2008 Annual Report
we grew up here
1859 - 2009
Corporate
PROFILE
NW Natural (nyse: nwn) is a 150-year-
old natural gas local distribution and
storage company headquartered in
Portland, Oregon, with a customer
growth rate consistently above the
national average. NW Natural serves
more than 662,000 customers in
Oregon and Southwest Washington.
In keeping with its steady growth, the
company has increased dividends paid
to shareholders for 53 consecutive years,
a feat matched by few publicly traded
companies. NW Natural operates
gas storage facilities in its service terri-
tory and provides gas storage services
to other energy companies in the
Northwest. NW Natural is developing
a new gas storage facility at Gill Ranch
near Fresno, California, and plans to
develop a new gas transmission pipeline
called Palomar in Oregon to provide
enhanced gas deliverability and
reliability for the region.
SERVICE TERRITORY
and Infrastructure Projects
ASTORIA
washington
MIST STORAGE
VANCOUVER
GASCO LNG
PORTLAND
LINCOLN CITY
MOLALLA
NEWPORT LNG
SALEM
ALBANY
EUGENE
THE DALLES
PALOMAR
MADRAS
oregon
COOS BAY
KEY
REGIONAL RESOURCE CENTER
LNG PLANT
UNDERGROUND STORAGE
GILL RANCH STORAGE
HEADQUARTERS
PROPOSED PALOMAR PIPELINE
SACRAMENTO
northern california
SAN FRANCISCO
GILL RANCH STORAGE
FRESNO
fi nancial overview
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
2008
2007
percent
increase
(decrease )
1,037,855
356,215
69,525
1,033,193
369,042
74,497
11.4
44.9
55.1
12.5
46.3
53.7
–
(3 )
(7 )
(9 )
(3 )
3
26,438
26,501
26,821
26,407
(1 )
–
2.63
2.61
1.52
1.58
23.71
44.23
2.78
2.76
1.44
1.50
22.52
48.66
(5 )
(5 )
6
5
5
(9 )
4
5
2
(1 )
Gas sales and transportation deliveries (000 therms) 1,260,751
4,576
Degree days
662,341
Customers at year-end
1,133
Employees at year-end
1,214,969
4,374
652,012
1,141
dividends paid on common stock (per share)
payment date
February 15
May 15
August 15
November 15
Total dividends paid
$ 0.375
0.375
0.375
0.395
$ 1.520
$ 0.355
0.355
0.355
0.375
$ 1.440
diluted earnings per share
(in dollars)
dividends paid per share
(in dollars)
$3.00
2.50
2.00
1.50
1.00
.50
0
2004
2005
2006
2007
2008
$1.52
1.47
1.42
1.37
1.32
1.27
1.22
2004
2005
2006
2007
2008
Diluted earnings per share were $2.61 in 2008 – the
second highest in the company’s history.
Annual dividends paid per share in 2008 increased
for the 53rd consecutive year. Th e indicated dividend
rate at year-end was $1.58 per share.
Th e 1950s were years of great change,
both in style and technology. In addition
to the popularity of television and the
automatic transmission, the 1950s brought
natural gas to the Pacifi c Northwest.
table of contents
letter to shareholders ............................................................ 4
years of trust ........................................................... ........... . 9
comfort & convenience: it,s timeless ................................ 11
a legacy of service ..................................................................... 13
-year timeline ............................................................ .......... 14
financial overview ..................................................................... 16
corporate officers .................................................................... 22
board of directors .................................................................... 23
quarterly financial information ........................................ 24
shareholder information ...................................................... 25
financial statements - form -k annual report
Gregg Kantor,
President
and CEO
Mark Dodson, retired CEO
and current board member
letter to
Shareholders
years of service
One hundred and fi fty years
ago, new Portland arrivals
H.C. Leonard and John Green
raised $50,000 from East
Coast investors. Even before
Oregon achieved statehood,
these men were promoting
the promise of the Northwest:
its natural beauty, its bounty
and its growth potential. Th ey
used the money they raised
to start a gas light company,
illuminating the streets and
houses of their adopted
hometown.
Today, we at NW Natural
speak about the Pacifi c
Northwest in much the same
way as our company’s found-
ers, Leonard and Green. Th e
region continues to attract
dynamic, energetic individuals
because of its quality of life,
diverse economy and environ-
mental stewardship.
Th e promise of the North-
west is the promise of NW
Natural.
As we turn 150, we are proud
to celebrate our legacy of suc-
cess. We are equally enthusi-
astic about looking ahead. At
a time when both our nation
and the energy industry are
facing dramatic change, we
have put in place the tools
to adjust, adapt and excel.
steady amid
the turbulence
In 2008, we stayed on course
and accomplished what we
said we would.
Our earnings of $69.5
million, or $2.61 per share,
were at the high end of our
earnings guidance. In fact,
the 2008 results were second
only to those of 2007, a year
that benefi ted substantially
from unusually high margin
gains from our gas cost-shar-
ing mechanism.
In addition, we increased
dividends paid to sharehold-
ers owning common stock
for the 53rd consecutive year
– a record that is one of the
longest on the New York
Stock Exchange.
And we did all this while the
nation was experiencing one
of the worst economic reces-
sions since 1929.
Like the rest of the nation,
the economic slowdown
has aff ected the Northwest’s
housing market. Home-
building has declined, but
Portland’s Skidmore Fountain was
dedicated in 1888. Located just
a few blocks from NW Natural’s
headquarters, it is memorable both
for its gracious beauty and for its
inscription: Good citizens are the
riches of a city.
our customer growth rate
of 1.6 percent in 2008 still
ranked among the highest
in the industry.
After 150 years, you learn
how to deal with good and
bad business cycles. You plan
ahead and you execute. Th is
far-sighted approach helped
the company transition from
lighting to heating early in its
history, and it was the reason
we were able to deliver a solid
performance in 2008.
Th ree years ago we initiated a
comprehensive redesign of our
operations, which helped us
reduce our work force by more
than 10 percent and control
costs across the company.
When we started this eff ort, we
intended to size our work force
to operate more effi ciently. A
greater reliance on construction
contractors gave us the fl exibil-
ity needed to rapidly respond
to the downturn in housing.
We also created an incentive-
based sales team. In 2008,
the team met our conversion
targets, which helped off set the
slowdown in new housing starts.
And because of the redesign,
and our continuing commit-
ment to managing costs, we
were able to off set losses from
our gas cost-sharing mechanism
caused by the higher price of
natural gas in the fi rst seven
months of 2008.
In the midst of the nation’s
fi nancial turbulence, we kept
a strong balance sheet. We set
aside a $50 million cash reserve
early in the fourth quarter,
when markets were unusually
volatile. Our total capitalization
and liquidity remained solid,
as represented by our strong
credit ratings: Moody’s at A2 ,
Standard & Poor’s at AA-.
strengthening
the core
In 2008, we benefi ted from
the many operating changes
made in 2006 and 2007.
But, we also continued to
fi ne tune and improve our
operations. New technology
and organizational changes
came together, advancing
our eff orts to work more
effi ciently and eff ectively.
Last year, employee and
contract construction crews
began sending and receiv-
ing work order information
electronically. An automated
vehicle location system now
helps our newly centralized
resource management team
direct the closest crew truck
to a job site or emergency.
In 2009, we will deploy this
new technology with other
fi eld employees to take full
advantage of these systems.
We also spent much of 2008
designing and installing new
business software. Since early
this year, data entered in the
fi eld and in the offi ce now
fl ow into a single integrated
system. Th is is speeding the
movement of information,
leading to more timely and
accurate reporting and more
responsive decision making.
working in partner-
ship with regulators
In 1860, our fi rst year of
gas deliveries, cast iron pipes
brought gas to the company’s
fi rst customers. Today, we
use fl exible polyethylene or
steel pipes with sophisticated
cathodic protection. Safety
and reliability have always
been our highest priority.
In 2009, the federal govern-
ment is expected to establish
new rules for assessing gas
distribution pipelines. But
well before regulators con-
sidered distribution integrity
rules, NW Natural had acted
on many of the proposed
requirements. We were one
of the fi rst utilities in the
nation to replace all cast
iron pipes. And we have
had a bare steel removal
program in place
since 2001.
However, even
with so much of the work
behind us, new rules bring
additional costs.
For a number of years,
the Oregon Public Utility
Commission (OPUC) has
allowed timely rate recovery
of our costs for pipeline safety
programs: replacing old pipe
before problems arise and
implementing pipeline integ-
rity programs to maintain the
safety of our existing pipeline
system. In early 2009, the
OPUC agreed to integrate
these programs with the new
federal distribution integrity
management requirements
and provide for annual rate
recovery through a new
System Integrity Program.
In 2008, we also worked
successfully
with Oregon
2008 HIGHLIGHTS
in , nw natural:
• Reported net income of $69.5
million or $2.61 per share.
• Ranked fi rst in the nation
among 59 other utilities
in the 2008 J.D. Power
and Associates Gas Utility
Residential Customer
Satisfaction Survey.
• Reduced earnings exposure
through approval of a new
gas cost-sharing mechanism
in Oregon.
• Reached an agreement with
Oregon regulators authoriz-
ing rate recovery for pipeline
safety investments.
• Completed a rate case in
Washington state increasing
revenue requirements by
approximately $2.7 million
a year.
• Sold our Boeing 737 air-
plane investment that had
been leased to a commercial
airline since its purchase
in the 1980s, disposing of
the company’s last noncore
asset and recording an after-
tax gain of over $1 million.
• Gill Ranch Storage, LLC
fi led a permit application
for approximately 20 billion
cubic feet (Bcf ) of under-
ground storage capacity
and a 27-mile pipeline
near Fresno, California.
• Palomar Gas Transmis-
sion LLC fi led a permit
application with the
Federal Energy Regulatory
Commission to build and
operate a 217-mile natural
gas pipeline in Oregon.
• Entered an agreement
to build a biodigester on
Oregon’s largest organic
farm with support from
Smart Energy, NW Natu-
ral’s new and innovative
customer carbon off set
program.
• Raised the quarterly divi-
dend rate by more than
5 percent, making this
the 53rd consecutive year
of increasing dividends
paid per share.
• Maintained the company’s
strong credit ratings from
Moody’s and from Standard
& Poor’s.
regulators to revise our 20-
year-old gas cost-sharing
mechanism to better balance
the risks and rewards between
customers and sharehold-
ers. In the past, we returned
two-thirds of any money
saved on gas cost purchases to
customers, while shareholders
kept one-third of the sav-
ings. If gas costs were higher
than forecasted in our rates,
shareholders absorbed one-
third of any losses.
Th e new agreement reached
with the OPUC allows us
to annually select either a
90/10 or 80/20 customer-
shareholder split. Th is gives us
added fl exibility in managing
gas costs.
In March 2008, NW Natural
fi led for a general rate case in
Washington, where approxi-
mately 10 percent of our
customer base is located.
Under the Washington
Utilities and Transportation
Commission (WUTC) fi nal
order, NW Natural’s revenue
requirements increase by
approximately $2.7 million a
year. NW Natural’s authorized
return on equity is 10.1 per-
cent, and its authorized rate of
return is 8.4 percent. Overall,
we believe this represents a fair
outcome for the company and
its customers. Th e new rates
took eff ect January 1, 2009.
expanding
the playing field
NW Natural’s founders,
Leonard and Green, never
allowed geography to limit
their aspirations. Th ey moved
from the East Coast to
Astoria, where the Colum-
bia River meets the Pacifi c
Ocean. Th ey then relocated
to Portland where they fore-
saw greater opportunity.
While NW Natural is proud
of its Northwest roots, we are
also looking for growth beyond
our traditional boundaries.
In 2008, we advanced storage
and pipeline projects that will
give us a larger role in the West
Coast’s energy infrastructure.
In July, NW Natural and
Pacifi c Gas & Electric (PG&E)
fi led applications with state
regulators to develop approxi-
mately 20 billion cubic feet
(Bcf) of underground storage
capacity at Gill Ranch, near
Fresno, California. Th e applica-
tions included construction of
about 27 miles of pipeline from
the storage site to PG&E’s gas
transmission system.
In December, the California
Public Utility Commission
deemed the fi ling complete
and announced the project
is on an accelerated environ-
mental permitting track. We
intend to have all necessary
permits in place by the end
of 2009 and to begin storage
operations by the end of 2010.
Although California is one of
the nation’s largest energy users,
it lags behind in development
of underground storage. And
we expect demand for storage
to grow in step with the state’s
demand for natural gas.
State laws in California and
Washington limiting carbon
emissions from electric gen-
eration are certain to create
a regional need for more
gas-fi red electric generation –
and add to gas price volatility.
Gas storage has always been
an important asset, but never
more so than now, as we
anticipate the adoption
of climate change policies.
Also in December, Palomar
Gas Transmission LLC,
a joint venture between
NW Natural and Trans-
Canada Corporation, fi led
a permit application with the
Federal Energy Regulatory
Commission to build and
operate a 217-mile, 36-inch
pipeline. Palomar would con-
nect a TransCanada-owned
interstate pipeline east of the
Cascade mountains to Western
Oregon. It would have the
capacity to transport up to
1.3 Bcf of natural gas per day.
Palomar Pipeline can be
thought of as two projects: an
east section and a west section.
Today, Oregon is one of a
few states in the nation to
have its major populated areas
served by a single interstate
pipeline. Th e east portion
of Palomar would help
strengthen service reliability
to our 662,000 customers by
providing a second path into
the Willamette Valley. Th e east
section would also bring in
additional domestic supplies
from the Rocky Mountains.
If one of the proposed
liquefi ed natural gas (LNG)
total shareholder return
(annualized as a percent, including
reinvestment of dividends)
one year
five years ten years
-6.1%
11.5%
10.1%
0%
2008
2003-2008 1998-2008
terminals is built on the
Columbia River, Palomar
could be extended west,
allowing NW Natural cus-
tomers access to additional gas
supplies. We believe adding a
new supply option close to our
market is an important way
to help mitigate future price
volatility for our customers.
keeping the trust
A local utility’s success is
dependent on two things:
its product and its reputation.
Th rough the years, our prod-
uct’s use may have evolved
from gas lights to natural
gas heating, but one thing
has remained constant since
1859: our desire to provide
exceptional service.
And last year, we were both
proud and appreciative that
our customers took notice
of our eff orts.
In 2008, NW Natural
received the highest overall
score in the nation in the
J.D. Power and Associates Gas
Utility Residential Customer
Satisfaction Survey.
It was clear from the survey
that our ratings on honesty
and ethics, energy education,
bill management, corporate
citizenship, and concern for
the environment were major
factors contributing to our top
customer satisfaction ranking.
To us, the survey results mean
we’re living up to the service
standards we have inherited
from generations of employees.
leadership milestones
Becoming CEO as NW
Natural celebrates its 150th
year is a reminder of the
continuity of leadership we
have enjoyed – leadership that
through the years has been
clear and consistent about its
business principles and plans.
Today, we have the strategies
in place and a committed,
talented team ready for what
the future holds – and for
this, we owe a great deal of
gratitude to retiring CEO
Mark Dodson. We are pleased
that Mark will continue
to provide the company
his counsel and insights
as a member of our Board
of Directors.
Among his many accomplish-
ments, Mark was a leader on
climate change issues. With his
retirement, Oregon continues
to look to NW Natural for
guidance and involvement. In
December, I was appointed
to Governor Ted Kulongoski’s
new Oregon Energy Policy
Council, which will create a
comprehensive energy plan
for the state. I also continue
to serve on the Governor’s
Global Warming Commission
and remain involved in the
American Gas Association’s
eff orts on climate change.
we grew up here
After 150 years, our history
is impossible to separate from
that of the Pacifi c Northwest.
We have drawn sustenance
and support from this unique
part of the nation, just as we
have provided it with warmth
and energy.
Th e board and offi cers of
NW Natural are constantly
aware of our responsibility
to our 150-year-old heritage
and to the communities of
the Northwest.
Last year demonstrated
the strength, stability and
resilience of this company.
We believe we have the strate-
gies and resources in place
to continue providing solid
results and sustained value –
in 2009 and beyond.
We have demonstrated that we
can manage costs and grow
the business profi tably. Our
customers value our service and
our role in their communities.
We entered 2009 with new
regulatory tools in place that
will continue to benefi t both
customers and shareholders.
We have developed far-sighted,
yet realistic plans to grow and
diversify the company.
Above all, we continue to
benefi t from the unique vital-
ity of the Pacifi c Northwest.
We are optimistic about the
future of both this region
and this company.
In our 150th year, you can
expect more of what you
have come to rely on us for:
stewardship of the infrastruc-
ture we own and the land
on which it rests; a habit of
looking ahead and anticipating
change; and fulfi llment of our
commitments to shareholders,
customers, communities
and employees.
Once again, thank you for
your confi dence and trust
in NW Natural. We look
forward to continuing to
work on your behalf.
Sincerely,
Gregg S. Kantor
President and
Chief Executive Offi cer
Th e gas company has a long history of
excellent shareholder service. In 1924,
the dividend team was responsible for
calculating and processing dividends
for shareholders. In 2008, a two-person
Investor Relations staff supported both
institutional and individual investors.
2008 marked the 53rd consecutive year
of increased dividends paid.
Early in the 20th century, gas companies
began promoting gas stoves and other new
products as electricity replaced gas lamps.
By 1930, gas stoves outnumbered wood
and coal units. In 1935, these Portland
Gas & Coke employees demonstrated the
benefi ts of gas baking.
150
years
of trust
h.c. leonard
john green
The founders
As young men, H.C. Leonard and
John Green left the East for the Western
frontier. Passing through San Francisco,
they were inspired by the city’s gas light
system. Th ey later settled in Portland,
where they received a perpetual fran-
chise from the territorial government to
provide gas service. Th e company they
started thrives today as NW Natural.
To build a gas distribution
system in Portland, Oregon,
our founders H.C. Leonard
and John Green borrowed
$50,000 from East Coast
investors – a massive invest-
ment in the 1850s. After 150
years of success, it is clear they
invested wisely.
While early investors were few
in number, today thousands
of individuals own NW Natu-
ral stock, totaling nearly 27
million shares. Th ese investors
– many of them with NW
Natural in their retirement
portfolios – have benefi ted
from 53 consecutive years
of increased dividends.
Central to our success has
been the ability to adapt.
When electric lights replaced
gas, the Portland Gas Light
Company dropped “Light”
from its name and began pro-
moting gas ranges, furnaces
and water heaters. On the fi rst
day of operation in 1860, the
Leonard & Green gas works
company delivered gas to
49 customers in southwest
Portland. Today, NW Natural
serves more than 662,000
homes and businesses across
historical growth of invested
in nw natural – through
$30,000
25,000
20,000
15,000
10,000
5,000
0
8
5
9
1
8
6
9
1
8
7
9
1
8
8
9
1
8
9
9
1
8
0
0
2
An investor who bought $100 of NW Natural common
stock in 1958, and reinvested dividends through 2008,
would have realized a total return of more than $29,000,
producing an annual average compound growth rate of
more than 12 percent.
107 communities in Oregon
and Southwest Washington.
While customer growth
has played a big role in NW
Natural’s success, so have wise
infrastructure investments.
Our underground storage at
Mist, Oregon, allows us to buy
gas at the best available prices
and store it until it’s needed –
so we can keep our gas costs
as low as possible. In addition,
storage services to large gas
users add earnings outside
our utility business.
Today, we’re planning for a
greater role in managing gas
infrastructure in the West.
We’re developing underground
storage in California, and we
expect to add much-needed
transmission pipeline capacity
in Oregon.
Before natural gas arrived in the
Northwest, about one-third of Port-
land Gas & Coke’s revenues came
from gas manufacturing byproducts.
Th e employees shown above delivered
briquettes, one type of byproduct,
to customers’ homes for heating
and cooking.
Gas lighting arrived in Portland on
the heels of the gold rush and the
Oregon Trail migration. Th is advance
in both indoor and outdoor lighting
accompanied Portland’s evolution
from a frontier town to a regional
economic and social hub.
COMFORT &
CONVENIENCE:
it’s timeless
Evolution
Th e company started by Leonard and
Green manufactured gas, fi rst from
coal and later from oil. When natural
gas began fl owing through company
pipelines in 1956, technicians visited
customers’ homes to prepare appliances
for the new, higher energy fuel. Th ey
converted more than 200,000 pieces of
equipment. Th is signaled the company’s
switch from manufacturer to service
provider.
When Leonard and Green gas
works opened for business,
customers received manu-
factured gas to light their
homes. Th ey welcomed gas
lamps, which burned cleaner,
brighter and longer than
lights using kerosene, their
previous fuel option.
Today, customers use gas for
cooking and heating as well as
manufacturing and running
high-effi ciency, on-site electric
generating equipment.
Originally, customers came
to the company’s offi ce to
pick up and pay their bills.
Today, customers can sit in
their homes and order gas
service, arrange technician
visits and pay for gas service –
all online. Th ey can call
NW Natural and make
arrangements using an
customers registered for web services
300,000
250,000
200,000
150,000
100,000
2005
2006
2007
2008
Use of NW Natural’s web site continues to grow, as more
and more customers choose to do business with the com-
pany online. According to J.D. Power and Associates, in
2008 nwnatural.com was one of the highest-rated utility
web sites in the country.
automated voice message
service – or talk with a
friendly, effi cient customer
service representative.
Historically, the company’s
goal was to sell more custom-
ers more gas. Today, we work
closely with customers to
help them use less, not more,
energy. Our innovative rate
structure, the Conservation
Tariff , allows us to promote
conservation and help cus-
tomers save money – without
harming shareholders.
From single-family homes to
senior centers, from corner
dry cleaners to the largest
high-tech employers, NW
Natural customers rely on us
for safe, dependable service.
In addition, they look to us
for leadership on energy effi -
ciency, conservation and new
natural gas applications.
Over the years, radios have largely given
way to cell phones and computers. In
2008, paperwork orders became a thing
of the past, and construction crews began
receiving job information electronically.
Today, automated vehicle location technol-
ogy lets the dispatch center fi nd the closest
vehicle for rapid emergency response.
Just as these employees did in the 1970s,
mail room staff ers start work well before
dawn and use the latest technology to
make sure customers receive their bills on
time. Today’s mail room prepares up to
35,000 bills for mailing each day.
a legacy
of service
A caring culture
Caring: It’s the essence of NW Natural’s
culture. Whether collecting rubber for
the war eff ort (above) or concentrating on
the maintenance of gas equipment (below),
gas company employees have always given
of themselves, on and off the job. Employee
volunteer activities range from helping at
animal shelters to coaching kids’ athletic
teams to serving as volunteer police offi cers.
In 1894, an employee named
Ah Ling helped recover com-
pany documents during
a fl ood that virtually shut
down the city of Portland.
When told to go home to
rest, he kept returning to his
work site so he could help
out. He later returned his pay
check, hoping the company
would use it to rebuild.
Ah Ling’s dedication and
passion continues today.
NW Natural employees show
how much they care, as well
as how skilled they are at their
jobs. Here’s what some of our
customers write about them.
“Mr. Cliff Rose was not only
exceptionally competent and
helpful, but also very personable.
Th e entire experience of dealing
with your company was a pleas-
ant one. I want to thank you
and Mr. Rose in particular for
your exceptional assistance.”
“A note of thanks for sending
Jim Fitzgerald to my home today
and for his knowledge in iden-
tifying the gas leak at my condo.
He was so considerate and kind,
and I want you to know he is
a wonderful technician.”
customers served by each operating employee
1,000
900
800
700
600
500
400
2004
2005
2006
2007
2008
Th e number of customers served by operating employees
continued to increase in 2008, as we have improved
operational eff ectiveness.
“Just want to say that I am
continually impressed with your
customer service. Every time
I have called your company,
I have spoken to knowledge-
able, friendly and effi cient reps.
Anymore, good customer service
is hard to fi nd.”
With experiences like these, it’s
no surprise that our customers
gave us the highest ratings in
the nation in the 2008 J.D.
Power and Associates Gas
Utility Residential Customer
Satisfaction Survey.
We’ve known for a long time
that NW Natural’s employees
are the best in the business.
We’re pleased that our cus-
tomers see it that way, too.
Eighteen-hundred and fift y-nine
1859
H.C. Leonard and
John Green receive
a perpetual franchise
for gas service
from the territo-
rial government fi ve
weeks before Oregon
became a state.
1861
The start of the Civil War encourages
migration to the Pacifi c Northwest.
1879
Light bulb
invented.
