220 NW Second Avenue
Portland, Oregon 97209
nwnatural.com
NYSE: NWN
Growing responsibly.
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2007 ANNUAL REPORT
Corporate Profile
Utility Service Territory
NW Natural (NYSE: NWN) is a 149-year-old natural gas local distribution
and storage company headquartered in Portland, Oregon, with a customer
growth rate well above the national average. NW Natural serves more than
652,000 customers in Oregon and southwest Washington, including the
Portland-Vancouver metropolitan area, the Willamette Valley, the Oregon
coast and the Columbia River Gorge. In keeping with its steady growth,
the company has increased dividends paid to shareholders for 52 consecutive
years, a feat matched by few publicly traded companies. NW Natural purchases
natural gas for its core market from a variety of suppliers in the western United
States and Canada. The company operates gas storage facilities in its service
territory, contracts for additional gas storage outside its service territory, 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 natural gas transmission pipeline from
central Oregon to northwest Oregon providing enhanced gas deliverability and
reliability for the region.
Williams gas pipeline
NW Natural gas
transmission line
Kelso Beaver Pipeline
Coos County pipeline
LNG plant
Regional resource centers
Mist underground gas storage
Headquarters
2007
2006
percent
increase
(decrease )
Diluted Earnings Per Share (IN DOLLARS)
Financial 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
1,033,193
369,042
74,497
1,013,172
340,176
63,415
12.5
46.3
53.7
10.7
46.3
53.7
26,821
26,407
27,540
27,284
2.78
2.76
1.44
1.50
22.52
48.66
2.30
2.29
1.39
1.42
21.97
42.44
Gas sales and transportation deliveries (000 therms) 1,214,969
4,374
Degree days (25-year average, 4,265)
652,012
Customers at year-end
1,141
Employees at year-end
1,192,649
4,089
636,584
1,211
DIvIDENDS PAID ON COMMON STOCK (per share)
PAYMENT DATE
February 15
May 15
August 15
November 15
Total dividends paid
$ 0.355
0.355
0.355
0.375
$ 1.440
$ 0.345
0.345
0.345
0.355
$ 1.390
2
8
17
17
–
–
(3 )
(3 )
21
21
4
6
2
15
2
7
2
(6 )
$3.00
2.50
2.00
1.50
1.00
0.50
0
‘03
‘04
‘05
‘06
‘07
Diluted earnings per share were $2.76 in 2007, up
21 percent over 2006.
Dividends Paid Per Share (IN DOLLARS)
$1.47
1.42
1.37
1.32
1.27
1.22
‘03
‘04
‘05
‘06
‘07
Annual dividends paid per share in 2007 increased
for the 52nd consecutive year. The indicated
dividend rate at year-end was $1.50 per share.
We grew up here.
n w n a t u r a l . c o m
3
Table of
contents
Letter to SharehoLderS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
IntervIew wIth the PreSIdent . . . . . . . . . . . . . . . . . . . . . . . 8
a StrategIc and LaStIng FoundatIon . . . . . . . . . . . . . . 10
PurPoSe, ProSPerIty, SuStaInabILIty . . . . . . . . . . . . . . . . . 12
accountabLe to Future generatIonS . . . . . . . . . . . . . . 14
FInancIaL overvIew . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
corPorate oFFIcerS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
board oF dIrectorS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
QuarterLy FInancIaL InFormatIon . . . . . . . . . . . . . . . . . . 24
FInancIaL StatementS – Form 10-K annuaL rePort
4
Letter to Shareholders
Front: Mark Dodson,
Chief Executive Officer
Back: Gregg Kantor,
President and Chief
Operating Officer
A foundation for sustainable success
NW Natural has always taken a
long-term view of its commitments
to customers, employees, share-
holders and the communities it
serves. This stewardship ethic has
helped us grow and thrive for
149 years. And in today’s world of
new economic and environmental
realities, it has never been more
important or more valued by
those who rely on us.
In 2007, we ramped up our efforts
on behalf of sustainability – for both
our company and our planet – and
we’re proud of what we accomplished.
We reorganized to better compete
and to improve customer service. We
planned strategic investments in gas
storage and transmission pipelines –
necessary infrastructure as the nation
increasingly relies on natural gas to
help reduce carbon emissions. And
we were among the first gas utilities
in the nation to give its customers
options to combat global warming.
By year’s end, it was clear not only
that we’d made responsible deci-
sions, but also that we’d executed
well. Our financial results show
that responsible growth can drive
sustained high performance.
Much ventured, much gained
The year 2007 was exceptional both
in terms of the company’s accom-
plishments and its financial results.
Earnings were up more than 17
percent, with earnings per share
increasing by nearly 21 percent.
Gas cost savings allowed us to
lower customer rates for 2008
and brought NW Natural customers
and shareholders significant financial
benefits. Oregon and Washington
residential customers saw rates drop
by 8 and 10 percent, respectively.
Oregon’s incentive cost-sharing
mechanism refunds to customers
two-thirds of the money saved
on gas purchases while allowing
shareholders to keep one-third
of the savings. NW Natural’s
portion of these savings totaled
$12 million, equivalent to 27 cents
a share.
A regulatory surcharge resulting
from Oregon legislation passed in
2005 also added to 2007 earnings.
Legislators sought to ensure that
the taxes utilities paid equaled the
amount of taxes collected from rate-
payers. Because we paid more taxes
than we collected in rates in 2006
and 2007 tax years, we expect to
collect $6 million from customers
for these periods, equivalent to
13 cents a share.
Despite a slowdown in housing
starts, NW Natural continued
to grow at a rate well above the
national average. The Northwest’s
relatively strong economy helped
us maintain a customer growth
rate of 2.4 percent, compared to
a national average of 1.2 percent.
Last year, we shared with you the
changes we were making in our
operations to become more efficient.
Our timing could not have been better.
The improvements initiated in 2006
contributed to 2007 results and posi-
tion us well to ride out the current
economic slowdown. For example,
our newly reorganized sales team
reversed a trend of declining residen-
tial conversions to gas, producing the
first annual increase in eight years.
Since implementing these changes,
the company is operating with more
than 10 percent fewer employees. We
are proud to say we accomplished
these reductions almost entirely
through attrition and voluntary
separations – an uncommon feat
in today’s business environment.
Our strong financial performance
in 2007 allowed us to invest
ahead of schedule on a number
of projects designed to reinforce
the safety and reliability of our gas
system. These investments totaled
approximately $5 million for the
year. Excluding these accelerated
expenditures, core O&M was
up only 1 percent, thus meeting
one of our main objectives: keeping
increases in our operating costs
lower than customer growth.
Cash provided by operations in 2007
reached $184 million compared to
$149 million in 2006. These record
results reflected the effects of our
improved operations and higher
deferred gas cost benefits. And for
the second consecutive year, we
produced positive free cash flow – a
rare achievement for a fast-growing
natural gas utility.
Overall, 2007 was a remarkable year.
