 70
percent 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, 2009 and 2008, with consolidated indebtedness to total
capitalization ratios of 52.8 percent, and 54.7 percent, respectively.
The syndicated credit agreement also requires that we maintain credit ratings with S&P and
Moody’s and notify the lenders of any change in our senior unsecured debt ratings 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 agreement. However, a change in
our debt rating below BBB- or Baa3 would require additional approval from the OPUC prior to
issuance of debt, and interest rates on any loans outstanding under the credit agreement are tied to debt
ratings, which would increase or decrease the cost of any loans under the credit agreement when
ratings are changed (see “Credit Ratings,” below).
Credit Ratings
The table below summarizes our current credit ratings from two rating agencies, S&P and
Moody’s.
Commercial paper (short-term debt)
Senior secured (long-term debt)
Senior unsecured (long-term debt)
Ratings outlook
S&P
A-1
AA-
A+
Stable
Moody’s
P-1
A1
A3
Stable
The above credit ratings are dependent upon a number of factors, both qualitative and
quantitative, and are subject to change at any time. The disclosure of 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.
Redemptions of Long-Term Debt
We redeemed MTNs during 2009, 2008 and 2007 as follows:
Thousands
Medium-Term Notes:
6.31% Series B due 2007
6.80% Series B due 2007
6.50% Series B due 2008
6.65% Series B due 2027(1)
Redeemed
in 2009
Redeemed
in 2008
Redeemed
in 2007
$
-
-
-
300
$
-
-
5,000
-
$20,000
9,500
-
-
(1)
In November 2009 one investor in our 6.65 percent secured MTNs due 2027 exercised its right under a
one-time put option to redeem $0.3 million of the $20 million outstanding. This one-time put option has
now expired, and the remaining $19.7 million principal outstanding is expected to be redeemed at maturity
in November 2027.
66
Cash Flows
Operating Activities
2009 compared to 2008:
Year-over-year changes in our operating cash flows are primarily affected by net income,
changes in working capital requirements and other cash and non-cash adjustments to operating
results. In 2009, cash flow from net income and operating activity adjustments, excluding working
capital changes, increased $29.1 million compared to 2008. Working capital changes in 2009 increased
$176.5 million compared to the same period in 2009. The overall change in cash flow from operating
activities was an increase of $205.6 million. The significant factors contributing to the cash flow
changes between 2009 and 2008 are as follows:
•
•
•
•
•
•
•
•
an increase of $82.1 million from deferred gas cost savings reflecting lower actual gas
prices compared to gas prices collected in customer rates in 2009, net of amounts already
refunded to customers (see below);
an increase of $72.0 million from decreases in accounts receivable and accrued unbilled
revenue primarily due to the collection of higher balances in accounts receivable and
accrued unbilled revenue balances at year end 2008;
an increase of $41.6 million from income tax refunds received from a change in tax
accounting method for certain repairs and maintenance costs (see below);
an increase of $31.2 million related to the net decrease in gas inventory balances due to the
higher price of gas injected into storage in 2008;
an increase of $25.7 million from accounts payable, reflecting lower gas prices at the end of
2009 compared to 2008;
a decrease of $25.0 million related to our pension contributions in 2009 to reduce our
unfunded liability;
a decrease of $13.4 million from deferred income taxes, reflecting the approved tax
deduction for repair and maintenance costs (see below); and
a decrease of $10.1 million related to the loss realized on the settlement of our interest rate
hedge in 2009.
2008 compared to 2007:
In 2008, cash flow from net income and operating activity adjustments, excluding working
capital changes, decreased $37.9 million compared to 2007. Working capital changes in 2008
decreased cash flow by $111.0 million compared to 2007. The majority of these working capital
changes, particularly those related to accounts receivable, unbilled revenues inventories, income taxes
receivable and accounts payable, reversed early in 2009 reflecting changes in seasonal working
capital. The overall change in cash flow from operating activities in 2008 compared to 2007 was a
decrease of $148.9 million. The significant factors contributing to the cash flow changes between 2008
and 2007 are as follows:
•
•
an increase of $55.4 million in deferred income taxes and investment tax credits primarily
from additional accelerated depreciation and a net operating loss (see Note 8);
a decrease of $84.0 million in deferred gas costs, $30.4 million in accounts payable and
$14.3 million in inventories, primarily due to the higher gas cost prices in 2008 compared to
2007;
67
•
•
a decrease of $58.5 million in accounts receivable and accrued unbilled revenue due to the
colder weather in December 2008 and our November 1, 2008 rate increase (see Results of
Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,”
above); and
a decrease of $20.8 million in income taxes receivable primarily due to bonus depreciation
and an estimate for a future pension contribution, for which we saw an increase in deferred
income taxes.
In June and July of 2009, we refunded an aggregate $35.8 million from a regulatory liability
account to our Oregon and Washington customers for the customers’ share of accumulated gas cost
savings from November 1, 2008 through March 31, 2009. This reduction in cash was only part of the
gas cost savings accumulated from lower gas prices during the 2008-09 gas contract year. Additional
savings for customers have accumulated since March 31, 2009, and these amounts are being refunded
to customers through lower rates starting November 1, 2009.
In December 2008, we filed an application with the IRS requesting a change in our tax
accounting method to expense routine repair and maintenance costs for gas pipelines that are currently
being capitalized and depreciated for book purposes. The IRS consented to our request in August 2009,
and we recognized a tax deduction of approximately $59 million on our 2008 tax return, which resulted
in a federal tax refund of approximately $21 million during the fourth quarter of 2009.
At December 31, 2008, we reported an estimated net operating loss (NOL) for federal and
Oregon income tax purposes of $19.2 million and $23.8 million, respectively, primarily due to the
effects of accelerated tax depreciation provided by the Economic Stimulus Act. As a result of the
change in our tax accounting method for repair and maintenance costs discussed above as well as our
increased pension contribution, our NOL for federal and Oregon income tax purposes was $89.0
million and $87.2 million on our 2008 federal and Oregon tax returns, respectively. The federal NOL
was carried back to 2006 for a refund of taxes paid in prior years, while the Oregon NOL has been
carried forward to reduce current and future taxable income. We anticipate that we will be able to use
all loss carryforwards in future years. The 2008 Oregon NOL would expire in 2023 if not used in
earlier years.
In February 2009, the American Recovery and Reinvestment Act of 2009 (Act) was signed into
law. This Act provides a 50 percent bonus depreciation deduction for qualified property acquired or
constructed and placed in service in 2009. We estimate that the bonus depreciation deduction will defer
the payment of approximately $12.9 million of federal income taxes during 2009 to future periods.
We have lease and purchase commitments relating to our operating activities that are financed
with cash flows from operations (see “Contractual Obligations,” above and Note 11).
Investing Activities
Cash requirements for investing activities in 2009 totaled $162.1 million, an increase of $52.3
million from $109.8 million in 2008. Cash requirements for the acquisition and construction of our
utility plant were $91.2 million in 2009, down from $96.6 million in 2008. The decrease is primarily
due to reduced capital expenditures from lower customer growth in new construction and reduced
system expansion costs.
Cash requirements for investments in non-utility property were $43.9 million in 2009, primarily
related to investments in Gill Ranch, compared to $7.4 million in 2008. Cash proceeds of $6.8 million
68
from the sale of our investment in a Boeing 737-300 aircraft were used to partially offset our
investments in non-utility activities last year. We added $30.5 million to restricted cash balances in
2009, which collateralizes equipment purchase contracts and bank loans for Gill Ranch, as compared
to $5.0 million in 2008. Cash provided by other investing activities in 2009 totaled $3.4 million
compared to cash used of $8.3 million in 2008. The change in 2009 is primarily due to a net recovery
of capital costs in the amount of $1.6 million from Palomar in 2009 compared to $7.5 million of cash
contributions to Palomar in 2008, and $2.3 million in proceeds from life insurance collected in 2009
compared to $0.2 million in 2008.
In 2010, utility capital expenditures are estimated to be between $80 and $90 million, and
non-utility capital investments are expected to be between $120 million and $145 million for business
development projects that are currently in process (see “2010 Outlook,” above).
Over the five-year period 2010 through 2014, utility capital expenditures are estimated at
between $400 and $500 million, reflecting continued customer growth, gas storage development at
Mist, technology improvements and utility system improvements, including requirements under the
Pipeline Safety Improvement Act of 2002. Most of the required funds for utility capital expenditures
and Mist expansion are expected to be internally generated over the five-year period, and any
remaining funding will be obtained through the issuance of long-term debt or equity securities, with
short-term debt providing liquidity and bridge financing. We have a shelf registration statement filed
with the SEC. Under this shelf registration, we can issue either debt or equity securities. We expect to
file a new shelf registration statement during 2010. As of December 31, 2009, the remaining balance of
unused financing available and approved by the OPUC under the current shelf registration was
$175 million.
Our funding of the total remaining cost for the current development at Gill Ranch project is
estimated to be between $105 million and $125 million. As of December 31, 2009, we have invested
$54.7 million of equity funds in Gill Ranch. The remaining project cost is expected to be met from a
combination of equity funds and debt, which will be non-recourse to NW Natural. We have not
pledged any of our utility assets, nor have we provided any parent guarantees, toward Gill Ranch’s
obligations.
In 2010, Palomar will continue to work on the planning and permitting phase of the pipeline
project. The total cost for planning and permitting is estimated to be between $40 million and $50
million, of which our ownership interest is 50 percent. As of December 31, 2009, we have invested
$14.1 million. The total cost estimate for the entire 217-mile pipeline, if constructed, is estimated to be
between $750 million and $800 million, with our current 50 percent share estimated at between $375
million and $400 million. The initial planning and developing costs will be financed with equity funds
from us and our partner, TransCanada. See “2010 Outlook,” above.
The Palomar pipeline project includes both an east and west segment. Palomar intends to
proceed with the construction of the west segment of the pipeline if an LNG terminal is
developed. However, the development of LNG terminals along the Columbia River may or may not
proceed, dependent upon a variety of factors, including obtaining state and federal permits, securing
acceptable financing and economic conditions. Palomar had executed precedent agreements whereby a
significant majority of the pipeline capacity was committed to one shipper. In April 2009, Palomar and
that shipper replaced their existing precedent agreement with a new agreement for the same amount of
capacity and Palomar received $15.8 million of cash proceeds which had supported the shipper’s
obligations under the prior agreement. The cash proceeds received were applied against project
69
costs. Under the precedent agreement now in effect, the shipper currently provides an alternate form of
credit support, which is expected to support a portion of the ongoing planning and permitting costs as
the project develops. In addition, Palomar has the right to request additional credit support from the
shipper at future stages of development. A failure to provide acceptable ongoing credit support to meet
the shipper’s obligations may result in Palomar reassessing its commitment to the development of the
west segment.
Based on an ongoing review of the Palomar pipeline project, and continuing interest expressed
by the majority shipper, as well as interest expressed by other potential shippers, PGH believes that the
Palomar project is still viable, particularly the east segment. Palomar has binding precedent agreements
with two shippers, including our own utility, which represents a majority of the current design capacity
on the pipeline. Palomar has also been discussing precedent agreements with other potential shippers
for the east segment in particular, should some of that capacity be available. We will continue to
manage project risks, evaluate project costs and assess the fair value of our investment on a quarterly
basis, including a valuation of the available credit support. Additionally, PGH will continue to evaluate
market conditions and project status to determine if and when to proceed with construction of all or
some portion of the project. See Part I, Item 1A., “Risk Factors,” above.
Financing Activities
Cash used by financing activities in 2009 totaled $76.7 million, as compared to cash provided
of $75.9 million in 2008. Factors contributing to the $152.6 million net decrease in financing activities
primarily includes a $276.6 million aggregate decrease in the changes in short-term debt between 2009
compared to 2008. The change in short-term debt was partially offset by long-term debt issuances
totaling $125 million in 2009. We use long-term debt proceeds primarily to finance capital
expenditures, refinance maturing short-term debt and redeem long-term debt maturities as well as for
general corporate purposes.
In 2000, we announced a program to repurchase up to 2 million shares, or up to $35 million in
value, of our common stock through a repurchase program. In 2007, the program was modified to
authorize the repurchase of up to 2.8 million shares or up to $100 million and was extended through
May 2010. The purchases are made in the open market or through privately negotiated transactions. No
repurchases were made in 2009 or 2008. Repurchases in 2007 totaled 963,428 shares or $44.2 million,
at an average price of $46.03 per share. Since the program’s inception, we have repurchased an
aggregate 2.1 million shares of common stock at a total cost of $83.3 million, at the average price of
$39.19 per share (see Part II, Item 5, “Market for the Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities,” above).
70
In 2009, we produced free cash flow of $35.8 million, compared to negative free cash flow of
$115.3 million in 2008 and free cash flow of $27.5 million in 2007. Free cash flow is the amount of
cash remaining after the payment of all cash expenses, capital expenditures (investment activities) and
dividends. Free cash flow is a non-GAAP financial measure, but we believe this supplemental
information enables the reader of the financial statements to better understand our cash generating
ability and to benefit from seeing cash flow results from management’s perspective in addition to the
traditional GAAP presentation. We monitor free cash flow as one measure of our return on
investments. Provided below is a reconciliation from cash provided by operations (GAAP basis) to our
non-GAAP free cash flow.
Thousands
Cash provided by operating activities
Cash used in investing activities
Cash dividend payments on common stock
Free cash flow
2009
2008
2007
$ 240,335
(162,141)
(42,415)
$ 34,721
(109,825)
(40,178)
$ 183,640
(117,479)
(38,613)
$ 35,779
$(115,282) $ 27,548
The free cash flow information presented above is not intended to be a substitute for, nor is it
meant to be a better measure of, cash flow results prepared in accordance with GAAP. In addition, the
non-GAAP measure we provide may be calculated differently by other companies that present a
similar non-GAAP financial measure for free cash flow.
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,” above). Pension costs for our two qualified defined benefit
plans, which are allocated between operations and maintenance expense and capital accounts based on
employee payroll distributions, totaled $14.6 million in 2009, an increase of $10.3 million over 2008.
The fair market value of the assets in these two plans increased to $201.3 million at
December 31, 2009 from $163.1 million at December 31, 2008. The increase was due to a positive
return on plan assets of $28.6 million and a $25.0 million employer contribution, partially offset by
benefit payments of $15.4 million.
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 new funding requirements for defined benefit plans. The
Act establishes a 100 percent funding target for plan years beginning after December 31, 2009.
However, a delayed effective date of 2011 may apply if the pension plan meets the funding targets of
94 percent in 2009 and 96 percent in 2010. Our qualified defined benefit pension plans are currently
underfunded by $83.9 million at December 31, 2009. We plan to make contributions during 2010 of
approximately $10 million during the first quarter. For more information, see Note 7.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2009, 2008 and 2007, our ratios of earnings to fixed charges,
computed using the Securities and Exchange Commission method, were 3.86, 3.76 and 3.92,
respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed
71
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. See Exhibit 12.
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—Contingencies,”
above). At December 31, 2009, a cumulative $106.0 million in environmental costs was recorded as a
regulatory asset, consisting of $36.7 million of costs paid to-date, $59.8 million for additional
environmental accruals for costs expected to be paid in the future and accrued regulatory interest of
$9.5 million. If it is determined that both the insurance recovery and future customer rate recovery of
such costs was not probable, then the costs will be charged to expense in the period such determination
is made. For further discussion of contingent liabilities, see Note 11.
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 1.
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 storage facilities, to meet the
expected requirements of our core utility customers. Our gas purchase contracts are primarily index-
based and subject to monthly re-pricing, a strategy that is intended to reflect market price trends during
the upcoming year. Our PGA mechanisms in Oregon and Washington provide for the recovery from
customers of actual commodity costs, except that, for Oregon customers, we currently absorb 10
percent of the higher cost of gas sold, or retain 10 percent of the lower cost, in either case as compared
to the annual PGA price built into customer rates.
Commodity Price Risk
Natural gas commodity prices are subject to fluctuations due to unpredictable factors including
weather, pipeline transportation congestion, potential market speculation and other factors that affect
short-term supply and demand. Commodity-price financial swap and option contracts (financial hedge
contracts) are used to convert certain natural gas supply contracts from floating prices to fixed or
capped prices. These financial hedge contracts are generally included in our annual PGA filing for
recovery, subject to a regulatory prudence review. At December 31, 2009 and 2008, notional amounts
under these financial hedge contracts totaled $310.9 million and $393.0 million, respectively. If all of
the commodity-based financial hedge contracts had been settled on December 31, 2009, a loss of about
$15.8 million would have been realized and recorded to a deferred regulatory account (see Note 10).
72
We monitor the liquidity of our financial hedge contracts. Based on the existing open interest in the
contracts held, we believe existing contracts to be liquid. All of our financial hedge contracts settle by
or are extendible to October 31, 2012. The $15.8 million unrealized loss is an estimate of future cash
flows based on forward market prices that are expected to be paid as follows: $9.7 million in the next
12-month period, and $6.1 million thereafter. The amount realized will change based on market prices
at the time contract settlements are fixed.
Interest Rate Risk
We are exposed to interest rate risk 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.
Foreign Currency Risk
The costs of certain natural gas commodity supplies and certain pipeline 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 with respect to purchases of natural gas from Canadian suppliers. At December 31, 2009 and
2008, notional amounts under foreign currency forward contracts totaled $6.6 million and $5.2 million,
respectively. As of December 31, 2009, all foreign currency forward contracts mature within one
year. If all of the foreign currency forward contracts had been settled on December 31, 2009, a gain of
$0.3 million would have been realized (see Note 10).