1894
Flood causes
complete service
interruption.
1889
The Eiffel
Tower
opens.
1862
Leonard
& Green
gas works
becomes
Portland Gas
Light Co.
1913
Portland Gas
Company changes
its name to Portland
Gas & Coke Company.
1924
Ross Island Bridge built.
1905
Lewis & Clark exposition opens.
1920
Women granted
right to vote.
1859
1869
1879
1889
1899
1909
1919
1929
1892
C. F. Adams, who bought
the company with
Abbot Mills, renames
it Portland Gas Company.
1884
Mark Twain’s
The Adventures
of Huckleberry Finn
is published.
1869
Portland Fire Department uses
gas to keep water from freezing
in horse drawn trucks.
1909
Pendleton Round-Up begins
1918
End of WWI. Company
begins selling preferred
stock to local customers.
1913
Gasco’s Linnton
plant opens.
1859
Construction of the gas
distribution system begins.
1859
Oregon becomes the 33rd state.
to Two-thousand and nine
1937
Bonneville Dam completed.
1980
Mt. St. Helens erupts.
2009
NW Natural
celebrates its
150th birthday.
1991
Barbara Roberts
elected as
Oregon’s fi rst
female governor.
1930
Gasco begins selling
vehicle fuel.
1956
The company begins adding natural gas to its
distribution system. The switch from manufac-
tured to natural gas required
the conversion of more
than 200,000 appliances.
1983
Construction on One Pacifi c
Square, the company’s present
headquarters in Old Town
Portland, is completed.
2004
South Mist Pipeline
Extension is completed.
1939
1949
1959
1969
1979
1989
1999
2009
1965
Company offi ces
open in Astoria
and Lincoln City.
2004
First Coos Bay customers receive natural gas.
1941
Gasco employees hail a shipment of briquettes des-
tined to provide heat for the troops at Fort Lewis.
1969
Gasco’s Linnton LNG
tank is completed.
1977
The Portland Trailblazers
win the NBA Championship
against the
Philadelphia 76ers.
1987
Company begins storing
gas underground at Mist.
1958
Name changed to Northwest Natural Gas Company.
1959
Gas company celebrates
Oregon’s 100th birthday.
Comparative Consolidated INCOME STATEMENTS
Th ousands, except per share amounts (year ended December 31)
2008
2007
2006
2005
2004
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
$ 1,037,855
656,568
25,072
$ 1,033,193
639,150
25,001
$ 1,013,172
648,156
24,840
$ 910,486
563,860
21,633
$ 707,604
399,244
16,865
356,215
369,042
340,176
324,993
291,495
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
102,155
21,943
57,371
181,469
Income from operations
144,036
154,923
136,762
126,947
110,026
Other income and expense - net
3,746
1,445
2,134
1,205
2,828
Interest charges - net
37,579
37,811
39,247
37,283
35,751
Income before income taxes
110,203
118,557
99,649
90,869
77,103
Income taxes
Net income
40,678
44,060
36,234
32,720
26,531
$ 69,525
$ 74,497
$ 63,415
$ 58,149
$ 50,572
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
26,438
26,594
26,821
26,995
27,540
27,657
27,564
27,621
27,016
27,283
$ 2.63
$ 2.61
$ 2.78
$ 2.76
$ 2.30
$ 2.29
$ 2.11
$ 2.11
$ 1.87
$ 1.86
Dividends per share of common stock
$ 1.52
$ 1.44
$ 1.39
$ 1.32
$ 1.30
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.
Comparative Consolidated balance sheets
Th ousands (December 31)
2008
2007
2006
2005
2004
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
$ 2,142,988 $ 2,052,161
615,533
659,123
1,436,628
1,483,865
67,149
74,506
7,904
9,314
59,245
65,192
1,495,873
1,549,057
$ 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
$ 1,794,972
505,286
1,289,686
33,963
5,244
28,719
1,318,405
Current assets:
Cash and cash equivalents
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
Regulatory liabilities 1
Deferred income taxes and investment tax credits
Fair value of non-trading derivatives 1
Other liabilities
Total capitalization and liabilities
6,916
81,288
102,688
(2,927 )
96,067
45,027
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
5,248
60,634
64,401
(2,434 )
66,477
42,791
237,117
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
$ 1,956,856
98,851
178,653
58,451
9,216
91,263
16,399
60,618
8,393
$ 2,042,304 $ 1,732,195
$ 628,373
512,000
1,140,373
$ 594,751
512,000
1,106,751
$ 599,545
517,000
1,116,545
$ 586,931 $ 568,517
484,027
1,052,544
521,500
1,108,431
248,000
94,422
–
12,455
2,785
36,467
394,129
248,613
257,831
158,381
178,825
$ 2,378,152
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
102,500
102,478
15,000
10,242
2,897
34,168
267,285
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
165,699
216,740
5,487
24,440
$ 1,732,195
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.
Comparative fi nancial statistics
year-end market price & book value per share
(in dollars)
comparison of five-year cumulative total return
(based on $100 invested on 12/31/03)
$60
50
40
30
20
10
0
2004
2005
2006
2007
2008
$200
175
150
125
100
75
50
2003
2004
2005
2006
2007
2008
book value per share
year-end market price
nwn
s&p utilities index
s&p small cap
high /low market price
Th e year-end market-to-book ratio was 1.9x in 2008.
Total shareholder return (annualized) over the fi ve years ending
December 31, 2008 was 11.5 percent, compared to the Standard & Poor’s
(S&P) Electric & Gas Utilities Index rate of 5.3 percent and the S&P
Small Cap 600 Index rate of a negative 5.9 percent.
capital and project expenditures
(in millions of dollars)
year-end capitalization
(in millions of dollars)
$160
140
120
100
80
60
40
20
0
2004
2005
2006
2007
2008
customer growth
system maintenance & improvements
pipeline integrity
mist storage
gill ranch
palomar pipeline
south mist pipeline
Total capital expenditures in 2008 were $118 million, of which $100
million was utility related.
$1,200
1,000
800
600
400
200
0
2004
2005
2006
2007
2008
common equity
long term debt
At the end of 2008 total capitalization grew to over $1.1 billion, of which
55 percent was common equity.
Comparative fi nancial statistics
Common stock
Ratios at year-end:
Price/earnings ratio
Dividend yield at year-end rate - %
Dividend payout - %
Return on average common equity - %
Per share data - ($):
Basic earnings
Diluted earnings
Dividends paid
Dividend rate at year-end
Book value at year-end
Market price:
High
Low
Year-end
Average
2008
2007
2006
2005
2004
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
18.0
3.9
69.5
9.4
1.87
1.86
1.30
1.30
20.64
34.13
27.46
33.74
31.06
Number of shares of common stock outstanding (000):
Year-end
Average
26,501
26,438
26,407
26,821
27,284
27,540
27,579
27,564
27,547
27,016
Coverage data (ratio of earnings to)
Fixed charges - Securities and Exchange Commission method 3.76
3.92
3.40
3.32
3.02
Cash fl ow data ($000)
Cash provided by operating activities
Cash used in investing activities
Utility plant
34,721
(109,825 )
183,640
(117,479 )
148,566
(90,567 )
79,066
(92,008 )
104,899
(132,631 )
Capital expenditures ($000)
Depreciation - % of average depreciable utility plant
Accumulated depreciation† - % of depreciable utility plant
$ 96,582
3.4
42.2
$ 93,785
3.4
40.8
$ 95,307
3.4
39.6
$ 89,259
3.4
38.4
$ 138,347
3.4
37.2
Capital structure at year-end (%)
(Exclusive of current portion of long-term debt)
First mortgage bonds
Unsecured debt
Total long-term debt
Common stock equity
Total capital structure
Eff ective tax rate
44.9
–
44.9
55.1
100.0
46.3
–
46.3
53.7
100.0
46.3
–
46.3
53.7
100.0
47.0
–
47.0
53.0
100.0
45.6
0.4
46.0
54.0
100.0
Eff ective tax rate - % of pretax income
37
37
36
36
34
† Includes regulatory liability for accrued asset removal costs.
Comparative operating statistics
total customers at year-end
(in thousands)
gas sales and transportation deliveries
(in millions of therms)
680
660
640
620
600
580
560
540
520
500
1,400
1,200
1,000
800
600
400
200
0
2004
2005
2006
2007
2008
2004
2005
2006
2007
2008
We added 10,329 new customers in 2008, expanding our customer base
by 1.6 percent. In the past fi ve years, the company has added over 84,000
new customers.
firm sales
interruptible sales
transportation
Gas sales and transportation deliveries in 2008 increased 4 percent from
2007, due primarily to customer growth and colder weather.
utility gas revenues
(by class)
1%
2%
utility net operating revenues (margin)
(in millions)
7%
5%
29%
56%
$350
300
250
200
150
100
50
0
residential
commercial
industrial firm sales
industrial interruptible sales
transportation
other
2004
2005
2006
2007
2008
residential
commercial
industrial
other
Revenues from residential, commercial and industrial fi rm sales customers is
90 percent of total gas revenues.
Utility margin decreased 4 percent from 2007 due primarily to gas cost
sharing gains in 2007 compared to losses in 2008, but has increased
18 percent since 2004.
Comparative operating statistics
Selected Utility Data
2008
2007
2006
2005
2004
Gas sales and transportation deliveries (000 therms):
Residential
Commercial
Industrial fi rm
Industrial interruptible
Total gas sales
Transportation
Total volumes delivered
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 in 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)
Total employees
Number of customers served by each operating employee
1,133
932
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
352,356
222,875
62,843
104,278
742,352
389,514
1,131,866
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
662,341
4,576
7%
721
4,300
829,989
86.56
79.21
6,609
8,363
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
471,502
250,287
64,507
100,740
887,036
10,755
–
2,862
900,653
563,772
21,633
315,248
617,163
4,178
(2)%
682
3,972
815,334
71.42
67.96
5,649
6,966
1,305
738
383,067
200,424
45,259
55,380
684,130
12,655
–
4,160
700,945
399,176
16,865
284,904
596,635
3,853
(10)%
670
3,844
756,672
56.60
53.77
7,177
8,913
1,288
721
corporate offi cers
DAVID H. ANDERSON, 47
[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. (-)
LEA ANNE DOOLITTLE, 54
[2000]
senior vice president (-present)
Vice President, Human Resources (-)
Director of Compensation, Pacifi Corp (-)
GREGG S. KANTOR, 51
[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
(-)
MARDILYN SAATHOFF, 52
[2008]
chief governance officer
and corporate secretary
Chief Compliance Offi cer and Assistant General
Counsel, Tektronix, Inc. (-)
General Counsel to Oregon Governor Kulongoski
and Business and Economic Development Advisor
(-)
DAVID R. WILLIAMS, 56
[1978]
vice president utility services
(-present)
Director, Utility Operations
and Labor Relations (-)
General Manager, Utility Operations (-)
MARK S. DODSON, 64
[1997]
retired chief executive officer
(-)*
Chief Executive Offi cer (-)
President and Chief Executive Offi cer (-)
President and Chief Operating Offi cer (-)
General Counsel (-)
Senior Vice President, Public Aff airs (-)
STEPHEN P. FELTZ, 53
[1982]
treasurer and controller
(-present)
Assistant Treasurer and Manager,
General Accounting (-)
MARGARET D. KIRKPATRICK, 54
[2005]
vice president and general
counsel (-present)
Partner, Stoel Rives LLP (-)
J. KEITH WHITE, 56
[1996]
vice president business development
and energy supply and chief strategic
officer (-present)
Managing Director, Gas Operations and Wholesale
Services (-)
Managing Director, Chief Strategic Offi cer (-)
GRANT M. YOSHIHARA, 54
[1991]
vice president utility operations
(-present)
Managing Director, Utility Services (-)
General Manager, Consumer Services (-)
[Date joined NW Natural]
*Mr. Dodson retired December 31, 2008.
board of directors
TIMOTHY P. BOYLE, 59
[2003] (4) (5)
President and
Chief Executive Offi cer
Columbia Sportswear
Company
Portland, Oregon
MARTHA L. “STORMY”
BYORUM, 60
[2004] (2) (6)
Senior Managing Director
Stephens Cori Capital Advisors
New York, New York
MARK S. DODSON, 64
[2003] (4) (5)
Former Chief Executive Offi cer
NW Natural
Portland, Oregon
C. SCOTT GIBSON, 56
[2002] (1) (3) (4)
President
Gibson Enterprises
Portland, Oregon
GREGG S. KANTOR, 51
[2008]
President and
Chief Executive Offi cer
NW Natural
Portland, Oregon
JANE L. PEVERETT, 50
[2007] (2) (3) (5)
President and
Chief Executive Offi cer
British Columbia
Transmission Corporation
Vancouver, British Columbia
JOHN D. CARTER, 63
[2002] (1) (2) (6)
President and
Chief Executive Offi cer
Schnitzer Steel Industries, Inc.
Portland, Oregon
[2002] (1) (2) (6)
TOD R. HAMACHEK, 63
[1986] (1) (2) (5)
Former Chairman and
Chief Executive Offi cer
Penwest Pharmaceuticals
Company
Seattle, Washington
GEORGE J. PUENTES, 61
[2007] (4) (6)
President
Don Pancho Authentic
Mexican Foods, Inc.
Salem, Oregon
KENNETH THRASHER, 59
[2005] (2) (3) (4)
Chairman and
Chief Executive Offi cer
Compli Corporation
Portland, Oregon
RUSSELL F. TROMLEY, 69
[1994] (1) (2) (3)
Chairman and
Chief Executive Offi cer
Tromley Industrial Holdings, Inc.
Tualatin, 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
in memoriam
In 2008, we were greatly saddened by the
death of Randy Papé, a 12-year board
member. He was not only dedicated to
NW Natural, but he was also a vigorous
advocate for the state of Oregon and the
policies and organizations that make this
such a remarkable place to live. Randy
will be missed by all who knew him.
RANDALL C. PAPÉ, 57
[1996] (1) (4) (6)
President and
Chief Executive Offi cer
Th e Papé Group, Inc.
Eugene, Oregon
quarterly fi nancial information
Quarterly Financial Information (unaudited)
Dollars (thousands except per share amounts)
March 31
June 30
Sept. 30
Dec. 31
Total
2008
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2007
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$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 *
$394,091
139,008
48,075
1.77
1.76
$183,249
64,118
2,617
0.10
0.10
$124,245
49,663
(5,908 )
(0.22 )
(0.22 )
$331,608
116,253
29,713
1.12
1.11
$1,033,193
369,042
74,497
2.78 *
2.76 *
* Quarterly earnings 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 2007 and 2008 was:
2008
Quarter Ended
March 31
June 30
September 30
December 31
2007
Quarter Ended
March 31
June 30
September 30
December 31
High
$50.74
48.22
55.23
53.71
High
$46.34
52.85
49.37
50.89
Low
$41.07
43.08
43.66
36.61
Low
$39.79
44.05
40.98
44.28
Th e closing quotations for the common stock on December 31, 2008 and December 31, 2007 were $44.23 and $48.66, respectively.
shareholder information
notice of annual meeting
Th e 2009 Annual Meeting will be held at
2 p.m., Th ursday, May 28, 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 admis-
sion 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 13, 2009
May 15, 2009
August 14, 2009
November 13, 2009
certifications
Th e Chief Executive Offi cer certifi ed to
the NYSE on May 23, 2008 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, 2007, the certifi cates of the Chief
Executive Offi cer and the Chief Financial
Offi cer of the company certifying the qual-
ity of the company’s public disclosure. For
the year ended December 31, 2008, 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 as follows:
• Call (800) 541-9967, or
• Write to NW Natural Board of Directors,
c/o Corporate Secretary, or
• Email Directors@nwnatural.com
forward-looking statements
Th e statements made in this Annual
Report that are not purely historical,
including statements regarding growth,
returns, business development, opera-
tional changes, 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 - MS NYC60-2710
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
CREDITS
produced by nw natural’s corporate communications, finance and corporate governance departments
photo credits
Unless otherwise indicated, the photos used in this book are from NW Natural’s archives.
Page 4 - Gregg Kantor and Mark Dodson at Skidmore Fountain: Robbie McClaran, photographer; Skidmore Fountain: OHS.
Page 9 - H.C. Leonard, J. Green: OHS.
Page 14 - H.C. Leonard, J. Green, Civil War era portrait, William Clark, Meriwether Lewis, Pendleton Round-Up, Linnton plant: OHS. Gas lamp post, light bulb, Eiffel Tower, Sacajawea,
Oregon State Seal, Mark Twain, fi re truck: Clipart.com. Bonneville Dam: BPA.gov. Ross Island Bridge: Oregon.gov and James B. Norman, photographer. Women’s suffrage stamp, toy
soldier: istockphoto.com.
Page 15 - Front page of The Oregonian, Mt. St. Helens, Barbara Roberts: OHS. Astoria Bridge, cupcake, basketball: istockphoto.com. Bill Walton: OHS and courtesy of Bill Walton and
Portland Trail Blazers. Mark Dodson: Bruce Beaton, photographer. Coos Bay ribbon cutting: Bill Grami, photographer.
Page 22, 23, 25 - Executive illustrations: Dale Headrick, illustrator.
Back inside cover: Mauricio Carcamo, Jim Fitzgerald, Randy and Jenny Friedman: Bruce Beaton, photographer.
OHS = Oregon Historical Society
printing
RR Donnelly
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, 2008
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 definitions of “accelerated filer,” “large 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, 2008, the registrant had 26,435,373 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 $1,211,499,354.
At February 23, 2009, 26,501,188 shares of the registrant’s Common Stock (the only class of Common Stock)
were outstanding.
Portions of the Proxy Statement of the registrant’s, to be filed in connection with the 2009 Annual Meeting of
Shareholders, are incorporated by reference in Part III.
DOCUMENTS INCORPORATED BY REFERENCE
* Cover as amended by Form 10-K/A filed with the SEC on March 6, 2009.
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission
on Form 10-K
For the Fiscal Year Ended December 31, 2008
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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.
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations . . .
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.
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 losses
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.
1
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
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 regulated
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 regulated 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.
Forward-Looking Statements
Statements and information included in this report that are not purely historical are forward-
looking statements within the “safe harbor” provisions and meaning of Section 21E of the Securities
Exchange Act of 1934, as amended (Exchange Act). Forward-looking statements include, but are not
limited to, statements concerning plans, objectives, goals, strategies, future events or performance,
trends, cyclicality, growth, development of projects, exploration of new gas supplies, 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, and
adequacy of regulatory deferrals. Such statements are expressed in good faith and we believe have a
reasonable basis; however, each forward-looking statement involves uncertainties and is qualified in its
entirety by reference to the following important factors, among others, that could cause our actual
results to differ materially from those projected, including:
•
•
•
prevailing state and federal governmental policies and regulatory actions with respect to
allowed rates of return, industry and rate structure, timely and adequate purchased gas cost
and investment recovery, acquisitions and dispositions of assets and facilities, operation and
construction of plant facilities, present or prospective wholesale and retail competition,
changes in laws and regulations including but not limited to tax laws and policies, changes
in and compliance with environmental and safety laws, regulations, policies and orders, and
laws, regulations and orders with respect to the maintenance of pipeline integrity, including
regulatory allowance or disallowance of costs based on regulatory prudency reviews;
economic factors that could cause a severe downturn in the national economy, in particular
the economies of Oregon and Washington, thus affecting demand for natural gas;
unanticipated population growth or decline and changes in market demand caused by
changes in demographic or customer consumption patterns;
the creditworthiness of customers, suppliers and financial derivative counterparties;
•
• market conditions and pricing of natural gas relative to other energy sources;
•
unanticipated changes that may affect our liquidity or access to capital markets, including
volatility in the credit environment and financial services sector;
capital market conditions, including their effect on financing costs, the fair value of pension
assets and on pension and other postretirement benefit costs;
application of the Oregon Public Utility Commission rules interpreting Oregon legislation
intended to ensure that utilities do not collect more income taxes in rates than they actually
pay to government entities;
•
•
• weather conditions, natural phenomena including earthquakes or other geohazard events,
and other pandemic events;
competition for retail and wholesale customers and our ability to remain price competitive;
our ability to access sufficient gas supplies and our dependence on a single pipeline
transportation company for natural gas transmission;
property damage associated with a pipeline safety incident, as well as risks resulting from
uninsured damage to our property, intentional or otherwise;
financial and operational risks relating to business development and investment activities,
including the Palomar pipeline and the proposed Gill Ranch underground gas storage
facility;
unanticipated changes in interest or foreign currency exchange rates or in rates of inflation;
•
•
•
•
•
2
•
•
•
•
•
•
changes in estimates of potential liabilities relating to environmental contingencies or in
timely and adequate regulatory or insurance recovery for such liabilities;
unanticipated changes in future liabilities and legislation relating to employee benefit plans,
including changes in key assumptions;
our ability to transfer knowledge of our aging workforce and maintain a satisfactory
relationship with the union that represents a majority of our workers;
potential inability to obtain permits, rights of way, easements, leases or other interests or
other necessary authority to construct pipelines, develop storage or complete other system
expansions and the timing of such projects;
federal, state or other regulatory actions related to climate change; and
legal and administrative proceedings and settlements.
These forward-looking statements involve risks and uncertainties. We may make other forward-
looking statements from time to time, including statements in press releases and public conference
calls and webcasts. All forward-looking statements made by us are based on information available to
us at the time the statements are made and speak only as of the date on which such statement is made.
We undertake no obligation to update any forward-looking statement to reflect events or circumstances
after the date on which such statement is made or to reflect the occurrence of unanticipated events.
New factors emerge from time to time and it is not possible for us to predict all such factors, nor can
we assess the impact of each such factor or the extent to which any factor, or combination of factors,
may cause results to differ materially from those contained in any forward-looking statement. Some of
these risks and uncertainties 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.
3
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. 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, two wholly-owned subsidiaries
and a joint venture. A reference to NW Natural (“we,” “us” or “our”) in this report means NW Natural
and it 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 which 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 or utility. Local gas
distribution 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 the 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 96 percent of our consolidated assets and 85
percent of our consolidated net income in 2008 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 14 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 2008, we had approximately 662,000 total customers, consisting of 599,000
residential, 62,000 commercial and 1,000 industrial sales and transportation customers. Approximately
90 percent of our 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 customer or industry
accounts for a significant portion of our revenues.
4
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
movement 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 we supplement
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 market 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 Day Sendout;”
• Lowest reasonable cost—Applying strategies to acquire gas supplies at the lowest
reasonable cost to utility customers;
• Price stability—Making use of physical assets (e.g. gas storage) 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, liquidity, price risk management, 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 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 market prices, but there may be price discounts on supplies
from the U.S. Rocky Mountains in the near term due to of the limited amount of transmission capacity
to transport that supply to existing markets. Several projects have been proposed recently to increase
pipeline capacity out of the U.S. Rocky Mountain region. 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.
5
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 contracts,
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.
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. There are four general methods that we currently use for managing gas
commodity price risk:
•
•
•
•
negotiating fixed prices directly with gas suppliers;
negotiating financial instruments that exchange the floating price in a physical supply
contract for a fixed price (referred to as price swaps);
negotiating financial instruments that set a ceiling or floor price, or both, on a floating price
contract (referred to as calls, puts, and collars); and
buying gas and injecting it into storage. 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 are refunded to
core utility customers, as well as generates incremental revenues which are included in our gas storage
business segment. See Note 2.
Regulatory alignment. Mechanisms for gas cost recovery are designed to be fair, and 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 cost recovery through:
•
re-setting customer rates annually for changes in forecasted purchased gas costs and
customer deferrals of prior year’s actual versus forecasted gas purchase costs. (see Part II,
Item 7., “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased Gas
Adjustment”);
6
•
•
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 the gas to our distribution
system and gains or losses related to 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 increased dramatically over the last
several years primarily due to shifts in the balance of supply and demand, which has been affected by
the level of gas imports, regional accessibility to gas supplies, supply disruptions, changes in the global
energy markets, availability of pipeline capacity to transport natural gas from region to region, and
changes in general economic conditions. 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 had been
relatively stable until recently. In 2006, two of the five major pipelines used by NW Natural filed with
the Federal Energy Regulatory Commission (FERC) for significant rate increases which were
implemented in 2007. Pipeline transportation rate increases are generally passed on to our customers
through state-approved 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 to fix or limit the price of gas commodity purchases.
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 enter into commodity swaps, puts, calls and collars anywhere from one
month up to five years into the future. Realized gains or losses from financial commodity hedge
contracts are treated as reductions or increases to the cost of gas.