The company’s total shareholder return
was 18 percent, and the end-of-year
share price was $48.66, up $6.22.
New business opportunities
change, making carbon-reduction
legislation likely in the near future.
It also became clear to us that the
only short-term practical option
for large-scale electric generation
is natural gas – so the nation must
begin thinking more seriously about
its gas supplies.
This recognition reinforced our
earlier interest in new business
development related to gas
transportation and storage. It also
encouraged us to build on the
expertise acquired from managing
and operating our Mist storage
field and its connecting pipelines.
In August, we announced the
creation of Palomar Gas Transmis-
sion LLC, a joint venture formed
with TransCanada Corporation. The
partnership plans to build a new
transmission pipeline connecting
TransCanada’s interstate system
with NW Natural’s distribution
system. A second Palomar segment
could connect to a liquefied natural
gas import terminal if one is built
on the Columbia River.
In September, we also announced
the formation of Gill Ranch Storage,
LLC. This NW Natural subsidiary
plans to build and operate a 20 bil-
lion cubic feet (Bcf) underground
gas storage facility near Fresno,
California. We are working on this
project jointly with Pacific Gas and
Electric, which brings experience
with storage and pipelines in
California as well as with the
state’s regulatory environment.
Rewarded for responsible actions
In business, as in the natural world,
sustainability requires balance. For
a utility, that means balancing and
aligning the interests of all those who
rely on us – customers, employees,
shareholders and communities in
Oregon and Washington.
The year 2007 saw a tipping point
for public perception about climate
Without raising rates we found new
ways to align the interests of all our
5
constituencies. We streamlined our
operations to improve customer
service while increasing shareholder
value. We kept our commitments
to employees. And we strengthened
relationships with Northwest commu-
nities through our local philanthropic
efforts and involvement with civic
and national policy issues.
Highlights
In 2007, NW Natural:
• Earned a record $2.76 per diluted
share, up 21 percent over 2006,
and provided a total shareholder
return of 18 percent.
• Ranked first in the West and
second nationally in the annual
J.D. Power & Associates customer
satisfaction survey.
• Produced record cash flow
from operations of $184 million,
resulting in positive free cash
flow for the year.
• Increased our Mist gas storage
capacity by 1.8 Bcf to approxi-
mately 16 Bcf.
• Formed a joint venture with
TransCanada to build Palomar
Pipeline, and formed Gill Ranch
Storage, LLC to develop a gas
storage facility in California with
Pacific Gas and Electric Company.
• Extended our weather normal-
ization and decoupling rate
mechanisms in Oregon into 2012.
• Was named to the list of the 10
“Most Admired Companies” in the
“Across All Industries” category
by the Portland Business Journal.
• Ranked as one of the 100 top
corporate citizens in the nation
by CRO Magazine (formerly
Business Ethics) for the
seventh year in a row.
• Was honored with the
RecycleWorks Award by
the City of Portland for
our sustainability efforts.
• Was confirmed by Standard and
Poor’s at a secured debt rating
of AA- with the top business
risk profile ranking.
• Was confirmed by Moody’s at a
secured debt rating of A2 with
low business risk, and rating
outlook was changed to positive
from stable.
• Raised the quarterly dividend
rate by 6 percent, making this
the 52nd consecutive year of
increasing dividends per share.
Environmental stewardship
Our Northwest customers are
known for their environmental
concern and savvy. When surveyed,
they said they expected us to play
a leading role in fighting climate
change. So in 2007, we launched
our Smart Energy program and
became the nation’s first stand-
alone gas utility to help customers
offset carbon dioxide emissions
associated with their natural gas use.
Total Shareholder Return
(ANNUALIZED AS A PERCENT)
6
21%
18%
15%
12%
9%
6%
3%
0%
Ten Years
1997 – 2007
Five Years
2002 – 2007
One Year
2007
Our annualized total return (dividends plus stock appreciation)
was 18.2 percent in 2007, 16.7 percent over the past five years,
and 9.3 percent over 10 years.
We’re also taking a close look at
the effects climate change could
have on the gas industry. As chair
of the American Gas Association’s
Climate Change Task Force, I spoke
at numerous public forums to
help the gas industry focus on the
challenge of climate change, and to
articulate the important role natu-
ral gas must play in future carbon
legislation. And recently, Governor
Ted Kulongoski appointed NW
Natural’s Gregg Kantor to be one
of 11 members of his new Oregon
Global Warming Commission.
While there may be questions about
what climate change will mean for
the future energy picture, we believe
there will be greater demand for
natural gas. And to anticipate and
respond to the impacts on our busi-
ness, we will continue to be actively
involved in local and national climate
change policy discussions.
We will also continue to aggres-
sively support the efficient and
direct use of natural gas. Using
highly efficient natural gas water
heaters, furnaces and other
appliances can help cut carbon
emissions by thousands of pounds
per year. Natural gas will be a criti-
cal resource in a carbon-constrained
world, and we intend to stay focused
on making sure it is used wisely.
Toward sustaining our success
In 2007, we took bold steps –
toward greater operational efficien-
cies, toward a leadership role in climate
change discussions, and toward
becoming a larger presence in West
Coast gas storage and transportation.
The year 2008 is about follow
through – with the organizational
changes we started in 2006 and
2007, and with the new business
development plans we set in motion
last year. At the same time, we’ll be
keeping an eye on the horizon.
Our ongoing process improvement
efforts will apply new technology
to our retooled organization. After
a year of planning, we completed
on time and on budget the imple-
mentation of a new technology
system that will strengthen our
business procedures, from supply
change management to data analysis.
As our work continues this year,
we will also be installing new
dispatching and global positioning
software that will help us make
better use of field resources.
When we announced plans for
Palomar and Gill Ranch last year,
we knew we were just at the begin-
ning of two long development and
permitting processes.
In 2008, we are busy showing
communities and regulators that
the Palomar Pipeline can be built
safely, with utmost respect for the
environment, agricultural land
and communities along the trans-
mission line route. We expect to
file for a siting permit with the
Federal Energy Regulatory
Commission in 2008.
The Gill Ranch project will require
an environmental assessment, a
permit from the California Public
Utilities Commission and other
regulatory approvals. We will also
follow up on our successful open
season by pursuing agreements
with parties that expressed
interest in the project.
This will be a busy regulatory year
for our core utility as well. First,
we have filed a general rate case in
Washington, where we serve about
10 percent of our customers.
In Oregon, the commission will
be reviewing the gas cost-sharing
mechanisms for utilities across the
state. As part of that proceeding,
the commissioners will be looking
at how well NW Natural’s gas cost-
sharing mechanism performs for
customers and the company. Our
current sharing mechanism is more
than a decade old and was created at
a time when natural gas prices were
more stable. Given the volatility of
prices today, we believe updating the
mechanism to create a more appropri-
ate risk/reward balance for customers
and shareholders makes sense.