Credit Risk
Credit exposure to suppliers. Certain suppliers that sell us gas 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 believe these
costs would be subject to the PGA sharing mechanism discussed above. Since most of our commodity
supply contracts are priced at the monthly market index price tied to liquid exchange points, and we
have significant storage flexibility, we believe that it is unlikely that 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, 2009, our overall credit exposure relating to commodity hedge contracts reflects an
amount owed to our finance derivative counterparties of $15.8 million. 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 current market conditions and credit concerns, we continue to
enforce strong credit requirements. We actively monitor our derivative credit exposure and place
counterparties on hold for trading purposes or require cash collateral, letters of credit or guarantees as
73
circumstances warrant. Our actual derivative credit exposure, which reflects amounts that financial
derivative counterparties owe to us, is $0.2 million, and these are under contracts that expire or are
expected to settle on or before October 31, 2012.
The following table summarizes our overall 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:
Thousands
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Financial Derivative Position by Credit Rating
Unrealized Fair Value Gain (Loss)
Dec. 31, 2009
Dec. 31, 2008
-
$
(15,792)
-
-
$(15,792)
$ (16,827)
(122,287)
(12,006)
-
$(151,120)
To mitigate the credit risk of financial derivatives we have master netting arrangements with
our counterparties that provide for making or receiving net cash settlements. Generally, transactions of
the same type in the same currency that have a 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
that 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.
Credit exposure to insurance companies for environmental damage claims. We regularly
monitor the financial condition of insurance companies who provide general liability insurance policy
coverage to NW Natural and its predecessors with respect to environmental damage claims. We have
filed claims for our environmental costs with nine insurance companies, of which six have credit
ratings of A- or better from A.M. Best Co. (AM Best). AM Best is a global independent credit rating
agency who has provided quantitative and qualitative analysis of insurance company balance sheet
strength for over 100 years. AM Best uses a rating scale that ranges from A++ (“Superior” financial
strength) to F (“In Liquidation”), with a rating of A- considered “Excellent.” A strong credit rating
from AM Best is not a guaranty that an insurance company will be able to meet its contractual
obligations. The three insurance companies who do not have credit ratings of A- or better are expected
to have sufficient funds in reserves to cover these claims. Our credit exposure to insurance companies
for environmental claims, which reflects amounts we believe are owed to us, could be material. In the
event we are unable to recover environmental expenses from these insurance policies, we will seek
recovery of unreimbursed amounts through customer rates.
74
Weather Risk
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. In 2003, the OPUC approved a weather normalization mechanism for residential and
commercial customers. This mechanism affects customer bills between December 1 through May 15 of
each winter heating season, increasing or decreasing the margin component of customers’ rates to
reflect gas usage based on “average” weather using the 25-year average temperature for each day of
the billing period. The mechanism 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, 2009,
approximately 9 percent of our Oregon customers had opted out. In addition to the Oregon customers
opting out, our Washington residential and commercial customers account for approximately 10
percent 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 less than 20
percent of all residential and commercial customers.
75
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 Income for the Years Ended December 31, 2009,
2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets at December 31, 2009 and 2008 . . . . . . . . . . . . . . . . . . . . . .
Page
77
78
79
80
Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the
Years Ended December 31, 2009, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
82
Consolidated Statements of Cash Flows for the Years Ended December 31, 2009,
2008 and 2007 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
83
84
Quarterly Financial Information (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
125
Supplementary Data for the Years Ended December 31, 2009, 2008 and 2007:
Financial Statement Schedule
Schedule II—Valuation and Qualifying Accounts and Reserves . . . . . . . . . . . . . . . . . . . .
126
Supplemental Schedules Omitted
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
76
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) and 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 NW Natural’s internal control over financial
reporting as of December 31, 2009. 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.
Based on our assessment and those criteria, management has concluded that NW Natural
maintained effective internal control over financial reporting as of December 31, 2009.
The effectiveness of internal control over financial reporting as of December 31, 2009 has been
audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated
in their report which appears in this annual report.
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
David H. Anderson
Senior Vice President and Chief Financial Officer
February 26, 2010
77
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Northwest Natural Gas Company:
In our opinion, the consolidated financial statements listed in the accompanying table of contents present fairly, in all
material respects, the financial position of Northwest Natural Gas Company and its subsidiaries at December 31, 2009
and 2008, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedule listed in the accompanying table of contents presents fairly, in
all material respects, the information set forth therein when read in conjunction with the related consolidated financial
statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s
management is responsible for these financial statements and financial statement schedule, 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 these financial statements, on the financial statement schedule, and on the
Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in
accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are
free of material misstatement and whether effective internal control over financial reporting was maintained in all
material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation. 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.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts
for fair value measurements in 2008.
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 26, 2010
78
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Thousands, except per share amounts (year ended December 31)
2009
2008
2007
Operating revenues:
Gross operating revenues
Less: Cost of sales
Revenue taxes
Net operating revenues
Operating expenses:
Operations and maintenance
General taxes
Depreciation and amortization
Total operating expenses
Income from operations
Other income and expense - net
Interest charges - net of amounts capitalized
Income before income taxes
Income tax expense
Net income
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
Dividends declared
$1,012,711
611,168
24,656
$1,037,855
656,568
25,072
$1,033,193
639,150
25,001
376,887
356,215
369,042
127,104
28,253
62,814
218,171
158,716
3,714
40,637
121,793
46,671
113,360
26,660
72,159
212,179
144,036
3,746
37,579
110,203
40,678
120,488
25,288
68,343
214,119
154,923
1,445
37,811
118,557
44,060
$
75,122
$
69,525
$
74,497
26,511
26,576
26,438
26,594
26,821
26,995
$
$
$
2.83
2.83
1.60
$
$
$
2.63
2.61
1.52
$
$
$
2.78
2.76
1.44
See Notes to Consolidated Financial Statements.
79
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)
Assets:
Plant and property:
Utility plant
Less accumulated depreciation
Utility plant - net
Non-utility property
Less accumulated depreciation and amortization
Non-utility property - net
Total plant and property
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Regulatory assets - current
Fair value of non-trading derivatives
Inventories:
Gas
Materials and supplies
Income taxes receivable
Prepayments and other current assets
Total current assets
Investments, deferred charges and other assets:
Regulatory assets - non-current
Fair value of non-trading derivatives
Other investments
Restricted cash
Other
Total investments, deferred charges and other assets
Total assets
2009
2008
$2,216,112
682,060
$2,142,988
659,123
1,534,052
1,483,865
146,622
10,540
136,082
74,506
9,314
65,192
1,670,134
1,549,057
8,432
35,543
77,438
71,230
(3,125)
29,954
6,504
71,672
9,285
-
21,302
6,916
4,118
81,288
102,688
(2,927)
147,319
4,592
86,134
9,933
20,811
20,098
328,235
480,970
316,536
843
67,365
-
16,139
400,883
288,470
146
53,231
901
5,377
348,125
$2,399,252
$2,378,152
See Notes to Consolidated Financial Statements.
80
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)
Capitalization and liabilities:
Capitalization:
Common stock - no par value; authorized 100 million shares; issued and
outstanding 26,533,028 and 26,501,188 at December 31, 2009 and 2008,
respectively
Earnings invested in the business
Accumulated other comprehensive income (loss)
Total common stock equity
Long-term debt
Total capitalization
Current liabilities:
Short-term debt
Long-term debt due within one year
Accounts payable
Taxes accrued
Interest accrued
Regulatory liabilities - current
Fair value of non-trading derivatives
Other current and accrued liabilities
Total current liabilities
Deferred credits and other liabilities:
Deferred income taxes and investment tax credits
Regulatory liabilities - non-current
Pension and other postretirement benefit liabilities
Fair value of non-trading derivatives
Other
Total deferred credits and other liabilities
Commitments and contingencies (see Note 11)
Total capitalization and liabilities
2009
2008
$ 337,361
328,712
(5,968)
$ 336,754
296,005
(4,386)
660,105
601,700
628,373
512,000
1,261,805
1,140,373
102,000
35,000
123,729
21,037
5,435
46,628
19,643
39,097
392,569
300,898
248,622
127,687
3,193
64,478
744,878
-
248,000
-
94,422
12,455
2,785
20,456
136,735
36,467
551,320
257,831
228,157
138,229
21,646
40,596
686,459
-
$2,399,252
$2,378,152
See Notes to Consolidated Financial Statements.
81
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME
Thousands
Balance at Dec. 31, 2006
Net Income
Change in unrealized loss from price risk
management activities
Change in non-qualified employee benefit plan
liability, net of $487 of tax
Amortization of non-qualified employee benefit
plan liability, net of ($81) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock option plan
Stock-based compensation
Issuance of common stock
Common stock repurchased
Balance at Dec. 31, 2007
Net Income
Change in unrealized loss from price risk
management activities
Change in non-qualified employee benefit plan
liability, net of $731 of tax
Amortization of non-qualified employee benefit
plan liability, net of ($140) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2008
Net Income
Change in non-qualified employee benefit plan
liability, net of $1,273 of tax
Amortization of non-qualified employee benefit
plan liability, net of ($58) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2009
Common
Stock
and
Premium
$371,127
-
Earnings
Invested in
the Business
$230,774
74,497
Accumulated
Other
Comprehensive
Income (Loss)
$(2,356)
-
Total
Shareholders’
Equity
$599,545
74,497
Comprehensive
Income
$74,497
-
-
-
-
-
-
(38,613)
-
-
-
-
266,658
69,525
-
-
-
-
(40,178)
-
-
-
296,005
75,122
-
285
-
536
2,094
2,180
(44,627)
331,595
-
-
-
-
275
-
282
1,523
3,079
336,754
-
-
(41)
(1,232)
127
-
-
-
-
-
-
(3,502)
-
41
(1,145)
220
-
-
-
-
-
(4,386)
-
(41)
(41)
(1,232)
(1,232)
127
285
(38,613)
536
2,094
2,180
(44,627)
594,751
69,525
127
$73,351
$69,525
41
41
(1,145)
(1,145)
220
275
(40,178)
282
1,523
3,079
628,373
75,122
220
$68,641
$75,122
-
(1,936)
(1,936)
(1,936)
-
39
-
229
(776)
1,115
$337,361
-
-
(42,415)
-
-
-
$328,712
354
-
-
-
-
-
$(5,968)
354
39
(42,415)
229
(776)
1,115
$660,105
354
$73,540
See Notes to Consolidated Financial Statements.
82
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Thousands (year ended December 31)
Operating activities:
Net income
Adjustments to reconcile net income to cash provided by operations:
Depreciation and amortization
Deferred income taxes and investment tax credits
Undistributed gains from equity investments
Deferred gas costs - net
Gain on sale of non-utility investments
Income from life insurance investments
Contributions to qualified defined benefit pension plans
Non-cash expenses related to qualified defined benefit pension plans
Deferred environmental expenditures
Settlement of interest rate hedge
Deferred regulatory costs and other
Changes in working capital:
Accounts receivable and accrued unbilled revenue - net
Inventories of gas, materials and supplies
Income taxes receivable
Prepayments and other current assets
Accounts payable
Accrued interest and taxes
Other current and accrued liabilities
Cash provided by operating activities
Investing activities:
Investment in utility plant
Investment in non-utility property
Proceeds from sale of non-utility investments
Proceeds from life insurance
Net proceeds from (contributions to) non-utility equity investments
Restricted cash
Other
Cash used in investing activities
Financing activities:
Common stock issued (purchased), net of expenses
Common stock repurchased
Long-term debt issued
Long-term debt retired
Change in short-term debt - net
Cash dividend payments on common stock
Other
Cash provided by (used in) financing activities
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
Income taxes paid
2009
2008
2007
$ 75,122
$ 69,525
$ 74,497
62,814
36,775
(1,329)
36,819
(45)
(3,416)
(25,000)
9,914
(10,069)
(10,096)
(15,029)
35,506
15,110
20,811
(1,204)
1,188
11,232
1,232
240,335
72,159
50,192
(667)
(45,291)
(1,737)
(2,190)
-
2,855
(8,179)
-
(9,347)
(36,493)
(16,123)
(20,811)
363
(24,540)
(724)
5,729
34,721
(91,201)
(43,923)
120
2,255
1,600
(30,524)
(468)
(162,141)
(96,582)
(7,416)
7,531
208
(7,450)
(5,006)
(1,110)
(109,825)
68,343
(5,252)
(130)
38,665
(1,544)
(1,939)
-
4,387
(8,842)
-
(2,940)
22,029
(1,816)
-
(6,528)
5,841
(8,190)
7,059
183,640
(93,785)
(24,442)
2,628
881
(5,413)
-
2,652
(117,479)
(375)
-
125,000
(300)
(158,851)
(42,415)
263
(76,678)
1,516
6,916
8,432
$
2,310
-
-
(5,000)
117,751
(40,178)
1,030
75,913
809
6,107
6,916
$
2,180
(44,627)
-
(29,500)
43,000
(38,613)
1,739
(65,821)
340
5,767
6,107
$
$ 36,762
$ 10,000
$ 37,669
$ 12,300
$ 38,508
$ 56,215
See Notes to Consolidated Financial Statements.
83
NORTHWEST NATURAL GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization and Principles of Consolidation
The consolidated financial statements include the accounts of Northwest Natural Gas Company
(NW Natural), which primarily consist of our regulated gas distribution business and our
regulated gas storage business, which includes our wholly-owned subsidiary Gill Ranch
Storage, LLC (Gill Ranch), and other investments and business activities, which primarily
consist of our wholly-owned subsidiary NNG Financial Corporation (Financial Corporation)
and an equity investment in a natural gas transmission pipeline (See Note 2).
In this report, the term “utility” is used to describe the gas distribution business and the term
“non-utility” is used to describe the gas storage business and other non-utility investments and
business activities (see Note 2). Intercompany accounts and transactions have been eliminated,
except for transactions required to be included under regulatory accounting standards to reflect
the effect of such regulation.
Investments in corporate joint ventures and partnerships in which our ownership interest is 50
percent or less and over which we do not exercise control are accounted for by the equity
method or the cost method.
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 be
reported in future periods. Management believes that the estimates and assumptions used are
reasonable.
Industry Regulation
Our principal businesses are the distribution of natural gas, which is regulated by the Oregon
Public Utility Commission (OPUC) and Washington Utilities and Transportation Commission
(WUTC), and gas storage services, which are regulated by the Federal Energy Regulatory
Commission (FERC), the California Public Utilities Commission (CPUC) and to a certain
extent by the OPUC. 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 regulatory accounting. Our businesses with cost-based rates are authorized by
the OPUC, WUTC and the FERC to earn a reasonable return on invested capital, while our
business with market-based rates is authorized by the CPUC to earn a return to the extent we
are able to charge competitive prices above our costs.
In applying regulatory accounting, we capitalize or defer certain costs and revenues as
regulatory assets and liabilities pursuant to orders of the OPUC or WUTC issued to provide for
recovery of revenues or expenses from, or refunds to, utility customers in future periods,
including a return or a carrying charge.
84
At December 31, 2009 and 2008, the amounts deferred as regulatory assets and liabilities were
as follows:
Thousands
Regulatory assets:
Unrealized loss on non-trading derivatives (1)
Income tax asset
Pension and other postretirement benefit obligations (2)
Environmental costs - paid (3)
Environmental costs - accrued but not yet paid (3)
Other (4)
Total regulatory assets
Regulatory liabilities:
Gas costs payable
Unrealized gain on non-trading derivatives (1)
Accrued asset removal costs
Other (4)
Total regulatory liabilities
Current
Non-Current
2009
2008
2009
2008
$19,643
-
7,502
-
-
2,809
$136,735
-
8,074
-
-
2,510
$
3,193
76,240
109,932
46,204
59,844
21,123
$ 21,646
69,948
113,869
36,135
29,969
16,903
$29,954 $147,319
$316,536
$288,470
$37,055
6,504
-
3,069
$ 5,284
4,592
-
10,580
$
6,915
843
238,757
2,107
$ 1,868
146
223,716
2,427
$46,628 $ 20,456
$248,622
$228,157
(1)
(2)
(3)
(4)
An unrealized gain or loss on non-trading derivatives does not earn a rate of return or a carrying
charge. These amounts, when realized at settlement, are recoverable through utility rates as part of the
purchased gas adjustment mechanism.
Qualified pension plan and other postretirement benefit obligations are approved for regulatory
deferral. Such amounts are recoverable in rates, including an interest component, when recognized in net
periodic benefit cost (see Note 7).
Regulatory environmental costs are related to sites that are approved for regulatory deferral. We earn the
authorized rate of return as a carrying charge on amounts paid, whereas the amounts accrued but not yet
paid do not earn a rate of return or a carrying charge until expended.
Other primarily consists of deferrals and amortizations under other approved regulatory mechanisms. The
accounts being amortized typically earn a rate of return or carrying charge.
The amortization period for our regulatory assets and liabilities ranges from less than one year
to an undeterminable period. Our regulatory liabilities 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 realized. Similarly, most of our regulatory deferred accounts
are amortized over 12 months. However, certain regulatory account balances, such as income
taxes, environmental costs, pension obligations 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 that continued application of regulatory accounting for regulated activities is
appropriate and consistent with the current regulatory environment, and that all regulated assets
and liabilities at December 31, 2009 and 2008 will be recoverable or refundable through future
utility rates. We annually review all regulatory assets 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, then
we would be required to write off the net unrecoverable balances against earnings.
85
New Accounting Standards
Adopted Standards
Business Combinations. Effective January 1, 2009, we adopted authoritative guidance on
business combinations. This guidance amends the principles and requirements for how an
acquiror accounts for and discloses its business combinations. The adoption of this standard did
not have a material effect on our financial condition, results of operations or cash flows.
Noncontrolling Interests. Effective January 1, 2009, we adopted authoritative guidance on
consolidation. This guidance amends the reporting requirements of consolidation for
noncontrolling interests in subsidiaries to improve the relevance, comparability and
transparency of the financial information disclosed. The adoption of this standard did not have
a material effect on our financial condition, results of operations or cash flows.