In addition to the prices that are hedged through financial contracts, we also use gas storage as
a physical hedge. We purchase and inject about 15 to 20 percent of our annual gas supply requirements
into storage during the summer when demand and gas prices are generally lower. The gas is stored for
withdrawal during the winter months in five different storage facilities. We own and operate three of
7
these storage facilities located within our service territory, which eliminates 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 are to manage the price
exposure for a majority of our gas supply portfolio for the following gas contract year, with prices
hedged for approximately 60 percent of year round supplies and 80 percent or more of our expected
winter-heating season supplies based on forecasted customer requirements.
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 that is based on the coldest weather experienced over the last 20 years in our service
territory. We start with the coldest heating season during the last 20 years and then modify it to include
the coldest single weather day over that same 20-year period. This coldest “design day” is the
maximum anticipated demand on the natural gas distribution system during a 24-hour period, which
currently assumes weather at an average temperature of 12 degrees Fahrenheit. 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 63 percent of our firm customer design day requirements with storage and peaking
supply sources located within or adjacent to our service territory. 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 produced very high sendout days but they were still about 20 percent below our 2004
record. 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 2008-2009 winter heating season:
Projected Sources of Supply for Design Day Sendout
Sources of Supply
Firm supplier contracts
Off-system firm storage contracts
Mist underground storage (utility only)
Company-owned LNG storage
Recall agreements
Total
Therms
(in millions)
Percent
3.3
1.1
2.4
1.8
0.4
9.0
37
12
27
20
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 customers and positions the utility to meet future requirements.
8
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—70 percent of our supply comes from
Canada, with the balance coming primarily from the U.S. Rocky Mountain region, 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. At January 1, 2009, we had 28 firm contracts with 15 suppliers and remaining terms
ranging from five months to six years, which provide for a maximum of 2.2 million therms of firm gas
per day during the peak winter heating season and 1.1 million therms per day during the entire year.
These contracts have a variety of pricing structures and purchase obligations. During 2008, we
purchased 831 million therms of gas under the following contract 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
50
16
34
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 10 and 15 percent of our average daily contract volumes. Firm year-round supply
contracts have remaining terms ranging from one to six years. 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
2008, new short-term purchase agreements were entered into with nine suppliers. These agreements
have a variety of pricing structures and provide for a total of up to 1.5 million therms per day during
the 2008-2009 heating season. We intend to enter into new purchase agreements in 2009 for equivalent
volumes of gas with existing or new suppliers, as needed, to replace contracts that will expire during
2009.
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 enabling us to purchase spot gas in lieu
of firm contract volumes, thereby allowing us to take advantage of favorable pricing on the spot market
from time to time.
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 facility. Current
production is approximately 19,000 therms per day from about 17 wells, supplying 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.
9
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 transportation contract 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 2004, we completed our South Mist pipeline extension
project, which is a utility transmission pipeline from our Mist gas storage field to growing portions of
our distribution service area. 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 is the first recalled capacity since 2004. Under our regulatory agreement with
the OPUC, storage capacity that has been developed and used by the gas storage segment can be
recalled as needed and transferred to utility rate base at our original cost less accumulated depreciation,
with a corresponding rate increase to customers to reflect the cost of service. The core utility market
now has 2.4 million therms per day of deliverability and approximately 9 Bcf of working gas
committed from the Mist storage facility. As storage capacity is recalled to serve core utility
customers, we may be able to develop new storage capacity to replace it and continue serving interstate
customers.
We also have contracts with The Williams Companies’ Northwest Pipeline (Northwest
Pipeline) for firm gas storage services from an underground storage facility at Jackson Prairie near
Chehalis, Washington, and an LNG facility at 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. 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 an additional 52,000 therms per day of
year-round upstream capacity, plus 390,000 therms per day of recallable capacity and supply. The
contracts for 52,000 therms per day of year-round capacity expire in July 2009. Two of the three
recallable capacity/supply contracts are renewed on a year-to-year basis, while the third expires in
2010 at which time we would expect to renew annually.
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
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gas flows are bi-directional and it 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 currently developing plans to
build a pipeline project (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 that currently move through the Northwest Pipeline system (See
Part II, Item 7., “2009 Outlook”).
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.
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 previously extended into 2009 for
approximately 350,000 therms per day of firm transportation capacity from the U.S. Rocky Mountain
region. In February 2008, we extended the term of this contract through 2044. Also in February 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.
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 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 NOVA system in British Columbia and Alberta,
allowing purchases to be made from the gas fields of Alberta, Canada.
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Integrated Resource Plan
The OPUC and WUTC have implemented IRP processes under which utilities develop plans
defining alternative growth scenarios and resource acquisition strategies. Elements of these plans
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;
a primary goal of “least cost” service; and
consistency with state energy policy.
We filed our 2008 IRP with the OPUC and an update to our 2007 IRP with the WUTC in April
2008. In October 2008, we received notification from the WUTC that our 2007 IRP met the
requirements of the Washington Administrative Code. In January 2009, the OPUC acknowledged our
2008 IRP. Although 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. 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 50 percent, and our operating convenience and
environmental advantage over fuel oil, provides the potential for continuing growth from residential
and commercial conversions. In 2008, 9,609 net new residential customers were added, primarily from
single- and multi-family new construction, but also from the conversion of existing homes from oil,
electric or propane appliances to natural gas. The net increase of all new customers added in 2008 was
10,329. This represents a 12-month growth rate of 1.6 percent, which is above the national average for
local gas distribution companies as reported by the American Gas Association. On an annual basis,
residential and commercial customers typically account for about 55 percent of our utility’s total
volumes delivered and about 85 percent of gross operating revenues, while industrial customers
account for about 45 percent of volumes and about 13 percent of gross revenues. The remaining 2% of
gross operating revenues is derived from miscellaneous services and other regulatory charges.
12
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 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 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, we 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 quality 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. 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.
We redesigned our industrial rates in Oregon and Washington as part of our general rate cases
in 2003 and 2004, respectively, in order to better reflect relative costs of service and to become more
competitive in the industrial market. In August 2006, the OPUC and WUTC approved tariff changes to
the service options for our industrial accounts. The changes set out additional parameters that give us
more certainty in the level of gas supplies we will need to purchase in order to serve this customer
group. The parameters include an annual election cycle period, special pricing provisions for
out-of-cycle changes and the requirement that 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
under our regulatory tariff.
We have negotiated special transportation service agreements with several of our largest
industrial customers. These special 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
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.
13
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.
Currently, 3 percent of our consolidated assets and 12 percent of our consolidated net income in
2008 are related to the gas storage business segment. For each of the years ended December 31, 2008,
2007, and 2006, this business segment derived a majority of its revenues from multi-year contracts
with less than 10 customers taking 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 Bcf, or 56
percent of storage capacity, is currently used by our utility, and the remaining 7 Bcf, or 44 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, 2008, 2007 and
2006.
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.
We plan to move ahead with construction later this year, subject to market conditions and our ability to
obtain regulatory approvals (see “Gill Ranch,” below).
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 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 excess utility storage and related transportation capacity.
Excess capacity is usually available during the spring and summer months when the demand for gas by
utility customers is low.
Customers. Our gas storage business segment generally enters into contracts with customers for
firm storage capacity for terms ranging from one to 10 years. Currently, our 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
contracted 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 April 2009 through March 2015, with the largest customer’s contract expiring in March
2015.
14
Competitive conditions. Our existing 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 and marketers.
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 FERC, except that these customers
are located and served in Oregon.
Gill Ranch. In September 2007, we announced a joint project with Pacific Gas & Electric
Company (PG&E) to develop a new underground natural gas storage facility at Gill Ranch near
Fresno, California (Gill Ranch). We formed a wholly-owned subsidiary of NW Natural to develop and
operate the facility, Gill Ranch Storage, LLC. Our subsidiary will initially own 75 percent of the
project, and PG&E will own 25 percent. The initial development of this new storage facility is
expected to provide approximately 20 Bcf of underground gas storage capacity and will include
approximately 27 miles of transmission pipeline when the initial phase is completed. We estimate our
75 percent share of the total project cost for the initial phase of development, which began in 2008 and
is expected to continue through 2010, to be between $160 million and $180 million. In July 2008, Gill
Ranch filed an application with the California Public Utilities Commission (CPUC) for a Certificate of
Public Convenience and Necessity. If granted, Gill Ranch will be subject to CPUC regulation with
respect to rates and will require regulatory approvals for certain activities, including but not limited to
securities issuance, terms of services, systems of accounts, lien grants and sales of property. We expect
the initial phase of Gill Ranch to be in-service by late 2010.
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., “2009 Outlook—Strategic Opportunities—
Pipeline Diversification,” below) and pipeline assets in NNG Financial Corporation, as well as some
operating and non-operating expenses of the parent company that cannot be charged to utility
operations. Until recently, this segment also had equity investments in several windpower and solar
electric generating projects in California and a Boeing 737 aircraft leased to a commercial airline. The
aircraft investment was sold in April 2008, and the windpower and solar investments were sold in
years prior to 2008. Approximately 1 percent of our consolidated assets and about 3 percent of 2008
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, 2008.
15
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 and the FERC. The OPUC and WUTC also
regulate our issuance of securities. Approximately 90 percent of our utility operating revenues are
derived from Oregon customers, and the balance is derived from Washington customers.
We periodically file general rate case and rate tariff requests with the OPUC, WUTC and FERC
to change the rates we charge our utility and storage customers. 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 on December 26, 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. In
the future, we may be subject to regulation in other states, such as California, resulting from our
strategic investments such as Gill Ranch. For further information, see Part II, Item 7., “Results of
Operations—Regulatory Matters,” and “Gas Storage—Gill Ranch,” 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;
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 tanks (Central
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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
12, for a further discussion of potential environmental responses, related costs and regulatory and
insurance recovery.
Future Environmental Issues
We recognize that our business is likely to face 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 the 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.
The outcome of 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, additional charges to
fund energy efficiency activities, or other regulatory actions. These actions could result in increased
costs associated with operating and maintaining our facilities, could increase other costs to our
business and could impact the prices we charge our customers. Because natural gas is a fossil fuel with
low carbon content, it is possible that future carbon constraints could create additional demand for
natural gas, both for electric production and direct use in homes and businesses.
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. In 2008, our current President and CEO was appointed to the newly formed
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, 2008, our workforce consisted of 717 members of the Office and Professional
Employees International Union (OPEIU), Local No. 11, AFL-CIO, and approximately 400
management level and other non-bargaining employees. Our labor agreement (Joint Accord) with
members of OPEIU that covers wages, benefits and working conditions extends to May 31, 2009, and
thereafter from year to year unless either party serves notice of its intent to negotiate modifications to
the collective bargaining agreement. Each party has served notice of intent to negotiate the terms of an
agreement prior to the May 31, 2009 expiration date.
Additions to Infrastructure
We expect to make a significant level of capital expenditures for additions to utility and 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 2009, utility capital expenditures are estimated to be between $100 and $110 million, and non-utility
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capital investments are estimated to be between $50 and $70 million for business development projects
that are currently in process. For the years 2009-2013, capital expenditures for the utility are estimated
to be between $450 and $500 million, while the amount for business development investments after
2009 will depend largely on future decisions about potential opportunities in gas storage and pipeline
projects.
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. 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 on 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.
Our Chief Executive Officer certified to the New York Stock Exchange (NYSE) on May 23,
2008 that, as of that date, he was not aware of any violation by the company of the NYSE’s corporate
governance listing standards, and that we had filed with the SEC, as Exhibits 31.1 and 31.2 to our
Annual Report on Form 10-K for the year ended December 31, 2007, the certificates of the Chief
Executive Officer and the Chief Financial Officer certifying the quality of NW Natural’s internal
control over financial reporting and public disclosures. For the year-ended December 31, 2008, the
certificates of the Chief Executive Officer and the Chief Financial Officer are filed with this report as
Exhibits 31.1 and 31.2.
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,” and other documents we
file with the SEC. This list is not exhaustive and our management places no priority or likelihood based
on their order of presentation.
Economic risk. Changes in the economy and in the financial markets may have a negative
impact on our financial condition and results of operations.
The global credit and financial markets have been experiencing significant disruption and
volatility in recent months. At the same time the U.S. economy has slowed, unemployment rates are
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rising, and there has been an increase in mortgage defaults and a decrease in the value of homes and
investment assets, which has adversely affected the income and financial resources of many domestic
households. It is unclear whether the federal responses to these conditions will lessen the severity or
duration of this economic downturn. Our operations 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 and 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 rates and charges, the issuance of securities, services and
facilities, terms of customer services, system of accounts, investments, safety standards, transactions
with affiliated interests and other matters. In addition, FERC has regulatory authority over our
interstate gas storage services, and the CPUC will have regulatory authority over our Gill Ranch gas
storage development and 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 return on our investment. We 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
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. Early in 2008, we saw natural gas
prices rise to record high levels as demand grew, especially for new electric power generation, which
was outpacing North American gas production. Then during the second half of 2008, the price of
natural gas fell significantly as our national economy fell into a recession and demand for natural gas
declined while North American gas production increased. There are a number of external factors that
affect the balance of natural gas supply and demand, including the level of gas imports, regional
accessibility to gas supplies, supply disruptions, changes in the global energy markets, the availability
of pipeline capacity to transport natural gas from region to region and changes in general economic
conditions. The cost we pay for natural gas is generally passed through to our customers through an
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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
materially 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.
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 actual purchased gas costs and the actual
recoveries of gas costs in rates be recognized as current income or expense (see Part II, Item 7.,
“Results of Operations—Regulatory Matters—Rate Mechanisms”). Accordingly, higher gas costs than
those assumed in setting rates can adversely affect our operating cash flows, liquidity and results of
operations, until such costs are recovered from customers. 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 business.
Our ability to obtain adequate and cost effective short-term and long-term financing depends on
our credit ratings as well as the liquidity and stability of financial markets. Our businesses rely on
access to capital markets, including the commercial paper 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. A negative change in our ratings by credit rating agencies could
adversely affect our financing cost, liquidity and access to capital. Additionally, downgrades in our
current credit ratings below investment-grade could cause additional delays in accessing the credit
markets by the utility while we seek supplemental regulatory approval from the OPUC. Disruptions in
the capital and credit markets could also adversely affect our ability to access short-term and long-term
capital. 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. Longer 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 may negatively impact our
ability to run the business and make strategic investments.
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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.
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 and other financial market risks. We
attempt to manage these exposures and mitigate our risks through enforcement of established risk
limits and risk management procedures, including hedging activities that are in accordance with our
derivatives policies. 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 result in a material adverse effect on
our operating revenues, costs, derivative assets and liabilities, and operating cash flows.
We cannot and 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 a material
adverse effect on our operating revenues, costs, derivative assets and liabilities, and operating cash
flows. 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
hedged than we anticipated. Additionally, if our derivative instruments and hedging transactions do not
qualify for hedge accounting under Statement of Financial Accounting Standards (SFAS) No. 133,
“Accounting for Derivative Instruments and Hedging Activities,” our hedges may not be effective and
our results of operations, cash flows and financial condition could be adversely affected.
We also have credit related exposure to financial derivative counterparties. In general, we
require our counterparties to have a high level 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 by counterparties, an actual default by a particular counterparty could have a greater impact
than we estimated. Additionally, under most of our hedging arrangements, any downgrade of our
senior secured long-term debt credit rating below investment grade 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 draws from our borrowing facilities.
Customer growth risk. Our results of operations may be negatively affected if we are unable to
sustain customer growth rates in our local gas distribution business.
Our 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. Should there be continued weakness in the new housing market, a slowdown in the conversion
market or declining use of natural gas by our residential and commercial customer base, there could be
an adverse long-term impact on our utility margin, earnings and cash flows.
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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 and propane. We also compete with suppliers of electricity and fuel oil for
commercial applications. In the industrial market, we compete with all forms of energy suppliers.
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. Also, technological improvements in other
energy sources could erode our competitive advantage. If natural gas prices continue to rise relative to
other energy sources, it may negatively affect our ability to attract new customers, and our residential,
commercial and industrial customers may use alternative sources of energy or bypass our systems in
favor of contracts with lower per-unit costs, which could have a negative impact on our customer
growth rate and results of operations.
Additionally, 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 all of
the natural gas we store and deliver, and limitations on our ability to obtain supplies could have a
material impact on our financial results.
Our ability to provide natural gas for current and future sales depends upon our ability to obtain
and deliver supplies of natural gas, 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 the drilling of new wells and
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 materially 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 and it 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. Our results of operations may be negatively impacted if there is a rupture in the pipeline and we
incur costs associated with actions taken to mitigate service disruptions.
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.
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Business development projects involve many risks. We are in the early development stages on
two strategic business development projects: the Gill Ranch gas storage facility in California, and the
Palomar gas transmission pipeline in Oregon. We may also engage in other business development
projects in the future. 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 market prices; and operating cost
increases. Additionally, natural gas storage and gas 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 lenders at reasonable interest
rates. If the current tight credit markets persist or become more inaccessible, we may be unable to
acquire the necessary financing to 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, secure acceptable financing, 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, results of operations and cash flows.
Joint partner risk. Investing in business development projects through partnerships, joint
ventures or other business arrangements decreases our ability to manage certain risks.
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 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 results of operations, financial
condition 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 some of these 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 could adversely affect our results of operations and financial
condition. In addition, disputes may arise between potentially responsible parties and regulators as to
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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.
We cannot predict with certainty the amount or timing of future expenditures related to
environmental investigation and remediation that may be required 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. There are also 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 results of operations, particularly if those costs are not fully recoverable from
customers.
Global climate change legislation risk. Management expects that future legislation may
impose carbon constraints to address global climate change exposing us to regulatory and financial
risk.
There are a number of new federal and state legislative and regulatory initiatives being
proposed and adopted in an attempt to control or limit the effects of global warming and overall
climate change, including greenhouse gas emissions such as carbon dioxide. The outcome of federal
and state actions to address climate change could result in a variety of regulatory programs including
potential new regulations, additional requirements to fund energy efficiency activities, or other
regulatory actions. These actions could result in increased compliance and other costs, additional
operating restrictions, and could impact the prices we charge our customers, which could adversely
affect our business practices, financial condition or results of operations.
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
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 cold weather could
adversely affect our utility margin in the short-term as we may be required to purchase gas at spot rates
in a rising price market to obtain sufficient volumes to fulfill customer requirements. 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. Oregon customers may opt out of the
mechanism. Approximately 10 percent of our residential and commercial customers are in Washington
where we do not have a weather normalization mechanism or conservation tariff. Furthermore,
continuation of the weather normalization mechanism and conservation tariff in Oregon after October
2012, are 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.
Higher gas costs and rates and an increasing national focus on energy conservation may result
in increased gas conservation by customers, which can decrease sales and adversely affect our results
of operations. The OPUC authorized our conservation tariff, which is designed to recover lost margin
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due to changes in residential and commercial customers’ consumption. The conservation tariff is
scheduled to expire in October 2012 (see “Results of Operations—Rate Mechanisms—Conservation
Tariff,” below). The failure of the OPUC to extend the conservation tariff in the future could adversely
affect our financial condition, cash flows and results of operations. 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, 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 substantial losses. The occurrence of any of these events may not be 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 national disasters, terrorist
activities and other extreme events to which we may not able to promptly respond.
National disasters, terrorist activities and other extreme events are a threat to our assets and
operations. Companies in our industry may face a heightened risk 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 capital, or impact our suppliers or our
customers directly. We maintain emergency planning and training programs to remain ready to respond
to extreme events. However, a slow or inadequate response to extreme events may have an adverse
affect on operations and earnings. We may not be able to obtain sufficient insurance to cover all risks
associated with national disasters, terrorist activities and other extreme 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 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 costs of providing such benefits is subject to changes in the market value of our
pension fund assets, changing demographics, including longer life expectancies of beneficiaries, an
expected increase in the number of eligible former employees over the next five to 10 years, increases
in healthcare costs, current and future legislative changes and various actuarial calculations and
assumptions. The actuarial assumptions used may differ materially from actual results due to changing
market and economic conditions, withdrawal rates, interest rates and other factors. These differences
may result in a significant 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 yields
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
25
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 cash flows and results of operations.
Workforce risk. Our business is heavily dependent on being able to attract and retain qualified
employees and to 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 bargaining agreement that will expire May 31, 2009. The
Company and the Union are expected to negotiate an agreement, but failure to reach an acceptable
collective bargaining agreement with the Union in a timely manner 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 terms of a revised collective
bargaining agreement may 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 effectively in today’s competitive marketplace.
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 we collect by more than $100,000 we are required to implement a rate
schedule with an automatic adjustment clause to refund or surcharge 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 negatively affect our results of operations. Tax law and its related regulations and case law are
inherently complex. 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
26
taxing authorities. Unforeseen changes in laws, regulations or adverse judgments may negatively affect
our financial condition and results of operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
We have no unresolved comments.
ITEM 2. 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 lease expires on May 31, 2018. Resource
centers are maintained on owned or leased premises at convenient points in the distribution system. We
own LNG storage facilities in Portland and near Newport, Oregon.
We hold interests in approximately 8,500 net acres of underground natural gas storage and
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.
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.
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 12, 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, 2008.
27
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
2008
High
$50.74
48.22
55.23
53.71
Low
$41.07
43.08
43.66
36.61
2007
High
$46.34
52.85
49.37
50.89
Low
$39.79
44.05
40.98
44.28
The closing quotations for our common stock on December 31, 2008 and 2007 were $44.23 and
$48.66, respectively.
(B) As of December 31, 2008, there were 7,673 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
2008
$0.375
0.375
0.375
0.395
$1.520
2007
$0.355
0.355
0.355
0.375
$1.440
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.
28
(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, 2008:
ISSUER PURCHASES OF EQUITY SECURITIES
Period
Balance forward
10/01/08-10/31/08
11/01/08-11/30/08
12/01/08-12/31/08
Total
(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)
1,645
21,275
1,349
24,269
$43.88
$47.83
$44.01
$47.35
2,124,528
-
-
-
2,124,528
$16,732,648
-
-
-
$16,732,648
(1) During the quarter ended December 31, 2008, 22,005 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, 2,264 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,
2008, 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, 2009 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, 2008, 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.
29
ITEM 6. SELECTED FINANCIAL DATA
Thousands, except per share amounts and
ratio of earnings to fixed charges
2008
For the year ended December 31,
2005
2006
2007
2004
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
$ 566,840
298,943
46,579
68,978
$ 555,312
298,800
54,567
74,876
$ 536,468
290,666
66,986
93,107
$ 471,502
250,287
64,507
100,740
$ 383,067
200,424
45,259
55,380
981,340
14,288
1,760
21,784
1,019,172
656,504
25,072
337,596
18,619
983,555
14,191
5,996
12,228
1,015,970
639,094
25,001
351,875
17,167
987,227
12,800
—
161
1,000,188
648,081
24,840
327,267
12,909
887,036
10,755
—
2,862
900,653
563,772
21,633
315,248
9,745
684,130
12,655
—
4,160
700,945
399,176
16,865
284,904
6,591
Net operating revenues
$ 356,215
$ 369,042
$ 340,176
$ 324,993
$ 291,495
Net income
$
69,525
$
74,497
$
63,415
$
58,149
$
50,572
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
26,438
26,594
26,821
26,995
27,540
27,657
27,564
27,621
27,016
27,283
$
$
$
2.63
2.61
1.52
$
$
$
2.78
2.76
1.44
$
$
$
2.30
2.29
1.39
$
$
$
2.11
2.11
1.32
$
$
$
1.87
1.86
1.30
Total assets - at end of period
$2,378,152
$2,014,061
$1,956,856
$2,042,304
$1,732,195
Long-term debt
Ratio of earnings to fixed charges
$ 512,000
3.76
$ 512,000
3.92
$ 517,000
3.40
$ 521,500
3.32
$ 484,027
3.02
(1) Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation as described in Part II, Item 7.,
“Business Segments - Utility Operations - Regulatory Adjustment for Income Taxes Paid.”