We will also continue to be active
in issues that affect our shareholders
on the national front. Federal legis-
lation passed in 2006 that reduced
the tax rate on dividends and capital
gains to 15 percent for individual
taxpayers is due to expire in 2010.
We have been working with the
American Gas Association and other
member companies to advocate this
tax relief be made permanent. We
believe this legislation addressed
an inequitable double taxation on
dividends. Maintaining a lower tax
on dividends has been one of our
industry’s top priorities for years,
and we will continue to work to
make this provision permanent.
Governance for the future
Over our 149-year history, NW
Natural’s management and board
have believed the key to our suc-
cess is making sure this company
7
In 2007 we ramped up our efforts to ensure the
sustainability of our company and our planet
– and we’re proud of what we accomplished.
As we approach our 150th anni-
versary, NW Natural continues to
grow – and grow responsibly. We
understand the obligations we have,
and we appreciate the trust that our
customers and shareholders have
placed in us. We want you to know
we intend to be relentless in our
efforts to honor that trust and to
meet the new challenges and
expectations that lie ahead.
Sincerely,
Mark S. Dodson
Chief Executive Officer
has the talent to lead it into the
future. Last year, the company took
action on several fronts to carry
on that legacy.
First, two new directors joined
the board. Jane Peverett, President
and CEO of British Columbia
Transmission Corporation, and
George Puentes, President of
Don Pancho Authentic Mexican
Foods, add new expertise and
skills to a board that is already
remarkable for its diverse and
extensive business experience.
Second, in 2007, the board elected
Gregg Kantor President and Chief
Operating Officer. He has served
as our Executive Vice President
since late 2006 and previously held
positions as Senior Vice President
and Vice President of Public and
Regulatory Affairs. Gregg’s move
to President and COO provides
additional leadership to help drive
operational improvements.
Working responsibly,
growing sustainably
NW Natural is a company with
tremendous commitment and
talent at every level.
You can see it in the results produced
by our gas supply team’s smart
purchases or in the gas storage
income generated by the employ-
ees who operate and market our
Mist storage field. You can see it
in the safety and system reliability
numbers resulting from our field
employees’ work. You can see it in
the customer satisfaction ratings
received by our call center repre-
sentatives and service technicians.
And the list goes on.
This is a company of very special
employees who believe deeply that
they are stewards of a great com-
pany and of a critical piece of the
Northwest’s infrastructure. NW
Natural is lucky to have them, and
we are proud to serve with them.
8
Interview with
Gregg Kantor, President and Chief Operating Officer
What does sustainability
mean for NW Natural?
We approach sustainability from
several different angles. We think
about sustaining the company
long term – for the benefit of our
customers, employees, sharehold-
ers and local communities. For
example, over the last 24 months
we restructured our operations
to be more efficient and more
competitive, so we can remain a
healthy company for many years
into the future.
We also think about sustainability
the way it’s more commonly used
today, in the sense of preserving
resources for future generations.
In that regard we have to use natural
gas wisely, so that it can remain
affordable and accessible for our
customers to heat their homes and
to fuel the Northwest’s economy.
As a company, we’re also committed
to using and throwing away less
paper, using less fuel and reducing
emissions in all our operations.
What were the main accomplish-
ments of NW Natural’s utility
operations in 2007?
Here at NW Natural, we started
the Smart Energy carbon emis-
sions offset program and, under
Mark Dodson’s leadership, we’re
helping the national gas industry
take on issues related to climate
change.
We are focused on making sure
this company can compete for
another 150 years. We are also
mindful that we’re stewards of
valuable natural gas supplies, and
we want to ensure this resource
is used efficiently. Finally, we
want to make sure adequate gas
storage and pipelines are in place
so that as the nation becomes more
aggressive about addressing climate
change, natural gas is available for
direct use by consumers and for
power generation.
We made great advances toward
implementing the new operating
model we described in last year’s
annual report. We’ve reorganized our
work along process lines, centralized
many work groups, and standardized
more of our daily tasks and proce-
dures. We outsourced functions that
aren’t central to the gas business and
improved the remaining processes
to provide better customer service.
We also began to move our business
processes into a unified software
system. On Jan. 7 of this year, we
completed the first phase of this
effort, converting our accounting
and purchasing processes to this
new system.
Today we are operating more
efficiently and effectively, and we
are providing our customers better
9
We have to use natural gas wisely, so that it can remain
affordable and accessible for our customers
to heat their homes and to fuel the Northwest’s economy.
service than we were just a year
ago. In 2008, the focus on improv-
ing our operations will continue
with the addition of even more
technology.
With a new integrated work
management system, vehicle locating
devices and new computers in our
trucks, we’ll be able to respond more
quickly to customer and emergency
calls. We’ll also be able to dispatch
employees and equipment more
efficiently system wide, eliminat-
ing artificial boundaries between
resource centers.
How did your relationship
with your employees hold up
through these changes?
The union leadership was a full
partner in last year’s efforts.
By centralizing and redesigning
many work functions, we are
operating effectively with fewer
employees. By January 2008,
we had approximately 10 percent
fewer positions than we had
12 months earlier.
We made a commitment that
we’d do everything possible to
reduce positions using attrition,
and we lived up to that promise.
Virtually all reductions were made
through attrition or voluntary
severance. And because we kept
employees informed of pending
changes, a number of them took
the initiative to find positions
with other companies before
the changes took place.
While we restructured our opera-
tions, we committed ourselves to
hiring from within the company
whenever possible. Since the time
we announced the reorganization,
we filled more than 80 percent of
our open positions with existing
employees.
That’s not to say it’s been easy.
Our union/management team
worked hard over many months
to make sure employees had
plenty of options and that they
would be treated equitably if their
positions were eliminated. Yet
some employees still had to make
tough choices, moving into new
positions or in some cases even
relocating their families to
remain with us.
It’s been a challenge for all of us
to learn new ways of doing our
jobs, operating with fewer manag-
ers and employees, and looking at
our work differently. However, I’m
very proud to say that everyone in
the company – from managers to
our human resources team to the
union leadership and individual
employees – acted with respect and
integrity throughout the process.
10
A strategic and lasting
foundation.
A business that’s been operating
for 149 years gets in the habit of
thinking long term. For NW Natural,
it’s not enough to meet earnings
targets. We’re always planning
ways to sustain the financial health
of our business far into the future.
In 2007, the result was a major
overhaul of the company’s structure,
making us more responsive
and competitive.
11
We have roots in the Northwest,
and we plan to keep serving communities for a long time.
It’s our home.
But hometowns change, and so do the forces that affect a utility’s success.
To remain a leader in the natural gas industry as well as a respected corpo-
rate citizen, our business model has to be flexible and dynamic.
In 2006, we took a hard look at ourselves to see if we were meeting our own
expectations – as well as those of our customers, our employees and our
shareholders. In response to what we learned, we spent 2007 restructuring
large parts of NW Natural. By centralizing key functions, integrating our
work into a process-driven model, and identifying areas to improve our busi-
ness practices, we are prepared to take on future competitive challenges.