Derivative Instruments and Hedging Activities. Effective January 1, 2009, we adopted
authoritative guidance on derivatives and hedging, which requires enhanced disclosures on
derivative instruments and hedging activities. This guidance expands disclosures by adding
qualitative disclosures about our hedging objectives and strategies, fair value gains and losses,
and credit-risk-related contingent features in derivative agreements. The disclosures are
intended to provide an enhanced understanding of:
•
•
•
how and why we use derivative instruments;
how derivative instruments and related hedge items are accounted for; and
how derivative instruments and related hedged items affect our financial condition, results
of operations and cash flows.
The adoption and implementation of this standard did not have, and is not expected to have, a
material effect on our financial statement disclosures. The required disclosures are included in
Note 10, below.
Determining Whether Share-Based Payment Transactions are Participating
Securities. Effective January 1, 2009, we adopted authoritative guidance on earnings per
share. This guidance requires nonforfeitable rights to dividends or dividend equivalents on
unvested share-awards to be included in the computation of earnings per share under the
two-class method. The adoption of this standard did not have, and is not expected to have, a
material effect on our financial condition, results of operations or cash flows.
Fair Value Considerations. Effective for periods ending after June 15, 2009, we adopted
authoritative guidance on fair value measures and disclosures. This pronouncement provides
guidance and required disclosures, if necessary, to determine if the market for measuring our
financial instruments has significantly decreased in volume and level of activity. The adoption
of this standard did not have a material effect on our financial statement disclosures.
Subsequent Events. Effective for periods ending after June 15, 2009, we adopted authoritative
guidance on subsequent events. This guidance establishes principles and disclosure
requirements for events or transactions that occur after the balance sheet date but before the
financial statements are issued. As of February 26, 2010, we have evaluated events subsequent
to the balance sheet date. For subsequent events, see Note 12.
86
Plan Assets in Postretirement Benefit Plans. Effective for annual periods ending after
December 15, 2009, we adopted authoritative guidance on pension and other postretirement
benefits, which requires enhanced disclosures of plan assets in an employer’s defined benefit
pension or other postretirement benefit plans. The disclosures are intended to provide an
enhanced understanding of:
•
•
•
•
•
how investment allocation decisions are made;
the major categories of plan assets;
the inputs and valuation techniques used to measure the fair value of plan assets;
the effect of fair value measurements using significant unobservable inputs (Level 3 input
from accounting for fair value measures and disclosures) on changes in plan assets for the
period; and
significant concentration or risk within plan assets.
The adoption of this pronouncement did not have a material effect on our financial statement
disclosures.
Fair Value Disclosures. Effective for periods ending after December 15, 2009, we adopted
authoritative guidance on fair value measures and disclosures. This guidance requires
additional disclosures for significant transfers between levels in the fair value hierarchy,
enhanced disclosures for the level 3 rollforward table and more disaggregation of fair value
inputs. The adoption of this pronouncement did not have a material impact on our financial
statement disclosures.
Recent Accounting Pronouncements
Variable Interest Entity. In 2009, the Financial Accounting Standards Board (FASB) issued
authoritative guidance on variable interest entities. This guidance requires an analysis to
determine whether our variable interest provides us with a controlling financial interest in the
variable interest entity. It defines the primary beneficiary of the variable interest entity as the
entity having:
•
•
power to control the activities that most significantly impact the performance; and
the obligation to absorb losses or right to receive benefits from the entity that could
potentially be significant to the variable interest entity.
These changes are effective for the interim and annual reporting periods that begin after
November 15, 2009. We are evaluating the impact these updates will have on our investments
in variable interest entities. If consolidated, our variable interest entities could have a material
impact on our balance sheet, but it is not expected to materially impact our results of operations
or cash flows.
Plant and Property and Accrued Asset Removal Costs
Plant and property is stated at cost, including capitalized labor, materials and overhead (see
Note 9). In accordance with regulatory accounting, the cost of constructing utility plant and gas
storage assets generally includes an allowance for funds used during construction (AFUDC) or
capitalized interest. AFUDC represents the net financing cost during the period the funds are
used for construction purposes (see “Allowance for Funds Used During Construction,”
87
below). When gas storage assets under construction are expected to be subject to market based
rates, then the cost of construction will include capitalized interest in accordance with GAAP,
not regulatory AFUDC.
Our provision for depreciation of utility property is computed under the straight-line, age-life
method in accordance with external engineering studies and as approved by regulatory
authorities. The weighted average depreciation rate for plant in service was approximately 2.9
percent for the year ended December 31, 2009 and approximately 3.4 percent for the years
ended 2008 and 2007, reflecting the approximate average economic life of the property.
In accordance with long-standing industry practice, we accrue for future asset removal costs on
many long-lived assets through a charge to depreciation expense allowed in rates and
accumulate such amounts in regulatory liabilities. At the time removal costs are incurred,
accumulated depreciation is charged with the costs of removal and the book cost of the
asset. Our estimate of accumulated removal costs is based on rates using approved depreciation
studies. No gain or loss is recognized upon normal retirement. In the rate setting process, the
accrued asset removal costs are treated as a reduction to net rate base.
Allowance for Funds Used During Construction
Certain additions to utility plant include AFUDC, which represents the net cost of borrowed or
other funds used during construction and is calculated using actual current interest rates and
authorized rates for return on equity, if applicable. If borrowings are less than the total costs of
construction work in progress, then a composite rate of interest on all debt, shown as a
reduction to interest charges, and a return on equity funds, shown as other income, is used to
compute the AFUDC. While cash is not realized currently from AFUDC, it is realized in future
years through increased revenues from rate recovery resulting from higher rate base and higher
depreciation expense. Our composite AFUDC rates were 1.0 percent in 2009, 3.6 percent in
2008 and 5.4 percent in 2007.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents include cash on hand and
highly liquid temporary investments with original maturity dates of three months or less. At
December 31, 2008, outstanding checks of approximately $1.0 million were included within
accounts payable, but no such reclasses were required in 2009.
Revenue Recognition and Accrued Unbilled Revenues
Utility revenues, derived primarily from the sale and transportation of gas, are recognized when
the gas is delivered to and received by the customer. Revenues include accruals for gas
delivered but not yet billed to customers based on estimates of gas deliveries from meter
reading dates to month end (accrued unbilled revenues). Accrued unbilled revenues are
dependent upon a number of factors that require management’s judgment, including total gas
receipts and deliveries, customer use by billing cycle and weather. Accrued unbilled revenues
are reversed the following month when actual billings occur. Our accrued unbilled revenues at
December 31, 2009 and 2008 were $71.2 million and $102.7 million, respectively.
88
Utility operating revenues also include the recognition of a regulatory adjustment for income
taxes paid. This revenue adjustment reflects an OPUC rule whereby we are required to
implement a rate refund or a rate surcharge to utility customers. This automatic refund or
surcharge is accrued based on the estimated difference between income taxes paid and income
taxes authorized to be collected in rates for each tax year.
Non-utility revenues, derived primarily from gas storage business segment, are recognized
upon delivery of services to customers. Revenues from our asset optimization partner are
recognized over the life of the optimization contract for the guaranteed amount, and recognized
as earned for amounts above the guaranteed amount. See Note 2.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable consist primarily of amounts due for gas sales and transportation services
to core utility customers, plus amounts due for gas storage services and other miscellaneous
receivables. With respect to these trade receivables, including accrued unbilled revenues, we
establish an allowance for uncollectible accounts (allowance) based on the aging of receivables,
collection experience of current past due accounts including payment plans, and historical
trends of write-offs as a percent of revenues. With respect to large individual customer
receivables, a specific allowance is established and added to the general allowance 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 to be
uncollectible. Differences between our estimated allowance and actual write-offs will occur
based on changes in general economic conditions, customer credit issues and the level of
natural gas prices. Each quarter the allowance for uncollectible accounts is adjusted, as
necessary, based on the most current information available.
Inventories
Inventories, which consist primarily of natural gas in storage for the utility, are generally stated
at the lower of average cost or net realizable value. The regulatory treatment of gas inventories
provides for cost recovery in customer rates. All gas that is injected into storage is priced into
inventory based on actual purchase costs. All gas that is withdrawn from inventory is charged
to cost of gas during the current period at the weighted average cost of inventory. Material and
supplies inventories are stated at the lower of average cost or net realizable value.
Derivatives
In accordance with accounting for derivatives and hedges, we measure derivatives at fair value
and recognize them as either assets or liabilities on the balance sheet. Accounting for
derivatives and hedges requires that changes in the fair value of a derivative be recognized
currently in earnings unless specific 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 derivatives contracts
are approved by regulatory authorities for recovery or refund through customer rates.
Accordingly, the changes in fair value of these contracts are deferred as regulatory assets or
liabilities pursuant to regulatory accounting. Derivatives contracts entered into for core utility
customer requirements after the purchased gas adjustment (PGA) rate has been set are subject
to the PGA incentive sharing mechanism. Under our PGA sharing mechanism in effect
89
prior to November 1, 2008, 67 percent of the changes in fair value were deferred as regulatory
assets or liabilities and the remaining 33 percent was recorded to the income statement for
derivatives that do not qualify for hedge accounting, and to Other Comprehensive Income for
hedges that do qualify for hedge accounting. A modified PGA sharing mechanism was
approved in Oregon, effective on November 1, 2008, under which we are required to select, by
August 1 of each year, either an 80 percent deferral or 90 percent deferral of higher or lower
gas costs such that the impact on current earnings from the gas cost sharing is either 20 percent
or 10 percent, respectively. For the PGA year in Oregon beginning November 1, 2009, we
selected the 90 percent deferral of gas cost differences. For the PGA year in Oregon beginning
November 1, 2008, we selected the 80 percent deferral of gas cost differences. In Washington,
100 percent of our gas costs are deferred. See Note 10.
Our financial derivatives policies set forth the guidelines for using selected financial derivative
products to support prudent risk management strategies within designated parameters. Our
objective for using derivatives is to decrease the volatility of earnings and cash flows and to
prevent speculative risk. The use of derivatives is permitted only after the risk exposures have
been identified, are determined to exceed acceptable tolerance levels and are necessary to
support normal business activities. We do not enter into derivative instruments for trading
purposes and we believe that any increase in market risk created by holding derivatives should
be offset by the exposures they modify.
Fair Value
In accordance with fair value accounting, we use the following fair value hierarchy for
determining inputs for our pension plan assets and our derivative fair value measurements:
• Level 1: Valuation is based upon quoted prices for identical instruments traded in active
markets;
• Level 2: Valuation is based upon 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 that 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; and (g) credit spreads, as well as other relevant economic measures.
Revenue Taxes
We account for revenue-based taxes assessed by governmental entities as a separate cost
collected from customers for remittance to those governmental entities. Therefore, revenue
taxes are accounted for as a cost of sale and presented separately on the income statement.
90
Income Tax Expense
NW Natural and its wholly-owned subsidiaries file consolidated federal and state income tax
returns. Current income taxes are allocated based on each entity’s respective taxable income or
loss and investment tax credits as if each entity filed a separate return. We account for income
taxes in accordance with accounting standards for income taxes. Accounting for income taxes
requires recognition of deferred tax liabilities and assets for the future tax consequences of
events that have been included in the consolidated financial statements or tax returns. Under
this method, deferred tax liabilities and assets are determined based on the difference 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 (see Note 8).
Accounting for income taxes also requires recognition of deferred income tax assets and
liabilities for temporary differences where regulators prohibit deferred income tax treatment for
ratemaking purposes. We have recorded a deferred tax liability equivalent of $76.2 million and
$69.9 million at December 31, 2009 and 2008, respectively, to recognize future taxes payable
resulting from transactions that have previously been reflected in the financial statements for
these temporary differences. Regulatory assets or liabilities corresponding to such additional
deferred income tax assets or liabilities may be recorded to the extent we believe they will be
recoverable from or payable to customers through the ratemaking process. Pursuant to
regulatory accounting, a corresponding regulatory asset has been recorded which represents the
probable future revenue that will result from inclusion in rates charged to customers of taxes
which will be paid in the future. The probable future revenue to be recorded takes into
consideration the additional future taxes which will be generated by that revenue. Amounts
applicable to income taxes due from customers primarily represent differences between the
book and tax basis of net utility plant in service and actual removal costs incurred.
Deferred investment tax credits on utility plant additions and leveraged leases, which reduce
income taxes payable, are deferred for financial statement purposes and amortized over the life
of the related plant or lease.
Other Income and Expense—Net
Other income and expense—net consists of income from company-owned life insurance,
interest on deferred regulatory account balances and short-term debt cash investments, income
from equity investments, gain on sale of investments, non-operating expenses related to our
proposed pipeline project and other miscellaneous income and expense from merchandise sales,
rents, leases and other items.
Thousands
Gains from company-owned life insurance
Interest income
Income from equity investments
Net interest on deferred regulatory accounts
Gain on sale of investments
Other non-operating
Total other income and expense - net
91
2009
2008
2007
$ 3,416
211
1,329
2,051
45
(3,338)
$ 2,190
250
667
552
1,737
(1,650)
$ 1,939
537
130
84
1,544
(2,789)
$ 3,714
$ 3,746
$ 1,445
Earnings Per Share
Basic earnings per share are computed using the weighted average number of common shares
outstanding each year. Diluted earnings per share reflect the potential effects of the exercise of
stock options and other stock-based compensation. Diluted earnings per share are calculated as
follows:
Thousands, except per share amounts
Net income
2009
2008
2007
$75,122
$69,525
$74,497
Average common shares outstanding - basic
Effect on shares from stock options and other stock based compensation
26,511
65
26,438
156
26,821
174
Average common shares outstanding - diluted
Earnings per share of common stock - basic
Earnings per share of common stock - diluted
26,576
26,594
26,995
$
$
2.83
2.83
$
$
2.63
2.61
$
$
2.78
2.76
For the years ended December 31, 2009, 2008 and 2007, 2,142 shares, 1,248 shares and 442
shares, respectively, represent the number of stock options which were excluded from the
calculation of diluted earnings per share because the effect was antidilutive.
2.
CONSOLIDATED SUBSIDIARY OPERATIONS AND SEGMENT INFORMATION:
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 also refer to our
local gas distribution business as the “utility,” and our “gas storage” and “other” business
segments as “non-utility.” Our gas storage segment includes Gill Ranch, LLC (Gill Ranch), and
our “other” segment includes our equity investment in a natural gas transmission pipeline and
Financial Corporation.
Local Gas Distribution
Our local gas distribution segment is a regulated utility principally engaged in the purchase,
sale and delivery of natural gas, including 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, also approved
by the OPUC or WUTC. Approximately 90 percent of our customers are located in Oregon and
10 percent in Washington. On an annual basis, residential and commercial customers typically
account for 50 to 60 percent of our utility’s total volumes delivered and 80 to 90 percent of our
utility’s margin, while industrial customers account for 40 to 50 percent of volumes and 5 to 15
percent of margin. The remaining 10 percent or less of margin is derived from miscellaneous
services, gas cost savings and other regulatory charges.
92
Industrial customers 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. No individual customer or industry group accounts for a significant portion of our
utility revenues or margins.
Gas Storage
Our gas storage business segment includes natural gas storage services provided to interstate
and intrastate customers in the Pacific Northwest using underground gas storage and pipeline
facilities we own and operate. We also use an independent energy marketing company to
provide asset optimization services for the utility under a contractual arrangement, the results of
which are included in this business segment. For each of the years ended December 31, 2009,
2008 and 2007, this business segment derived a majority of its revenues from our share of asset
optimization services performed by an independent energy marketing company and from multi-
year gas storage contracts we have with less than 10 customers who contract for service at our
Mist storage facility. Five storage customers currently account for over 90 percent of our
existing contract storage capacity, with the largest customer accounting for about half of that
total capacity. These five customers have contracts that expire at various dates through April
2017.
Results for the gas storage segment include revenues, net of amounts shared with core utility
customers, from a contract with an independent energy marketing company that optimizes the
use of our utility assets when not needed to serve core utility customers. In Oregon, we retain
80 percent of the pre-tax income from these services when the costs of the capacity have not
been included in utility rates, or 33 percent of the pre-tax income when the costs have been
included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a
deferred regulatory account for crediting back to core utility customers. We have a similar
sharing mechanism in Washington for revenue derived from storage and third party
optimization.
In 2007, we announced a joint project with Pacific Gas & Electric Company (PG&E) to
develop an underground natural gas storage facility at Gill Ranch near Fresno, California. We
formed a wholly-owned subsidiary of NW Natural, Gill Ranch, to develop and operate the
facility. Gill Ranch owns 75 percent of the project, and PG&E owns 25 percent. As of
December 31, 2009 and 2008, total assets at Gill Ranch were $116.3 million and $13.2 million,
respectively.
While our primary focus for growing the gas storage business is on the current development
at Gill Ranch, we also plan to continue expanding our interstate storage facilities at Mist,
Oregon. In 2009, we completed three-dimensional seismic surveys and initiated engineering
work for a new 3 to 4 Bcf expansion at Mist. Pending successful marketing efforts, we expect
to move forward with the project and would target a 2011 in-service date. The total project cost
estimates are between $45 million and $55 million. This estimated cost range includes the
development of a second compression station and a pipeline gathering system at Mist that
will enable future storage expansions. The total Mist gas storage assets, excluding amounts
allocated to our utility, was $58.4 million in 2009 and $56.5 million in 2008.
93
Other
We have non-utility investments and other business activities which are aggregated and
reported as a business segment called “other.” Although in the aggregate these investments and
activities are not material, we identify and report them as a stand-alone segment based on our
current organizational structure and decision-making process because these business
investments and activities are not specifically related to our utility or gas storage segments.