30
SELECTED FINANCIAL DATA (continued)
Thousands, except customer and gas cost per therm data
2008
2007
2006
2005
2004
For the year ended December 31,
Capitalization - at end of period
Common stock equity
Long-term debt
Total capitalization
$ 628,373
512,000
$ 594,751
512,000
$ 599,545
517,000
$ 586,931
521,500
$ 568,517
484,027
$1,140,373
$1,106,751
$1,116,545
$1,108,431
$1,052,544
Gas sales and transportation deliveries (therms):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Total gas sales
Transportation
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
352,356
222,875
62,843
104,278
742,352
389,514
Total volumes delivered
1,260,751
1,214,969
1,192,649
1,157,567
1,131,866
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)
594,481
61,756
625
180
136
657,178
580,346
60,749
634
189
128
642,046
564,700
59,889
650
197
99
625,535
545,163
58,914
666
201
78
605,022
525,976
57,973
629
178
106
584,862
4,576
7%
4,374
3%
721
4,300
86.56
687
4,110
75.00
4,089
(4%)
678
4,052
75.37
4,178
(2%)
682
3,972
71.42
3,853
(10%)
670
3,844
56.60
31
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, 2008, 2007 and 2006.
Unless otherwise indicated, references in this discussion to “Notes” are to the Notes to Consolidated
Financial Statements in this report.
The consolidated financial statements include 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 consist of
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) and our other regulated and non-regulated investments
and business activities (other segment) (see “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).
Executive Summary
Highlights of 2008:
• Consolidated net income was $69.5 million, or $2.61 per share;
• Net operating revenues decreased 3 percent from $369.0 million to $356.2 million, largely
due to a $17.6 million swing in our utility’s sharing of higher gas costs;
• Operations and maintenance expense decreased 6 percent or $7.1 million;
• Cash flow from operations decreased $148.9 million due to temporary working capital
requirements, while our credit and liquidity position remained strong;
• General rate case was approved in Washington with a $2.7 million increase in annual
revenues, effective January 1, 2009;
• Permit applications were filed for our gas storage project in California and our gas
transmission pipeline project in Oregon, keeping these strategic investment opportunities on
track for potential development over the next few years;
• We ranked number one in the nation among gas utilities in the 2008 J.D. Power and
Associates Gas Utility Residential Customer Satisfaction Survey; and
• We raised the quarterly common stock dividend by 5 percent to $0.395 per share in the
fourth quarter of 2008, making this the 53rd consecutive year of increasing dividends paid to
shareholders.
Our business primarily consists of our regulated utility and gas storage operations. Factors
critical to the success of the utility business include: maintaining a safe and reliable distribution
system; 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
32
reasonable and timely manner. Our utility 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 gas storage business include: developing additional storage
capacity at competitive market prices; retaining existing customers or being able to market 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 charges rates that 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 will be subject to
regulation by the California Public Utilities Commission (CPUC), upon completion of certain
milestones (see “2009 Outlook—Strategic Opportunities—Gas Storage Development,” below).
2009 Outlook
In 2009, 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.
Business Improvements. We are developing and implementing new technology into our
operations while honing the new processes established by the changes to our operating model over the
last several years. Our goal is to integrate, consolidate and streamline operations and support our
employees with new technology tools that should enable us to become more effective and efficient. We
intend to continue developing new technology such as: an enterprise resource planning system, which
provides an integrated comprehensive suite of business application software to more efficiently process
and manage information in all parts of our business; continued deployment of our new automated
dispatching system throughout the business, which provides integrated planning and scheduling with
global positioning capabilities to more effectively collect and distribute data to employees in remote
locations; and completing the installation of our automated meter reading system, which will convert
the remaining customer meters so that all of our meters can be read electronically by the end of 2009.
We expect these and other new technologies to continue supporting our new operating model, which
re-aligned our operating functions into key process areas such as customer services, energy supply and
gas delivery, to help centralize and standardize all of our business operations. For further discussion,
see “Strategic Opportunities,” below.
Strategic Position. In our rapidly changing business environment, we remain focused on
creating shareholder value while balancing the interests of our customers, employees and the
communities we serve. In doing so, we intend to develop and re-work plans in response to our
changing business environment, including potential climate change legislation as well as ongoing
economic, regulatory, business development and workforce challenges and opportunities. For further
discussion, see “Issues, Challenges and Performance Measures,” and “Strategic Opportunities,” below.
Business Development. In addition to exploring new growth opportunities, we intend to
continue advancing key natural gas infrastructure investments during 2009, including our gas
transmission pipeline project in Oregon and our gas storage project in California. For further
discussion of these two projects, see “Strategic Opportunities,” below.
Organizational Effectiveness. Our employees continue to be our most highly valued resource.
We intend to continue supporting our employees with a positive work environment, providing
33
development training, and developing new technologies to achieve our goals and facilitate
improvements to our operating model. For further discussion see “Strategic Opportunities,” below.
Issues, Challenges and Performance Measures
Managing the business in a period of gas price volatility. Our gas acquisition strategy is
primarily designed to secure sufficient supplies of natural gas to meet the needs of our utility’s
residential, commercial and industrial customers on firm service. Equally important, however, is our
strategy to hedge gas prices for a significant portion of our annual purchase requirements based upon
our utility’s gas load forecast for core utility customers. We have hedged gas prices for the majority of
our gas purchases for the gas contract year that began on November 1, 2008, and we believe we have
sufficient supplies of natural gas to meet the needs of our core utility customers. Although gas prices
reached historically high levels during the third quarter of 2008, the price of natural gas has declined
significantly in recent months and is currently below the prices embedded in our customers’ rates
through our annual purchased gas adjustment (PGA). Gas costs lower or higher than those set in the
PGA may positively or negatively impact earnings, respectively, due to an incentive sharing
mechanism in Oregon. Higher gas costs are also likely to affect our competitive advantage because
they could reduce our ability to add residential and commercial customers and potentially cause
industrial customers to shift their energy needs to alternative fuel sources. In October 2008, the OPUC
approved a change to the PGA incentive sharing mechanism that allows us to select a cost-sharing ratio
annually. The PGA cost-sharing ratio, along with gas hedging strategies and inventories in storage,
enables us to manage and reduce earnings risk exposure due to higher gas costs. We believe the
modification to the Oregon PGA better aligns customer and shareholder interests. In Washington,
where we recover 100 percent of our actual gas purchase costs from customers, there has been no
change to the PGA mechanism (see “Results of Operations—Regulatory Matters—Rate
Mechanisms—Purchased Gas Adjustment,” below).
Economic weakness and financial market stress. The overall weakness in the U.S. economy,
including disruption in the global credit and financial markets, increasing numbers of foreclosures and
bankruptcies, lower rates of new housing construction, and volatility in energy prices, has resulted in
significant negative pressure on consumer demand and business spending. These conditions could have
a negative impact on our financial results including certain key performance measures such as margins,
customer growth rates, bad debt expense, and net interest charges. Our customer growth rate, which in
recent years has slowed but continues at a rate above the national average, declined to 1.6 percent
during 2008 compared to 2.4 percent in 2007. Based on current market conditions, we expect customer
growth rates in 2009 to continue at or near 2008 levels, or possibly lower if economic conditions
deteriorate further, but our growth rate should remain above the national average due to a relatively
low market penetration of natural gas in our service territory, the forecasted population growth in our
service territory, the potential for environmental initiatives in Oregon and Washington that could favor
natural gas as an energy source, and our efforts to convert existing homes from other heating fuels to
natural gas.
Our funding for strategic investment opportunities is dependent upon our ability to access
capital markets and maintain working capital sufficient to meet operating requirements. We intend to
continue focusing on: maintaining a strong balance sheet; providing sufficient liquidity resources;
monitoring and managing critical business risks; and securing, as needed, proceeds from the issuance
of equity or long-term debt securities in order to fund utility and business development capital
expenditures. To help mitigate the effect of the negative economic and capital market trends referred to
34
above, we expect to manage costs, extend short-term debt maturities, maintain higher cash balances,
increase the aggregate commitment amount under existing or new credit facilities as needed, and
access capital markets to secure proceeds from the issuance of long-term securities for capital
expenditure requirements. If we are unable to secure financing to fund certain strategic opportunities,
we may look at potentially re-prioritizing the use of existing resources or consider delaying
investments until market conditions improve.
We believe that, despite the current economic and credit market environment, our financial
condition, including our liquidity position, is strong and we can access capital at reasonable costs. See
Part I, Item 1A., “Risk Factors,” above and “Financial Condition—Liquidity and Capital Resources,”
below.
Strategic Opportunities
Business Process Improvements. To address our economic and competitive challenges, we
intend to re-assess business processes for continuous improvements. Our goal is to integrate,
consolidate and streamline operations and support our employees with new technology tools that
enable us to become more effective and efficient. In 2008, we implemented the first phase of our new
enterprise resource planning (ERP) system, and in February 2009 we implemented the second phase.
This new ERP system provides a comprehensive suite of business application software that interfaces
with our existing customer information and automated dispatching systems. We expect this new ERP
system to improve overall operating efficiencies by automating:
•
•
•
the integration of systems and data;
the control procedures with auditable financial and operational workflows; and
certain areas of our monthly closing and financial reporting process.
In 2006, we automated the reading of gas meters on approximately one-third of our customers’
meters. The meters equipped with this technology now electronically transmit usage data to receiving
devices located in our vehicles as they are driven in the area, substantially reducing the labor costs
associated with manually reading those customer meters. In 2008, we initiated a project to automate
the reading of gas meters (AMR) for our remaining customers. The capital cost of this project is
estimated to be $30 million, and in January 2009 we filed for regulatory recovery of this investment.
Also in 2008, we initiated an automated dispatching system, which provides integrated planning and
scheduling with global positioning system capabilities to more effectively collect and distribute data.
These technology investments and other initiatives are expected to facilitate process improvements and
contribute to long-term operational efficiencies throughout NW Natural.
Pipeline Diversification. Currently, we depend on a single interstate pipeline company to ship
gas supplies to our system. Palomar Gas Transmission, LLC, (Palomar) is a wholly-owned subsidiary
of Palomar Gas Holdings, LLC, (PGH). PGH is owned 50 percent by NW Natural and 50 percent by
TransCanada Gas Transmission Northwest’s (GTN). Palomar is seeking to build and operate a
217-mile natural gas transmission pipeline in Oregon to serve our utility and the growing markets in
Oregon and other parts of the western United States. The Palomar pipeline would extend west from an
interconnection with GTN’s existing interstate transmission mainline near Madras, Oregon to an
interconnection with NW Natural’s gas distribution system near Molalla, Oregon and then extend
further west to additional interconnections including a possible connection to one of the several
liquefied natural gas (LNG) terminals proposed to be built on the Columbia River. Palomar would
35
diversify NW Natural’s 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. Palomar would also provide our utility customers with access
to a new source of gas supply if an LNG terminal is built on the Columbia River. The Palomar pipeline
would be regulated by the FERC. In December 2008, Palomar filed for a Certificate of Public
Convenience and Necessity with the FERC.
Palomar continues to work on the planning and permitting phase of the project, which is
expected to extend through 2010. The total cost for planning and permitting is estimated to be between
$40 million and $45 million, 50 percent of which is our investment based on our ownership interest. At
December 31, 2008, the amount we had invested was $14.2 million. 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 approximately $350 million and $400 million.
During 2009 and 2010, 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. 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. We will continue to assess project risks and evaluate the project costs and fair value of
our investment on a quarterly basis, including a valuation of the available credit support.
Gas Storage Development. In September 2007, we announced a joint project with Pacific
Gas & Electric Company (PG&E) to develop an underground natural gas storage facility near Fresno,
California. We formed a wholly-owned subsidiary, Gill Ranch, to plan, develop and operate the
facility. In July 2008, Gill Ranch filed an application with the CPUC for a Certificate of Public
Convenience and Necessity. In December 2008, the CPUC indicated that our application qualified for
a Mitigated Negative Declaration, which allows an expedited review process. We expect to establish
the application review schedule with the CPUC early in 2009 and to receive a decision on our
application by the end of 2009. Gill Ranch will become subject to CPUC regulation regarding various
matters including, but not limited to, securities issuances, lien grants and sales of property. We
estimate our share of the total cost of this project to be between $160 and $180 million. Our share
represents 75 percent of the total cost of the initial phase of storage development for an estimated 20
Bcf of gas storage capacity and approximately 27 miles of gas transmission pipeline during the 2008 to
2010 period. The initial phase of gas storage at Gill Ranch is currently scheduled to be in-service by
late 2010.
Earnings and Dividends
Net income was $69.5 million, or $2.61 per share, for the year ended December 31, 2008,
compared to $74.5 million, or $2.76 per share, and $63.4 million, or $2.29 per share, for the years
ended December 31, 2007 and 2006, respectively. Returns on equity for these three years were 11.4
percent, 12.5 percent and 10.7 percent, respectively.
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;
36
•
•
•
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;
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.
2007 compared to 2006:
Positive factors contributing to increased earnings were:
•
•
•
•
•
a $9.7 million increase in utility margin from higher sales volumes to residential and
commercial customers due to customer growth;
a $6.0 million increase in utility margin from a regulatory adjustment for income taxes paid;
a $4.0 million increase in utility margin from our regulatory share of gas cost savings, up
from $8.1 million in 2006 to $12.1 million in 2007;
a $5.8 million increase in utility margin from temporary mark-to-market adjustments on
derivative contracts, with a $2.9 million gain realized in 2007 and a $2.9 million loss
realized in 2006; and
a $4.2 million increase in margin from gas storage operations, due to an expansion of firm
storage capacity and higher revenues sharing from asset optimization.
Partially offsetting the above positive factors were:
•
•
•
a $3.9 million increase in depreciation expense, primarily related to increased utility plant in
service;
a $5.9 million increase in operations and maintenance expense due to higher bonuses tied to
improved operating results and increases for certain strategic initiatives including utility
maintenance projects and training; and
a $7.8 million increase in income tax expense related to higher taxable income.
Dividends paid on our common stock were $1.52 a share in 2008, compared to $1.44 a share in
2007 and $1.39 a share in 2006. The current indicated annual dividend rate is $1.58 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
37
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;
income taxes; and
environmental contingencies.
Management has discussed the 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, certain accounting principles, primarily
Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain
Types of Regulation,” 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.
SFAS No. 71 requires us to account for these types of deferred expenses (or deferred revenues) as
regulatory assets (or regulatory liabilities) on the balance sheet. When we are allowed to recover these
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 SFAS No. 71,
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.
We continue to apply SFAS No. 71 in accounting for our regulated utility operations. Future
regulatory changes or changes in the competitive environment could require us to discontinue the
38
application of SFAS No. 71 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 regulatory and competitive conditions, we believe that it is
reasonable to expect continued application of SFAS No. 71 for our regulated activities, and that all of
our regulatory assets and liabilities at December 31, 2008 and 2007 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, 2008 and 2007 were $102.7 million and $78.0 million, respectively. The
increase in accrued unbilled revenues at year-end 2008 was primarily due to higher volumes reflecting
colder weather and higher gas prices included in customer rates. If the estimated percentage of unbilled
volume at December 31, 2008 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 $4.4 million,
$0.4 million and $0.4 million, respectively.
Utility revenues may 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 refund or surcharge is accrued based on the
estimated difference between income taxes paid and income taxes authorized to be collected in rates
for the tax year (see “Results of Operations—Business Segments – Utility Operations—Regulatory
Adjustment for Income Taxes Paid,” below).
Non-utility revenues, derived primarily from our gas storage business segment, are recognized
upon delivery of the service to customers. Revenues from asset optimization, which are included in our
gas storage segment, are recognized when services are provided by the independent energy marketing
company in accordance with our contractual agreement. Our current asset optimization agreement
includes guaranteed amounts which are recognized pro-rata on a monthly basis over the contract term.
Accounting for Derivative Instruments and Hedging Activities
Our financial derivatives and 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 SFAS
No. 71 (see Note 1, “Industry Regulation”), and no gain or loss is recognized in current income. The
gain or loss from the fair value of a derivative instrument that is subject to regulatory deferral is
39
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 gains and losses is recorded in accordance with SFAS No. 133, “Accounting for
Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138 and SFAS No. 149,
collectively referred to as SFAS No. 133 (see Note 1, “Derivatives” and “Industry Regulation”).
Derivative contracts outstanding at December 31, 2008 were measured at fair value using models or
other market accepted valuation methodologies derived from observable market data. The 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, 2008 and 2007, see Note 11.
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. Our interest rate swap qualifies
for hedge accounting under SFAS No. 133, assuming the swap is highly effective.
Derivative hedge contracts are subject to a hedge effectiveness test to determine the financial
statement treatment of each specific derivative. As of December 31, 2008, 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 SFAS No. 133 to
determine the hedge effectiveness of our interest rate swap which qualifies as a cash flow hedge. We
extended the effective date of our interest rate swap from December 1, 2008 to April 1, 2009 which
resulted in an ineffectiveness of $1.5 million. In accordance with SFAS No. 71, we have reclassified
this amount to regulatory assets. The ineffectiveness for all other derivative contracts is determined
using the dollar offset method under SFAS No. 133. The effectiveness test applied to financial
derivatives is dependent on the type of derivative and its use.
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
Subtotal on commodity—utility
Net gain (loss) on foreign currency forward purchases—utility
Total realized net gain (loss)
2008
$34,256
1,527
2007
2006
$(41,954) $(18,849)
(1,160)
(662)
35,783
(728)
(42,616)
662
(20,009)
355
$35,055
$(41,954) $(19,654)
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 contracts 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 11).
40
Accounting for Pensions
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 employee
postretirement 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, the
Retirement Plan for Non-Bargaining Unit Employees and the Welfare Benefits Plan for
Non-Bargaining Unit Employees were closed to anyone hired or rehired. Instead, non-bargaining unit
employees hired or re-hired after December 31, 2006 are provided an enhanced Retirement K Savings
Plan benefit. Benefits provided to bargaining unit employees under the retirement plan for bargaining
unit employees were not affected by these changes.
Net periodic pension costs (pension costs) and projected benefit obligations (benefit
obligations) are determined in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,”
using a number of key assumptions including discount rates, rate of compensation increases, retirement
ages, mortality rates and the expected long-term return on plan assets (see Note 7). These key
assumptions have a significant impact on the amounts reported. Pension 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. The market-related valuation reflects
differences between expected returns and actual investment returns, which are recognized over a three-
year period from the year in which they occur, thereby reducing year-to-year volatility in pension
costs.
SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement
Plans,” requires balance sheet recognition of the overfunded or underfunded status of pension 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 benefit obligations. However, the pension costs relating to
certain NW Natural pension plans are recovered in utility rates based on SFAS No. 87, and as such we
received regulatory approval from the OPUC pursuant to SFAS No. 71 to record the overfunded or
underfunded status as a regulatory asset or regulatory liability, 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 assumptions, including evaluations
of relevant discount rates, an evaluation of expected long-term investment returns based on asset
classes and target asset allocations, and 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, 2008 measurement date, we reviewed and updated:
•
•
•
•
our pension discount rate assumptions from a range of 6.75 to 6.87 percent to a range of
6.44 to 6.72 percent. 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 rate of future compensation increases from a range of 4.0 to 5.0 percent to a
range of 3.5 to 5.0 percent;
our expected long-term return on plan assets remained unchanged at 8.25 percent; and
other key assumptions as needed.
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At December 31, 2008, our net pension liability (benefit obligations minus market value of plan
assets) for the two qualified defined benefit plans increased by $96.6 million compared to 2007. Poor
equity and bond market performance had a significant impact on the fair value of plan assets resulting
in the large increase in our unfunded pension liability. Changes in valuation assumptions impact our
benefit obligations. Benefit obligations at December 31, 2008 increased $7.4 million due to a decrease
in our discount rate assumptions and increased by $5.0 million due to updating our mortality tables.
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 rate of return assumption, 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, 2008, 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 (27.18) percent, 1.82 percent, 2.97 percent and 10.10 percent,
respectively.
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 pension costs and benefit
obligations to future changes in certain actuarial assumptions:
Thousands, except percent
Discount rate
Expected long-term return on plan assets
Change in
Assumption
Impact on
2008 Pension Costs
Impact on Benefit
Obligations at
Dec. 31, 2008
(0.25%)
(0.25%)
$785
$431
$7,809
N/A
The impact of a change in pension 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 SFAS No. 109, “Accounting for Income
Taxes,” and Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48),
“Accounting for Uncertainty in Income Taxes,” an Interpretation of SFAS No. 109, “Accounting for
Income Taxes,” which require that deferred tax assets and liabilities be recognized using enacted tax
rates for the effect of temporary differences between the book and tax basis of recorded assets and
liabilities. SFAS No. 109 and FIN 48 also require that deferred tax assets be reduced by a valuation
allowance if it is more likely than not that some portion or all of the deferred tax asset will not be
realized. Our net long-term deferred tax liability totaled $257.8 million at December 31, 2008. This
liability is estimated based on the expected future tax consequences of items recognized in the financial
statements. 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 other
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, 2008, we did not have a valuation allowance due to our
expectation that all of these assets will be realized.
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SFAS No. 109 also requires the recognition of additional 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, 2008 and 2007, we had regulatory assets representing
differences between book and tax basis related to pre-1981 property of $69.9 million and $68.6
million, respectively, and recorded an offsetting deferred tax liability for the same amounts (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).
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 SFAS No. 5,
“Accounting 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 $35.9 million as of December 31, 2008. 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 12).
43
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, WUTC and FERC. The OPUC and WUTC also regulate our issuance of
securities. In 2008, 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 September 1,
2003, the OPUC authorized rates to customers based on a return on shareholders’ 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 was consistent with a rate of return on total
long-term capitalization of 8.4 percent. These new customer rates went into effect on January 1, 2009.
Under these new rates, our annual revenue requirements will increase by approximately $2.7 million,
or 3 percent. Although we agreed not to file another general rate case in Washington before January
2010, the parties agreed that we may file separately for a decoupling mechanism upon completion of a
trial program currently being conducted by another utility, which is expected to be completed during
2009.
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
44
in December 2008 to obtain FERC approval to revise the depreciation rates associated with Mist assets
used to derive the cost-based interstate storage rates. In that proceeding, which is currently pending, we
are requesting FERC approval to revise the depreciation rates used for the Mist interstate storage
services to match the depreciation rates for the same assets that were recently adjusted under state
regulation. We do not expect the approval of these new depreciation rates to have a material impact on
our maximum rates approved by FERC, or any immediate impact on the actual rates currently charged
to interstate storage customers.
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 contractual arrangements to hedge the purchase price 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 2008, the OPUC and WUTC approved rate changes effective on November 1, 2008
under our PGA mechanisms. The effect of the rate changes was to increase the average monthly bills
of Oregon residential customers by 14 percent and those of Washington residential customers by 21
percent.
Additionally, in October 2008, the OPUC approved changes to our PGA incentive sharing
mechanism. Under the Oregon PGA mechanism, we collect an amount for purchased gas costs based
on estimates included in rates. If the actual purchased gas costs differ from the estimated amounts
included in rates, then we are required to defer that difference and pass it on to customers as an
adjustment to future rates. Under the prior Oregon PGA incentive sharing mechanism effective through
October 31, 2008, 67 percent of the difference was to be deferred such that the impact on current
earnings is either a charge to expense for 33 percent of the higher cost of gas sold, or a credit to
expense for 33 percent of the lower purchased gas costs.
Under the new Oregon PGA incentive sharing mechanism, effective November 1, 2008, 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. As was the case under the prior mechanism, we will be subject to
an annual earnings review to evaluate the utility’s financial performance. Under both the prior and the
new sharing mechanism, if earnings exceed a threshold level, then 33 percent of the amount above the
threshold will be deferred for future refund to customers. Under the prior Oregon PGA incentive
mechanism, effective through the end of October 2008, the deferral was 67 percent of gas cost
differences and the threshold level was equal to our authorized ROE of 10.2 percent plus 300 basis
points. Under the new mechanism, if we select the 80 percent deferral, we retain all of our earnings up
to 150 basis points above the currently authorized ROE, or if we select the 90 percent deferral, we
retain all of our earnings up to 100 basis points above the currently authorized ROE. For the PGA year
in Oregon beginning on November 1, 2008, we selected the 80 percent deferral of gas cost differences.
The earnings threshold is currently subject to adjustment up or down each year depending on
movements in long-term interest rates.
In 2008 and 2007, the earnings threshold after adjustment for long-term interest rates was 13.1
percent and 13.4 percent, respectively. No amounts were required to be refunded to customers as a
45
result of the 2007 earnings review, and we do not expect that any amounts will be required to be
refunded to customers as a result of the 2008 earnings review, which will be approved by the OPUC
during the second quarter of 2009. 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.