We know we’re on the right track by looking at 2007 results. In addition
to controlling our operational expenses, we reversed a trend of declining
conversions and found new ways to better serve our customers.
CUSTOMERS SERVED BY EACH OPERATING EMPLOYEE
1000
900
800
700
600
500
400
‘03
‘04
‘05
‘06
‘07
The number of customers served by operating employees continued to increase
in 2007, as we have improved operational effectiveness.
For example, we’ve worked hard to make our Web site convenient and
easy to use, and customers are taking notice. With more than 215,000
customers registered to use our site’s self-service area, visits to our online
service features increased by 34 percent last year to more than 2 million.
We’ve also improved our call center’s response time by 13 percent through
a series of technology enhancements and contracting for peak-season help.
Today we are a more fluid and responsive company and we intend to keep
growing and evolving. It’s what we’ve all come to expect from NW Natural.
12
Purpose, prosperity,
sustainability.
There are utilities – and there’s the
larger energy industry. NW Natural is
ready to expand its role beyond local
gas distribution to participate more
fully in the regional energy business.
We are making investments that are
positioned to add shareholder value as
natural gas becomes even more impor-
tant to the nation’s energy portfolio.
13
It may not seem that a small, independent natural gas utility based in Oregon
can influence the regional energy picture.
But that’s exactly what we plan to do. And here’s how.
First, we know what we’re good at. We’re great at building and operating
storage facilities. We do an excellent job of building and managing pipelines.
Secondly, we know how to read the writing on the wall.
Today, that writing says the U.S. is going to be relying on natural gas to
reduce greenhouse gas emissions causing climate change. In the Northwest
alone, demand for natural gas is projected to increase by nearly 7.5 percent
over the next four years, and could grow as high as 30 percent over the
next two decades.*
While we’re not in the gas exploration business, we can build on what we
know to help West Coast gas customers access the supplies they need at a
price they can afford.
That’s why in 2007 we expanded our own underground storage facilities
in Oregon. We also took the first steps to develop storage in California
and a new major pipeline, called Palomar, connecting our system to the
TransCanada interstate system.
From our vantage point, we see changes coming in the nation’s energy policy
and in our region’s energy needs. Our storage and transportation projects will
support the West Coast’s energy-dependent economy as carbon constraints
limit fuel options. These investments will also strengthen the foundation of
NW Natural for future customers, employees and shareholders.
* NWGA, Natural Gas & Climate Change in the Pacific Northwest, 2007.
GAS STORAGE REVENUES AND NET INCOME
(IN MILLIONS OF DOLLARS)
$30
25
20
15
10
5
0
‘03
‘04
‘05
‘06
‘07
Gross revenue
Net income
Growth in gas storage revenues and net income reflects growing market demand
for gas storage services.
14
Accountable to future
generations.
As climate change becomes a growing concern, customers are
looking to NW Natural for help reducing greenhouse gas emissions.
We’re using a variety of strategies, tools and programs to meet
our customers’ needs at the same time we’re modifying our own
practices to reduce the environmental impacts of our operations.
15
In the Pacific Northwest,
we have a strong connection to nature
and value the gifts it provides.
Natural resources are the backbone of a healthy, vibrant and prosperous
society. These resources must be used wisely to allow future generations
the same opportunities and quality of life enjoyed today.
We have listened to our customers’ concerns about climate change and
consider it an opportunity and obligation to develop strategies that reduce
greenhouse gas emissions. Our pioneering rate structure encourages energy
efficiency and supports programs that help customers reduce their gas use.
Last year, these programs* saved enough gas to heat 4,300 homes. This model
has been adopted by many natural gas utilities throughout the United States.
81 percent of customers surveyed
said they supported our development of a voluntary program
to help reduce carbon emissions.
Last year, we expanded our low-income weatherization program to help
Oregonians earning 60 to 80 percent of the state’s median income, making
us one of the first utilities in the nation to reach out to this group. Our goal
is to help the working poor and seniors make simple home improvements
that reduce their energy use. We also became the first stand-alone gas utility
in the country to offer customers a carbon offset program. These progressive
solutions protect the environment while supporting the economy.
We recognize that we cannot ask others to do something that we wouldn’t do
ourselves. Across our company, we are rethinking our work and discovering
new ways to reduce our environmental footprint. A team of engineers and
gas supply staff developed an innovative operating procedure that prevents
methane from being released into the atmosphere during pipeline projects.
The first time this new method was used, it reduced the greenhouse gas
equivalent of taking 118 cars off the road for one year.
We’re also putting technology and processes in place to measure our own
carbon output and using socially responsible vendors and purchasing eco-
logically friendly products to lessen our impact on the planet. Protecting
this beautiful place we call home isn’t just another business goal for us,
it’s a passion we share with our customers.
* Offered by Energy Trust of Oregon.
16
Comparative Consolidated INCOME STATEMENTS
Thousands, except per share amounts (year ended December 31)
2007
2006
2005
2004
2003
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
$ 1,033,193
639,150
25,001
$ 1,013,172
648,156
24,840
$ 910,486
563,860
21,633
$ 707,604
399,244
16,865
$ 611,256
323,190
14,650
369,042
340,176
324,993
291,495
273,416
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
96,420
20,475
54,249
171,144
Income from operations
154,923
136,762
126,947
110,026
102,272
Other income and expense - net
1,445
2,134
1,205
2,828
2,150
Interest charges - net
37,811
39,247
37,283
35,751
35,099
Income before income taxes
118,557
99,649
90,869
77,103
69,323
Income taxes
Net income
Redeemable preferred stock dividend requirements
44,060
36,234
32,720
26,531
23,340
74,497
–
63,415
–
58,149
–
50,572
–
45,983
294
Earnings applicable to common stock
$ 74,497
$ 63,415
$ 58,149
$ 50,572
$ 45,689
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
26,821
26,995
27,540
27,657
27,564
27,621
27,016
27,283
25,741
26,061
$ 2.78
$ 2.76
$ 2.30
$ 2.29
$ 2.11
$ 2.11
$ 1.87
$ 1.86
$ 1.77
$ 1.76
Dividends per share of common stock
$ 1.44
$ 1.39
$ 1.32
$ 1.30
$ 1.27
See Notes to Consolidated Financial Statements in the company’s Annual Report on Form 10-K.