This segment primarily consists of an equity method investment in a joint venture to build and
operate an interstate gas transmission pipeline in Oregon (Palomar) and other pipeline assets in
Financial Corporation. This segment also includes some operating and non-operating revenues
and expenses of the parent company that cannot be allocated to utility operations. As of
December 31, 2009 and 2008, our investment balance in Palomar, which is net after tax of
amounts received in 2009 from a shipper credit support agreement, was $14.1 million and
$14.2 million, respectively. The total cost estimate for the entire 217-mile pipeline, if
constructed, is estimated to be between $700 million and $800 million, with our current 50
percent share estimated at between $350 million and $400 million. Palomar has executed
binding precedent agreements with shippers, including our own utility, for a majority of the
current design capacity on the pipeline. These agreements also provide commitments of credit
support to the project. Our maximum loss exposure related to Palomar at December 31, 2009
would be limited to our investment balance less any commitments or credit support recovered
from third parties.
In 2008, we sold our investment in a Boeing 737-300 aircraft for approximately $6.8 million
total including accrued rents. We purchased the aircraft in 1987 and leased it to Continental
Airlines for the entire time it was owned by NW Natural. As a result of the sale, we recognized
an after-tax gain of $1.1 million in 2008. In 2007, we sold our limited partnership interest in
two wind power electric generation projects in California for $2.1 million, which resulted in an
after-tax gain of $0.9 million.
Financial Corporation holds certain non-utility financial investments, but its assets primarily
consist of an active, wholly-owned subsidiary which owns a 10 percent interest in an 18-mile
interstate natural gas pipeline. Financial Corporation’s total assets were $1.4 million and $1.3
million at December 31, 2009 and 2008, respectively.
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Segment Information Summary
The following table presents summary financial information about the reportable segments for
the years ended 2009, 2008 and 2007. Inter-segment transactions are insignificant.
Thousands
2009
Net operating revenues
Depreciation and amortization
Income from operations
Net income
Total assets at Dec. 31, 2009
2008
Net operating revenues
Depreciation and amortization
Income from operations
Net income
Total assets at Dec. 31, 2008
2007
Net operating revenues
Depreciation and amortization
Income from operations
Net income
3.
CAPITAL STOCK:
Common Stock
Utility
Gas Storage
Other
Total
$ 357,005
61,472
142,228
65,960
2,205,313
$ 337,596
70,690
128,957
58,739
2,289,601
$ 19,738
1,342
16,442
8,923
173,648
$ 18,459
1,469
14,943
8,363
72,073
$
144
-
46
239
20,291
$ 376,887
62,814
158,716
75,122
2,399,252
$
160
-
136
2,423
16,478
$ 356,215
72,159
144,036
69,525
2,378,152
$ 351,875
67,410
140,434
64,938
$ 16,999
933
14,481
8,454
$
168
-
8
1,105
$ 369,042
68,343
154,923
74,497
As of December 31, 2009 and 2008, we had 100 million common shares authorized.
As of December 31, 2009, we had reserved for issuances 194,918 shares of common stock
under the Employee Stock Purchase Plan (ESPP), 480,959 shares under our Dividend
Reinvestment and Direct Stock Purchase Plan and 1,295,585 shares under our Restated Stock
Option Plan (Restated SOP).
Stock Repurchase Program
We have a share repurchase program for our common stock under which we purchase shares on
the open market or through privately negotiated transactions. We currently have Board
authorization through May 2010 to repurchase up to an aggregate of 2.8 million shares, or up to
$100.0 million. No shares of common stock were repurchased pursuant to this program in 2009
or 2008. Since inception in 2000, a total of 2.1 million shares have been repurchased at a total
cost of $83.3 million.
95
Summary of Changes in Common Stock
The following table shows the changes in the number of shares of our common stock issued
and outstanding for the years 2009, 2008 and 2007:
Balance, Dec. 31, 2006
Sales to employees
Exercise of stock options - net
Repurchase
Balance, Dec. 31, 2007
Sales to employees
Exercise of stock options - net
Balance, Dec. 31, 2008
Sales to employees
Exercise of stock options - net
Balance, Dec. 31, 2009
4.
STOCK-BASED COMPENSATION:
Shares
27,283,741
21,373
75,850
(973,616)
26,407,348
19,500
74,340
26,501,188
8,615
23,225
26,533,028
We have several stock-based compensation plans, including: a the Long-Term Incentive Plan
(LTIP); a Restated SOP; an ESPP; and a Non-Employee Directors Stock Compensation Plan
(NEDSCP). These plans are designed to promote stock ownership in NW Natural by employees
and officers and, in the case of the NEDSCP, by non-employee directors.
Long-Term Incentive Plan. The LTIP is intended to provide a flexible, competitive
compensation program for eligible officers and key employees. An aggregate of 500,000 shares
of common stock was authorized for grants under the LTIP as stock bonus, restricted stock or
performance-based stock awards. Shares awarded under the LTIP may be purchased on the
open market.
At December 31, 2009, 230,858 shares of common stock were available for award under the
LTIP, assuming that performance based grants currently outstanding are awarded at the target
level. The LTIP stock awards are compensatory awards for which compensation expense is
recognized based on the fair value of performance-based stock awards, or a pro rata
amortization over the vesting period for the outstanding awards of restricted stock.
Performance-based Stock Awards. Since the LTIP’s inception in 2001, performance-
based stock awards have been granted annually based on three-year performance periods. At
December 31, 2009, certain performance-based stock award measures had been achieved for
the 2007-09 award period. Accordingly, participants are estimated to receive 16,784 shares of
common stock and 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. At December 31, 2008 and 2007, we awarded 58,244
and 66,666 shares of common stock, respectively, for the 2006-08 and 2005-07 award periods,
plus 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. During 2009, we expensed $0.5 million related to the 2007-09
96
performance-based stock award, and on a cumulative basis we accrued a total $1.5 million
related to the 2007-09 performance period. In 2008 and 2007, we expensed $0.5 million and
$0.6 million, respectively, related to the 2006-08 and 2005-07 performance-based stock award
periods, and on a cumulative basis we accrued a total of $2.0 million for both 2006-08 and
2005-07 performance periods.
At December 31, 2009, the aggregate number of performance-based shares granted and
outstanding at the threshold, target and maximum levels were as follows:
Year
Awarded
2008
2009
Performance
Period
2008-10
2009-11
Total
Performance Share Awards Outstanding
Threshold
6,935
7,410
14,345
Target
36,500
39,000
75,500
Maximum
73,000
78,000
151,000
The threshold level estimates future payout assuming the minimum award payable is achieved
for each component of the formula in the LTIP. For each of these performance periods, awards
will be based on total shareholder return relative to a peer group of gas distribution companies
over the three-year performance period and on performance results achieved relative to specific
core and non-core strategies. Compensation expense is recognized in accordance with
accounting for stock compensation, based on performance levels achieved and an estimated fair
value using a Black-Scholes or binomial model. The weighted-average per share grant date fair
value of unvested shares at December 31, 2009 and 2008 was $19.40 and $20.95, respectively.
The weighted-average per share grant date fair value of shares vested during the year was
$27.85 and granted during the year was $18.74. In 2009 and 2008, under these LTIP grants we
accrued $1.0 million and expensed $0.9 million, while in 2007 we accrued $2.7 million and
expensed $2.3 million.
Restricted Stock Awards. Restricted stock awards also have been granted under the
LTIP. A restricted stock award was granted in 2004 consisting of 5,000 shares that vested
ratably over the period 2005-09, and a restricted stock award was granted in 2006 consisting of
6,500 shares that vested ratably over the period 2007-09. As of December 31, 2009, all
restricted stock awards were fully vested and paid out.
Restated Stock Option Plan. A total of 2,400,000 shares of common stock were reserved for
issuance under the Restated SOP. Options under the Restated SOP may be granted only to
officers and key employees designated by a committee of our Board of Directors. All options
are granted at an option price equal to the closing market price on the date of grant and may be
exercised for a period up to 10 years and 7 days from the date of grant. Option holders may
exchange shares they have owned for at least six months, at the current market price, to
purchase shares at the option price.
97
The fair value of each stock option is estimated on the grant date using the Black-Scholes
option pricing model with the following weighted average assumptions and outcomes:
Risk-free interest rate
Expected life (in years)
Expected market price volatility factor
Expected dividend yield
Forfeiture rate
Weighted average grant date fair value
February
2009
September
2008
February
2008
February
2007
2.0%
4.7
22.5%
3.8%
3.7%
$ 5.46
3.0%
4.7
18.4%
2.9%
3.9%
$ 7.05
2.8%
4.7
18.4%
3.5%
3.8%
$ 5.34
4.7%
6.2
17.2%
3.2%
4.4%
$ 7.66
The expected life of the 2009 and 2008 grants was calculated based on our actual experience
with previously exercised option grants. The simplified formula for “plain vanilla” options was
used in 2007 to determine the expected life as defined and permitted by stock option accounting
guidance. The risk-free interest rate was based on the implied yield currently available on U.S.
Treasury zero-coupon issues with a life equal to the expected life of the options. Historical data
was used to estimate the volatility factor, measured on a daily basis, for a period equal to the
duration of the expected life of the option awards. The dividend yield was based on
management’s current estimate for future dividend payouts at the time of grant. We expense the
total cost of stock option awards granted to retirement eligible employees at the date of grant in
accordance with stock option accounting guidance and the retirement vesting provisions of our
option agreements.
Information regarding the Restated SOP activity for the three years ended December 31, 2009
is summarized as follows:
Price per Share
Option
Shares
Range
Weighted -
Average
Exercise Price
Intrinsic
Value
(In millions)
Balance outstanding, Dec. 31, 2006
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2007
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2008
Granted
Exercised
Forfeited
$20.25 - 38.30
44.48
334,000
100,600
(75,850) 20.25 - 34.95
(1,000)
44.48
20.25 - 44.48
357,750
119,050
43.29 - 51.09
(74,340) 20.25 - 44.48
(6,050) 26.30 - 44.48
396,410
111,750
(23,225) 20.25 - 34.95
20.25 - 51.09
41.15
-
n/a
$31.14
44.48
28.73
44.48
35.36
43.62
30.70
41.56
38.62
41.15
30.92
n/a
Balance outstanding, Dec. 31, 2009
484,935
$26.30 - 51.09
$39.57
$
n/a
n/a
1.4
n/a
4.8
n/a
1.3
n/a
2.3
n/a
0.3
n/a
2.7
Shares available for grant
Dec. 31, 2007
Dec. 31, 2008
Dec. 31, 2009
98
1,035,400
922,400
810,650
In the year ended December 31, 2009, cash of $1.1 million was received for option shares
exercised and a $0.2 million related tax benefit was realized. For the 12 months ended
December 31, 2009, 2008 and 2007, the total fair value of options that vested was $0.4 million,
$0.3 million and $0.2 million, respectively.
The following table summarizes additional information about stock options outstanding and
exercisable at December 31, 2009:
Outstanding
Exercisable
Range of Exercise Prices
$26.30 - 51.09
Stock
Options
484,935
Weighted-
Average
Remaining
Life in Years
Stock
Options
(In millions)
Aggregate
Intrinsic
Value
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Life in Years
7.19
254,948
$2.0
$37.39
6.10
As of December 31, 2009, there was $0.7 million of unrecognized compensation cost related to
the unvested portion of outstanding stock option awards expected to be recognized over a
period extending through 2012.
Employee Stock Purchase Plan. The ESPP allows employees to purchase common stock at 85
percent 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 $24,000 worth of stock
through payroll deductions over a 12-month period.
In accordance with accounting for stock compensation, 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:
Thousands
2009
2008
2007
Operations and maintenance expense, for stock-based compensation
Income tax benefit
$1,434 $1,598
(623)
(559)
$ 2,986
(1,165)
Net stock-based compensation effect on net income
$ 875 $ 975
$ 1,821
Amounts capitalized for stock-based compensation
$ 229
$ 282
$
479
Non-Employee Directors Stock Compensation Plan. In February 2004, the NEDSCP was
amended to permit non-employee directors to receive stock awards either in cash or in
stock. As a result of modifications to the directors’ compensation arrangements, the NEDSCP
was further amended in September 2004 to eliminate any further awards, either in cash or
stock, on and after January 1, 2005.
Prior to the September 2004 amendment to the NEDSCP, if non-employee directors elected to
receive their awards in stock, approximately $100,000 worth of common stock was awarded
upon joining the Board. These stock awards were subject to vesting and to restrictions on sale
and transferability. The shares vested in monthly installments over the five calendar years
following the award. On January 1 of each year following the initial award, non-employee
directors who elected to receive their awards in stock were awarded an additional $20,000
worth of restricted stock, which vested in monthly installments in the fifth year following the
award (after the previous award had fully vested). We hold the certificates for the restricted
shares until the non-employee director ceases to be a director. Participants receive all dividends
99
and have full voting rights on both vested and unvested shares. All awards vest immediately
upon the death of a director or upon a change in control of the Company. Any unvested shares
are considered to be unearned compensation, and thus are forfeited if the recipient ceases to be
a director. The shares were purchased in the open market at the time of the award. At
December 31, 2009, all shares were fully vested.
5.
COST AND FAIR VALUE BASIS OF LONG-TERM DEBT:
The issuance of first mortgage debt, including secured medium-term notes (MTNs), 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.
The maturities on the long-term debt outstanding for each of the 12-month periods through
December 31, 2014 amount to: $35 million in 2010; $10 million in 2011; $40 million in 2012;
none in 2013; and $60 million in 2014.
Thousands
Medium-Term Notes
First Mortgage Bonds:
6.50% Series B due 2008
4.11% Series B due 2010
7.45% Series B due 2010
6.665% Series B due 2011
7.13% Series B due 2012
8.26% Series B due 2014
3.95% Series B due 2014 (1)
4.70% Series B due 2015
5.15% Series B due 2016
7.00% Series B due 2017
6.60% Series B due 2018
8.31% Series B due 2019
7.63% Series B due 2019
5.37% Series B due 2020 (2)
9.05% Series A due 2021
5.62% Series B due 2023
7.72% Series B due 2025
6.52% Series B due 2025
7.05% Series B due 2026
7.00% Series B due 2027
6.65% Series B due 2027 (3)
6.65% Series B due 2028
7.74% Series B due 2030
7.85% Series B due 2030
5.82% Series B due 2032
5.66% Series B due 2033
5.25% Series B due 2035
Less long-term debt due within one year
Total long-term debt
2009
2008
2007
$
-
10,000
25,000
10,000
40,000
10,000
50,000
40,000
25,000
40,000
22,000
10,000
20,000
75,000
10,000
40,000
20,000
10,000
20,000
20,000
19,700
10,000
20,000
10,000
30,000
40,000
10,000
$
-
10,000
25,000
10,000
40,000
10,000
-
40,000
25,000
40,000
22,000
10,000
20,000
-
10,000
40,000
20,000
10,000
20,000
20,000
20,000
10,000
20,000
10,000
30,000
40,000
10,000
$
5,000
10,000
25,000
10,000
40,000
10,000
-
40,000
25,000
40,000
22,000
10,000
20,000
-
10,000
40,000
20,000
10,000
20,000
20,000
20,000
10,000
20,000
10,000
30,000
40,000
10,000
636,700
35,000
512,000
-
517,000
5,000
$601,700
$512,000
$512,000
(1) Issued in July 2009
(2) Issued in March 2009
(3) In November 2009 one investor in our 6.65 percent secured MTNs due 2027 exercised its right under a one-time
put option to redeem $0.3 million of the $20 million outstanding. This one-time put option has now expired, and
the remaining $19.7 million remaining principal outstanding is expected to be redeemed at maturity in
November 2027.
100
In March 2009, we issued $75 million of 5.37 percent secured MTNs due February 1, 2020, and
in July 2009, we issued another $50 million of secured MTNs with an interest rate of 3.95
percent and a maturity of July 15, 2014. Proceeds from these MTNs were used to fund utility
capital expenditures, to redeem utility short-term debt, and to provide utility working capital for
general corporate purposes.
According to fair value accounting, we elected to not adjust our long-term debt balance to fair
value. The following table provides an estimate of the fair value of our long-term debt, using
market prices in effect on the valuation date. Interest rates for debt with similar credit ratings,
terms and remaining maturities were used to estimate fair value for long-term debt issues.
Thousands
Long-term debt including amounts due
within one year
Dec. 31, 2009
Dec. 31, 2008
Carrying
Amount
Estimated
Fair Value
Carrying
Amount
Estimated
Fair Value
$636,700
$707,755
$512,000
$505,828
6.
SHORT-TERM DEBT AND CREDIT FACILITIES:
Our primary source of short-term funds is from the sale of commercial paper and bank loans. In
addition to issuing commercial paper to meet seasonal working capital requirements, including
the financing of gas purchases, gas inventories and accounts receivable, 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. Our current bank loans at Gill
Ranch are supported by cash collateral. At December 31, 2009 and 2008, the amounts and
average interest rates of commercial paper debt outstanding were $69.8 million at 0.3 percent
and $248.0 million at 1.6 percent, respectively, while bank loans outstanding were $32.2
million at 0.8 percent and $0, respectively.
In March 2009, Gill Ranch entered into a cash collateralized credit facility for up to $40 million
that has been extended until September 30, 2010. As of December 31, 2009, Gill Ranch had
$32.2 million of borrowings outstanding included under short-term debt on the balance sheet,
with a corresponding cash collateral amount included under restricted cash – current on the
balance sheet. The effective interest rate on Gill Ranch’s credit facility is 0.8 percent.