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
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 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—
Comparison of Gas Distribution 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 “Comparison of Gas Distribution
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. In May 2003, the OPUC
approved our request to defer unreimbursed environmental costs associated with certain named sites
including those described in Note 12. 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
46
environmental expenses. Through a series of extensions, this authorization has been extended through
January 25, 2009. We have requested another extension through January 2010, and that request is
currently pending. See Note 12.
Industrial Tariffs. In August 2006, the OPUC and WUTC approved tariff changes to the
service options for our major industrial customers. The changes set forth additional parameters that
give us more certainty in the level of gas supplies we will need to acquire to serve this customer group.
The parameters include an annual election period, special pricing provisions for out-of-cycle changes
and a requirement that customers on our annual weighted average cost of gas tariff complete the term
of their service election.
System Integrity Program. In July 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
Transportation’s Pipeline and Hazardous Materials Safety Administration. We record these costs as
either capital expenditures or regulatory assets, accumulate the costs over each 12 months ending
September 30, and recover the costs, subject to audit, through rate changes effective with the annual
PGA in Oregon. The rate treatment for these costs expired on September 30, 2008. In February 2009,
the OPUC approved a stipulated agreement to create a new, consolidated system integrity program
(SIP). The new SIP would integrate the older and the proposed programs into a single program. The
SIP also includes a component for a proposed distribution integrity management program, which will
be implemented following issuance of new federal regulations. Costs will be tracked into rates
annually, with recovery to be sought after the first $3.3 million of capital costs which are our
responsibility. An annual cap for expenditures will be approximately $12 million, with any
extraordinary costs above the cap to be approved with written consent of all parties.
The SIP applies to costs incurred in Oregon during the period from October 2008 to October
2011, or until the effective date of new rates adopted in the company’s next general rate case. We do
not have any special accounting or rate treatment for pipeline integrity costs incurred in the state of
Washington.
AMR Deferral Application. In 2006, we automated the reading of gas meters on approximately
one-third of our customers’ meters. In 2008, we initiated a project to automate the reading of gas
meters for our remaining customers. The capital cost of our AMR project is estimated to be $30
million, and in January 2009 we filed for approval to defer the costs associated with the AMR project.
This request is pending before the OPUC. If the request for deferral accounting is approved, we will
then seek approval to recover the deferred costs in our next PGA filing.
Depreciation Study. In December 2008, the OPUC and WUTC approved our filed depreciation
study and our request to change the amortization of our regulatory asset account balance on pre-1981
plant. These approvals specifically authorized the implementation of new depreciation rates in Oregon
and Washington, with corresponding decrease to customer rates effective January 1, 2009. The new
amortization rates on pre-1981 plant, with a corresponding increase to customer rates, became effective
January 1, 2009 in Washington and will be effective November 1, 2009 in Oregon. The implementation
of these new rates will have the effect of decreasing depreciation expense and increasing effective
income tax expense rates, both of which will be offset by a corresponding change in utility operating
revenues. In addition, in December 2008 we filed our depreciation study with FERC requesting approval
to apply these same new depreciation rates for our gas storage business assets. If approved, we expect the
new depreciation rates to be effective as of January 1, 2009. Our FERC filing is currently pending.
47
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.
2008 compared to 2007:
Total utility margin decreased $14.3 million or 4 percent in 2008 compared to 2007 even
though residential and commercial customers contributed an additional $7.1 million to margin in 2008,
including the effects of the weather normalization and decoupling mechanisms. Total utility volumes
sold and delivered in 2008 increased by 4 percent over last year due to the colder than average weather
and 1.6 percent customer growth. The major factors contributing to the decline in utility margin were
the $17.6 million swing in our regulatory share of higher gas costs, a $4.2 million decrease in
regulatory adjustments for income taxes paid and a $1.6 million decrease in margin from industrial
customers due to weaker 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 increased residential and commercial margins of $2.5 million for the
year ended December 31, 2007 based on weather that was 3 percent colder than average. Our
decoupling mechanism offset $4.9 million of residential and commercial margin losses in 2008, after
adjusting for price elasticity in the annual Oregon PGA filing, compared to a margin increase of $0.5
million in 2007.
2007 compared to 2006:
Total utility margin increased $24.6 million or 8 percent in 2007 compared to 2006 with
residential and commercial customers contributing an additional $9.7 million to margin in 2007,
including the effects of the weather normalization and decoupling mechanisms. The $1.0 million
decrease in margin from industrial customers in 2007 was partially offset by a decrease in other margin
adjustments from regulatory deferrals and amortizations and miscellaneous fees. Total utility volumes
sold and delivered in 2007 were about the same as in 2006. An increase in our regulatory share of gas
cost savings of $4.0 million and a regulatory adjustment related to income taxes paid of $6.0 million
also contributed to the increase in margin (see “Regulatory Adjustment for Income Taxes Paid,” and
“Cost of Gas Sold,” below).
Our weather normalization mechanism offset residential and commercial margin gains by $2.5
million for the year ended December 31, 2007 based on weather that was 3 percent colder than
average, compared to an increase of $2.3 million in added margin for the year ended December 31,
2006 based on weather that was 4 percent warmer than average. The decoupling mechanism added
$0.5 million to residential and commercial margin in 2007, after adjusting for price elasticity in the
annual Oregon PGA filing, compared to a margin decrease of $2.6 million in 2006.
48
The following table summarizes the composition of gas utility volumes and revenues for the
years ended December 31, 2008, 2007 and 2006:
Total utility volumes sold and delivered
1,260,751
1,214,969
1,192,649
45,782
2008
2007
2006
Favorable/(Unfavorable)
2008
vs. 2007
2007
vs. 2006
428,787
265,531
47,340
184,832
87,484
246,777
398,960
249,659
52,340
161,790
89,128
263,092
382,665
242,683
66,971
150,153
112,736
237,441
29,827
15,872
(5,000)
23,042
(1,644)
(16,315)
$ 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
$ 536,468
290,666
66,986
4,901
93,107
7,899
—
161
1,000,188
648,081
24,840
$ 11,528
143
(7,988)
443
(5,898)
(346)
(4,236)
9,556
3,202
(17,410)
(71)
16,295
6,976
(14,631)
11,637
(23,608)
25,651
22,320
$ 18,844
8,134
(12,419)
1,026
(18,231)
365
5,996
12,067
15,782
8,987
(161)
$ 337,596
$ 351,875
$ 327,267
$(14,279)
$ 24,608
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
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
Gain (loss) from gas cost incentive sharing
Other margin adjustments
$ 224,683
90,402
29,771
6,381
(5,505)
436
$ 213,698
85,960
31,333
4,966
12,135
(229)
$ 204,951
83,334
32,383
4,333
8,083
(5,473)
$ 10,985
4,442
(1,562)
1,415
(17,640)
665
(1,695)
(12,770)
4,422
(4,236)
$ 8,747
2,626
(1,050)
633
4,052
5,244
20,252
(4,778)
3,138
5,996
Margin before regulatory adjustments
Weather normalization mechanism
Decoupling mechanism
Regulatory adjustment for income taxes paid (1)
346,168
(15,266)
4,934
1,760
347,863
(2,496)
512
5,996
327,611
2,282
(2,626)
—
Utility margin
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)
$ 337,596
$ 351,875
$ 327,267
$(14,279)
$ 24,608
599,285
62,115
941
662,341
4,576
7%
589,676
61,397
939
652,012
4,374
3%
575,116
60,523
945
636,584
4,089
(4%)
9,609
718
2
10,329
14,560
874
(6)
15,428
(1) Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation as
described below under “Regulatory Adjustment for Income Taxes Paid.”
(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.
49
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. Beginning in 2006, this mechanism became effective for the period from
December 1 through May 15 of each heating season. Approximately 10 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
our customers, so that we do not have an incentive to encourage greater consumption contrary to
customers’ energy conservation efforts. In Washington, where the remaining approximately 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.
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 and economic
conditions in our service territory.
2008 compared to 2007:
•
•
operating revenues increased 1 percent due to a 7 percent increase in volumes, partially
offset by lower customer rates of 8 to 10 percent over the first 10 months of 2008;
volumes were 7 percent higher, primarily reflecting 1.6 percent customer growth and 5
percent colder weather; and
• margin was 2 percent higher, reflecting increased volumes from customer growth and from
colder weather for customers not covered by weather normalization (see “Cost of Gas
Sold,” below).
2007 compared to 2006:
•
•
operating revenues increased 3 percent, primarily due to a 4 percent increase in volumes;
volumes were 4 percent higher, primarily reflecting 2.4 percent customer growth and 7
percent colder weather; and
• margin before regulatory adjustments for weather normalization, decoupling and income
taxes paid was 4 percent higher, reflecting increased volumes from customer growth and
higher gas cost savings from our PGA incentive sharing mechanism in Oregon (see “Cost of
Gas Sold,” below).
Industrial Sales and Transportation
Industrial operating revenues include the commodity cost component of gas sold under sales
service but not to transportation service. Therefore, industrial customer switching between sales
service and transportation service can cause swings in operating revenues but generally our margins
are not affected because we do not mark up the cost of gas. As such, we believe margin is a better
50
measure of performance for the industrial sector. The primary factors that impact results of operations
in industrial sales and transportation markets are as follows:
2008 compared to 2007:
•
•
operating revenues decreased $13.8 million, or 10 percent, due to a transfer of customer
volumes from sales service to transportation and to lower sales rates during the first 10
months in 2008;
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 in margin from higher
margins to lower margin rate schedules and from customers that reduced their usage due to
the current economic environment, but this decrease was partially offset by a margin gain of
$0.8 million from curtailment charges for use by a small number of industrial customers
during cold weather.
2007 compared to 2006:
•
•
operating revenue decreased $29.3 million, or 17 percent, due to customers transferring
from sales service to transportation service where cost of gas is not a component in
operating revenues;
volumes delivered to industrial customers decreased 1.0 million therms, or less than 1
percent, reflecting a reduction in sales volumes of 38.2 million therms offset by an increase
in transportation volumes of 37.3 million therms; and
• margin decreased 3 percent, reflecting higher volumes under lower margin special
contracts.
Several large industrial customers transferred from sales service back to transportation service
in 2008. High natural gas prices can result from time to time in a number of our large industrial
customers switching from 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 to
serve those customers.
Regulatory Adjustment for Income Taxes Paid
The Oregon legislature passed legislation, effective January 1, 2006, to ensure that regulated
utility operations do not collect in rates more money for income taxes than the utility actually pays to
taxing authorities. Under this legislation, 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 record a refund due 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 record a surcharge due
from our Oregon utility customers.
For the 2006 tax year, we filed to recover $1.7 million through a surcharge to our Oregon utility
customers. This surcharge was primarily driven by higher income taxes paid on gains from gas cost
savings from our PGA incentive sharing mechanism in 2006 and strong operating results. The OPUC
51
approved our filing, and we collected a total of $1.9 million, representing a surcharge of $1.7 million
plus accrued interest of $0.2 million, from customers in June 2008. For the 2007 tax year, we filed to
recover $5.5 million through a surcharge to our Oregon utility customers. We have reached an
agreement in principle with OPUC Staff and other parties on that surcharge and are in the process of
finalizing a stipulation and supporting documentation. We expect to collect a total of $6.4 million,
representing a surcharge of $5.5 million plus accrued interest of $0.9 million. Again, this surcharge
was primarily driven by higher income taxes paid on gains from gas cost savings from our PGA
incentive mechanism in 2007. For the 2008 tax year, we anticipate that the difference between income
taxes paid and the amounts collected in rates will be less than $100,000, and in accordance with the
rules, we have not recorded any adjustment for this year. However, in 2008 we recognized a combined
adjustment for the 2006 and 2007 tax years of $1.8 million, based on revised estimates of our 2006 and
2007 tax surcharges, representing $1.2 million plus accrued interest of $0.6 million.
Other Revenues
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 $21.8 million in 2008, compared to
$12.2 million in 2007 and $0.2 million in 2006.
2008 compared to 2007:
Other revenues in 2008 were $9.6 million higher than in 2007 primarily due to a $10.5 million
refund to utility customers for the gas storage sharing mechanism revenues, partially offset by a $1.9
million surcharge for our rate adjustment for income taxes paid.
2007 compared to 2006:
Other revenues in 2007 were $12.1 million higher than in 2006 primarily due to a $3.1 million
increase in deferrals under the decoupling mechanism (see “Results of Operations—Regulatory
Matters—Rate Mechanisms,” above), a $6.1 million decrease in amortization expense related to the
decoupling deferrals from prior periods, a $1.7 million increase in interstate gas storage credits to
customers reflecting higher regulatory sharing of net income from storage operations and a decrease of
$1.3 million in amortization expense related to demand side management deferrals.
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, under the terms of 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
52
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).
2008 compared to 2007:
•
•
•
total cost of gas sold increased $17.4 million or 3 percent;
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.
2007 compared to 2006:
•
•
•
total cost of gas sold decreased $9.0 million or 1 percent;
the average cost of gas sold remained at 81 cents per therm; and
net losses of $42.0 million were realized from our financial hedges, compared to $20.0
million of net losses in 2006.
For the year ended December 31, 2008, our actual gas costs were higher than the gas costs
embedded in rates, while during the same period in 2007 and 2006 our actual gas costs were
significantly lower than gas costs embedded in rates. The effect on shareholders from the gas cost
incentive sharing was a margin gain of $12.1 million and $8.1 million in 2007 and 2006, respectively,
compared to a margin loss of $5.5 million in 2008. For a discussion of the change in our Oregon gas
cost sharing incentive mechanism, effective November 1, 2008, see “Results of Operations—
Regulatory Matters—Rate Mechanisms—Purchased Gas Adjustment,” above.
Business Segments Other than Utility Operations
Gas Storage
Our gas storage segment primarily consists of the non-utility portion of our Mist underground
storage facility, asset optimization and Gill Ranch. In 2008, we earned $8.4 million, or 31 cents per
share, from our gas storage business segment, after regulatory sharing and income taxes. This
compares to net income of $8.5 million, or 32 cents per share, in 2007 and $6.0 million, or 21 cents per
share, in 2006. Earnings in 2008 and 2007 were higher than 2006 primarily because of increased
revenues from additional contract storage and higher margins from optimization services under a
contract with an independent energy marketing company.
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
53
mechanism in Washington for pre-tax income derived from gas storage and optimization services. We
are currently in the process of developing a second underground storage facility, Gill Ranch, and
related pipeline near Fresno, California. Our Gill Ranch project is expected to serve the California and
west coast market. 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’s equity balance as of
December 31, 2008 and 2007 was $1.3 million and $1.4 million, respectively, and our equity balance
in the proposed Palomar transmission pipeline was $14.2 million and $6.0 million, respectively. In
2008 and 2007, we sold the last of our non-core assets, resulting in after-tax gains of $1.1 million and
$0.9 million, respectively. The remaining investment balance at Financial Corporation reflects a
non-controlling interest in the Kelso Beaver pipeline. The current equity balance in Palomar reflects
our investment to date in a proposed 217-mile transmission pipeline.
Net income from our other business segment for the years ended December 31, 2008, 2007 and
2006 was $2.4 million, $1.1 million and $0.8 million, respectively. The increase in 2008 compared to
2007 reflects the gain on sale of our investment in a Boeing 737-300 aircraft and income from our
equity investment in Palomar. The increase in 2007 over 2006 reflects the sale of our limited
partnership interest in two wind power electric generation projects in California. See Note 2.
Consolidated Operations
Operations and Maintenance
Operations and maintenance expenses decreased by $7.1 million in 2008, or 6 percent,
compared to 2007. In 2007 operations and maintenance expense included additional costs for strategic
initiatives. Operations and maintenance expense increased $5.9 million in 2007, or 5 percent,
compared to 2006, also reflecting higher expenditures for strategic initiatives in 2007. The following
summarizes the major factors that contributed to changes in operations and maintenance expense:
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. Delinquent account balances were $0.1 million
higher than last year, compared to a $36.5 million, or 25 percent, increase in accounts
receivable and unbilled revenues. Our bad debts as a percent of revenues remained
consistent with 2007 at 0.3 percent.
54
2007 compared to 2006:
•
•
•
•
a $3.8 million increase in employee compensation and benefit expense, primarily due to
bonuses related to improved financial and operating results on annual and long-term
incentive plan performance goals;
a $1.9 million increase in costs for maintenance projects and geo-hazard repairs;
a $0.9 million increase in training, maintenance and telecommunication expenses related to
the implementation of the first phase of a new integrated information system; and
a $0.3 million increase in start up expenses for the Smart Energy program.
Partially offsetting the above increases was:
•
a $1.5 million decrease in severance expenses.
General Taxes
General taxes, which are principally comprised of property and payroll taxes and regulatory
fees, increased $1.4 million, or 5 percent, in 2008 compared to 2007, and increased $0.9 million, or 4
percent, in 2007 compared to 2006. The major factors that contributed to changes in general taxes are:
2008 compared to 2007:
•
a $1.3 million increase in property taxes related to higher tax rates and increased utility
plant balances.
2007 compared to 2006:
•
•
•
a $0.4 million increase in property taxes related to a 3 percent increase in utility plant
balances;
a $0.3 million increase in regulatory fees based on higher gross operating revenue; and
a $0.2 million increase in other taxes due to an increase in the annual fee to the Oregon
Department of Energy.
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. In November 2007, the Oregon Tax Court ruled in our favor stating that these
inventories were exempt from property tax. However, the ODOR appealed the judgment to the Oregon
Supreme Court in August 2008. If we are successful in this litigation, we would be entitled to a refund
of over $5.0 million for property taxes paid on inventories beginning with the 2002-2003 tax year, plus
accrued interest. Due to the uncertain outcome of the proceeding, we have not recorded the recovery of
property taxes paid on gas inventories or appliance inventories to recognize the potential gain
contingency.
55
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
Average depreciation rate - utility
Average depreciation rate - non-utility
2008
2007
2006
$2,101,900
41,088
$2,013,191
38,970
$1,925,837
37,661
2,142,988
2,052,161
1,963,498
62,882
11,624
74,506
56,444
10,705
67,149
36,952
5,700
42,652
$2,217,494
$2,119,310
$2,006,150
$
$
70,691
1,468
72,159
$
$
67,410
933
68,343
$
$
63,552
883
64,435
3.4%
2.5%
3.4%
2.1%
3.4%
2.5%
Total depreciation and amortization expense increased by $3.8 million, or 6 percent, in 2008
and by $3.9 million, or 6 percent, in 2007. The increased expense for both years is 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).
New depreciation rates were approved by the OPUC and WUTC, effective January 1, 2009 (see
“Regulatory Matters—Rate Mechanisms—Depreciation Study,” above).
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
Total other income and expense - net
2008 compared to 2007:
2008
2007
2006
$ 2,190
250
667
552
1,737
(1,650)
$ 1,939
537
130
84
1,544
(2,789)
$2,609
363
191
(177)
-
(852)
$ 3,746
$ 1,445
$2,134
Other income and expense–net increased by $2.3 million in 2008 over 2007. The increase was
primarily due to an increase of $1.1 million in other non-operating income (expense), reflecting the
56
additional start-up expenses in 2007 for business development and other strategic initiatives, and by a
$0.2 million increase from 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.
2007 compared to 2006:
Other income and expense–net declined by $0.7 million in 2007 over 2006. The decline was
primarily due to a decrease of $0.7 million in gains from company-owned life insurance, reflecting
lower policy benefits realized during 2007, and a net increase of $1.9 million in other non-operating
expenses, reflecting expenses for business development and other strategic initiatives. These negative
changes were partially offset by an increase in earnings from equity investments of Financial
Corporation of $1.5 million, reflecting the gain on sale of its limited partnership interests in two wind
power electric generation projects, and an increase of $0.3 million in net interest charges on deferred
regulatory accounts, reflecting lower net credit balances outstanding in these accounts.
Interest Charges—Net of Amounts Capitalized
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 medium-term notes (MTNs) in July 2008, with increased costs due to
higher short-term debt balances offset by lower interest rates on short-term debt. In 2007, interest
charges—net of amounts capitalized was $1.4 million, or 4 percent, lower than in 2006, reflecting
lower balances on long-term debt outstanding due to the redemption of $20 million of MTNs in March
2007 and $9.5 million of MTNs in May 2007. 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 3.6 percent in 2008, 5.4 percent in 2007 and 4.7 percent in 2006.
Income Tax Expense
The decrease in income tax expense of $3.4 million or 8 percent in 2008, compared to 2007
was primarily due to lower consolidated earnings and a slightly lower effective tax rate of 36.9 percent
in 2008 compared to 37.2 percent in 2007. The decrease in our effective tax rate was primarily the
result of a higher non-taxable gain on company-owned life insurance. Income tax expense increased by
$7.8 million or 22 percent in 2007, as compared to total income tax expense of $36.2 million in 2006,
and the effective tax rate increased slightly from an effective rate of 36.4 percent in 2006. For more
information on our income taxes, including a reconciliation between the statutory federal income tax
rate and the effective rate, see Note 1 and Note 8.
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
57
requirements are necessary to maintain attractive credit ratings and have access to capital markets at
reasonable costs. Our consolidated capital structure was as follows:
December 31,
Common stock equity
Long-term debt
Short-term debt, including current maturities of long-term debt
Total
Liquidity and Capital Resources
2008
2007
2006
45.3% 47.4% 48.1%
36.8% 40.8% 41.5%
17.9% 11.8% 10.4%
100.0% 100.0% 100.0%
At December 31, 2008, we had $6.9 million of cash and cash equivalents compared to $6.1
million at December 31, 2007. Short-term liquidity is provided by cash balances, internal cash flow
from operations, proceeds from the sale of commercial paper notes, unsecured credit facilities,
including multi-year commitments which are primarily used to back-up commercial paper (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 to finance
capital expenditures and refinance maturing short-term or long-term debt.
Our senior long-term debt ratings are AA- and A2 from S&P and Moody’s, respectively, while
our short-term debt ratings are A-1+ and P-1 from S&P and Moody’s, respectively. The capital
markets, including the commercial paper market, have experienced significant volatility and tight
credit conditions in recent months, as reflected by increased spreads and limited access to new
financing. As a result of these market conditions, we delayed a planned fourth quarter 2008 debt
issuance until the first quarter of 2009. In lieu of the delayed debt issuance, we entered into two $15
million bilateral bank lines of credit with maturities of one and three months, and borrowed from
corporate-owned life insurance policies to provide added liquidity. With our current debt ratings we
have been able to issue commercial paper notes at attractive rates and have not had to borrow from our
$250 million back-up facility. In the event that we are not able to issue commercial paper or other debt
instruments due to market conditions, we expect that our liquidity needs can be met by using cash
balances or drawing upon our committed credit facility (see “Credit Agreements,” 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, market conditions permitting.
In the event that our senior secured long-term debt credit ratings are downgraded below
investment grade, 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 costs and may trigger significant
increases in draws from our borrowing facilities.
Based on our current credit ratings, our experience with issuing commercial paper, our current
cash reserves, the availability and size of our committed credit facilities and our ability to issue long-
term debt and equity securities under the universal shelf registration statement, we believe our liquidity
is sufficient to meet our anticipated cash requirements, including the contractual obligations and
investing and financing activities discussed below.
Dividend Policy
We have paid quarterly dividends on our common stock in each year since the stock was first
issued to the public in 1951. Annual common dividend payments per share, adjusted for stock splits,
have increased each year since 1956. The amount and timing of dividends payable on our common
58
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, 2008 by maturity and
type of obligation.
Thousands
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
Payments Due in Years Ending December 31,
2011
2010
2012
2013
2009
Thereafter
Total
$248,000
-
33,417
$
-
35,000
33,406
$
-
10,000
30,858
$
-
40,000
28,536
$
-
-
27,625
$
-
427,000
285,432
$ 248,000
512,000
439,274
26,839
599
4,129
229,804
80,670
19,126
461
4,127
89,079
61,114
19,556
163
4,080
34,835
64,175
20,394
21
4,230
21,277
49,067
21,571
-
4,268
21,277
41,602
116,388
-
26,501
17,731
87,826
223,874
1,244
47,335
414,003
384,454
53,081
5,154
762
-
-
-
58,997
Total
$676,539
$247,467
$164,429
$163,525
$116,343
$960,878
$2,329,181
(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, 2008.
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.
Holders of one long-term debt issue have a put option that, if exercised, would require the
repurchase of up to $20 million principal amount in 2009. If repurchased prior to maturity, then the
interest obligation shown in the above table would be reduced in future years. The interest rate on this
long-term debt issue with a put option is 6.65 percent.