Comparative Consolidated BALANCE SHEETS
17
Thousands (December 31)
2007
2006
2005
2004
2003
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
$ 2,052,161
615,533
1,436,628
67,149
7,904
59,245
1,495,873
$ 1,963,498
574,093
1,389,405
42,652
6,916
35,736
1,425,141
$ 1,875,444
536,867
1,338,577
40,836
5,990
34,846
1,373,423
$ 1,794,972
505,286
1,289,686
33,963
5,244
28,719
1,318,405
$ 1,657,589
471,716
1,185,873
23,395
4,855
18,540
1,204,413
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
6,107
69,442
78,004
(2,890 )
79,944
25,691
256,298
193,536
3,227
54,070
11,179
$ 2,014,183
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
4,706
48,369
59,109
(1,763 )
50,859
34,554
195,834
196,280
6,557
47,985
8,718
$ 1,956,856
98,851
178,653
58,451
9,216
$ 2,042,304
91,263
16,399
60,618
8,393
$ 1,732,195
77,272
23,885
73,845
10,130
$ 1,585,379
$ 594,751
512,000
1,106,751
$ 599,545
517,000
1,116,545
$ 586,931
521,500
1,108,431
$ 568,517
479,500
1,052,544
$ 506,316
494,500
1,006,635
143,100
119,731
5,000
13,259
2,827
29,794
313,711
275,090
206,340
18,587
93,704
$ 2,014,183
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
85,200
86,029
–
8,605
2,998
31,589
214,421
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
166,714
178,742
–
18,867
$ 1,585,379
1 Current and long-term portions of regulatory assets, regulatory liabilities and fair value of non-trading derivatives are combined for presentation above.
These Financial Statements are condensed. See full Financial Statements and Notes to Consolidated Financial Statements in the company’s Annual Report on Form 10-K.
18
Comparative Financial STATISTICS
Year-End Market Price & Book Value Per Share
(IN DOLLARS)
Comparison of Five-Year Cumulative Total Return
(BASED ON $100 INVESTED ON 12/31/02)
60
50
40
30
20
10
0
‘03
‘04
‘05
‘06
‘07
$275
250
225
200
175
150
125
100
75
‘02
‘03
‘04
‘05
‘06
‘07
Market Price
Book Value
High/Low Market Price
NWN
S&P Utilities Index
S&P Small Cap 600
The year-end market-to-book ratio averaged 1.78x over the past five years.
Total annualized return to shareholders (dividends paid plus market appreciation)
was 16.7 percent for the five-year period ending December 31, 2007.
Our total annualized return over the five-years ending December 31, 2007 was
16.7 percent, compared to the Standard & Poor’s (S&P) Small Cap 600 Index rate
of 16.0 percent and the S&P Electric & Gas Utilities Index rate of 21.4 percent.
Capital Expenditures
(IN MILLIONS OF DOLLARS)
Capitalization
(IN MILLIONS OF DOLLARS)
160
140
120
100
80
60
40
20
0
‘04
‘05
‘06
‘07
Customer Growth
System Maintenance & Improvements
Gas Storage
Pipeline Integrity
South Mist Pipeline
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
‘03
‘04
‘05
‘06
‘07
Common Stock
Long-Term Debt
Short-Term Debt
Focusing on profitable capital expenditures improved earnings and cash flows.
Our capital expenditures for gas storage increased in 2007 due to strong
market demand for storage services.
In 2007, $38.6 million in cash dividends were paid to common shareholders,
$44.6 million was used for share repurchases and $29.5 million of long-term
debt was retired.
Comparative Financial STATISTICS
19
2007
2006
2005
2004
2003
17.5
3.1
51.8
12.5
2.78
2.76
1.44
1.50
22.52
52.85
39.79
48.66
46.20
18.5
3.3
60.4
10.7
2.30
2.29
1.39
1.42
21.97
43.69
32.83
42.44
36.98
16.2
4.0
62.6
10.1
2.11
2.11
1.32
1.38
21.28
39.63
32.42
34.18
35.92
18.0
3.9
69.5
9.4
1.87
1.86
1.30
1.30
20.64
34.13
27.46
33.74
31.06
17.3
4.1
71.8
9.3
1.77
1.76
1.27
1.30
19.52
31.30
24.05
30.75
27.72
Common stock
Ratios at year-end:
Price/earnings ratio
Dividend yield at year-end rate - %
Dividend payout - %
Return on average common equity - %
Per share data - ($):
Basic earnings
Diluted earnings
Dividends paid
Dividend rate at year-end
Book value at year-end
Market price:
High
Low
Year-end
Average
Number of shares of common stock outstanding (000):
Year-end
Average
26,407
26,821
27,284
27,540
27,579
27,564
27,547
27,016
25,938
25,741
Coverage data (ratio of earnings to)
Fixed charges - Securities and Exchange Commission method
3.92
3.40
3.32
3.02
2.84
Cash flow data ($000)
Cash provided by operating activities
Cash used in investing activities
Utility plant
183,640
(117,479 )
148,566
(90,567 )
79,066
(92,008 )
104,899
(132,631 )
105,254
(124,801 )
Capital expenditures ($000)
Depreciation - % of average depreciable utility plant
Accumulated depreciation - % of depreciable utility plant
93,785
3.4
40.8
95,307
3.4
39.6
89,259
3.4
38.4
138,347
3.4
37.2
121,411
3.5
38.0
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
Effective tax rate
46.3
0.0
46.3
53.7
100.0
46.3
0.0
46.3
53.7
100.0
47.0
0.0
47.0
53.0
100.0
45.6
0.4
46.0
54.0
100.0
49.0
0.7
49.7
50.3
100.0
Effective tax rate - % of pretax income
37
36
36
34
34
20
Comparative Operating STATISTICS
Total Customers
(IN THOUSANDS)
Gas Sales and Transportation Deliveries
(IN MILLIONS OF THERMS)
660
640
620
600
580
560
540
520
500
1400
1200
1000
800
600
400
200
0
‘03
‘04
‘05
‘06
‘07
Residential
Commercial
Industrial
‘03
‘04
‘05
‘06
‘07
Firm
Interruptible
Transportation
We added 15,428 new customers in 2007, expanding our customer base
by 2.4 percent. In the past five years, we have added over 91,000 new
customers.
Gas sales and transportation deliveries in 2007 were 2 percent higher at over
1.2 billion therms, due primarily to strong customer growth in residential and
commercial segments.
Utility Gas Revenues
(BY CLASS)
55%
55%
Utility Net Operating Revenues (Margin)
(IN MILLIONS OF DOLLARS)
$350
300
250
200
150
100
50
0
2%
2%
1%
1%
7%
7%
5%
5%
30%
30%
Residential
Residential
Commercial
Commercial
Industrial Interruptible
Industrial Interruptible
Transportation
Transportation
Industrial Firm
Industrial Firm
Other
Other
‘03
‘04
‘05
‘06
‘07
Residential
Commercial
Industrial
Other
Revenues from residential, commercial and industrial firm sales customers
have consistently exceeded 87 percent of total gas revenues since 2000.
We continue to see growth in utility margin, with an increase of 33 percent
over the past five years.