We have a multi-year $250 million syndicated credit agreement, pursuant to which we may
extend commitments for additional one-year periods subject to lender approval. We extended
commitments under this credit agreement to May 31, 2013. The credit agreement allows us to
request increases in the total commitment amount from time to time, up to a maximum amount
of $400 million, and to replace any lenders who decline to extend the terms of the credit
agreement. The credit agreement also permits the issuance of letters of credit in an aggregate
amount up to the applicable total borrowing commitment. Any principal and unpaid interest
owed on borrowings under the credit agreement are due and payable on or before the expiration
date, which is May 31, 2013. Additionally, we had two committed bilateral bank lines of credit
totaling $30 million in effect as of November 2008, of which $15 million expired December 31,
2008 and $15 million expired February 27, 2009. There were no outstanding balances under the
syndicated credit and no letters of credit issued or outstanding at December 31, 2009 and 2008.
101
The syndicated 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 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 syndicated credit agreement also requires us to maintain a consolidated indebtedness to
total capitalization ratio of 70 percent 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, 2009 and
2008, with a consolidated indebtedness to total capitalization ratio of 52.8 percent, and 54.7
percent, respectively.
7.
PENSION AND OTHER POSTRETIREMENT BENEFITS:
We maintain two qualified non-contributory defined benefit pension plans, several
non-qualified supplemental pension plans for eligible executive officers and certain key
employees, and other postretirement employee benefit plans. Only the two qualified defined
benefit pension plans have plan assets, which are held in a qualified trust to fund retirement
benefits. Effective January 1, 2007 and 2010, the qualified defined benefit retirement plans for
non-union and union employees, respectively, were closed to new participants. Instead,
non-union and union employees hired or re-hired after December 31, 2006 and 2009,
respectively, are currently provided an enhanced Retirement K Savings Plan (RKSP) benefit.
Also, effective January 1, 2007, the postretirement Welfare Benefit Plan for Non-Bargaining
Unit Employees was closed to new participants after December 31, 2006.
102
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 over
the three-year period ended December 31, 2009, and a summary of the funded status and
amounts recognized in the consolidated balance sheets using measurement dates of
December 31, 2009, 2008 and 2007:
Thousands
Reconciliation of change in benefit
obligation:
Obligation at January 1
Service cost
Interest cost
Benefits paid
Plan amendments
Change in assumptions
Net actuarial (gain) or loss
Liability transfer
Postretirement Benefits
Pension Benefits
2008
2009
2007
2009
Other Benefits
2008
2007
$ 281,127 $ 260,561 $269,410 $ 23,863 $ 22,186 $ 22,436
505
1,293
(1,299)
-
(645)
(104)
-
8,708
16,057
(15,924)
3,887
(23,916)
2,339
-
6,402
17,948
(17,149)
(3,921)
14,265
9,319
-
6,141
17,373
(16,247)
5
9,146
4,291
(143)
521
1,403
(1,259)
-
839
173
-
522
1,568
(1,428)
-
1,099
(883)
-
Obligation at December 31
$ 307,991 $ 281,127 $260,561 $ 24,741 $ 23,863 $ 22,186
Reconciliation of change in plan
assets:
Fair value of plan assets at
January 1
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets at
$ 163,115 $ 241,418 $236,518 $
(63,267)
1,211
(16,247)
19,658
1,166
(15,924)
28,641
26,705
(17,149)
- $
-
1,428
(1,428)
- $
-
1,259
(1,259)
-
-
1,298
(1,298)
December 31
$ 201,312 $ 163,115 $241,418 $
- $
- $
-
Funded status at December 31
$(106,679) $(118,012) $ (19,143) $(24,741) $(23,863) $(22,186)
Our qualified defined benefit pension plans had an aggregate projected benefit obligation of
$285.2 million, $261.5 million and $243.1 million at December 31, 2009, 2008 and 2007,
respectively, and the fair value of plan assets was $201.3 million, $163.1 million and $241.4
million, respectively. Changes in valuation assumptions impact our projected benefit
obligations. Benefit obligations at December 31, 2009 increased $19.1 million due to a
decrease in our discount rate assumptions and increased by $4.2 million due to changes in other
assumptions. The projected benefit obligations at December 31, 2008 increased $7.4 million
due to a decrease in the discount rate assumptions and increased by $5.0 million due to
updating our mortality table. The combination of investment returns and future cash
contributions by the company is expected to provide sufficient funds to cover all future benefit
obligations of the plans.
103
The following table provides amounts amortized from accumulated other comprehensive
income (AOCI) or regulatory assets to net periodic benefit cost during 2009, 2008, and 2007:
Thousands
Net periodic benefit costs:
Actuarial loss
Prior service cost
Transition obligation
Total
Regulatory Asset Amortization
Pension Benefits
2008
2009
2007
Other Postretirement Benefits
2008
2007
2009
AOCI Amortization
Pension Benefits
2008
2009
2007
$6,189
1,260
-
$
-
1,290
-
$1,910
1,017
-
$7,449
$1,290
$2,927
$ 17
197
411
$625
$
-
197
411
$608
$
4
197
411
$612
$449
(37)
-
$398
(37)
-
$245
(36)
-
$412
$361
$209
In 2010, an estimated $7.5 million, consisting of $6.4 million of actuarial losses, $0.7 million of
prior service cost and $0.4 million transition obligation will be amortized from regulatory assets
to net periodic benefit costs and $0.6 million consisting of $0.6 million of actuarial losses
and negligible prior service cost will be amortized from AOCI.
An assumed discount rate was determined independently for each pension plan and other
postretirement benefit plans based on the Citigroup Above Median Curve (discount rate curve)
using high quality bonds (i.e. rated AA- or higher by S&P or Aa3 or higher by Moody’s). The
discount rate curve was then applied to match the estimated cash flows to reflect the timing and
amount of expected future benefit payments for these plans.
The expected long-term rate of return on plan assets was developed as a weighted average of
the expected earnings 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 plans’ assets are invested and the target asset allocation for plan assets.
Our investment strategy and policies for the qualified pension plan assets held in the
Retirement Trust Fund were approved by our retirement committee, which is composed of
senior management employees with the assistance of an 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 and portfolio risk. All
investments are expected to satisfy the requirements of the rule of prudent investments as set
forth under the Employee Retirement Income Security Act of 1974. The approved asset classes
are cash and short-term investments, fixed income, common stock and convertible securities,
absolute and real return strategies, real estate and investments in our common stock. Plan assets
may be invested in separately managed accounts or in commingled or mutual funds. Re-
balancing will take place periodically as needed, or when significant cash flows occur, in order
to maintain the allocation of assets within the stated target ranges. Our expected long-term rate
of return is based upon historical index returns by asset class, adjusted by a factor based on our
historical return experience and active portfolio management by professional investment
managers. The Retirement Trust Fund is not currently invested in any NW Natural securities.
104
Our pension plan asset allocation at December 31, 2009 and 2008, and the target allocation and
expected long-term rate of return by asset category, are as follows:
Asset Category
US Large Cap Equity
US Small/Mid Cap Equity
Non-US Equity
Emerging Markets
Fixed Income
Real Estate
Absolute Return Strategy
Real Return Strategy
Cash and cash equivalents
Weighted Average
Percentage of
Plan Assets
Dec. 31,
2009
2008
17.5% 14.3%
13.8% 9.6%
19.4% 17.9%
0.5% 0.0%
18.2% 21.2%
6.5% 11.3%
15.0% 18.9%
6.8% 6.8%
2.3% 0.0%
Target
Allocation
Expected Long-term
Rate of Return
18%
12%
18%
5%
17%
8%
15%
7%
0%
8.25%
9.25%
8.85%
10.50%
5.25%
7.00%
8.00%
7.00%
-
8.25%
Our non-qualified supplemental defined benefit pension plans’ benefit obligations were $22.8
million, $19.6 million and $17.5 million at December 31, 2009, 2008 and 2007,
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 AOCI
under common stock equity, net of tax, until they are amortized as a component of net periodic
benefit cost. Although these are unfunded plans with no plan assets due to their nature as
non-qualified plans, we indirectly fund our obligations with company- and trust-owned life
insurance.
Our plans for providing postretirement benefits other than pensions also are unfunded plans, but
are subject to regulatory deferral. The gains and losses, prior service costs and transition assets
or obligations for these plans were recognized as a regulatory asset. The accumulated
postretirement benefit obligation for those plans was $24.7 million, $23.9 million and $22.2
million at December 31, 2009, 2008 and 2007, respectively.
Net periodic benefit cost consists of service costs, interest costs, the amortization of actuarial
gains and losses, the expected returns on plan assets and, in part, on a market-related valuation
of assets. The market-related valuation reflects differences between expected returns and actual
investment returns, which are recognized over a three-year period or less from the year in
which they occur, thereby reducing year-to-year net periodic benefit cost volatility.
105
The following tables provide the components of net periodic benefit cost for the qualified and
non-qualified pension and other postretirement benefit plans for the years ended December 31,
2009, 2008 and 2007 and the assumptions used in measuring these costs and benefit
obligations:
Thousands
Service cost
Interest cost
Expected return on plan assets
Amortization of transition
obligations
Amortization of prior service costs
Amortization of net actuarial loss
Pension Benefits
2008
2009
2007
Other Postretirement
Benefits
2008
2009
2007
$
6,402 $
17,948
(15,696)
6,141 $
17,373
(19,087)
8,708 $
16,057
(18,490)
522 $
521 $
1,568
-
1,403
-
505
1,293
-
-
1,223
6,810
19
1,253
385
-
1,188
2,123
411
197
-
411
197
-
411
197
25
Net periodic benefit cost
$
16,687 $
6,084 $
9,586 $ 2,698 $ 2,532 $ 2,431
Assumptions for net periodic benefit
cost:
Weighted-average discount rate
Rate of increase in compensation
Expected long-term rate of return
Assumptions for funded status:
Weighted-average discount rate
Rate of increase in compensation
Expected long-term rate of return
6.60%
6.79%
3.25%-5.0% 3.5%-5.0% 4.0%-5.0%
8.25%
8.25%
8.25%
6.03% 7.12% 6.56% 5.91%
n/a
n/a
n/a
n/a
n/a
n/a
6.01%
6.60%
3.25%-5.0% 3.5%-5.0% 4.0%-5.0%
8.25%
8.25%
8.25%
6.79% 5.78% 7.12% 6.56%
n/a
n/a
n/a
n/a
n/a
n/a
The assumed annual increase in trend rates used in measuring other postretirement benefits as
of December 31, 2009 were 9 percent for medical and 11 percent for prescription
drugs. Medical costs were assumed to decrease gradually each year to a rate of 5.0 percent by
2017, while prescription drug costs were assumed to decrease gradually each year to a rate of
5.0 percent by 2021.
Assumed health care cost trend rates can have a significant effect on the amounts reported for
the health care plans. A one percentage point change in assumed health care cost trend rates
would have the following effects:
Thousands
Effect on total of service and interest cost components of net periodic
postretirement health care benefit cost
Effect on health care cost component of the accumulated postretirement benefit
obligation
1%
Increase
1%
Decrease
$ 79
$ (68)
$713
$(625)
106
The following table provides information regarding employer contributions and benefit
payments for the two qualified pension plans, the non-qualified pension plans and the other
postretirement benefit plans for the years ended December 31, 2009 and 2008, and estimated
future payments:
Thousands
Employer Contributions by Plan Year
Pension Benefits
Other Benefits
2008
2009
2010 (estimated)
Benefit Payments
2007
2008
2009
Estimated Future Payments
2010
2011
2012
2013
2014
2015-2019
$
1,645
27,137
6,154
$ 15,924
16,247
17,149
$ 21,120
17,974
18,639
19,065
19,631
112,487
$1,259
1,428
1,921
$1,298
1,259
1,428
$1,921
1,969
1,906
1,920
1,990
9,773
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 new funding requirements for defined
benefit plans. The Act establishes a 100 percent funding target for plan years beginning after
December 31, 2008. However, a delayed effective date of 2011 may apply if the pension plan
meets the funding targets of 94 percent in 2009 and 96 percent in 2010. Our qualified defined
benefit pension plans are currently underfunded by $83.9 million at December 31, 2009, and
we expect to make contributions during 2010 of approximately $10 million.
Our RKSP is a qualified defined contribution plan under Internal Revenue Code
Section 401(k). We also have non-qualified deferred compensation plans for eligible officers
and senior managers. These plans are designed to enhance the retirement program of employees
and to assist them in strengthening their financial security by providing an incentive to save and
invest regularly. Our matching contributions to these plans totaled $2.1 million in 2009, $2.1
million in 2008, and $1.9 million in 2007. The RKSP includes an Employee Stock Ownership
Plan. In addition, we make contributions on behalf of each union employee to the Western
States Office and Professional Employees Pension Fund, a multi-employer plan. Our
contributions to the Western States Plan totaled $0.4 million in 2009, 2008 and 2007.
Fair Value
Following 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
our custodian uses the funds market value. The custodian provides the market values for
investments directly owned.
107
US Large Cap Equity: Level 1 assets are valued at the closing price reported on the active
market on which the individual security is traded. This asset class includes investments
primarily in U.S. common stocks.
US Small/Mid Cap Equity: Level 1 assets are valued at the closing price reported on the active
market on which the individual security is traded. Level 2 assets are valued based on
information provided by the plan’s investment custodians. The financial statements of the
commingled fund are audited annually by independent accountants. Values for such funds are
stated at estimated fair values, which have been determined based on the unit values of the
funds. Unit values are determined by the bank sponsoring such funds by dividing the fund’s net
assets at fair value by its units outstanding at the valuation date. This asset class includes
investments primarily in U.S. common stocks.
Non-US Equity: Level 1 assets are valued at the closing price reported on the active market on
which the individual security is traded. Level 2 assets are valued based on information provided
by the plan’s investment custodians. The financial statements of the commingled fund are
audited annually by independent accountants. Values for such funds are stated at estimated fair
values, which have been determined based on the unit values of the funds. Unit values are
determined by the bank sponsoring such funds by dividing the fund’s net assets at fair value by
its units outstanding at the valuation date. This asset class includes investments primarily in
foreign equity common stocks.
Emerging Market Equity: Level 1 assets are valued at the net asset value of the shares held by
the plan at year end. This asset class includes investments primarily in emerging market
common stocks.
Fixed Income: Level 1 assets are valued at the net asset value of the shares held by the plan at
year end. This asset class includes investments primarily in investment grade debt and fixed
income securities.
Real Estate Funds: Level 3 assets are valued based on the interest held by the plan, for which
fair values of the underlying investments are subject to appraisal as directed by the funds’
management. This asset class includes a real estate fund that invests directly in real estate. The
underlying properties held in the funds are appraised utilizing the following approaches: the
cost approach (the current cost of replacing the real estate less deterioration and functional and
economic obsolescence), the income approach (the ability of the underlying properties to
generate net rental income) and the comparable sales approach (recent sales of comparable real
estate in the same market). The plan’s ability to redeem these investments is subject to certain
restrictions and cash availability. The real estate fund we are invested in normally provides for
a quarterly distribution subject to 45 days advance notice of withdrawal. However, this fund is
currently restricting withdrawals and has not made any distributions over the last six calendar
quarters. No firm estimate can be made at this time when withdrawal requests will be honored.
As of December 31, 2009, we have not submitted a withdrawal request.
Absolute Return Strategy: Level 2 assets are valued based on information provided by the
Plan’s investment custodians. The financial statements of the partnerships are audited annually
by independent accountants, with the value of the underlying investments based on the
estimated fair value of the various holdings in the portfolio as reported in the financial
statements at net asset value. This asset class includes a hedge fund of funds. Our investment
108
normally provides for a quarterly distribution subject to 95 days advance notice of
withdrawal. Currently there are no restrictions on withdrawal requests, and as of December 31,
2009 we have not submitted a withdrawal request.
Real Return Strategy: Level 1 assets are valued at the net asset value of the shares held by the
plan at year end. This asset class includes an investment in a broad range of assets and
strategies primarily including fixed income and equity securities, along with commodities.
Cash and Cash Equivalents: Level 2 assets are valued at the net asset value of the shares held
by the plan at year end. This asset class includes a money market mutual fund.
The preceding valuation methods may produce a fair value calculation that is not indicative of
net realizable value or reflective of future fair values. Furthermore, 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 financial
instruments could result in a different fair value measurement at the reporting date.
Our Plan’s assets are invested in various investment securities. 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 that such changes
could materially affect our investment account balances and the amounts reported as Plan assets
available for benefits payments.
The following table presents the Plan assets, including outstanding receivables and liabilities,
of the Retirement Trust as of December 31, 2009.
Investments, in thousands
US Large Cap Equity
US Small/Mid Cap Equity
Non-US Equity
Emerging Markets Equity
Fixed Income
Real Estate
Absolute Return Strategy
Real 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
Total investment in Retirement Trust
Level 1
Level 2 Level 3
Total
$ 35,266
-
25,395
1,021
36,682
-
-
13,592
-
$
-
27,953
13,456
-
-
-
30,097
-
4,614
$
-
-
-
-
-
12,936
-
-
-
$ 35,266
27,953
38,851
1,021
36,682
12,936
30,097
13,592
4,614
$111,956
$76,120
$12,936
$201,012
$
$
$
200
400
600
300
$201,312
109
Level 3 Investments
The following table presents the beginning balance, activity and ending balance of Level 3
investments that have their fair values established using significant unobservable inputs as of
December 31, 2009:
Thousands
January 1, 2009 balance
Transfers into level 3
Transfers out of level 3
Total gains or (losses):
Included in earnings
Included in other comprehensive income or regulatory accounts
Purchases, sales, issuances and settlements:
Purchases
Issuances
Sales
Settlements
December 31, 2009 balance
8.