In February 2008, we extended the term of an agreement with Northwest Pipeline for
approximately 350,000 therms per day of firm transportation capacity from the U.S. Rocky Mountain
region through 2044. Also in February 2008, we executed an agreement with a third party to take
59
assignment of their firm transportation contract starting no earlier than 2012 and no 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.
Approximately 700 of our utility employees are members of the Office and Professional
Employees International Union, Local No. 11. These employees are covered by a labor agreement
(Joint Accord) with respect to wages, benefits and working conditions. This Joint Accord will expire
on May 31, 2009. Each party has served notice of intent to negotiate the terms of an agreement prior to
the May 31, 2009 expiration date.
Commercial Paper
Our primary source of short-term liquidity is from internal cash flows and the sale of
commercial paper notes payable. 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 and
Note 6). Our commercial paper program did not experience any liquidity disruptions as a result of the
recent credit problems that affected issuers of asset-backed commercial paper and certain other
commercial paper programs. At December 31, 2008 and 2007 we had commercial paper outstanding of
$248.0 million and $143.1 million, respectively (see Note 6). This year’s outstanding balances were
higher than last year primarily due to gas cost deferrals associated with higher gas purchases, higher
balances in gas inventories and accounts receivable, commodity hedge payments, and delaying the
issuance of long-term debt.
Credit Agreements
We have a syndicated line of credit for unsecured revolving loans totaling $250 million
available and committed for a term expiring on May 31, 2012, with $210 million of that commitment
amount extended through May 31, 2013. Additionally, we entered into two committed bilateral bank
lines of credit totaling $30 million in November 2008, of which $15 million expired December 31,
2008 and $15 million expired February 27, 2009. The lenders under our syndicated and bilateral credit
agreements are major financial institutions with committed balances and investment grade credit
ratings as of December 31, 2008 as follows:
Lender rating, by category
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Amount
Committed
(in $000’s)
$135,000
45,000
85,000
-
$265,000
Based on recent conditions in the credit markets, 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 the lenders’ creditworthiness, including a review of
capital ratios, credit default swap spreads and credit ratings, we believe the risk of lender default is
minimal.
60
Pursuant to the terms of our credit agreement for the syndicated line of credit, we may request
maturity extensions for additional one-year periods subject to lender approval. We extended
commitments with six of the seven lenders under the syndicated credit agreement, with commitments
totaling $210 million, to May 31, 2013. The credit agreement also 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. There were no outstanding balances under this credit
agreement at December 31, 2008 and 2007. 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, 2008 and
2007, with our consolidated indebtedness to total capitalization ratios of 54.7 percent, and 52.7 percent,
respectively.
The credit agreement 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, 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.
Credit Ratings
The table below summarizes our 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
Moody’s
A-1+
AA-
A+
Negative
P-1
A2
A3
Stable
Both rating agencies have assigned investment grade credit ratings to NW Natural. These 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. During the
fourth quarter of 2008, our ratings outlook was changed from stable to negative by S&P and from
positive to stable by Moody’s.
Redemptions of Long-Term Debt
We redeemed MTNs during 2008, 2007 and 2006 as follows:
Thousands
Medium-Term Notes
6.05% Series B due 2006
6.31% Series B due 2007
6.80% Series B due 2007
6.50% Series B due 2008
Redeemed
in 2008
Redeemed
in 2007
Redeemed
in 2006
$
-
-
-
5,000
$
-
20,000
9,500
-
$8,000
-
-
-
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Cash Flows
Operating Activities
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 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, will reverse over the next six months 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:
2008 compared to 2007:
•
•
•
•
an increase in cash flow 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 in cash flows of $84.0 million in deferred gas costs, $30.4 million in accounts
payable and a $14.3 million in inventories, primarily due to the higher gas cost prices in
2008 compared to 2007;
a decrease in cash flow 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; and
a decrease in cash flow 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).
In December 2008, we filed an application for a change in tax accounting method in connection
with routine repairs and maintenance of gas pipeline that are currently being capitalized and
depreciated. We anticipate that the Internal Revenue Service (IRS) will consent to this change during
the first quarter of 2009. If consented to by the IRS, then we expect to claim a deduction and record
current tax benefits that will result in a cash refund of taxes paid. If approved, we estimate the tax
refund amount in 2009 for prior years’ taxes paid to be in excess of $15 million related to the routine
repairs and maintenance.
In 2007, cash flow from net income and operating activity adjustments, excluding working
capital changes, increased by $23.0 million, primarily due an increase in cash collections from deferred
gas costs and improved operating results. Working capital changes in 2007 increased cash flow by
$12.1 million. The overall change in cash flow from operations in 2007 was an increase of $35.1
million compared to 2006. The significant factors contributing to the cash flow changes between 2007
and 2006 are as follows:
2007 compared to 2006:
•
an increase in cash of $11.2 million in deferred income taxes and investment tax credits
related to a smaller reduction in 2007 than 2006;
62
•
•
•
•
•
an increase in cash of $17.9 million in deferred gas costs and an increase in cash of $27.5
million in accounts payable, reflecting deferral activity between the two years with respect
to purchased gas cost savings and off-system gas sales under our PGA;
a decrease in cash of $17.5 million due to the change in deferred regulatory and other costs;
an increase in cash of $25.8 million in accounts receivable and accrued unbilled revenue,
due to decreased rates in 2007 and weather that was warmer at the end of the year;
a decrease in cash of $13.2 million in income taxes receivable resulting from income tax
refunds received during 2006; and
a decrease in cash of $16.7 million in accrued interest and taxes due to higher cash
payments in 2007.
We have lease and purchase commitments relating to our operating activities that are financed
with cash flows from operations (see “Liquidity and Capital Resources—Contractual Obligations,”
above and Note 12).
Investing Activities
Cash requirements for investing activities in 2008 totaled $109.8 million, down from $117.5
million in 2007. Cash requirements for the acquisition and construction of utility plant were $96.6
million in 2008, up slightly from $93.8 million in 2007. Cash requirements for investments in
non-utility property were $7.4 million in 2008, primarily related to investments in Gill Ranch,
compared to $24.4 million in 2007, primarily due to investments made related to the Mist gas storage
expansion. Cash used in other investing activities in 2008 totaled $5.8 million compared to cash
collected of $0.7 million in 2007. The change in 2008 is primarily due to a $7.5 million investment in
the Palomar project and a $5.0 million restricted cash balance in Gill Ranch, partially offset by $6.8
million of proceeds received from the sale of our investment in a Boeing 737-300 aircraft.
Cash requirements for investing activities in 2007 totaled $117.5 million, up from $90.6 million
in 2006. Cash requirements for the acquisition and construction of utility plant were $93.8 million in
2007, down slightly from $95.3 million in 2006. Cash requirements for investments in non-utility
property increased to $24.4 million in 2007, compared to $1.8 million in 2006, primarily related to
investments in Mist gas storage, Gill Ranch and Palomar.
In 2009, utility capital expenditures are estimated to be between $100 and $110 million, and
non-utility capital investments are expected to be between $50 and $70 million for business
development projects that are currently in process (see “2009 Outlook,” above).
Over the five-year period 2009 through 2013, utility construction expenditures are estimated at
between $450 and $500 million. The estimated level of capital expenditures over the next five years
reflects 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 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.
Financing Activities
Cash provided by financing activities in 2008 totaled $75.9 million, as compared to cash used
of $65.8 million in 2007. Factors contributing to the $141.7 million net increase in cash include share
63
repurchases of $44.6 million in 2007 compared to no repurchases in 2008, long-term debt retired of
$5.0 million in 2008 compared to $29.5 million in 2007, and an increase in short-term debt balances of
$74.7 million in 2008, including borrowings from the cash surrender value in company-owned life
insurance policies, compared to 2007.
Cash used in financing activities in 2007 totaled $65.8 million, as compared to $59.4 million in
2006. Factors contributing to the $6.4 million net increase in cash used include an increase in share
repurchases of $28.7 million, an increase in long-term debt retired of $21.5 million, and a reduction in
long-term debt issuances of $25.0 million, offset by an increase in cash from the change in short-term
debt balances of $69.6 million in 2007 compared to 2006.
In October 2007, we entered into a forward-starting interest rate swap with a notional principal
amount of $50 million. This fixed-rate forward-starting swap is intended to mitigate a substantial
portion of the interest rate exposure associated with our anticipated issuance of MTNs in the first
quarter of 2009 when we would expect to cash settle this contract. The associated gain or loss on
settlement will be recorded as a regulatory asset or liability and amortized in accordance with
regulatory requirements. We did not issue any new long-term debt during 2007 or 2008.
In December 2006, we sold $25 million of 5.15 percent Series B, secured MTNs due 2016 and
used the proceeds to reduce short-term indebtedness and to fund utility construction.
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 2006 that program was modified to
2.6 million shares and $85 million in value, and the program was further modified in 2007 to authorize
the repurchase of up to 2.8 million shares or up to $100 million and was extended through May 2009.
The purchases are made in the open market or through privately negotiated transactions. No
repurchases were made in 2008. Repurchases in 2007 totaled 963,428 shares or $44.2 million; and in
2006 totaled 395,500 shares or $16.0 million. 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 (see Part II, Item 5,
“Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of
Equity Securities,” above).
In 2008, we produced negative free cash flow of $115.3 million, compared to free cash flow of
$27.5 million in 2007 and $19.7 million in 2006. 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 (year ended December 31)
2008
2007
2006
Cash provided by operating activities
Cash used in investing activities
Cash dividend payments on common stock
Free cash flow
$ 34,721
(109,825)
(40,178)
$ 183,640
(117,479)
(38,613)
$148,566
(90,567)
(38,298)
$(115,282) $ 27,548
$ 19,701
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
64
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 SFAS No. 87 (see “Application of Critical
Accounting Policies and Estimates – Accounting for Pensions,” 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 $4.3 million in 2008, a decrease of
$2.4 million over 2007.
The fair market value of the assets in these two plans decreased to $163.1 million at
December 31, 2008 down from $241.4 million at December 31, 2007. The decrease was due to a
negative return on plan assets of $63.3 million and benefit payments of $15.0 million net of
contributions.
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
92 percent in 2008, 94 percent in 2009 and 96 percent in 2010. Our qualified defined benefit pension
plans are currently underfunded by $98.4 million at December 31, 2008, and we expect to make at least
the minimum contribution required pursuant to the Act, which is currently estimated at $8 million. We
plan to make additional contributions during 2009, which could bring our total contributions in 2009
up to $40 million. We would need to make a total contribution of at least $17 million during 2009 to
avoid any restrictions on benefit payments. For more information, see Note 7.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2008, 2007 and 2006, our ratios of earnings to fixed charges,
computed using the Securities and Exchange Commission method, were 3.76, 3.92 and 3.40,
respectively. For this purpose, earnings consist of net income before taxes plus fixed charges, and fixed
charges consist of interest on all indebtedness, the amortization of debt expense and discount or
premium and the estimated interest portion of rentals charged to income.
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 SFAS No. 5 (see
“Application of Critical Accounting Policies and Estimates—Contingencies,” above). At December 31,
2008, a cumulative $66.1 million in environmental costs was recorded as a regulatory asset, consisting
of $30.1 million of costs paid to-date, $30.0 million for additional environmental accruals for costs
expected to be paid in the future and accrued regulatory interest of $6.0 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 12.
65
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 20
percent of the higher cost of gas sold, or retain 20 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, 2008 and 2007, notional amounts
under these financial hedge contracts totaled $393.0 million and $287.6 million, respectively. If all of
the commodity-based financial hedge contracts had been settled on December 31, 2008, a loss of about
$139.2 million would have been realized and recorded to a deferred regulatory account (see Note 11).
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, 2010. The $139.2 million unrealized loss is an estimate of future cash
flows based on forward market prices that are expected to be paid as follows: $130.3 million in the
next 12-month period, and $8.9 million in the following 12-month period. The amount realized will
change based on market prices at the time contract settlements are fixed.
Natural gas commodity prices early in the third quarter of 2008 were higher than prices
embedded in the corresponding PGA for unhedged purchases. To the extent that we purchase gas
volumes where the price is not hedged and the current market prices are above those embedded in rates
for current customer consumption (i.e. not for storage injections), our earnings are negatively impacted
because either 10 to 20 percent of any difference between the actual purchase gas costs and the gas
costs embedded in Oregon rates are recognized in current income. In 2008, we recognized a loss of
$5.5 million due to higher gas prices.
66
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. During the fourth quarter of
2007, we entered into a forward starting interest rate swap with a notional amount of $50 million to
hedge the interest rate on our next long-term debt issuance, which was expected to occur in the latter
part of 2008. However, due to credit market conditions, the swap was extended to the second quarter of
2009. This swap is with an A+/Aa2 rated counterparty and qualifies as a cash flow hedge under SFAS
No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS
No. 138 and SFAS No. 149 (collectively referred to as SFAS No. 133). The mark-to-market unrealized
loss at December 31, 2008 related to this interest rate swap was $11.9 million.
Holders of certain long-term debt have put options that, if exercised, would accelerate
maturities by $20 million in 2009 (see Note 5).
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, 2008 and
2007, notional amounts under foreign currency forward contracts totaled $5.2 million and $6.1 million,
respectively. As of December 31, 2008, no foreign currency forward contracts were outstanding with a
maturity date after November 30, 2009. If all of the foreign currency forward contracts had been settled
on December 31, 2008, a loss of $0.4 million would have been realized (see Note 11).
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, 2008, our credit exposure relating to commodity hedge contracts reflected an amount we
owed of $130.3 million to our finance derivative counterparties. Our financial derivatives policy
requires counterparties to have a minimum 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. Some counterparties were recently downgraded but continue to maintain
investment grade ratings (see table below). Due to current market conditions and credit concerns, we
67
continue to enforce strong credit requirements. We actively monitor our derivative credit exposure and
place counterparties on hold for trading purposes or require letters of credit or guarantees as
circumstances warrant. Our actual derivative credit exposure, which reflects amounts that financial
derivative counterparties owe to us, is under contracts that expire or are expected to settle on or before
October 31, 2010.
The following table summarizes our 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, 2008
$ (16,827)
(122,287)
(12,006)
-
$(151,120)
Dec. 31, 2007
$
(309)
(13,941)
123
-
$(14,127)
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.
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, 2008, less
than 10 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.
68
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, 2008,
2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets at December 31, 2008 and 2007 . . . . . . . . . . . . . . . . . . . . . .
Page
70
71
72
73
Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the
Years Ended December 31, 2008, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
75
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008,
2007 and 2006 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
76
77
Quarterly Financial Information (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
114
Supplementary Data for the Years Ended December 31, 2008, 2007 and 2006:
Financial Statement Schedule
Schedule II—Valuation and Qualifying Accounts and Reserves . . . . . . . . . . . . . . . . . . . .
115
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.
69
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, 2008. 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, 2008.
The effectiveness of internal control over financial reporting as of December 31, 2008 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 27, 2009
70
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, 2008
and 2007, and the results of their operations and their cash flows for each of the three years in the period ended
December 31, 2008 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, 2008, 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. As discussed in Note 7 to the consolidated financial statements, the Company
changed the manner in which it accounts for defined benefit pension and other postretirement plans effective
December 31, 2006.
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 27, 2009
71
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Thousands, except per share amounts (year ended December 31)
2008
2007
2006
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
$1,037,855
656,568
25,072
$1,033,193
639,150
25,001
$1,013,172
648,156
24,840
356,215
369,042
340,176
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
114,560
24,419
64,435
203,414
136,762
2,134
39,247
99,649
36,234
$
69,525
$
74,497
$
63,415
26,438
26,594
26,821
26,995
27,540
27,657
$
$
2.63
2.61
$
$
2.78
2.76
$
$
2.30
2.29
-------------------------------------------
See Notes to Consolidated Financial Statements.
72
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
Accounts receivable
Accrued unbilled revenue
Allowance for uncollectible accounts
Regulatory assets
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
Fair value of non-trading derivatives
Other investments
Other
Total investments, deferred charges and other assets
Total assets
2008
2007
$2,142,988
659,123
$2,052,161
615,533
1,483,865
1,436,628
74,506
9,314
65,192
67,149
7,904
59,245
1,549,057
1,495,873
6,916
81,288
102,688
(2,927)
147,319
4,592
86,134
9,933
20,811
24,216
6,107
69,442
78,004
(2,890)
17,598
2,903
71,079
8,865
-
25,569
480,970
276,677
288,470
146
54,132
5,377
348,125
175,938
324
54,070
11,179
241,511
$2,378,152
$2,014,061
-------------------------------------------
See Notes to Consolidated Financial Statements.
73
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Thousands (December 31)
Capitalization and liabilities:
Capitalization:
Common stock
Earnings invested in the business
Accumulated other comprehensive income (loss)
Total common stock equity
Long-term debt
Total capitalization
Current liabilities:
Notes payable
Long-term debt due within one year
Accounts payable
Taxes accrued
Interest accrued
Regulatory liabilities
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
Pension and other postretirement benefit liabilities
Fair value of non-trading derivatives
Other
Total deferred credits and other liabilities
Commitments and contingencies (see Note 12)
Total capitalization and liabilities
2008
2007
$ 336,754
296,005
(4,386)
$ 331,595
266,658
(3,502)
628,373
512,000
594,751
512,000
1,140,373
1,106,751
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
-
143,100
5,000
119,731
13,137
2,827
61,326
14,829
29,794
389,744
206,340
213,764
41,619
3,758
52,085
517,566
-
$2,378,152
$2,014,061
-------------------------------------------
See Notes to Consolidated Financial Statements.
74
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME
Common
Stock
and
Premium
$383,805
-
Earnings
Invested in
the Business
$205,687
63,415
Unearned
Stock
Compensation
$(650)
-
Accumulated
Other
Comprehensive
Income (Loss)
$(1,911)
-
Total
Shareholders’
Equity
$586,931
63,415
Comprehensive
Income
$63,415
Thousands
Balance at Dec. 31, 2005
Net Income
Minimum pension liability
adjustment, net of $52 of tax
Change in non-qualified employee
benefit plan liability, net of $232
of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock
option plan
Stock-based compensation
Restricted stock reclassification
Issuance of common stock
Common stock repurchased
Common stock expense
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 ($86) of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock
-
-
298
-
317
555
(650)
2,773
(15,971)
-
371,127
-
-
-
-
-
-
(38,298)
-
-
-
-
-
(30)
230,774
74,497
-
-
-
285
-
-
-
(38,613)
536
2,094
2,180
(44,627)
331,595
-
-
-
-
-
-
-
266,658
69,525
-
-
-
275
-
-
-
(40,178)
option plan
Stock-based compensation
Issuance of common stock
Balance at Dec. 31, 2008
282
1,523
3,079
$336,754
-
-
-
$296,005
$
-
-
-
-
-
-
650
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
(81)
(81)
(81)
(364)
-
-
-
-
-
-
-
-
(2,356)
-
(41)
(364)
298
(38,298)
317
555
-
2,773
(15,971)
(30)
599,545
74,497
$63,334
$74,497
(41)
(41)
(1,232)
(1,232)
(1,232)
127
-
-
-
-
-
-
(3,502)
-
41
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)
(1,145)
220
-
-
-
-
-
$(4,386)
220
275
(40,178)
282
1,523
3,079
$628,373
220
$68,641
-------------------------------------------
See Notes to Consolidated Financial Statements.
75
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
Non-cash expenses related to qualified defined benefit pension plans
Deferred environmental expenditures
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
2008
2007
2006
$ 69,525
$ 74,497
$ 63,415
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
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
64,435
(16,440)
(191)
20,752
(495)
(2,609)
5,500
(6,675)
14,533
(3,722)
8,033
13,234
2,952
(21,708)
8,511
(959)
Cash provided by operating activities
34,721
183,640
148,566
Investing activities:
Investment in utility plant
Investment in non-utility property
Proceeds from sale of non-utility investments
Proceeds from life insurance
Contributions to non-utility equity investments
Other
Cash used in investing activities
Financing activities:
Common stock issued, 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 (decrease) 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
(96,582)
(7,416)
7,531
208
(7,450)
(6,116)
(93,785)
(24,442)
2,628
881
(5,413)
2,652
(95,307)
(1,773)
2,517
4,009
-
(13)
(109,825)
(117,479)
(90,567)
2,310
-
-
(5,000)
117,751
(40,178)
1,030
2,180
(44,627)
-
(29,500)
43,000
(38,613)
1,739
3,913
(15,971)
25,000
(8,000)
(26,600)
(38,298)
581
75,913
(65,821)
(59,375)
809
6,107
340
5,767
(1,376)
7,143
$
6,916
$
6,107
$
5,767
$ 37,669
$ 12,300
$ 38,508
$ 56,215
$ 39,294
$ 31,270
-------------------------------------------
See Notes to Consolidated Financial Statements.
76
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 by regulatory accounting under Statement of Financial
Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of
Regulation,” not to be eliminated.
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) 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 SFAS No. 71. Our businesses are
authorized by the OPUC, WUTC and the FERC to earn a reasonable return on invested capital.
In applying SFAS No. 71, 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.
77
At December 31, 2008 and 2007, 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
2008
2007
2008
2007
$136,735
-
8,074
-
-
2,510
$14,788
-
1,912
-
-
898
$ 21,646
69,948
113,869
36,135
29,969
16,903
$
3,758
68,649
27,152
27,956
35,098
13,325
$147,319
$17,598
$288,470
$175,938
$
5,284
4,592
-
10,580
$46,153
2,903
-
12,270
$
1,868
146
223,716
2,427
$ 6,290
324
204,886
2,264
$ 20,456 $61,326
$228,157
$213,764
(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).
Environmental costs are related to those 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.
We believe that continued application of SFAS No. 71 for regulated activities is appropriate
and consistent with the current regulatory environment, and that all regulated assets and
liabilities at December 31, 2008 and 2007 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 SFAS No. 71, then we would
be required to write off the net unrecoverable balances against earnings.
New Accounting Standards
Adopted Standards
Fair Value Measurements. In September 2006, the Financial Accounting Standards Board
(FASB) issued SFAS No. 157, “Fair Value Measurements,” which is effective for fiscal years
beginning after November 15, 2007. This statement defines fair value, establishes a framework
for measuring fair value and expands disclosures about fair value measurements. This statement
indicates, among other things, that a fair value measurement assumes that a transaction to sell
78
an asset or transfer a liability occurs in the principal market for the asset or liability or, in the
absence of a principal market, the most advantageous market for the asset or liability. SFAS
No. 157 defines fair value based upon an exit price model.
Relative to SFAS No. 157, the FASB issued FASB Staff Positions (FSP) 157-1, 157-2 and
157-3. FSP 157-1 amends SFAS No. 157 to exclude SFAS No. 13, “Accounting for Leases,”
and its related interpretive accounting pronouncements that address leasing transactions. FSP
157-2 delays the effective date of the application of SFAS No. 157 to fiscal years beginning
after November 15, 2008 for all nonfinancial assets and liabilities except for those that are
recognized or disclosed at fair value in the financial statements on a recurring basis. FSP 157-3,
issued and effective on October 10, 2008, clarifies the application of SFAS No. 157 when
relevant observable inputs in active markets are not available.
We adopted SFAS No. 157, FSP 157-1 and FSP 157-3 as of January 1, 2008, and adopted FSP
157-2 as of January 1, 2009. The adoption of these new accounting standards did not have, and
is not expected to have, a material effect on our financial condition, results of operations or
cash flows.
Fair Value Option for Financial Assets and Liabilities. In February 2007, the FASB issued
SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which
permits, but does not require, entities to measure many financial instruments and certain other
items at fair value. SFAS No. 159 became effective for fiscal years beginning after
November 15, 2007. We elected not to implement SFAS No. 159 because the majority of our
assets and liabilities are regulated by the OPUC and the WUTC, both of which generally allow
us to earn a reasonable return on invested capital based on original cost rather than current
market value.
Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. On
January 1, 2008, we adopted Emerging Issues Task Force (EITF) 06-11, “Accounting for
Income Tax Benefits of Dividends on Share-Based Payment Awards,” which provides the
accounting requirements for recognizing income tax benefits received on dividends paid to
employees holding equity-classified nonvested shares, equity-classified nonvested share units
or equity-classified outstanding share options, and how these benefits are charged to retained
earnings under SFAS No. 123R, “Share Based Payment.” The adoption of EITF 06-11 did not
have, and is not expected to have, a material effect on our financial condition, results of
operations or cash flows.