Comparative Operating STATISTICS
21
Selected Utility Data
2007
2006
2005
2004
2003
Gas sales and transportation deliveries (000 therms)
Residential
Commercial
Industrial firm
Industrial interruptible
Unbilled therms *
Total gas sales
Transportation
Total volumes delivered
Operating revenues and cost of sales ($000)
Utility operating revenues:
Residential
Commercial
Industrial firm
Industrial interruptible
Total gas sales revenues
Transportation
Unbilled revenues *
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 firm sendout (000 therms)
Maximum day total sendout (000 therms)
Utility employees
Number of customers served by each operating employee
398,960
249,659
52,340
89,128
–
790,087
424,882
1,214,969
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
652,012
4,374
3%
687
4,110
806,905
75.00
80.89
5,845
7,344
1,141
924
382,665
242,683
66,971
112,736
–
805,055
387,594
1,192,649
536,468
290,666
66,986
93,107
987,227
12,800
–
–
161
1,000,188
648,081
24,840
327,267
636,584
4,089
(4)%
678
4,052
820,542
75.37
80.50
5,672
7,401
1,211
845
371,538
233,987
74,880
149,106
–
829,511
328,056
1,157,567
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)%
673
3,936
815,334
71.42
67.96
5,649
6,966
1,305
738
352,356
222,875
62,843
104,278
–
742,352
389,514
1,131,866
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)%
677
3,907
756,672
56.60
53.77
7,177
8,913
1,288
721
343,534
226,257
55,314
47,994
12,099
685,198
414,554
1,099,752
328,346
176,336
33,578
23,661
561,921
17,962
14,474
–
7,627
601,984
323,128
14,650
264,206
578,150
3,952
(7)%
673
4,004
683,331
46.99
47.16
4,851
6,310
1,291
724
* Unbilled therms and revenues have been allocated by customer class for the years 2004 through 2007.
** Regulatory adjustment for income taxes paid is the result of the implementation in 2007 of utility regulation as described in our Annual Report on Form 10-K.
22
Corporate Officers
From left to right:
Grant Yoshihara, Gregg Kantor,
Margaret Kirkpatrick, Richelle Luther,
David Anderson, C. J. Rue, Steve Feltz,
Mark Dodson, Keith White,
Lea Anne Doolittle, Dave Williams
Photographed at the Crystal Springs
Rhododendron Garden - Portland, Oregon.
DAVID H. ANDERSON, 46 [2004]
Senior Vice President and Chief
Financial Officer (2004-present)
Senior VP and CFO, TXU Gas (2004)
Senior VP, Corporate Controller and
Principal Accounting Officer,
TXU Corp. (2003-2004)
VP, Investor Relations and Shareholder
Services, TXU Corp. (1997-2003)
MARk S. DODSON, 63 [1997]
Chief Executive Officer (2003-present)
President and Chief Executive
Officer (2003-2007)
President and Chief Operating
Officer (2001-2002)
General Counsel (1997-2002)
Senior Vice President, Public Affairs
(1997-2001)
LEA ANNE DOOLITTLE, 53 [2000]
Senior Vice President (2008-present)
Vice President, Human Resources
(2000-2007)
Director of Compensation, PacifiCorp
(1993-2000)
STEPHEN P. FELTz, 52 [1982]
Treasurer and Controller (1999-present)
Assistant Treasurer and Manager,
General Accounting (1996-1999)
GREGG S. kANTOR, 50 [1996]
President and Chief Operating
Officer (2007-present)
Executive Vice President (2006-2007)
Senior Vice President, Public and
Regulatory Affairs (2003-2006)
Vice President, Public Affairs and
Communications (1998-2002)
MARGARET D. kIRkPATRICk, 53
[2005]
Vice President and General Counsel
(2005-present)
Partner, Stoel Rives LLP (1990-2005)
RICHELLE T. LUTHER, 39 [2002]
Chief Governance Officer and
Corporate Secretary (2008-present)
Assistant Secretary (2002-2007)
Associate, Stoel Rives LLP (1997-2002)
C. J. RUE, 62 [1974]
Secretary (1982-2007)*
Assistant Treasurer (1987-2007)
J. kEITH WHITE, 55 [1996]
Vice President Business Development
and Energy Supply and Chief Strategic
Officer (2007-present)
Managing Director, Gas Operations and
Wholesale Services and Chief Strategic
Officer (2005-2007)
Managing Director, Chief Strategic
Officer (2003-2005)
DAVID R. WILLIAMS, 55 [1978]
Vice President Utility Services
(2007-present)
Director, Utility Operations
and Labor Relations (2005-2006)
General Manager, Utility Operations
(1999-2005)
GRANT M. YOSHIHARA, 53 [1991]
Vice President Utility Operations
(2007-present)
Managing Director, Utility Services
(2005-2006)
General Manager, Consumer Services
(2003-2005)
[Date joined NW Natural]
*Mr. Rue retired December 31, 2007.
23
Board of Directors
TIMOTHY P. BOYLE, 58
MARTHA L. “STORMY” BYORUM, 59
JOHN D. CARTER, 62
President and Chief Executive Officer
Columbia Sportswear Company
Portland, Oregon
[2003] (3) (5) (6)
Senior Managing Director
Stephens Cori Capital Advisors
New York, New York
[2004] (2) (6)
President and Chief Executive Officer
Schnitzer Steel Industries, Inc.
Portland, Oregon
[2002] (1) (2) (6)
MARk S. DODSON, 63
Chief Executive Officer
NW Natural
Portland, Oregon
[2003]
C. SCOTT GIBSON, 55
TOD R. HAMACHEk, 62
RANDALL C. PAPé, 57
JANE L. PEVERETT, 49
President
Gibson Enterprises
Portland, Oregon
[2002] (3) (4) (5)
Former Chairman and Chief
Executive Officer
Penwest Pharmaceuticals Company
Seattle, Washington
[1986] (1) (2) (5)
President and Chief Executive Officer
The Papé Group, Inc.
Eugene, Oregon
[1996] (1) (4) (6)
President and Chief Executive Officer
British Columbia
Transmission Corporation
Vancouver, British Columbia
[2007] (2) (5)
GEORGE J. PUENTES, 60
RICHARD G. REITEN, 68
kENNETH THRASHER, 58
RUSSELL F. TROMLEY, 68
President
Don Pancho Authentic
Mexican Foods, Inc.
Salem, Oregon
[2007] (4) (6)
Chairman of the Board
NW Natural
Portland, Oregon
[1996] (1) (4) (5) (6)
Chairman and Chief Executive Officer
Compli Corporation
Portland, Oregon
[2005] (2) (3) (4)
Chairman and Chief Executive Officer
Tromley Industrial Holdings, Inc.
Tualatin, Oregon
[1994] (1) (2) (3)
kEY: [Year elected to the board], (1) Governance Committee, (2) Audit Committee, (3) Organization and Executive Compensation Committee, (4) Public Affairs and Environmental Policy Committee,
(5) Strategic Planning Committee, (6) Finance Committee
24
Quarterly FINANCIAL INFORMATION
Quarterly Financial Information (unaudited)
Dollars (thousands except per share amounts)
March 31
June 30
Sept. 30
Dec. 31
Total
2007
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2006
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$394,091
139,008
48,075
1.77
1.76
$390,391
125,464
41,033
1.49
1.48
$183,249
64,118
2,617
0.10
0.10
$170,979
61,747
1,994
0.07
0.07
$124,245
49,663
(5,908 )
(0.22 )
(0.22 )
$114,914
41,341
(9,724 )
(0.35 )
(0.35 )
$331,608
116,253
29,713
1.12
1.11
$1,033,193
369,042
74,497
2.78 *
2.76 *
$336,888
111,624
30,112
1.10
1.09
$1,013,172
340,176
63,415
2.30 *
2.29 *
* 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.”