INCOME TAXES:
Level 3
Assets
Real estate
Funds
$18,494
-
-
-
(5,558)
-
-
-
-
$12,936
A reconciliation between income taxes calculated at the statutory federal tax rate and the
provision for income taxes reflected in the consolidated financial statements is as follows:
Thousands, except percentages
Income taxes at federal statutory rate
Increase (decrease):
Current state income tax, net of federal tax benefit
Amortization of investment and energy tax credits
Differences required to be flowed-through by regulatory
commissions
Gains on company and trust-owned life insurance
Other - net
Total provision for income taxes
Federal statutory tax rate
Increase (decrease):
Current state income tax, net of federal tax benefit
Amortization of investment and energy tax credits
Differences required to be flowed-through by regulatory
commissions
Gains on company and trust-owned life insurance
Other - net
Effective tax rate
2009
2008
2007
$42,627
$38,571
$41,495
5,568
(593)
4,100
(646)
4,566
(881)
(116)
(1,195)
380
(704)
(767)
124
(704)
(679)
263
$46,671
$40,678
$44,060
35.0%
35.0%
35.0%
4.6%
-0.5%
-0.1%
-1.0%
0.3%
3.7%
-0.6%
-0.6%
-0.7%
0.1%
3.9%
-0.7%
-0.6%
-0.6%
0.2%
38.3%
36.9%
37.2%
110
The provision (benefit) for current and deferred income taxes consists of the following:
Thousands
Current
Federal
State
Deferred
Federal
State
Total provision for income taxes
Total income taxes paid
2009
2008
2007
$ 6,221
2,300
$ (7,970) $41,086
7,764
(437)
8,521
(8,407)
48,850
31,937
6,213
42,862
6,223
(4,107)
(683)
38,150
49,085
(4,790)
$46,671
$40,678
$44,060
$10,000
$12,300
$56,215
The following table summarizes the total provision (benefit) for income taxes for the regulated
utility and non-utility business segments for the three years ended December 31:
Thousands
Regulated utility:
Current
Deferred
Deferred investment and energy tax credits
Non-utility business segments:
Current
Deferred
Deferred investment and energy tax credits
Total provision for income taxes
2009
2008
2007
$
871
40,829
(593)
$(13,034) $43,587
(3,856)
(713)
48,790
(646)
41,107
35,110
39,018
7,650
(2,086)
-
5,564
4,627
941
-
5,568
5,263
(53)
(168)
5,042
$46,671
$ 40,678
$44,060
111
The following table summarizes the tax effect of significant items comprising our deferred
income tax accounts for the two years ended December 31:
Thousands
Deferred tax liabilities:
Plant and property
Regulatory adjustment for income taxes paid
Regulatory income tax assets
Regulatory liabilities
Non-regulated deferred tax liabilities
Total
Deferred tax assets:
Regulatory assets
Unfunded pension and postretirement obligations
Non-regulated deferred tax assets
Loss and credit carryforwards
Total
Deferred income tax liabilities - net
Deferred investment tax credits
Deferred income taxes and investment tax credits
2009
2008
$231,768
2,169
72,721
13,506
-
$183,462
2,374
69,948
8,145
426
320,164
264,355
(14,436)
(3,925)
(2,860)
-
(21,221)
(4,335)
(2,709)
(471)
(1,557)
(9,072)
298,943
1,955
255,283
2,548
$300,898
$257,831
We have determined that we are more likely than not to realize all recorded deferred tax assets
as of December 31, 2009.
The following is a reconciliation of the change in our deferred tax balance for the year ended
December 31, 2009:
Thousands
Deferred tax expense, above, including investment tax credit
Increase in differences required to be flowed-through
Decrease in minimum pension liability included in AOCI
Decrease in deferred taxes associated with asset held for sale
Decrease in deferred investment tax credits
Change in deferred income tax accounts
2009
$38,743
6,292
(1,215)
(160)
(593)
$43,067
We calculate our deferred tax assets and liabilities according to accounting guidance on income
taxes, whereby deferred income taxes are generally determined based on the difference between
the financial statement and tax bases of assets and liabilities using enacted tax rates in effect in
the years in which the differences are expected to reverse. Deferred tax provisions are not
recorded in the income statement for certain temporary differences where regulators require
that we flow through deferred income tax benefits or expenses in the utility ratemaking process.
In February 2009, the American Recovery and Reinvestment Act of 2009 (Act) was signed into
law. This Act provides a 50 percent bonus tax depreciation deduction for qualified property
acquired or constructed and placed in service in 2009. The extra 50 percent depreciation
deduction in the first year is an acceleration of depreciation deductions that otherwise would
have been taken in the later years of an asset’s recovery period. The accelerated depreciation
112
provisions provided by the Act expired at December 31, 2009. We estimate that the bonus
depreciation deduction will defer the payment of approximately $12.9 million of federal
income taxes during 2009 to future periods.
In December 2008, we filed an application with the Internal Revenue Service (IRS) requesting
a change in our tax accounting method to expense routine repair and maintenance costs for gas
pipelines that are currently being capitalized and depreciated for book purposes. The IRS
consented to our request in August 2009, and we recognized a tax deduction of approximately
$59 million on our 2008 tax return as a result of this method change, which resulted in a federal
refund of approximately $21 million during the fourth quarter of 2009.
For the year ended December 31, 2008, we reported an estimated net operating loss (NOL) for
federal and Oregon income tax purposes of $19.2 million and $23.8 million, respectively,
primarily due to the effects of accelerated tax depreciation provided by the Economic Stimulus
Act. As a result of the change in our tax accounting method for repair and maintenance costs
discussed above as well as our increased pension contribution, our NOL for federal and Oregon
income tax purposes was $89.0 million and $87.2 million on our 2008 federal and Oregon tax
returns, respectively. The federal NOL was carried back to 2006 for a refund of taxes paid in
prior years, while the Oregon NOL has been carried forward to reduce current and future
taxable income. We anticipate that we will be able to use all loss carryforwards in future years.
The 2008 Oregon NOL would expire in 2023 if not used in earlier years.
Uncertain tax positions are accounted for in accordance with accounting standards that require
management’s assessment of the expected treatment of a tax position taken in a filed tax return,
or planned to be taken in a future tax return, that has not been reflected in measuring income
tax expense for financial reporting purposes. Until such positions are sustained by the taxing
authorities, we would not recognize the tax benefits resulting from such positions and would
report the tax effect as a liability in the Company’s consolidated balance sheet. As of
December 31, 2009, we had no uncertain tax positions.
An IRS examination of the 2006 through 2008 consolidated federal income tax returns
commenced during the fourth quarter of 2009. The IRS completed its examination of the 2002
through 2004 audit cycle in the second quarter of 2006 and completion of the 2006 through
2008 federal income tax returns is expected during 2010.
Interest and penalties related to any future income tax deficiencies will be recorded within
income tax expense in the consolidated statements of income.
113
9.
PROPERTY AND INVESTMENTS:
The following table sets forth the major classifications of our utility plant and accumulated
depreciation at December 31:
Thousands, except percentages
Transmission and distribution
Utility storage
General
Intangible and other
Gas stored long-term
Utility plant in service
Construction work in progress
Total utility plant
Less accumulated depreciation
Utility plant-net
2009
2008
Weighted
Average
Depreciation
Rate
2.7%
2.2%
5.0%
6.0%
0.0%
2.9%
Weighted
Average
Depreciation
Rate
3.3%
2.5%
3.2%
9.0%
0.0%
3.4%
Amount
$1,810,747
116,035
100,838
77,650
14,133
2,119,403
23,585
2,142,988
(659,123)
$1,483,865
Amount
$1,862,837
119,477
104,880
86,848
14,134
2,188,176
27,936
2,216,112
(682,060)
$1,534,052
Accumulated depreciation does not include the accumulated provision for asset removal costs
of $238.8 million and $223.7 million at December 31, 2009 and 2008, respectively. These
accrued asset removal costs are reflected on the balance sheets as regulatory liabilities (see
Note 1, “Plant and Property and Accrued Asset Removal Costs”).
The following table summarizes our investments in non-utility plant at December 31:
Thousands, except percentages
Non-utility storage
Other
Non-utility plant in service
Construction work in progress
Total non-utility plant
Less accumulated depreciation
Non-utility plant - net
2009
Weighted
Average
Depreciation
Rate
2.2%
Amount
$ 60,792
5,292
66,084
80,538
146,622
(10,540)
$136,082
2008
Weighted
Average
Depreciation
Rate
2.5%
Amount
$60,515
4,886
65,401
9,105
74,506
(9,314)
$65,192
The OPUC and WUTC approved our filed depreciation study and our request to change the
amortization of our regulatory tax asset account balance on pre-1981 plant. These approvals
specifically authorized the implementation of new depreciation rates in Oregon and
Washington, with a corresponding decrease to customer billing rates effective January 1,
2009. The new regulatory tax amortization schedule on pre-1981 assets, with a corresponding
increase to customer rates, became effective January 1, 2009 in Washington and November 1,
2009 in Oregon. The implementation of the new rates decreases depreciation expense and
114
increases income tax expense, both of which are offset on an annualized basis by a
corresponding change in utility operating revenues. FERC also approved the application of
these new depreciation rates for our interstate gas storage assets in May 2009, and the new rates
were made effective as of January 1, 2009. Due to the depreciation rate decreases, total
depreciation and amortization expense in 2009 decreased by $9.3 million, or 13 percent.
The following table summarizes other long-term investments, including financial investments
in life insurance policies accounted for at fair value and equity investments in certain
partnerships and joint ventures accounted for under the equity or cost methods, at
December 31:
Thousands
Life insurance investments
Note receivable
Investments in gas pipeline joint ventures
Other
Total other investments
2009
2008
$49,327
609
15,154
2,275
$35,427
518
15,214
2,072
$67,365
$53,231
Life Insurance Investment. We have invested in key person life insurance contracts to provide
an indirect funding vehicle for certain long-term employee benefit plan liabilities. The amount
in the above table is reported as cash surrender value, net of policy loans.
Investments in Gas Pipeline Joint Ventures. A wholly-owned subsidiary of Financial
Corporation, KB Pipeline Company, owns a 10 percent interest in an 18-mile interstate natural
gas pipeline. In 2007, we also entered into an agreement with TransCanada’s Gas Transmission
Northwest (GTN) for the purpose of designing, permitting, constructing and owning a gas
pipeline that would connect GTN’s interstate transmission pipeline to our local gas distribution
system to serve markets in Oregon and the western United States. As of December 31, 2009,
our investment balance in Palomar was $14.1 million, primarily related to planning and
permitting.
Variable Interest Entities. According to authoritative guidance on variable interest entities, we
determine whether consolidation is required for entities known as variable interest entities over
which control is achieved through means other than voting rights or for entities that do not have
sufficient equity investment at risk to permit financing its activities without additional financial
support. We currently have a variable interest in Palomar, which is accounted for as an equity
investment and not consolidated as it was determined we are not the primary beneficiary. See
Note 2.
10.
DERIVATIVES:
We have entered into swaps, options and combinations of options for the purchase of natural
gas and for the forecasted issuance of fixed-rate debt that qualify as derivative instruments
under accounting for derivative instruments and hedging activities. We primarily use derivative
financial instruments to manage commodity prices related to our natural gas requirements and
to manage interest rate risk exposure related to our long-term debt issuances.
In the normal course of business, we enter into indexed-price physical forward natural gas
commodity purchase (gas supply) contracts to meet the requirements of core utility
115
customers. We also enter into financial derivatives, up to prescribed limits, to hedge price
variability related to the physical contracts. Derivatives entered into prudently for future gas
years prior to our annual PGA filing receive regulatory deferral treatment. Derivative contracts
entered into for core utility customer requirements after the annual PGA rate was set on
November 1, 2009, are subject to the PGA incentive sharing mechanism, whereby 90 percent of
the changes in fair value are deferred as regulatory assets or liabilities and the remaining 10
percent is recorded to the income statement for contracts not qualifying for hedge accounting
and to other comprehensive income for contracts qualifying for hedge accounting.
Certain natural gas purchases from Canadian suppliers are payable in Canadian dollars,
including both commodity and demand charges, which expose us to adverse changes in foreign
currency rates. Foreign currency forward contracts are used to hedge the fluctuation in foreign
currency exchange rates for our commodity and commodity-related demand charges paid in
Canadian dollars. Foreign currency contracts for commodity costs are purchased on a
month-to-month basis because the Canadian cost is priced at the average noon-day exchange
rate for each month. Foreign currency contracts for demand costs have terms ranging up to 12
months. The gains and losses on the shorter-term currency contracts for commodity costs are
recognized immediately in cost of gas. The gains and losses on the currency contracts for
demand charges are not recognized in current income because they are subject to a regulatory
deferral tariff and, as such, are recorded as a regulatory asset or liability. These forward
contracts qualify for cash flow hedge accounting treatment under accounting for derivatives and
hedges. The mark-to-market adjustment at December 31, 2009 was an unrealized gain of $0.3
million. This unrealized gain is subject to regulatory deferral and, as such, was recorded as a
derivative asset, which is offset by recording a corresponding amount to a regulatory liability
account.
The unrealized mark-to-market value at December 31, 2009 for all derivative contracts
outstanding was a net loss of $15.5 million consisting of the following: a $15.8 million
unrealized loss on natural gas commodity hedge and derivative contracts, and a $0.3 million
unrealized gain on the foreign exchange forward contracts.
Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial
statement treatment of each specific derivative. As of December 31, 2009, all of our derivatives
were effective economic hedges and either qualified or were expected to qualify for regulatory
deferral or hedge accounting treatment. We use the hypothetical derivative method under
accounting for derivatives and hedges to determine the hedge effectiveness of interest rate
swaps. The ineffectiveness for all other derivative contracts is determined using the dollar
offset method. The effectiveness test applied to financial derivatives is dependent on the type of
derivative and its use. There was no ineffectiveness as of December 31, 2009.
We do most of our hedging for the upcoming gas year prior to the start of that gas year and
include the hedge prices in our annual PGA filing. We hedge our anticipated year-round sales
volumes based on normal weather. We entered the 2009-10 gas year (November 1, 2009—
October 31, 2010) hedged at a targeted level of approximately 75 percent, 60 percent
financially and 15 percent physically through gas storage. Additionally we entered the gas year
between 10 and 15 percent financially hedged for the 2010-11 and 2011-12 gas years. We have
Board authorization to hedge price risk for up to 100 percent of our gas supplies for the next
gas contract year.
116
The remaining 2009-10 gas year volumes hedged at December 31, 2009 include 522.7 million
therms of financial hedges and 66.1 million therms of gas storage hedges.
The following table discloses the balance sheet presentation of our derivative instruments as of
December 31, 2009 and 2008:
Thousands
Assets: (1)
Natural gas commodity
Foreign exchange
Total
Liabilities: (2)
Natural gas commodity
Interest rate
Foreign exchange
Total
Fair Value of Derivative Instruments
2009
Current Non-Current
2008
Current Non-Current
$ 6,214
290
$ 6,504
$19,643
-
-
$19,643
$ 843
-
$ 843
$3,193
-
-
$3,193
$
$
4,592
-
4,592
$136,290
-
445
$
$
146
-
146
$ 9,734
11,912
-
$136,735
$21,646
(1)
(2)
Unrealized fair value gains are classified under current- or non-current assets as fair value of
non-trading derivatives.
Unrealized fair value losses are classified under current- or non-current liabilities as fair value of
non-trading derivatives.
The following table discloses the income statement presentation for the unrealized gains and
losses from our derivative instruments for the years ended December 31, 2009 and 2008. It also
illustrates that all of our derivative instruments are related to regulated utility operations and
derivative gains and losses are deferred to balance sheet accounts in accordance with regulatory
accounting.
Thousands
Cost of sales
Other comprehensive income
(loss)
Gain (loss) recognized in income
(ineffective portion)
Less:
Amounts deferred to regulatory
accounts on balance sheet
Total impact on earnings
2009
Natural gas
commodity (1)
Foreign
exchange (3)
Natural gas
commodity (1)
2008
Interest
rate (2)
Foreign
exchange (3)
$(15,779)
$
-
$(141,286)
$
-
$
-
-
-
290
-
-
-
(10,375)
(445)
(1,537)
-
15,779
$
-
(290)
$
-
141,286
11,912
445
$
-
$
-
$
-
(1)
(2)
(3)
Unrealized gain (loss) from natural gas commodity hedge contracts is recorded in cost of sales
and reclassified to regulatory deferral accounts on the balance sheet.
Unrealized gain (loss) from interest rate hedge contracts is recorded in other comprehensive
income (loss) and reclassified to regulatory deferral accounts on the balance sheet.
Unrealized gain (loss) from foreign exchange forward purchase contracts is recorded in other
comprehensive income (loss), and reclassified to regulatory deferral accounts on the balance
sheet.
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The gross derivative liability excludes the netting of collateral. We had no collateral posted
with our counterparties at December 31, 2009. We attempt to minimize our potential exposure
to collateral calls by our counterparties to manage our liquidity risk. Based on our current credit
rating, most counterparties allow us credit limits that range from $15 million to $25 million
before collateral postings are required. We measure our collateral call exposure under credit
support agreements, which generally contain credit limits based on our credit ratings. We also
could be subject to collateral call exposure where we have agreed to provide adequate
assurance, which is not specific as to amount of credit limit allowed, but could potentially
require additional collateral in the event of a material adverse change. Estimated collateral calls
are included in the table below. The following table discloses the estimates with and without
potential adequate assurance calls, using outstanding derivative instruments at December 31,
2009, based on current gas prices and with various credit rating scenarios for NW Natural.
Thousands
(Current
Ratings)
A+/A3 BBB+/Baa1 BBB/Baa2 BBB-/Baa3 Speculative
With Adequate Assurance Calls
Without Adequate Assurance Calls
$-
$-
$-
$-
$-
$-
$-
$-
$7,760
$7,760
During 2009 we realized net losses of $187.9 million from the settlement of natural gas hedge
contracts, which was recorded as increases to the cost of gas, compared to realized net gains of
$35.1 million during 2008, which was recorded as decreases to the cost of gas. The currency
exchange rate in all foreign currency forward purchase contracts is included in our purchased
cost of gas at settlement; therefore, no gain or loss is recorded from the settlement of those
contracts. We settled our $50 million interest rate swap in March 2009 concurrent with our
issuance of the underlying long-term debt and realized a $10.1 million effective hedge loss,
which will be amortized to interest expense over the term of the debt.