Offsetting Amounts Related to Certain Contracts. On January 1, 2008, we adopted FSP FASB
Interpretation No. FIN 39-1 (FSP FIN39-1), “Offsetting of Amounts Related to Certain
Contracts.” FSP FIN 39-1 requires disclosure when a reporting entity offsets fair value amounts
from derivative instruments executed with the same counterparty under master netting
arrangements. Our disclosures on FSP FIN 39-1 are included in Note 11. The adoption and
implementation of FSP FIN 39-1 did not have, and is not expected to have, a material effect on
our financial statement disclosures.
Transfers of Financial Assets and Interests in Variable Interest Entities. In December 2008,
the FASB issued SFAS No. 140-4 and FIN 46R-8, “Disclosures by Public Entities about
Transfers of Financial Assets and Interests in Variable Interest Entities,” effective immediately
for periods ending after December 15, 2008. SFAS No. 140-4 and FIN 46R-8 require additional
79
disclosures related to the nature of, involvement in and judgments made when transferring
assets or liabilities to variable interest entities. The adoption and implementation of SFAS
No. 140-4 and FIN 46R-8 did not have, and is not expected to have, a material effect on our
financial statement disclosures.
Recent Accounting Pronouncements
Business Combinations. In December 2007, the FASB issued SFAS No. 141R, “Business
Combinations.” This statement amends the principles and requirements for how an acquiror
accounts for and discloses its business combinations. SFAS No. 141R is effective for fiscal
years and interim periods beginning after December 15, 2008. Based on our preliminary
assessment, this statement is not expected to have a material effect on our financial condition,
results of operations or cash flows.
Noncontrolling Interests in Consolidated Financial Statements. In December 2007, the FASB
issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements.” This
statement amends the reporting requirements of Accounting Research Bulletin No. 51 for
noncontrolling interests in subsidiaries to improve the relevance, comparability and
transparency of the financial information disclosed. SFAS No. 160 is effective for fiscal years
beginning after December 15, 2008. Based on the nature of this new statement and our current
organizational structure, adoption of this statement is not expected to have a material effect on
our financial condition, results of operations or cash flows.
Derivative Instruments and Hedging Activities. In March 2008, the FASB issued SFAS
No. 161, “Accounting for Derivative Instruments and Hedging Activities,” which requires
enhanced disclosures of derivative instruments and hedging activities. SFAS No. 161 is
effective for reporting periods beginning after November 15, 2008.
SFAS No. 161 will expand current 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 under SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities,” and its related
interpretations; and
how derivative instruments and related hedged items affect our financial condition, results
of operations and cash flows.
The adoption of SFAS No. 161 is not expected to have a material effect on our financial
statement disclosures.
Determining Whether Instruments Granted in Share-Based Payment Transactions are
Participating Securities. In June 2008, the FASB issued final FSP No. EITF 03-6-1,
“Determining Whether Instruments Granted in Share-Based Payment Transactions are
Participating Securities.” This statement requires nonforfeitable rights to dividends or dividend
equivalents on unvested share-based payment to be included in the computation of earnings per
share under the two-class method. This statement will be effective for fiscal years beginning
80
after December 15, 2008. Based on our preliminary assessment, the adoption of FSP No. EITF
03-6-1 is not expected to have a material effect on our financial condition, results of operations
or cash flows.
Pensions. In December 2008, the FASB issued SFAS No. 132R-1, “Employers’ Disclosures
about Pensions and Other Postretirement Benefits,” which requires enhanced disclosures of
plan assets in an employer’s defined benefit pension or other postretirement benefit plan. SFAS
No. 132R-1 is effective for reporting periods ending after December 15, 2009. 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 SFAS No. 157) on changes in plan assets for the period; and
significant concentration or risk within plan assets.
The adoption of SFAS No. 132R-1 is not expected to have a material effect on our financial
statement disclosures.
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 SFAS No. 71, the cost of constructing utility plant and gas storage
assets generally includes an allowance for funds used during construction (AFUDC). AFUDC
represents the net financing cost during the period the funds are used for construction purposes
(see “Allowance for Funds Used During Construction,” 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 3.4
percent for the years ended December 31, 2008, 2007 and 2006, 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
81
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 3.6 percent in 2008, 5.4 percent in
2007 and 4.7 percent in 2006.
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 and 2007, book overdrafts of $1.0 million and $4.9 million, respectively,
were included within accounts payable.
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, 2008 and 2007 were $102.7 million and $78.0 million, respectively.
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 services, are recognized as services
are provided by the independent energy marketing company in accordance with our contractual
agreement. Our current asset optimization agreement includes guaranteed amounts which are
recognized pro-rata on a monthly basis over the contact term. 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
82
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 purchases. 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 SFAS No. 133, as amended by SFAS No. 138, “Accounting for Certain
Derivative Instruments and Certain Hedging Activities,” and SFAS No. 149, “Amendment of
Statement 133 on Derivative Instruments and Hedging Activities” (collectively referred to as
SFAS No. 133), we measure derivatives at fair value and recognize them as either assets or
liabilities on the balance sheet. SFAS No. 133 requires that changes in the fair value of a
derivative be recognized currently in earnings unless specific hedge accounting criteria are met.
SFAS No. 133 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 SFAS No. 71. 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 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, 2008, we selected the 80
percent deferral of gas cost differences. See Note 11.
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 considered to be
unavoidable because they 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 SFAS No. 157, we use fair value measurements to record adjustments to
certain financial assets and liabilities and to determine fair value disclosures. When developing
83
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. See Note 10.
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.
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 SFAS No. 109, “Accounting for Income Taxes.” SFAS No. 109
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).
SFAS No. 109 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 to $69.9 million and $68.6
million at December 31, 2008 and 2007, 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 SFAS
No. 71, 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
84
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
Total other income and expense - net
Earnings Per Share
2008
2007
2006
$ 2,190
250
667
552
1,737
(1,650)
$ 1,939
537
130
84
1,544
(2,789)
$2,609
363
191
(177)
-
(852)
$ 3,746
$ 1,445
$2,134
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
Average common shares outstanding - basic
Effect on shares from stock based compensation
Average common shares outstanding - diluted
Earnings per share of common stock - basic
Earnings per share of common stock - diluted
2008
2007
2006
$69,525
$74,497
$63,415
26,438
156
26,821
174
27,540
117
26,594
26,995
27,657
$
$
2.63
2.61
$
$
2.78
2.76
$
$
2.30
2.29
For the years ended December 31, 2008, 2007 and 2006, 1,248 shares, 442 shares and 4,681
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 our Financial
Corporation subsidiary.
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
85
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 by the 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 are in Washington. On an annual basis, residential and commercial customers
typically account for about 55 percent of our utility’s total volumes delivered and about 85
percent of gross operating revenues, while industrial customers account for about 45 percent of
volumes and about 13 percent of gross revenues. The remaining 2 percent of gross operating
revenues is derived from miscellaneous services and other regulatory charges.
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
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, 2008,
2007 and 2006, this business segment derived a majority of its revenues 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 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 March 2015, with the largest customer’s contract expiring in March
2015.
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 September 2007, we announced a joint project with Pacific Gas & Electric Company
(PG&E) to develop a new underground natural gas storage facility at Gill Ranch near Fresno,
California. We formed a wholly-owned subsidiary of NW Natural to develop and operate the
86
facility. Gill Ranch Storage, LLC, will initially own 75 percent of the project, and PG&E will
own 25 percent. As of December 31, 2008 and 2007, our investment balance in Gill Ranch was
$13.1 million and $0.3 million, respectively.
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 expenses
of the parent company that cannot be charged to utility operations. As of December 31, 2008
and 2007, our investment balance in Palomar was $14.2 million and $6.0 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
approximately $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, 2008 would be
limited to our investment balance of $14.2 million less any commitments or credit support from
third parties.
In April 2008, NW Natural sold its 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 the second quarter of 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 net gain on sale 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 $1.3 million and $1.4
million at December 31, 2008 and 2007, respectively.
87
Segment Information Summary
The following table presents summary financial information about the reportable segments for
the years ended 2008, 2007 and 2006. Inter-segment transactions are insignificant.
Thousands
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
Total assets at Dec. 31, 2007
2006
Net operating revenues
Depreciation and amortization
Income from operations
Net income
3.
CAPITAL STOCK:
Common Stock
Utility
Gas Storage
Other
Total
$ 337,596
70,690
128,957
58,739
2,289,601
$ 351,875
67,410
140,434
64,938
1,940,722
$ 327,267
63,552
126,366
56,653
$18,459
1,469
14,943
8,363
72,073
$16,999
933
14,481
8,454
62,651
$12,761
883
9,870
5,982
$
160
-
136
2,423
16,478
$
168
-
8
1,105
10,688
$ 356,215
72,159
144,036
69,525
2,378,152
$ 369,042
68,343
154,923
74,497
2,014,061
$
148
-
526
780
$ 340,176
64,435
136,762
63,415
At the annual meeting of shareholders, held on May 22, 2008, our shareholders approved an
amendment to our Restated Articles of Incorporation increasing the total number of authorized
shares of common stock from 60 million to 100 million. At December 31, 2007, we had
60 million common shares authorized.
As of December 31, 2008, we had reserved for issuances 203,533 shares of common stock
under the Employee Stock Purchase Plan (ESPP), 577,713 shares under our Dividend
Reinvestment and Direct Stock Purchase Plan and 1,318,810 shares under our Restated Stock
Option Plan (Restated SOP).
In connection with the restatement of our Restated Articles of Incorporation, effective May 31,
2006, the par value of our common stock was eliminated. As a result, at December 31, 2008
and 2007, our “common stock” and “premium on common stock” account balances are
reflected on the balance sheet as “common stock.”
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 have Board authorization
through May 2009 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 2008. Since inception
in 2000, a total of 2.1 million shares have been repurchased at a total cost of $83.3 million.
88
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 2008, 2007 and 2006:
Balance, Dec. 31, 2005
Sales to employees
Exercise of stock options - net
Repurchase
Change to no-par common stock
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 (1)
Repurchase
Balance, Dec. 31, 2008
(1) For further details, see Restated SOP in Note 4.
4.
STOCK-BASED COMPENSATION:
Premium on
common
stock
(thousands)
$ 296,471
-
285
(1,461)
(295,295)
$
$
-
n/a
n/a
n/a
-
n/a
n/a
n/a
-
Shares
27,579,296
31,397
68,548
(395,500)
-
27,283,741
21,373
75,850
(973,616)
26,407,348
19,500
74,340
-
26,501,188
$
We have the following stock-based compensation plans: the Long-Term Incentive Plan (LTIP);
the Restated SOP; the Employee Stock Purchase Plan (ESPP); and the 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, 2008, 247,898 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 earned, 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, 2008, certain performance-based stock award measures had been achieved for
89
the 2006-08 award period. Accordingly, participants are estimated to receive 61,654 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, 2007 and 2006, we awarded 66,666
and 40,446 shares of common stock, respectively, for the 2005-07 and 2004-06 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 2008, we accrued and expensed $0.5 million related to the
2006-08 performance-based stock award, and on a cumulative basis we accrued a total $2.0
million related to the 2006-08 performance period. In 2007 and 2006, we accrued and expensed
$0.6 million and $0.9 million, respectively, related to the 2005-07 and 2004-06 performance-
based stock award periods, and on a cumulative basis we accrued a total of $2.0 million and
$1.7 million, respectively.
At December 31, 2008, the aggregate number of performance-based shares granted and
outstanding at the threshold, target and maximum levels were as follows:
Year
Awarded
2007
2008
Performance
Period
2007-09
2008-10
Total
Performance Share Awards Outstanding
Threshold
7,980
9,215
17,195
Target
42,000
48,500
90,500
Maximum
84,000
97,000
181,000
The threshold level estimates future payout assuming the minimum award payable is reached
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 SFAS
No. 123R, 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, 2008 and 2007 was $14.73 and $25.45, respectively. The weighted-
average per share grant date fair value of shares vested during the year was $38.40 and granted
during the year was $10.89. In 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 and
in 2006 we accrued and expensed $1.0 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 will vest
ratably over the period 2005-09, and a restricted stock award was granted in 2006 consisting of
6,500 shares that will vest ratably over the period 2007-09. A total of 8,334 restricted stock
award shares were vested at December 31, 2008. Compensation expense is recognized ratably
over the vesting period.
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 not less than the market value on the date of grant and may be
exercised for a period not exceeding 10 years and 7 days from the date of grant. Option holders
90
may exchange shares they have owned for at least six months, at the current market price, to
purchase shares at the option price. We use original issue shares upon exercise of options under
the plan.
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
Present value of options granted
February
2008
September
2008
2.8%
4.7
18.4%
3.5%
3.8%
$5.34
$37.95
3.0%
4.7
18.4%
2.9%
3.9%
$7.05
$44.50
2007
2006
4.7%
6.2
4.5%
6.2
17.2% 22.8%
4.0%
3.2%
3.3%
4.4%
$6.29
$7.66
$26.00
$33.38
The expected life of the 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 and 2006 to determine the expected life as defined and permitted by Staff Accounting
Bulletin No. 107. 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 employed in order 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 dividend payout 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 SFAS No. 123R and the retirement vesting provisions of our
option agreements.
91
Information regarding the Restated SOP activity for the three years ended December 31, 2008
is summarized as follows:
Price per Share
Balance outstanding, Dec. 31, 2005
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2006
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2007
Granted
Exercised
Forfeited
Option
Shares
Range
308,500 $20.25 - 38.30
97,800
(69,300) 20.25 - 31.34
(3,000) 31.34 - 34.29
34.29
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
43.29 - 51.09
119,050
(74,340) 20.25 - 44.48
(6,050) 26.30 - 44.48
Weighted -
Average
Exercise Price
Intrinsic
Value
(In millions)
$
$29.26
34.29
27.15
32.52
31.14
44.48
28.73
44.48
35.36
43.62
30.70
41.56
n/a
n/a
0.8
n/a
n/a
n/a
1.4
n/a
4.8
n/a
1.3
n/a
2.3
Balance outstanding, Dec. 31, 2008
396,410 $20.25 - 51.09
$38.62
$
Shares available for grant
Dec. 31, 2006
Dec. 31, 2007
Dec. 31, 2008
1,135,000
1,035,400
922,400
In the year ended December 31, 2008, cash of $2.3 million was received for option shares
exercised and a $0.3 million related tax benefit was realized. For the 12 months ended
December 31, 2008, 2007 and 2006, the total fair value of options that vested was $0.3 million,
$0.2 million and $0.4 million, respectively.
The following table summarizes additional information about stock options outstanding and
exercisable at December 31, 2008:
Outstanding
Exercisable
Range of Exercise Prices
$20.25 - 51.09
Stock
Options
396,410
Weighted-
Average
Remaining
Life in Years
Stock
Options
(In millions)
Aggregate
Intrinsic
Value
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Life in Years
7.47
167,410
$1.8
$33.77
6.04
As of December 31, 2008, 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 2011.
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. We use original issue shares for shares
purchased under the plan.
92
In accordance with SFAS No. 123R, stock-based compensation expense is recognized as
operations and maintenance expense or is capitalized as part of construction overhead. The
following table summarizes the allocations of stock-based compensation grants under our LTIP,
Restated SOP and ESPP:
Thousands
2008
2007
2006
Operations and maintenance expense, for stock-based compensation
Income tax effect
$1,598 $ 2,986
(1,165)
(623)
$2,304
(898)
Net stock-based compensation effect on net income
$ 975
$ 1,821
$1,406
Amounts capitalized
$ 282
$
479
$ 407
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
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, 2008, 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, under the Mortgage
and Deed of Trust (Mortgage), is limited by eligible property, including property additions,
adjusted net earnings and other provisions of the Mortgage. The Mortgage constitutes a first
mortgage lien on substantially all of our utility property.
93
The maturities on the long-term debt outstanding for each of the 12-month periods through
December 31, 2013 amount to: none in 2009; $35 million in 2010; $10 million in 2011; $40
million in 2012; and none in 2013. Holders of certain long-term debt have put options that, if
exercised, would accelerate the maturities by $20 million in 2009.
Thousands (December 31)
2008
2007
2006
Medium-Term Notes
First Mortgage Bonds:
6.31 % Series B due 2007(1)
6.80 % Series B due 2007(2)
6.50% Series B due 2008(3)
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
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
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
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
(1) Redeemed at maturity in March 2007.
(2) Redeemed at maturity in May 2007.
(3) Redeemed at maturity in July 2008.
$
-
-
-
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
$ 20,000
9,500
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
512,000
-
517,000
5,000
546,500
29,500
$512,000
$512,000
$517,000
No long-term debt was issued during 2008 and 2007. In 2006, we issued and sold $25 million
of 5.15 percent Series B secured medium term notes due 2016. Proceeds from this sale were
used, in part, to repay short-term debt and fund our ongoing utility construction program.
Because we elected not to implement SFAS No. 159, we do 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
94
credit ratings, terms and remaining maturities were used to estimate fair value for long-term
debt issues.
Thousands
Long-term debt including amounts due
Dec. 31, 2008
Dec. 31, 2007
Carrying
Amount
Estimated
Fair Value(1)
Carrying
Amount
Estimated
Fair Value(1)
within one year
$512,000
$505,828
$517,000
$557,916
(1) This estimate is calculated net of commission fees.
6.
NOTES PAYABLE AND CREDIT FACILITIES:
Our primary source of short-term funds is from the sale of commercial paper notes payable. 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 is periodically refinanced through
the sale of long-term debt or equity securities. Our commercial paper program is supported by
one or more committed credit facilities. At December 31, 2008 and 2007, the amounts and
average interest rates of commercial paper debt outstanding were $248.0 million and 1.6
percent and $143.1 million and 4.4 percent, respectively.
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 with six of the seven lenders under this credit agreement, with commitments
totaling $210 million, to May 31, 2013. The credit agreement also 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 for all except one lender, which has a commitment amount totaling $40 million
that is due and payable on or before May 31, 2012. Additionally, we entered into two
committed bilateral bank lines of credit totaling $30 million in November 2008, of which $15
million expired December 31, 2008 and $15 million expired February 27, 2009. There were no
outstanding balances under this credit agreement and no letters of credit issued or outstanding
at December 31, 2008 and 2007.
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, 2008 and
95
2007, with a consolidated indebtedness to total capitalization ratio of 54.7 percent, and 52.7
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 benefit plans for certain employees. 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, the qualified defined benefit plan and the
postretirement welfare plans for non-bargaining unit employees were closed to new employees.
Instead, non-bargaining unit employees hired or re-hired after December 31, 2006 are currently
provided an enhanced Retirement K Savings Plan (RKSP) benefit. Benefits provided to
bargaining unit employees under the Retirement Plan for Bargaining Unit Employees are not
affected by these changes.
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, 2008, and a summary of the funded status and
amounts recognized in the consolidated balance sheets using measurement dates of
December 31, 2008, 2007 and 2006:
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
2007
2008
2006
2008
Other Benefits
2007
2006
$ 260,561 $269,410 $267,854 $ 22,186 $ 22,436 $ 20,398
555
1,184
(1,015)
15
133
1,166
-
8,708
16,057
(15,924)
3,887
(23,916)
2,339
-
7,745
14,901
(13,183)
-
(9,208)
1,301
-
6,141
17,373
(16,247)
5
9,146
4,291
(143)
505
1,293
(1,299)
-
(645)
(104)
-
521
1,403
(1,259)
-
839
173
-
Obligation at December 31
$ 281,127 $260,561 $269,410 $ 23,863 $ 22,186 $ 22,436
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
December 31
Funded status:
Funded status at December 31
Unrecognized transition obligation
Unrecognized prior service cost
Unrecognized net actuarial loss
Net amount recognized
$ 241,417 $236,518 $218,555 $
19,658
1,166
(15,924)
(63,267)
1,211
(16,247)
30,088
1,058
(13,183)
- $
-
1,259
(1,259)
- $
-
1,298
(1,298)
-
-
1,015
(1,015)
$ 163,114 $241,418 $236,518 $
- $
- $
-
-
6,963
116,239
$(118,013) $ (19,143) $ (32,892) $(23,863) $(22,186) $(22,436)
2,469
-
2,063
5,512
2,288
45,862
5,189 $ 10,064 $ 18,482 $(18,023) $(16,748) $(15,616)
-
8,212
20,995
1,646
1,669
2,525
2,058
1,866
1,514
$
96
We adopted SFAS No. 158 effective December 31, 2006. Under SFAS No. 158, any actuarial
gains and losses, prior service costs and transition assets or obligations that were not recognized
under previous accounting standards must be recognized in accumulated other comprehensive
income (AOCI) under common stock equity, net of tax, until they are amortized as a
component of net periodic benefit cost. We consider the recognition of the underfunded status
of the qualified defined benefit plans and postretirement benefit plans to be subject to
regulatory deferral under SFAS No. 71. The unrecognized net gains and losses, prior service
costs and transition obligations relating to our qualified defined benefit pension and
postretirement benefit plans are recognized as regulatory assets. An estimated $8.1 million for
the qualified plans, consisting of $6.2 million of actuarial losses, $1.5 million of prior service
costs and transition obligations of $0.4 million, will be amortized from the regulatory asset
account to net periodic benefit cost in 2009. The gains and losses, prior service costs and
transition obligations related to our non-qualified supplemental pension plans are recognized in
AOCI, net of tax, under common stock equity because these expenses are not the basis for
regulatory recovery; however, these amounts are not material. In 2008, an estimated $0.4
million consisting of actuarial losses of $0.4 million and negligible prior service costs for the
non-qualified plans were amortized from AOCI to net periodic benefit cost.
Our qualified defined benefit pension plans had an aggregate projected benefit obligation of
$261.5 million, $243.1 million and $255.5 million at December 31, 2008, 2007 and 2006,
respectively, and the fair value of plan assets was $163.1 million, $241.4 million and $236.5
million, respectively. Changes in valuation assumptions impact our projected benefit
obligations. Benefit obligations at December 31, 2008 increased $7.4 million due to a decrease
in our discount rate assumptions and increased by $5.0 million due to updating our mortality
tables. The projected benefit obligations at December 31, 2007 decreased $23.9 million due to
an increase in the discount rate assumptions and increased by $3.4 million due to an increase in
the benefit payments for certain retirees. 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.
An assumed discount rate was determined independently for each pension plan and other
postretirement benefit plan based on the Citigroup Above Median Curve (discount rate curve)
using high quality bonds (i.e. rated AA- or higher by Standard & Poor’s or Aa3 or higher by
Moody’s Investors Service). 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. 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,
97
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.
Our pension plan asset allocation at December 31, 2008 and 2007, 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
Fixed Income
Real Estate
Absolute Return Strategy
Real Return Strategy
Weighted Average
Percentage of
Plan Assets
Dec. 31,
2008
2007
14.3% 18.1%
9.6% 13.1%
17.9% 24.9%
21.2% 13.3%
11.3% 8.9%
18.9% 16.3%
6.8% 5.4%
Target
Allocation
Expected Long-term
Rate of Return
20%
15%
20%
15%
8%
15%
7%
8.50%
9.50%
8.75%
5.50%
7.75%
9.00%
7.75%
8.25%
Our non-qualified supplemental defined benefit pension plans’ benefit obligations were $19.6
million, $17.5 million and $13.9 million at December 31, 2008, 2007 and 2006, 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 the plans 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 $23.9 million, $22.2 million and $22.4
million at December 31, 2008, 2007 and 2006, 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 from the year in which they
occur, thereby reducing year-to-year net periodic benefit cost volatility.
98
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,
2008, 2007 and 2006 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 loss
Pension Benefits
2008
2007
2006
Other Postretirement
Benefits
2007
2008
2006
$
6,141 $
17,373
(19,087)
8,708 $
16,057
(18,490)
7,745 $
14,901
(17,611)
521 $
505 $
1,403
-
1,293
-
556
1,184
-
19
1,253
385
-
-
411
411
411
1,188
2,123
979
3,520
197
-
197
25
195
1
Net periodic benefit cost
$
6,084 $
9,586 $
9,534 $ 2,532 $ 2,431 $ 2,347
Assumptions for net periodic benefit
cost:
Discount rate
Rate of increase in compensation
Expected long-term rate of return
Assumptions for funded status:
Discount rate
Rate of increase in compensation
Expected long-term rate of return
6.76%-6.87% 6.0%-6.05%
3.5%-5.0% 4.0%-5.0% 4.0%-5.0%
8.25%
8.25%
8.25%
5.75% 6.56% 5.91% 5.75%
n/a
n/a
n/a
n/a
n/a
n/a
6.44%-6.72% 6.76%-6.87% 6.0%-6.05% 7.12% 6.56% 5.91%
n/a
n/a
3.5%-5.0% 4.0%-5.0% 4.0%-5.0%
8.25%
n/a
n/a
n/a
n/a
8.25%
8.25%
The assumed annual increase in trend rates used in measuring other postretirement benefits as
of December 31, 2008 were 9.5 percent for medical and 11.5 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 2022.