The quarterly high and low trading range during 2006 and 2007 was:
2007
Quarter Ended
March 31
June 30
September 30
December 31
2006
Quarter Ended
March 31
June 30
September 30
December 31
High
$46.34
52.85
49.37
50.89
High
$36.57
37.04
40.08
43.69
Low
$39.79
44.05
40.98
44.28
Low
$32.83
33.30
35.81
38.53
The closing quotations for the common stock on Dec. 31, 2007 and Dec. 29, 2006 were $48.66 and $42.44, respectively.
Quarterly FINANCIAL INFORMATION
25
These publications, as well as other filings made
with the SEC, also are available on NW Natural’s
Web site at nwnatural.com. Our SEC filings 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 www.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, Oregon 97209
(503) 226-4211
(800) 422-4012
nwnatural.com
NYSE: NWN
Notice of Annual Meeting
Forward-Looking Statements
The 2008 Annual Meeting will be held at
2 p.m., Thursday, May 22, in the Hospitality
Suite on the fourth floor of NW Natural’s offices,
220 NW Second Avenue, Portland, Oregon.
A meeting notice and proxy statement will
be sent to all shareholders in mid-April.
Dividend Reinvestment
and Direct Stock Purchase Plan
Participants may make an initial investment
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
commissions for shares purchased on the open
market to fulfill purchases under the plan.
A prospectus will be sent upon request.
Scheduled Payment Dates
February 15, 2008
May 15, 2008
August 15, 2008
November 14, 2008
Certifications
The Chief Executive Officer certified to the NYSE
on June 1, 2007 that, as of that date, he was
not aware of any violation by the company of
NYSE’s corporate governance listing standards,
and the company had filed 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 December 31, 2006, the cer-
tificates of the Chief Executive Officer and the
Chief Financial Officer of the company certifying
the quality of the company’s public disclosure.
For the year ended December 31, 2007, the
certificates of the Chief Executive Officer and
Chief Financial Officer 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
• E-mail Directors@nwnatural.com
NW Natural’s future operating results will
be affected by various uncertainties and
risk factors, many of which are beyond the
company’s control, including governmental
policy and regulatory action, the competitive
environment, economic factors and weather
conditions. Some statements in this annual
report may be forward-looking, and actual
results may differ materially as a result of these
uncertainties. For a more complete description
of these uncertainties and risk factors, please
refer to the company’s filings with the SEC on
Forms 10-K and 10-Q.
Shareholder Information
Robert S. Hess
Investor Relations
(503) 220-2388
(800) 422-4012 Ext. 2388
rsh@nwnatural.com
Kimberlee V. Anderson
Shareholder Services
(503) 226-4211 Ext. 3412
(800) 422-4012 Ext. 3412
kva@nwnatural.com
Request for Publications
The following publications may be obtained
without charge by contacting the Corporate
Secretary at NW Natural’s address. Annual
Report; Form 10-K; Form 10-Q; Corporate
Governance Standards; Director Independence
Standards; Code of Ethics; and Board
Committee Charters.
26
PHOTO CREDITS
Page 4, 8, 9: Copyright © Robbie McClaran
Page 13: Top left - Copyright © Bruce Beaton
Page 22: Copyright © Bruce Beaton
Page 11: Top left - Copyright © Bruce Beaton
Middle left - Copyright © Robbie McClaran
Bottom left - Courtesy Valerie White
Far right - Copyright © Stuart Mullenberg
Bottom left - Copyright © Robbie McClaran
Far right - Copyright © Kurt Hettle
Page 15: Top left - Copyright © Stuart Mullenberg
Middle left - Copyright © Robbie McClaran
Bottom left - Copyright © Bruce Beaton
Page 23: Copyright © Bruce Beaton
Page 25: Middle - Copyright © Bruce Beaton
ILLUSTRATIONS
All charts: Dale Headrick
Form 10-K
Annual Report
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[X]
For the fiscal year ended December 31, 2007
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. [
]
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 definition 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 29, 2007, the registrant had 26,815,203 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 $1,226,580,437.
At February 25, 2008, 26,408,248 shares of the registrant’s Common Stock (the only class of Common Stock)
were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
List documents incorporated by reference and the Part of the Form 10-K into which the document is incorporated.
Portions of the Proxy Statement of Company, to be filed in connection with the 2008 Annual Meeting of
Shareholders, are incorporated by reference in Part III.
NORTHWEST NATURAL GAS COMPANY
Annual Report to Securities and Exchange Commission
on Form 10-K
For the Fiscal Year Ended December 31, 2007
Table of Contents
PART I
Item 1.
Glossary of Terms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Business Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Gas Supply, Storage and Transportation Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Regulation and Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Additions to Infrastructure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Pipeline Safety . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Competition and Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Environmental Issues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Available Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1A. Risk Factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 1B. Unresolved Staff Comments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 2.
Item 3.
Item 4.
PART II
Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 6.
Item 7.
Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Management’s Discussion and Analysis of Financial Condition and Results of Operations . . .
Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 8.
Item 9.
Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . .
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 9B. Other Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART III
Item 10.
Directors, Executive Officers and Corporate Governance . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 11.
Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 13.
Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Item 14.
Principal Accountant Fees and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
PART IV
Item 15.
Exhibits and Financial Statement Schedules . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
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GLOSSARY OF TERMS
Average weather: represents the 25-year average
degree days based on temperatures established in our
2003 Oregon general rate case.
Basic earnings per share: net income for a period,
divided by the average number of shares of common
stock outstanding during that period.
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. One hundred thousand Btu’s equal one
therm.
Core utility customers: residential, commercial and
industrial firm service customers on our distribution
system.
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.
Diluted earnings per share: net income for a period,
divided by the average number of shares of stock that
would be outstanding assuming the issuance of
common shares for all existing stock based
compensation plans with a dilutive impact during the
reporting period.
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.
Gas storage: a means of holding gas in facilities for
future delivery, either through injection into an
underground storage field, or storing it in the form of
liquefied natural gas.
General rate case: a periodic filing with state
regulators to establish equitable rates and balance the
interests of all classes of customers and our
shareholders.
Interruptible service: natural gas service offered to
customers (usually large commercial or industrial
users) under contracts or rate schedules that allow for
temporary interruptions to meet the needs of firm
service customers.
Liquefied natural gas (LNG): the cryogenic liquid
form of natural gas.
Open Season: A period of time during which
prospective customers express binding or
non-binding interest in pipeline or gas storage
services.
Purchased Gas Adjustment (PGA): a regulatory
mechanism for annually 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.