We are exposed to derivative credit risk primarily through securing pay-fixed natural gas
commodity swaps to hedge the risk of price increases for our natural gas purchases 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 in order for a counterparty to meet our credit requirements.
Our financial derivatives policy requires counterparties to have an 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
on derivatives. We utilize 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 utilize a Monte-Carlo simulation model to
estimate the change in credit and liquidity risk from the volatility of natural gas prices. We use the
results of the model to establish at-risk trading limits. The duration of our credit risk for all
outstanding derivatives currently does not extend beyond October 31, 2012.
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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, but we would expect such
loss to be eligible for regulatory deferral and rate recovery, subject to prudency review. All of
our existing counterparties currently have investment-grade credit ratings.
Fair Value
In accordance with fair value accounting, we include nonperformance 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. Our assessment of nonperformance 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, 2009.
The following table provides the fair value hierarchy of our derivative assets and liabilities as
of December 31, 2009 and 2008:
Thousands
Hierarchy
Level 1
Level 2
Level 3
Fair Value Measurements
Description of Derivative Inputs
Quoted prices in active markets
Significant other observable inputs
Significant unobservable inputs
Fair Value, net
$
-
(15,489)
-
$(15,489)
11.
COMMITMENTS AND CONTINGENCIES:
Lease Commitments
We lease land, buildings and equipment under agreements that expire in various years through
2095. Rental expense under operating leases was $5.3 million, $4.7 million and $4.6 million for
the years ended December 31, 2009, 2008 and 2007, respectively. The table below reflects the
future minimum lease payments due under non-cancelable leases at December 31, 2009. Such
payments total $45.0 million for operating leases. The net present value of payments on capital
leases less imputed interest was $1.0 million. These commitments relate principally to the lease
of our office headquarters, underground gas storage facilities, vehicles and computer
equipment.
Thousands
Operating leases
Capital leases
2010
2011
2012
2013
2014
Later
years
$4,162
582
$4,155
269
$4,279
95
$4,317
16
$4,641
-
$23,423
-
Minimum lease payments
$4,744
$4,424
$4,374
$4,333
$4,641
$23,423
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
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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. The
aggregate amounts of these agreements were as follows at December 31, 2009:
Thousands
2010
2011
2012
2013
2014
Thereafter
Total
Less: Amount representing interest
Total at present value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$145,305
37,819
23,640
16,741
13,951
-
237,456
5,370
$ 86,064
74,966
54,910
47,425
23,554
268,553
555,472
145,559
$4,157
3,464
-
-
-
-
7,621
63
$232,086
$409,913
$7,558
Our total payments of fixed charges under capacity purchase agreements in 2009, 2008 and
2007 were $84.6 million, $85.7 million and $90.1 million, respectively. Included in the
amounts were reductions for capacity release sales of $4.2 million for 2009, $5.0 million for
2008 and $5.3 million for 2007. 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
We own, or previously owned, properties that may require environmental remediation or
action. We accrue all material loss contingencies relating to these properties that we believe to
be probable of assertion and reasonably estimable. We continue to study the extent of our
potential environmental liabilities, but due to the numerous uncertainties surrounding the course
of environmental remediation and the preliminary nature of several environmental site
investigations, the range of potential loss beyond the amounts currently accrued, and the
probabilities thereof, cannot be reasonably estimated. We regularly review our remediation
liability for each site where we may be exposed to remediation responsibilities. The costs of
environmental remediation are difficult to estimate. A number of steps are involved in each
environmental remediation effort, including site investigations, remediation, operations and
maintenance, monitoring and site closure. Each of these steps may, over time, involve a number
of alternative actions, each of which can change the course of the effort. Many of these steps
are dependent upon the approval and direction of federal and state environmental
regulators. The policies, determinations and directions of the regulators may develop and
change over time and different regulators may take different positions on the various steps,
creating further uncertainty as to the timing and scope of remediation activities. In certain
cases, in addition to us, there are a number of other potentially responsible parties, each of
which, in proceedings and negotiations with other potentially responsible parties and regulators,
may influence the course of the remediation effort. The allocation of liabilities among the
potentially responsible parties is often subject to dispute and can be highly uncertain. The
120
events giving rise to environmental liabilities often occurred many decades ago, which
complicates the determination of allocating liabilities among potentially responsible
parties. Site investigations and remediation efforts often develop slowly over many years. In
addition, disputes may arise between potentially responsible parties and regulators as to the
severity of particular environmental matters and what remediation efforts are
appropriate. These disputes could lead to adversarial administrative proceedings or litigation,
with uncertain outcomes.
To the extent reasonably estimable, we estimate the costs of environmental liabilities using
current 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. Unless there is a better estimate within this range of probable
cost, we record the liability at the lower end of this range. It is likely that changes in these
estimates will occur throughout the remediation process for each of these sites due to
uncertainty concerning our responsibility, the complexity of environmental laws and
regulations and the selection of compliance alternatives. The status of each of the sites currently
under investigation is provided below.
Gasco site. We own property in Multnomah County, Oregon that is the site of a former gas
manufacturing plant that was closed in 1956 (the Gasco site). The Gasco site has been under
investigation by us for environmental contamination under the Oregon Department of
Environmental Quality’s (ODEQ) Voluntary Clean-Up Program. In June 2003, we filed a
Feasibility Scoping Plan and an Ecological and Human Health Risk Assessment with the
ODEQ, which outlined a range of remedial alternatives for the most contaminated portion of
the Gasco site. In May 2007, we completed a revised Upland Remediation Investigation Report
and submitted it to the ODEQ for review. In November 2007 we submitted a Focused
Feasiblity Study to ODEQ for groundwater source control which ODEQ conditionally
approved in March 2008. During the third quarter of 2009, we signed an Order on Consent with
the Environmental Protection Agency (EPA) which requires the design of a final remedial
action for the Gasco site sediments. During 2009, our net liability increased $33.4 million,
primarily based on the current baseline methodology for potential remediation for the new
sediments project. We have a net liability accrued of $53.5 million at December 31, 2009 for
the Gasco site, which is estimated at the low end of the range of potential liability because no
amount within the range is considered to be more likely than another and the high end of the
range cannot reasonably be estimated.
Siltronic site. We previously owned property adjacent to the Gasco site that now is the location
of a manufacturing plant owned by Siltronic Corporation (the Siltronic site). We are currently
implementing an investigation of manufactured gas plant wastes on the uplands at this site for
the ODEQ. The net liability accrued at December 31, 2009 for the Siltronic site is $1.2 million,
which is at the low end of the range of potential liability because no amount within the range is
considered to be more likely than another and the high end of the range cannot reasonably be
estimated.
Portland Harbor site. In 1998, the ODEQ and the EPA completed a study of sediments in a
5.5-mile segment of the Willamette River (Portland Harbor) that includes the area adjacent to
the Gasco and Siltronic sites. The Portland Harbor site was listed by the EPA as a Superfund
site in 2000 and we were notified that we were a potentially responsible party. We then joined
with other potentially responsible parties, referred to as the Lower Willamette Group, to fund
121
environmental studies in the Portland Harbor. Subsequently, the EPA approved a Programmatic
Work Plan, Field Sampling Plan and Quality Assurance Project Plan for the Portland Harbor
Remedial Investigation/Feasibility Study (RI/FS), completion of which is currently expected in
2010. The EPA and the Lower Willamette Group are conducting focused studies on
approximately nine miles of the lower Willamette River, including the 5.5-mile segment
previously studied by the EPA. In 2008, we received a revised estimate and updated our
estimate for additional expenditures related to RI/FS development and environmental
remediation. In August 2008, we signed a cooperative agreement to participate in a phased
natural resource damage assessment, with the intent to identify what, if any, additional
information is necessary to estimate further liabilities sufficient to support an early restoration-
based settlement of natural resource damage claims. As of December 31, 2009, we have a net
liability accrued of $8.9 million for this site, which is at the low end of the range of the
potential liability because no amount within the range is considered to be more likely than
another and the high end of the range cannot reasonably be estimated.
In April 2004, we entered into an Administrative Order on Consent providing for early action
removal of a deposit of tar in the river sediments adjacent to the Gasco site. We completed the
removal of the tar deposit in the Portland Harbor in October 2005, and on November 5, 2005
the EPA approved the completed project. The total cost of removal, including technical work,
oversight, consultant fees, legal fees and ongoing monitoring, was about $9.9 million. To date,
we have paid $9.4 million on work related to the removal of the tar deposit. As of
December 31, 2009, we have a net liability accrued of $ 0.5 million for our estimate of ongoing
costs related to the tar deposit removal.
Central Service Center site. In 2006, we received notice from the ODEQ that our Central
Service Center in southeast Portland (the Central Service Center site) was assigned a high
priority for further environmental investigation. Previously there were three manufactured gas
storage tanks on the premises. The ODEQ believes there could be site contamination associated
with releases of condensate from stored manufactured gas as a result of historic gas handling
practices. In the early 1990s, we excavated waste piles and much of the contaminated surface
soils and removed accessible waste from some of the abandoned piping. In early 2007, we
received notice that this site was added to the ODEQ’s list of sites where releases of hazardous
substances have been confirmed and its list where additional investigation or cleanup is
necessary. We are currently performing an environmental investigation of the property with the
ODEQ’s Independent Cleanup Pathway. As of December 31, 2009, we have recorded an
estimated liability of $0.5 million for investigation at this site. The estimate is at the low end of
the range of potential liability because no amount within the range is considered to be more
likely than another and the high end of the range cannot reasonably be estimated.
Front Street site. The Front Street site was the former location of a gas manufacturing plant we
operated. Although it is outside the geographic scope of the current Portland Harbor site
sediment studies, the EPA directed the Lower Willamette Group to collect a series of surface
and subsurface sediment samples off the river bank adjacent to where that facility was located.
Based on the results of that sampling, the EPA notified the Lower Willamette Group that
additional sampling would be required. As the Front Street site is upstream from the Portland
Harbor site, the EPA agreed that it could be managed separately from the Portland Harbor site
under ODEQ authority. As of December 31, 2009, we accrued an estimated liability of $0.5
million for the study of the site, which will include investigation of sediments and provide a
122
report of historical upland activities. The estimate is at the low end of the range of potential
liability because no amount within the range is considered to be more likely than another and
the high end of the range cannot reasonably be estimated.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Accrued Liabilities Relating to Environmental Sites. The following table summarizes the
accrued liabilities relating to environmental sites at December 31, 2009 and 2008:
Thousands
Gasco
Siltronic
Portland Harbor
Central Service Center
Front Street
Other
Total
Current Liabilities
2008
2009
$ 9,841
653
2,114
5
72
-
$12,685
$6,012
682
277
-
-
-
$6,971
Non-Current Liabilities
2009
$43,659
593
7,272
511
436
123
$52,594
2008
$14,071
332
13,642
526
294
80
$28,945
Regulatory and Insurance Recovery for Environmental Costs. In May 2003, the OPUC
approved our request to defer unreimbursed environmental costs associated with certain named
sites, including those described above. Beginning in 2006, the OPUC authorized us to accrue
interest on deferred environmental cost balances, subject to an annual demonstration that we
have maximized our insurance recovery or made substantial progress in securing insurance
recovery for unrecovered environmental expenses. Through a series of extensions, this
authorization has been extended through January 2010. We have requested another extension
through January 2011, and that request is currently pending.
On a cumulative basis, we have recognized a total of $101.4 million for environmental costs,
including legal, investigation, monitoring and remediation costs. Of this total, $36.1 million has
been spent to date and $65.3 million is recorded as an outstanding liability. At December 31,
2009, we had a regulatory asset of $106.0 million, which includes $36.7 million of total paid
expenditures to date, $59.8 million for additional environmental costs expected to be paid in the
future and accrued interest of $9.5 million. We believe the recovery of these deferred charges is
probable through the regulatory process. We intend to pursue recovery of an insurance
receivable and environmental regulatory deferrals from insurance carriers under our general
liability insurance policies, and the regulatory asset will be reduced by the amount of any
corresponding insurance recoveries. We consider insurance recovery of most of our
environmental costs probable based on a combination of factors including: a review of the
terms of our insurance policies; the financial condition of the insurance companies providing
coverage; a review of successful claims filed by other utilities with similar gas manufacturing
facilities; and Oregon law that allows an insured party to seek recovery of “all sums” from one
insurance company. We have initiated settlement discussions with a majority of our insurers. In
the event that settlements cannot be reached, we may pursue other legal remedies. We continue
to anticipate that our overall insurance recovery effort will extend over several years.
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As such we have classified our regulatory assets for environmental cost deferrals as
non-current. The following table summarizes the non-current regulatory assets relating to
environmental sites at December 31, 2009 and 2008:
Thousands
Gasco
Siltronic
Portland Harbor
Central Service Center
Front Street
Other
Total
Legal Proceedings
Non-Current Regulatory Assets
2009
2008
$ 69,607
2,974
31,500
550
910
507
$106,048
$30,707
2,327
31,791
545
338
396
$66,104
We are subject to claims and litigation arising in the ordinary course of business. Although the
final outcome of any of these legal proceedings, including the matter described below, cannot
be predicted with certainty, we do not expect that the ultimate disposition of any of these
matters will have a material adverse 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 (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 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 and discovery
is ongoing. We do not expect that the ultimate disposition of this matter will have a material
adverse effect on our financial condition, results of operations or cash flows.
12.
SUBSEQUENT EVENTS:
We have been involved in litigation with the Oregon Department of Revenue (ODOR) over
whether natural gas inventories and appliance inventories held for resale are required to be
taxed as personal property. This was appealed to and presented before the Oregon Supreme
Court in 2009. In January 2010, the Oregon Supreme Court unanimously ruled in our favor,
stating that these inventories were exempt from property tax. The ODOR has until March 11,
2010 to file a Motion for Reconsideration with the Oregon Supreme Court. We are entitled to a
refund of approximately $5.0 million, plus accrued interest, for property taxes paid on gas
inventories beginning with the 2002-03 tax year and appliance inventories beginning with the
2005-06 tax year. We will recognize this gain as income in 2010.
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NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Thousands, except per share amounts
2009
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2008
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
Quarter ended
March 31
June 30
Sept. 30 Dec. 31
Total
$437,355 $149,060 $116,854 $309,442 $1,012,711
376,887
48,626
142,639
75,122
(6,733)
47,363
(0.25)
1.79
(0.25)
1.78
119,703
31,406
1.19
1.18
65,919
3,086
0.12
0.12
2.83(1)
2.83(1)
$387,694 $191,254 $109,702 $349,205 $1,037,855
356,215
43,549
132,423
(10,120)
43,168
69,525
(0.38)
1.63
(0.38)
1.63
117,671
33,180
1.25
1.25
62,572
3,297
0.12
0.12
2.63(1)
2.61(1)
(1)
Quarterly earnings (loss) per share are based upon the average number of common shares outstanding
during each quarter. Because the average number of shares outstanding has changed in each quarter
shown, the sum of quarterly earnings (loss) per share may not equal earnings per share for the year.
Variations in earnings between quarterly periods are due primarily to the seasonal nature of our business.
125
NORTHWEST NATURAL GAS COMPANY
SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
COLUMN A
COLUMN B
Balance at
beginning
of
period
Thousands (year ended Dec. 31)
2009
Reserves deducted in balance
sheet from assets to which they apply:
COLUMN C
Additions
COLUMN D COLUMN E
Deductions
Charged to
costs
and expenses
Charged to
other
accounts
Net
Write-offs
Balance
at end
of
period
Allowance for uncollectible accounts
$2,927
$4,201
$-
$4,003
$3,125
2008
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
$2,890
$3,145
$-
$3,108
$2,927
2007
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
$3,033
$2,978
$-
$3,121
$2,890
126
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 December 31, 2009, 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
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, 2009 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 9A.
Management’s Report on Internal Control Over Financial Reporting and the Report of Independent
Registered Public Accounting Firm appear under Item 8.
ITEM 9B. OTHER INFORMATION
None.
127
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information concerning our Board of Directors, its Committees and the Audit Committee
financial expert contained in NW Natural’s definitive Proxy Statement for the May 27, 2010 Annual
Meeting of Shareholders is hereby incorporated by reference. The information concerning
“Section 16(a) Beneficial Ownership Reporting Compliance” and “Corporate Governance” contained
in our definitive Proxy Statement for the May 27, 2010 Annual Meeting of Shareholders is hereby
incorporated by reference.
Name
Dec. 31, 2009 Positions held during last five years
Age at
Gregg S. Kantor
David H. Anderson
Margaret D. Kirkpatrick
Lea Anne Doolittle
J. Keith White
David R. Williams
Grant M. Yoshihara
C. Alex Miller
Stephen P. Feltz
MardiLyn Saathoff
52
48
55
54
56
56
54
52
54
53
President and Chief Executive Officer (2009-
); President and Chief
Operating Officer (2007 - 2008); Executive Vice President (2006 -
2007); Senior Vice President, Public and Regulatory Affairs
(2003-2006).
Senior Vice President and Chief Financial Officer (2004-
).
Vice President and General Counsel (2005-
firm of Stoel Rives LLP (1991- 2005).
); Partner in the law
Senior Vice President (2008-
); Vice President, Human Resources
(2000-2007).
Vice President, Business Development and Energy Supply (2007-
Managing Director, Gas Operations and Wholesale Services
(2005-2006); Managing Director and Chief Strategic Officer
(2003-2005).
);
Vice President, Utility Services (2007-
); Director of Utility
Operations, Districts and managed Labor Relations (2004-2006).