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
$ 51
$ (45)
$732
$(646)
99
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, 2008 and 2007, and estimated
future payments:
Thousands
Employer Contributions by Plan Year
Pension Benefits
Other Benefits
2007
2008
2009 (estimated)
Benefit Payments
2006
2007
2008
Estimated Future Payments
2009
2010
2011
2012
2013
2014-2018
$
1,606
1,645
10,391
$ 13,183
15,924
16,247
$ 16,476
17,030
17,385
18,293
18,761
106,004
$ 1,298
1,259
2,063
$ 1,015
1,298
1,259
$ 2,063
2,096
2,171
2,101
2,810
10,384
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 92 percent in 2008, 94 percent in 2009 and 96 percent in 2010. Our
qualified defined benefit pension plans are currently underfunded by $98 million at
December 31, 2008, and we expect to make at least the minimum contribution required
pursuant to the Act, which is currently estimated at $8 million. We plan to make an additional
contribution during 2009, which could bring the total contribution in 2009 up to $40 million.
We would need to make a total contribution in 2009 of at least $17 million to avoid any
restrictions on benefit payments.
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 2008, $1.9
million in 2007, and $1.8 million in 2006. 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 totaled $0.4 million in 2008 and 2007 and $0.5 million in 2006.
100
8.
INCOME TAXES:
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
The provision for income taxes consists of the following:
Thousands
Current
Federal
State
Deferred
Federal
State
Total provision for income taxes
Total income taxes paid
2008
2007
2006
$38,571
$41,495
$34,877
4,100
(646)
4,566
(881)
3,655
(994)
(704)
(767)
124
(704)
(679)
263
(704)
(913)
313
$40,678
$44,060
$36,234
35.0%
35.0%
35.0%
3.7%
-0.6%
-0.6%
-0.7%
0.1%
3.9%
-0.7%
-0.6%
-0.6%
0.2%
3.7%
-1.0%
-0.7%
-0.9%
0.3%
36.9%
37.2%
36.4%
2008
2007
2006
$ (7,970) $41,086
7,764
(437)
$ 44,785
7,836
(8,407)
48,850
52,621
42,862
6,223
49,085
(4,107)
(683)
(14,180)
(2,207)
(4,790)
(16,387)
$40,678
$44,060
$ 36,234
$12,300
$56,215
$ 31,270
101
The following table summarizes the total provision (benefit) for income taxes for the regulated
utility and other non-utility business segments for the three years ended December 31, 2007:
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
2008
2007
2006
$(13,034) $43,587
(3,856)
(713)
48,790
(646)
$ 48,469
(14,810)
(756)
35,110
39,018
32,903
4,627
941
0
5,568
5,263
(53)
(168)
5,042
4,152
(583)
(238)
3,331
$ 40,678
$44,060
$ 36,234
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
2008
2007
$183,462
2,374
69,948
8,145
426
$159,506
2,356
68,649
478
249
264,355
231,238
(4,335)
(2,709)
(471)
(1,557)
(25,973)
(2,118)
-
-
(9,072)
(28,091)
255,283
2,548
203,147
3,193
$257,831
$206,340
We have determined that we are more likely than not to realize all recorded deferred tax assets
as of December 31, 2008.
102
The following is a reconciliation of the change in our deferred tax balance for the year ended
December 31:
Thousands
Deferred tax expense, above
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
2008
$49,731
1,299
(591)
1,698
(646)
$51,491
We calculate our deferred tax assets and liabilities under SFAS No. 109, whereby deferred
income taxes are generally determined based on the difference between the financial statement
and tax basis 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.
On February 13, 2008, the Economic Stimulus Act (ESA) was enacted providing an additional
first-year tax deduction for depreciation equal to 50 percent of the adjusted basis of “qualified
property.” 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 provisions provided by the ESA is expected to
expire at December 31, 2008. During 2008, we reduced income taxes currently payable by an
estimated $13.6 million.
For the year ended December 31, 2008, we had 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 ESA. The federal
NOL will be carried back to 2006 for a refund of taxes paid in prior years and the Oregon NOL
will be carried forward to reduce future taxable income. We anticipate that we will be able to
use all loss carryforwards in future years. The 2008 Oregon NOL will expire in 2023.
In July 2006, FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income
Taxes, an Interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting
for uncertainty in income taxes recognized in the financial statements in accordance with SFAS
No. 109. FIN 48 requires the use of a two-step approach for recognizing and measuring tax
positions taken or expected to be taken in a tax return. First, a tax position should only be
recognized when it is more likely than not, based on technical merits, that the position will be
sustained upon examination by the taxing authority. Second, a tax position that meets the
recognition threshold should be measured at the largest amount that has a greater than 50
percent likelihood of being sustained. We adopted FIN 48 as of January 1, 2007, and had no
material unrecognized tax benefits upon adoption or for the years ended December 31, 2008
and 2007. As a result, no interest or penalties were accrued for unrecognized tax benefits during
the year. The IRS has completed and closed its examination of the Company’s 2002, 2003 and
2004 tax years. The years after 2004 remain open to further examination by the IRS.
103
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
2008
2007
Weighted
Average
Depreciation
Rate
3.3%
2.5%
3.2%
9.0%
0.0%
3.4%
Weighted
Average
Depreciation
Rate
3.3%
2.6%
3.0%
8.8%
0.0%
3.4%
Amount
$1,735,934
112,984
96,612
71,044
14,232
2,030,806
21,355
2,052,161
(615,533)
$1,436,628
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
Accumulated depreciation does not include the accumulated provision for asset removal costs
of $223.7 million and $204.9 million at December 31, 2008 and 2007, 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
2007
Weighted
Average
Depreciation
Rate
2.1%
2008
Weighted
Average
Depreciation
Rate
2.5%
Amount
$60,515
4,886
65,401
9,105
74,506
(9,314)
$65,192
Amount
$54,083
4,881
58,964
8,185
67,149
(7,904)
$59,245
104
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
Investment in gas pipeline joint venture
Other
Total other investments
2008
2007
$35,427
518
15,214
2,973
$46,294
518
7,258
-
$54,132
$54,070
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.
Investment in Gas Pipeline Joint Venture. A wholly-owned subsidiary of Financial
Corporation, KB Pipeline Company, owns a 10 percent interest in an 18-mile interstate natural
gas pipeline. Also, in 2007, we entered into an agreement with TransCanada’s Gas
Transmission Northwest (GTN) for the purpose of designing, permitting, constructing and
owning a 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, 2008, our investment balance in Palomar was $14.2 million, primarily related to
planning and permitting.
Variable Interest Entities. FASB Interpretation No. 46(R), “Consolidation of Variable Interest
Entities,” provides guidance for determining whether consolidation is required for entities
known as variable interest entities over which control is achieved through means other than
voting rights or 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 we are not the
primary beneficiary. See Note 2.
10.
FAIR VALUE OF FINANCIAL INSTRUMENTS:
We use fair value measurements to record fair value adjustments to certain financial
instruments and to determine fair value disclosures. As of December 31, 2008, we recorded our
derivatives at fair value according to SFAS No. 157. As we elected not to implement SFAS
No. 159, we did not measure our long-term debt at fair value (see Note 1).
In accordance with SFAS No. 157, we use the following fair value hierarchy for determining
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
105
• 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. Derivative contracts
outstanding at December 31, 2008 were measured at fair value using models or other market-
accepted valuation methodologies derived from observable market data. These quoted prices
are primarily 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.
In accordance with SFAS No. 157, 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, 2008.
The following table provides the fair value hierarchy of our derivative assets and liabilities as
of December 31, 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
-
$
(153,643)
-
$(153,643)
11.
USE OF FINANCIAL 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 SFAS No. 133. 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 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 SFAS No. 71 regulatory deferral treatment. Derivatives contracts
entered into for core utility customer requirements after the annual PGA rate has been set are
subject to the PGA incentive sharing mechanism, whereby 80 percent of the changes in fair
value are deferred as regulatory assets or liabilities and the remaining 20 percent is recorded to
106
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 but 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 SFAS No. 133. The mark-to-market
adjustment at December 31, 2008 was an unrealized loss of $0.4 million. This unrealized loss is
subject to regulatory deferral and, as such, was recorded as a derivative liability, which is offset
by recording a corresponding amount to a regulatory asset account.
In 2007, we entered into a 10-year, $50 million fixed-price forward starting interest rate swap
contract to hedge the interest rate exposure related to the forecasted issuance of long-term debt.
This interest rate swap is an effective cash flow hedge under SFAS No. 133.
The unrealized mark-to-market value at December 31, 2008 for all derivative contracts
outstanding was a total loss of $153.6 million consisting of the following: a $141.3 million
unrealized loss on natural gas commodity hedge and derivative contracts, a $11.9 million
unrealized loss on the interest rate swap contract and a $0.4 million unrealized loss 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, 2008, 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
SFAS No. 133 to determine the hedge effectiveness of our interest rate swap which qualifies as
a cash flow hedge. We extended the effective date of our interest rate swap from December 1,
2008 to April 1, 2009 which resulted in an ineffectiveness of $1.5 million. In accordance with
SFAS No. 71, we have reclassified this amount from AOCI to regulatory assets. The
ineffectiveness for all other derivative contracts is determined using the dollar offset method
under SFAS No. 133. The effectiveness test applied to financial derivatives is dependent on the
type of derivative and its use.
107
At December 31, 2008 and 2007, the unrealized gains or losses from mark-to-market valuations
of our derivative instruments were primarily recorded as regulatory liabilities or regulatory
assets because the realized gains or losses at settlement are either included, or are expected to
be included, in utility rates pursuant to regulatory deferral mechanisms. The estimated fair
values of unrealized gains and losses on derivative instruments outstanding, determined using a
discounted cash flow model for swaps and a Black-Scholes model for options, were as follows:
Thousands
Natural gas commodity-based derivative
instruments:
Fair Value Gains (Losses)
Dec. 31, 2008
Dec. 31, 2007
Current
Non-Current Current Non-Current
Natural gas commodity hedge contracts
Interest rate hedge contract
Foreign currency forward purchase contracts
$(131,698)
-
(445)
$ (9,588)
(11,912)
-
$(12,099)
-
173
$(2,104)
(1,330)
-
Total
$(132,143)
$(21,500)
$(11,926)
$(3,434)
In 2008 and 2007, we realized net gains of $35.1 million and net losses of $42.0 million,
respectively, from the settlement of fixed-price natural gas financial swap contracts which were
recorded as decreases and increases to the cost of gas, respectively. Realized losses in 2007
were offset by lower gas purchase costs from the underlying hedged item, which were floating
rate physical supply contracts. The currency exchange rate in all foreign currency forward
purchase contracts is included in our cost of gas at settlement; therefore, no gain or loss was
recorded from the settlement of those contracts. There were no realized gains or losses on the
interest rate swap during 2008.
As of December 31, 2008, all of our natural gas financial hedge contracts mature on or before
October 2010. The maturity date on our interest rate swap contract is in April 2019.
12.
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 $4.7 million, $4.6 million and $4.4 million for
the years ended December 31, 2008, 2007 and 2006, respectively. The table below reflects the
future minimum lease payments due under non-cancelable leases at December 31, 2008. Such
payments total $47.3 million for operating leases. The net present value of payments on capital
leases less imputed interest was $1.2 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
2009
2010
2011
2012
2013
Later
years
$4,129
599
$4,127
461
$4,080
163
$4,230
21
$4,268
-
$26,501
-
Minimum lease payments
$4,728
$4,588
$4,243
$4,251
$4,268
$26,501
108
Gas Purchase and Pipeline Capacity Purchase and Release Commitments
We have signed agreements providing for the reservation of firm pipeline capacity under which
we are required to make fixed monthly payments for contracted capacity. The pricing
component of the monthly payment is established, subject to change, by U.S. or Canadian
regulatory bodies. In addition, we have entered into long-term sale agreements to release firm
pipeline capacity. We also enter into short-term and long-term gas purchase agreements. The
aggregate amounts of these agreements were as follows at December 31, 2008:
Thousands
2009
2010
2011
2012
2013
2014 through 2028
Total
Less: Amount representing interest
Total at present value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$229,804
89,079
34,835
21,277
21,277
17,731
414,003
7,698
$ 84,798
64,554
64,175
49,067
41,602
87,826
392,022
27,861
$4,128
3,440
-
-
-
-
7,568
56
$406,305
$364,161
$7,512
Our total payments of fixed charges under capacity purchase agreements in 2008, 2007 and
2006 were $85.7 million, $90.1 million and $69.2 million, respectively. Included in the
amounts were reductions for capacity release sales of $5.0 million for 2008, $5.3 million for
2007 and $3.7 million for 2006. 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. 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 events giving
109
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 DEQ for groundwater source control. We have a net liability accrued of
$20.1 million at December 31, 2008 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 DEQ. The net liability accrued at December 31, 2008 for the Siltronic site is $1.0 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 U.S. Environmental Protection Agency
(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
was listed by the EPA as a Superfund site in 2000 and we were notified that we are a
potentially responsible party. We then joined with other potentially responsible parties, referred
to as the Lower Willamette Group, to fund 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
110
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, 2008, we have a net liability accrued of $13.2 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 $10.8 million. To date,
we have paid $10.1 million on work related to the removal of the tar deposit. As of
December 31, 2008, we have a net liability accrued of $0.7 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, 2008, 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, 2008, we accrued an estimated liability of $0.3
million for the study of the site, which will include investigation of sediments and provide a
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.
111
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, 2008 and 2007:
Thousands
Gasco
Siltronic
Portland Harbor
Central Service Center
Front Street
Other
Total
Current Liabilities
Non-Current Liabilities
$
2008
2007
$
6,012
682
277
-
-
-
$
6,901
-
-
-
-
-
$
2008
14,071
332
13,642
526
294
80
2007
14,342
1,540
14,821
529
2
165
$
6,971
$
6,901
$
28,945
$
31,399
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 25, 2009. We have requested another
extension through January 2010, and that request is currently pending.
On a cumulative basis, we have recognized a total of $70.9 million for environmental costs,
including legal, investigation, monitoring and remediation costs. Of this total, $35.0 million has
been spent to date and $35.9 million is recorded as an outstanding liability. At December 31,
2008, we had a regulatory asset of $66.1 million, which includes $30.1 million of total paid
expenditures to date, $30.0 million for additional environmental costs expected to be paid in the
future and accrued interest of $6.0 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
but continue to anticipate that our overall insurance recovery effort will extend over several
years.
112
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, 2008 and 2007:
Thousands
Gasco
Siltronic
Portland Harbor
Central Service Center
Front Street
Other
Total
Legal Proceedings
Non-Current Regulatory Assets
2008
2007
$
$
$
30,707
2,327
31,791
545
338
396
66,104
$
29,042
2,227
30,869
545
1
370
63,054
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.
113
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Thousands, except per share amounts
March 31
June 30
Sept. 30
Dec. 31
Total
Quarter ended
2008
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2007
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$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(1)
2.61(1)
$394,091
139,008
48,075
1.77
1.76
$183,249
64,118
2,617
0.10
0.10
$124,245
49,663
(5,908)
(0.22)
(0.22)
$331,608
116,253
29,713
1.12
1.11
$1,033,193
369,042
74,497
2.78(1)
2.76(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.
114
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)
2008
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
$2,890
$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
2006
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
$3,067
$3,036
$-
$-
$3,121
$2,890
$3,070
$3,033
115
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, 2008, 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, 2008 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.
116
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 28, 2009 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 28, 2009 Annual Meeting of Shareholders is hereby
incorporated by reference.
Name
Dec. 31, 2008 Positions held during last five years
Age at
Mark S. Dodson
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
63
51
47
54
53
55
55
53
51
53
52
Chief Executive Officer (2007-2008); President and Chief Executive
Officer (2003-2007).
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- ); Senior
Vice President and Chief Financial Officer, TXU Gas Company
(2004); Senior Vice President, Principal Accounting Officer and
Controller TXU Corp. (2003-2004).
Vice President and General Counsel (2005-
); Partner, Stoel Rives
LLP (1991- 2005).
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, Acquire
Customers (2006); Director, Gas Operations (2005-2006); General
Manager, Utility Operations (1999-2004).
Vice President, Utility Operations (2007-
); Managing Director,
Utility Services (2005-2006); General Manager, Consumer
Services (2003-2004).
Vice President, Finance and Regulation (2009-
); 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 28, 2009.
There are no family relationships among our executive officers, directors or any person chosen to
become one of our officers or directors.
117
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.
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 28, 2009 Annual Meeting of Shareholders is hereby
incorporated by reference. Information related to Executive Officers as of December 31, 2008 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, 2008 (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))
75,000
396,410
15,119
6,300
72,767
47,617
n/a
613,213
n/a
$38.62
$43.25
n/a
n/a
n/a
n/a
247,898
922,400
188,414
n/a
n/a
n/a
n/a
1,358,712
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
Non-Employee Directors Stock
Compensation Plan4
Total
The information captioned “Beneficial Ownership of Common Stock by Directors and
Executive Officers” contained in our definitive Proxy Statement for the May 28, 2009 Annual Meeting
of Shareholders is incorporated herein by reference.
118
1
2
3
4
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, 2008, the number of shares shown in column (a) would
increase by 71,834 shares and the number of shares shown in column (c) would decrease by
71,834 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 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
participates’ stock accounts. The right of each participant in the DCP is that of a general,
unsecured creditor of the Company.
The material features of this plan are more particularly described in Note 4 to the Consolidated
Financial Statements included in this report.
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 28, 2009 Annual Meeting of Shareholders is
hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information captioned “2008 and 2007 Audit Firm Fees” in the Company’s definitive
Proxy Statement for the May 28, 2009 Annual Meeting of Shareholders is hereby incorporated by
reference.
119
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 123.
120
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 27, 2009
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
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/ C. Scott Gibson
C. Scott Gibson
/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 27, 2009
Principal Financial Officer
February 27, 2009
Principal Accounting Officer
February 27, 2009
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
121
February 27, 2009
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
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)
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)
EXHIBIT INDEX
To
Annual Report on Form 10-K
For Fiscal Year Ended
December 31, 2008
Exhibit Number
Document
*3a.
*3b.
*4a.
*4d.
*4e.
*4f.
*4f.(1)
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).
122
*4i.
4i.(1)
*4k.
*4m.
*4l.
*10j.(1)
*10j.(2)
*10j.(3)
*10j.(5)
*10j.(6)
*10j.(7)
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.
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).
Distribution Agreement, dated September 28, 2004, as amended and restated
on December 7, 2006, among the Company, Merrill Lynch, Pierce Fenner &
Smith Incorporated, UBS Securities LLC, J.P. Morgan Securities, Inc. and
Piper Jaffray & Co. (Incorporated herein by reference to Exhibit 4j. to Form
10-K for 2006, File No. 1-5973).
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).
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).
123
*10j.(8)
*10j.(9)
10j.(10)
10j.(11)
10j.(12)
10j.(13)
10j.(14)
10j.(15)
10j.(16)
10j.(17)
10j.(18)
10j.(19)
12
23
31.1
31.2
32.1
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.
Service Agreement (100310), dated January 21, 2008, between the
Company and Northwest Pipeline GP.
Service Agreement, dated January 21, 2008, between the Company and
Northwest Pipeline GP.
Service Agreement (Gas Storage Service), dated January 12, 1994, between
the Company and Northwest Pipeline Corporation.
Service Agreement (100309), dated January 21, 2008, between the
Company and Northwest Pipeline GP.
Service Agreement (100308), dated January 12, 1994, between the
Company and Northwest Pipeline GP.
Service Agreement, dated January 20, 1995, between the Company and
NOVA Gas Transmission Ltd.
Service Agreement, dated November 1, 2004, between the Company and
TransCanada PipeLines Limited.
Service Agreement, dated October 24, 2008, between Foothills Pipe Lines
Ltd. and the Company.
Amendment and Restatement of Firm Transportation Service Agreement,
dated November 1, 2004, between Terasen Gas Inc. and the Company.
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.
*10b.(1)
Executive Supplemental Retirement Income Plan (2007 Restatement)
(incorporated herein by reference to Exhibit 10b to Form 10-K for 2007,
File No. 1-15973).
Supplemental Executive Retirement Plan, effective September 1, 2004
restated December 20, 2007 (incorporated herein by reference to Exhibit
10b.(1) to Form 10-K for 2007, File No. 1-15973).
124
*10b.(2)
*10b.(3)
*10b.(4)
*10c.
*10c.(1)
10e.
10f.
*10f.(1)
*10g.
*10i.
*10k.
10o.
*10o.-1
*10p.-3
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 (incorporated herein by
reference to Exhibit 10.3 to Form 10-Q dated November 3, 2005,
File No. 1-15973).
Executive Deferred Compensation Plan, effective as of January 1, 1987,
restated as of February 26, 2009.
Directors Deferred Compensation Plan, effective June 1, 1981, restated as of
February 26, 2009.
Deferred Compensation Plan for Directors and Executives effective January
1, 2005, restated February 28, 2008 (incorporated herein by reference to
Exhibit 10f.(1) to Form 10-K for 2007, File No. 1-15973).
Form of Indemnity Agreement as entered into between the Company and
each director and executive officer (incorporated herein by reference to
Exhibit 10g. to Form 10-K for 1988, File No. 0-994).
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 January 1, 2003
(incorporated herein by reference to Exhibit 10 k. to Form 10-K for 2002,
File No. 0-994).
Form of Change in Control Severance Agreement between the Company
and each executive officer.
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).
Employment Agreement dated December 20, 2002, between the Company
and an executive officer (incorporated herein by reference to Exhibit 10p.-3
to Form 10-K for 2002, File No. 0-994).
125
*10p.-4
*10v.
*10w.
*10w.(1)
*10w.(2)
*10x.
*10x.(1)
*10aa.
*10bb.
Amendment dated December 14, 2006 to employment agreement dated
December 20, 2002 between the Company and Mark S. Dodson
(incorporated herein by reference to Exhibit 10.8 to Form 8-K dated
December 19, 2006, 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 (incorporated herein by reference to Exhibit 10.8 to Form 8-
K dated December 16, 2005, File No. 1-15973).
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).
* Incorporated herein by reference as indicated
126
NORTHWEST NATURAL GAS COMPANY
Statement Re: Ratio of Earnings to Fixed Charges
Thousands, except per share amounts
(Unaudited)
EXHIBIT 12
Year Ended December 31,
2008
2007
2006
2005
2004
Fixed Charges, as defined:
Interest on Long-Term Debt . . . . . . . . . . . . . . . . .
Other Interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of Debt Discount and Expense . . . .
Interest Portion of Rentals . . . . . . . . . . . . . . . . . .
$ 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
$ 33,776
2,184
773
1,489
Total Fixed Charges, as defined . . . . . . . . . . . . . .
$ 39,878
$ 40,644
$ 41,480
$ 39,160
$ 38,222
Earnings, as defined:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes on Income . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed Charges, as above . . . . . . . . . . . . . . . . . . . .
$ 69,525
40,678
39,878
$ 74,497
44,060
40,644
$ 63,415
36,234
41,480
$ 58,149
32,720
39,160
$ 50,572
26,531
38,222
Total Earnings, as defined . . . . . . . . . . . . . . . . . .
$150,081
$159,201
$141,129
$130,029
$115,325
Ratio of Earnings to Fixed Charges . . . . . . . . . . . . . . .
3.76
3.92
3.40
3.32
3.02
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, 333-46430, 333-55002, 333-70218, 333-100885, 333-120955, 333-134973 and 333-139819)
and in the Registration Statements on Form S-3 (Nos. 333-148527 and 333-123898) of Northwest
Natural Gas Company of our report dated February 27, 2009 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 27, 2009
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 27, 2009
/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 27, 2009
/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, 2008 (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 27th day of February 2009.
/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.
we grew up here
220 NW Second Avenue
Portland, Oregon 97209
nwnatural.com
NYSE: NWN
Cert no. SCS-COC-00648
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