Vice President, Utility Operations (2007-
); Managing Director,
Utility Services (2005-2006); Director, Utility Services
(2004-2005).
Vice President, Finance and Regulation (2009-
); Assistant
Treasurer (2008-); General Manager of Rates and Regulatory
Affairs (2002-2009).
Treasurer and Controller (1999-
).
Chief Governance Officer and Corporate Secretary (2008-
); Chief
Compliance Officer and Assistant General Counsel, Tektronix, Inc.
(2005-2008); General Counsel to Oregon Governor Kulongoski and
Business and Economic Development Advisor (2003-2005).
Each executive officer serves successive annual terms; present terms end on May 27, 2010.
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 applicable to all employees, including our chief
executive officer, chief financial officer and principal accounting officer, and a Financial Code of
Ethics that applies to senior financial employees, both of which are available on our website at
www.nwnatural.com. We intend to disclose on our website at www.nwnatural.com any amendments to
or waivers of our Code of Ethics for executive officers.
128
ITEM 11. EXECUTIVE COMPENSATION
The information concerning “Executive Compensation” and “Report of the Organization and
Executive Compensation Committee on Executive Management Compensation” contained in our
definitive Proxy Statement for the May 27, 2010 Annual Meeting of Shareholders is hereby
incorporated by reference. Information related to Executive Officers as of December 31, 2009 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, 2009 (see Note 4 to the
Consolidated Financial Statements):
(a)
(b)
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
(c)
Number of securities
remaining available for
future issuance under
equity compensation
plans (excluding
securities reflected in
column (a))
77,500
484,935
24,530
5,529
69,001
91,801
753,296
n/a
$39.57
$35.54
n/a
n/a
n/a
228,858
810,650
170,388
n/a
n/a
n/a
1,209,896
Plan Category
Equity compensation plans approved by
security holders:
Long-Term Incentive Plan (LTIP)
(Target Award)1
Restated Stock Option Plan
Employee Stock Purchase Plan
Equity compensation plans not approved
by security holders:
Executive Deferred Compensation
Plan (EDCP)2
Directors Deferred Compensation
Plan (DDCP)2
Deferred Compensation Plan for
Directors and Executives (DCP)3
Total
The information captioned “Beneficial Ownership of Common Stock by Directors and
Executive Officers” contained in our definitive Proxy Statement for the May 27, 2010 Annual Meeting
of Shareholders is incorporated herein by reference.
(1)
(2)
Shares issued pursuant to the LTIP do not include an exercise price, but are payable when the award criteria
are satisfied. If the maximum awards were paid pursuant to the performance-based awards outstanding at
December 31, 2009, the number of shares shown in column (a) would increase by 77,500 shares and the
number of shares shown in column (c) would decrease by 155,000 shares.
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
129
(3)
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 six percent 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. 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.
Effective January 1, 2005, the EDCP and DDCP were replaced by the Deferred Compensation Plan for
Directors and Executives (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 or 10 years as elected by the participant in accordance with the terms of the DCP. 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.
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 27, 2010 Annual Meeting of Shareholders is
hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information captioned “2009 and 2008 Audit Firm Fees” in the Company’s definitive
Proxy Statement for the May 27, 2010 Annual Meeting of Shareholders is hereby incorporated by
reference.
130
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 133.
131
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.
SIGNATURES
Date: February 26, 2010
NORTHWEST NATURAL GAS COMPANY
By:
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
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
/s/ Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
David H. Anderson
Senior Vice President
and Chief Financial Officer
/s/ Stephen P. Feltz
Stephen P. Feltz
Treasurer and Controller
/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/ Tod R. Hamachek
Tod R. Hamachek
/s/ Jane L. Peverett
Jane L. Peverett
/s/ George J. Puentes
George J. Puentes
/s/ Kenneth Thrasher
Kenneth Thrasher
/s/ Russell F. Tromley
Russell F. Tromley
TITLE
Principal Executive Officer and Director
DATE
February 26, 2010
Principal Financial Officer
February 26, 2010
Principal Accounting Officer
February 26, 2010
Director
Director
Director
Director
Director
Director
Director
Director
Director
132
February 26, 2010
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
EXHIBIT INDEX
To
Annual Report on Form 10-K
For Fiscal Year Ended
December 31, 2009
Exhibit Number
Document
*3a.
*3b.
*4a.
*4b.
*4c.
*4d.
*4e.
Restated Articles of Incorporation, as filed and effective May 31, 2006 and
amended June 3, 2008 (incorporated herein by reference to Exhibit 3a. to
Form 10-K for 2006, File No. 1-15973).
Bylaws as amended May 24, 2007 (incorporated herein by reference to
Exhibit 3.1 to Form 8-K dated May 29, 2007, File No. 1-15973).
Copy of Mortgage and Deed of Trust, dated as of July 1, 1946, to Bankers
Trust and R. G. Page (to whom Stanley Burg is now successor), Trustees
(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); and 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).
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).
Officers’ Certificate dated June 12, 1991 creating Series A of the
Company’s Unsecured Medium-Term Notes (incorporated herein by
reference to Exhibit 4e. to Form 10-K for 1993, File No. 0-994).
Officers’ Certificate dated June 18, 1993 creating Series B of the
Company’s Unsecured Medium-Term Notes (incorporated herein by
reference to Exhibit 4f. to Form 10-K for 1993, File No. 0-994).
Officers’ Certificate dated January 17, 2003 relating to Series B of the
Company’s Unsecured Medium-Term Notes and supplementing the
Officers’ Certificate dated June 18, 1993 (incorporated herein by reference
to Exhibit 4f.(1) to Form 10-K for 2002, File No. 0-994).
133
*4f.
*4g.
*4h.
4i.
*4j.
4k.
*4l.
*10a.(1)
*10a.(2)
*10a.(3)
Form of Credit Agreement between Northwest Natural Gas Company and
the banks that are party thereto, with JPMorgan Chase Bank, N.A., as
administrative agent and Bank of America, N.A., as syndication agent, dated
as of May 31, 2007, including Form of Note (incorporated herein by
reference to Exhibit 10.1 to Form 8-K dated June 1, 2007,
File No. 1-15973).
Form of Letter Agreement, between each of JPMorgan Chase Bank, N.A.,
Bank of America, N.A., U.S. Bank National Association, UBS Loan
Finance LLC, Wells Fargo Bank, N.A., Merrill Lynch Bank USA, dated as
of April 29, 2008, extending the Credit Agreement between Northwest
Natural Gas Company and each financial institutions with JPMorgan Chase
Bank, N.A., as Administrative Agent (incorporated herein by reference to
Exhibit 4i.(1) to Form 10-K for 2008, 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).
Letter Agreement among the Company, JPMorgan Chase Bank, N.A., Bank
of America, N.A., U.S. Bank National Association, Wachovia Bank,
National Association, Wells Fargo Bank, N.A., Bank of America, N.A.,
Successor by merger to Merrill Lynch Bank USA, and UBS Loan Finance
LLC, dated October 29, 2009.
Distribution Agreement, dated March 18, 2009, among Banc of America
Securities LLC, UBS Securities LLC, J.P. Morgan Securities Inc., and Piper
Jaffray and Co. (Incorporated herein by reference to Exhibit 1.1 to Form 8-
K dated March 23, 2009, File No. 1-15973).
Form of Letter Agreement, dated August 24, 2009, among Banc of America
Securities, LLC, UBS Securities LLC, J.P. Morgan Securities Inc., Piper
Jaffray & Co. and Wells Fargo Securities, LLC.
Form of Unsecured Medium-Term Notes, Series B (incorporated herein by
reference to Exhibit 4.2 to Form 8-K dated October 4, 2004,
File No. 1-15973).
Replacement Firm Transportation Agreement, dated July 31, 1991, between
the Company and Northwest Pipeline GP (incorporated herein by reference
to Exhibit 10j.(2) to Form 10-K for 1992, File No. 0-994).
Firm Transportation Service Agreement, dated November 10, 1993,
between the Company and Pacific Gas Transmission Company
(incorporated herein by reference to Exhibit 10j.(2) to Form 10-K for 1993,
File No. 0-994).
Service Agreement, dated June 17, 1993, between Northwest Pipeline GP
and the Company (incorporated herein by reference to Exhibit 10j.(3) to
Form 10-K for 1994, File No. 0-994).
134
*10a.(4)
*10a.(5)
*10a.(6)
*10a.(7)
*10a.(8)
*10a.(9)
*10a.(10)
*10a.(11)
*10a.(12)
*10a.(13)
*10a.(14)
*10a.(15)
*10a.(16)
*10a.(17)
Firm Transportation Service Agreement, dated June 22, 1994, between
Pacific Gas Transmission Company and the Company (incorporated herein
by reference to Exhibit 10j.(5) to Form 10-K for 1995, File No. 0-994).
Firm Service Agreement between the Company and Westcoast Energy Inc.,
dated as of April 1, 2003 (incorporated herein by reference to Exhibit 10 to
Form 10-Q for quarter ended March 31, 2003, File No. 0-994).
Service Agreement Amendment, dated February 12, 2008, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(7) to Form 10-K for 2007, File No. 1-15973).
Service Agreement, dated February 8, 2008, between the Company and
Northwest Pipeline GP (incorporated herein by reference to Exhibit 10j.(8)
to Form 10-K for 2007, File No. 1-15973).
Agreement between the Company and March Point Cogeneration Company,
dated February 8, 2008 (incorporated herein by reference to Exhibit 10j.(9)
to Form 10-K for 2007, File No. 1-15973).
Firm Transportation Service Agreement, dated October 22, 1993, between
the Company and Pacific Gas Transmission Company (incorporated herein
by reference to Exhibit 10j.(10) to Form 10-K for 2008, File No. 1-15973).
Service Agreement (100310), dated January 21, 2008, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(11) to Form 10-K for 2008, File No. 1-15973).
Service Agreement, dated January 21, 2008, between the Company and
Northwest Pipeline GP (incorporated herein by reference to Exhibit 10j.(12)
to Form 10-K for 2008, File No. 1-15973).
Service Agreement (Gas Storage Service), dated January 12, 1994, between
the Company and Northwest Pipeline Corporation (incorporated herein by
reference to Exhibit 10j.(13) to Form 10-K for 2008, File No. 1-15973).
Service Agreement (100309), dated January 21, 2008, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(14) to Form 10-K for 2008, File No. 1-15973).
Service Agreement (100308), dated January 12, 1994, between the
Company and Northwest Pipeline GP (incorporated herein by reference to
Exhibit 10j.(15) to Form 10-K for 2008, File No. 1-15973).
Service Agreement, dated January 20, 1995, between the Company and
NOVA Gas Transmission Ltd (incorporated herein by reference to Exhibit
10j.(16) to Form 10-K for 2008, File No. 1-15973).
Service Agreement, dated November 1, 2004, between the Company and
TransCanada PipeLines Limited (incorporated herein by reference to
Exhibit 10j.(17) to Form 10-K for 2008, File No. 1-15973).
Service Agreement, dated October 24, 2008, between Foothills Pipe Lines
Ltd. and the Company (incorporated herein by reference to Exhibit 10j.(18)
to Form 10-K for 2008, File No. 1-15973).
135
*10a.(18)
Amendment and Restatement of Firm Transportation Service Agreement,
dated November 1, 2004, between Terasen Gas Inc. and the Company
(incorporated herein by reference to Exhibit 10j.(19) to Form 10-K for 2008,
File No. 1-15973).
12
23
31.1
31.2
32.1
Statement re computation of ratios of earnings to fixed charges.
Consent of PricewaterhouseCoopers LLP.
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.
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:
10b.
10c.
*10d.
*10e.
*10f.
*10g.
10h.
*10i.
*10j.
10k.
Executive Supplemental Retirement Income Plan 2010 Restatement.
Supplemental Executive Retirement Plan, effective September 1, 2004
restated 2010.
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 From 10-K for 2006,
File No. 1-15973).
Form of Restated Stock Option Plan Agreement.
Executive Deferred Compensation Plan, effective as of January 1, 1987,
restated as of February 26, 2009 (incorporated herein by reference to Exhibit
10(e). to From 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 10(f). to
From 10-K for 2008, File No. 1-15973).
Deferred Compensation Plan for Directors and Executives effective
January 1, 2005, restated as of January 1, 2010.
136
10l.
10l.(1)
*10m.
10n.
10o.
*10p.
*10q.
*10r.
10s.
*10t.
*10u.
*10v.
*10w.
*10x.
*10y.
Form of Indemnity Agreement as entered into between the Company and
each director and certain executive officers.
Form of Indemnity Agreement as entered into between the Company and
certain executive officers.
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).
Executive Annual Incentive Plan, effective February 25, 2010.
Form of Agreement to Recoupment Provisions of Executive Annual
Incentive Plan, effective as of January 1, 2010.
Form of Change in Control Severance Agreement between the Company
and each executive officer (incorporated herein by reference to Exhibit
10(o). to From 10-K for 2008, File No. 1-15973).
Severance agreement dated December 19, 2008 between the Company and
Gregg S. Kantor (incorporated herein by reference to Exhibit 10.1 to
Form 8-K dated December 23, 2008, File No. 1-15973).
Northwest Natural Gas Company Long-Term Incentive Plan, as amended
and restated effective July 26, 2001 (incorporated herein by reference to
Exhibit 10(c) to Form 10-Q for the quarter ended June 30, 2001,
File No. 0-994).
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan.
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan (incorporated herein by reference to Exhibit 10.1 to
Form 8-K dated February 21, 2007, File No. 1-15973).
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan (incorporated herein by reference to Exhibit 10w.(2) to
Form 10-K for 2007, File No. 1-15973).
Form of Restricted Stock Bonus Agreement under the Long-Term Incentive
Plan (incorporated herein by reference to Exhibit 10.9 to Form 8-K dated
December 16, 2005, File No. 1-15973).
Restricted Stock Bonus Agreement with an executive officer dated July 26,
2006 (incorporated by reference to Exhibit 10.1 to Form 8-K dated July 28,
2006, File No. 1-15973).
Form of Consent dated December 14, 2006 entered into by each executive
officer (incorporated herein by reference to Exhibit 10.1 to Form 8-K dated
December 19, 2006, File No. 1-15973).
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).
137
10z.
Form of Long-Term Incentive Award Agreement under the Long-Term
Incentive Plan relating to a special award to an executive officer.
*Incorporated herein by reference as indicated
138
NORTHWEST NATURAL GAS COMPANY
Statement Re: Ratio of Earnings to Fixed Charges
Thousands, except per share amounts
(Unaudited)
EXHIBIT 12
Year Ended December 31,
2009
2008
2007
2006
2005
Fixed Charges, as defined:
Interest on Long-Term Debt . . . . . . . . . . . . . . . . .
Other Interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of Debt Discount and Expense . . . .
Interest Portion of Rentals . . . . . . . . . . . . . . . . . .
$ 37,447
1,937
1,503
1,735
$ 33,605
4,022
700
1,551
$ 34,294
4,116
711
1,523
$ 34,651
4,648
716
1,465
$ 34,330
2,665
808
1,357
Total Fixed Charges, as defined . . . . . . . . . . . . . .
$ 42,622
$ 39,878
$ 40,644
$ 41,480
$ 39,160
Earnings, as defined:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes on Income . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed Charges, as above . . . . . . . . . . . . . . . . . . . .
$ 75,122
46,671
42,622
$ 69,525
40,678
39,878
$ 74,497
44,060
40,644
$ 63,415
36,234
41,480
$ 58,149
32,720
39,160
Total Earnings, as defined . . . . . . . . . . . . . . . . . .
$164,415
$150,081
$159,201
$141,129
$130,029
Ratio of Earnings to Fixed Charges . . . . . . . . . . . . . . .
3.86
3.76
3.92
3.40
3.32
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. 33-63017, 333-55002, 333-70218, 333-100885, 333-120955, 333-134973 and 333-139819) and
in the Registration Statement on Form S-3 (No. 333-148527) of Northwest Natural Gas Company of
our report dated February 26, 2010 relating to the consolidated 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 26, 2010
CERTIFICATION
EXHIBIT 31.1
I, Gregg S. Kantor, certify that:
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 26, 2010
/s/ Gregg S. Kantor
Gregg S. Kantor
President and Chief Executive Officer
I, David H. Anderson, certify that:
CERTIFICATION
EXHIBIT 31.2
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 26, 2010
/s/ David H. Anderson
David H. Anderson
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, GREGG S. KANTOR, the President and Chief Executive Officer, and
DAVID H. ANDERSON, the Senior Vice President and Chief Financial Officer, of NORTHWEST
NATURAL GAS COMPANY (the Company), DOES HEREBY CERTIFY that:
1.
2.
The Company’s Annual Report on Form 10-K for the year ended December 31, 2009 (the Report)
fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of
1934, as amended; and
Information contained in the Report fairly presents, in all material respects, the financial condition
and results of operation of the Company.
IN WITNESS WHEREOF, each of the undersigned has caused this instrument to be executed
this 26th day of February 2010.
/s/ Gregg S. Kantor
President and Chief Executive Officer
/s/ David H. Anderson
Senior Vice President and
Chief Financial Officer
A signed original of this written statement required by Section 906 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.
produced by nw natural’s corporate communications, finance and corporate governance departments
photo credits
Page 4 - Gregg Kantor: Robbie McClaran, photographer.
Page 9 - Mist facility: Kurt Hettle, photographer.
Page 11 - Tualatin facility: Robbie McClaran, photographer.
Page 18 - Board of Directors: Robbie McClaran, photographer.
Page 19 - Corporate Offi cers: Robbie McClaran, photographer.
Page 21 - Robert Hess and Kimberlee Anderson: Robbie McClaran, photographer.
printing
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NYSE: NWN
Cert no. SCS-COC-000648