Return on invested capital (ROIC): a measure of
profitability calculated by dividing net income before
interest expense by average long-term invested
capital.
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.
Underground gas storage: storage of natural gas by
injection into underground wells; historically gas is
withdrawn during the winter heating season or during
periods of high gas prices.
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.
2
NORTHWEST NATURAL GAS COMPANY
PART I
ITEM 1. BUSINESS
General
Northwest Natural Gas Company was incorporated under the laws of Oregon in 1910. Our
company and its predecessors have supplied gas service to the public since 1859. Since September
1997, we have been doing business as NW Natural.
Business Segments
Local Gas Distribution
We are principally engaged in the distribution of natural gas in Oregon and southwest
Washington. In this report our principal business segment is referred to as local gas distribution or
utility. Local gas distribution involves purchasing gas from producers, transporting the gas over
interstate pipelines from the supply basins to our service territory, and reselling the gas to customers at
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 87 percent of our consolidated net income in 2007 are 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 southern Washington counties bordering the Columbia River. Gas
service is provided in 123 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 2007, we had approximately 590,000 residential customers, 61,000 commercial
customers and 900 industrial sales customers. Approximately 90 percent of our customers are located
in Oregon and 10 percent are in Washington. Industries served 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
industrial revenues.
Gas Storage
The gas storage business segment includes NW Natural’s underground natural gas storage
services to interstate and large intrastate customers using NW Natural’s storage and related
transportation capacity that is in excess of core utility customer requirements. Additionally, an
independent energy marketing company provides asset optimization services to the utility under a
contractual arrangement, the results of which are included in this business segment. Approximately 3
3
percent of our consolidated assets and 12 percent of consolidated net income in 2007 are related to the
gas storage business segment. For each of the years ended December 31, 2007, 2006, and 2005, this
business segment derived a majority of its revenues from multi-year contracts with less than 10
customers. The total working gas capacity of the Mist underground gas storage facility has been
increased from 14 Bcf to around 16 Bcf to reflect an expansion in certain reservoir pools. Of this
capacity, the gas storage business has access to about 7 Bcf of capacity while the utility has access to
the remaining 9 Bcf.
Pre-tax income from gas storage and third-party optimization activities 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 deferred to a regulatory
account for rate credits 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.
Interstate Gas Storage. This part of the business segment provides bundled firm or
interruptible gas storage services at Mist and related transportation services on NW Natural’s system to
and from Mist to interstate pipeline interconnections for several interstate customers. The interstate
storage services and maximum rates for these services are authorized by the Federal Energy
Regulatory Commission (FERC). The storage capacity used by this business has been developed 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. The firm storage service terms and conditions mirror the firm interstate storage service,
except that these customers are located and served in Oregon under an OPUC-approved rate schedule
that includes service and site-specific qualifications.
Third Party Optimization. We contract with an independent energy marketing company to
optimize the value of our unused storage and pipeline transportation assets, primarily through the use
of commodity transactions and pipeline capacity release transactions. See Part II, Item 7., “Results of
Operations—Business Segments Other than Local Gas Distribution—Gas Storage.”
Other
We have other investments, including assets in NNG Financial Corporation (Financial
Corporation) (see “Subsidiaries,” below), a Boeing 737-300 aircraft under lease to Continental Airlines
but currently held for sale, and investments in development projects such as Gill Ranch and Palomar
Pipeline (see “Subsidiaries,” below). Less than 1 percent of our consolidated assets and about 1 percent
of 2007 consolidated net income are related to activities in the “Other” business segment.
Subsidiaries
Financial Corporation
Financial Corporation, a wholly-owned subsidiary incorporated in Oregon, holds non-utility
financial investments. Financial Corporation has one active, wholly-owned subsidiary, KB Pipeline
Company (KB Pipeline), which owns a 10 percent interest in an 18-mile interstate natural gas pipeline.
4
In October 2007, Financial Corporation’s limited partnership investments in two wind power electric
generation projects in California were sold. In addition, in December 2007, one of Financial
Corporation’s two low-income housing project investments reached the end of its contract period and
the partnership investment was disposed of pursuant to the original terms of the agreement.
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. We formed a wholly-owned subsidiary of NW Natural to develop and operate the facility.
Gill Ranch Storage, LLC, will initially own 75 percent of the project, and PG&E will own 25 percent.
The new storage facility is expected to provide approximately 20 Bcf of underground gas storage
capacity, and will include 25 miles of transmission pipeline, when the initial phase is completed. We
estimate our share of the total cost for the initial phase of development to be between $150 million and
$160 million over the next three years, which represents 75 percent of the estimated project cost. We
conducted an open season to gauge interest in the storage facility from October 2007 to December
2007, and the results indicated a strong level of interest in gas storage at Gill Ranch from potential
storage customers. We expect to file an application with the California Public Utilities Commission
(CPUC) for a Certificate of Public Convenience and Necessity in mid-2008 and, if granted, Gill Ranch
will be subject to CPUC regulation with respect to rates and various regulatory approvals, including
but not limited to securities issuance, lien grants and sales of property. We expect the initial phase of
Gill Ranch to be in-service by late 2010.
Gas Supply, Storage and Transportation Capacity
General
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 system 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 customers between bundled sales service and transportation-only service. Sensitivity
analyses are performed 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 consist of:
• Reliability—Ensuring a gas resource portfolio that is sufficient to satisfy core utility
customer requirements under design-day weather conditions, as defined in our Integrated
Resource Plan (see “Regulation and Rates—Integrated Resource Plan,” below);
• 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 price variability; and
• Cost recovery—Managing gas purchase costs prudently to minimize the risks associated
with regulatory review and recovery of gas acquisition costs.
5
To achieve those goals, we employ a gas purchasing strategy based upon a diversity of supply,
liquidity, price risk management, asset optimization and regulatory alignment, as discussed in more
detail below.
Diversity of Supply. There are three means by which we diversify our gas supply acquisitions:
regional supply basin, contract types and contract duration.
The following table represents the actual and target purchase percentages from the regional
sources of gas supply available to us:
Regional Supply Basin
Region
Alberta
British Columbia
U.S. Rockies
Mist gas field
Total
2007 Actual
2007-2012 Target
41%
27%
32%
<1%
100%
45%
30%
25%
<1%
100%
We believe that gas supplies available in the western United States and Canada are adequate to
serve our core utility customers for the foreseeable future, and that our cost of gas generally will track
market prices.
We typically enter into gas purchase contracts for:
year-round baseload supply;
additional baseload supply for November–March (winter heating season);
•
•
• winter heating season contracts where we have the option to call on all, some or none 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. In general, we try to maintain a diversified portfolio of
purchase arrangements. For example, we use a variety of multi-year contract durations to avoid having
to re-contract all supplies every year. See “Core Utility Market Basic Supply,” below.
Liquidity. 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);
6
•
•
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 to our own activities to economically manage our gas supply costs, we
contract with an independent energy marketing company to more fully capture optimization
opportunities.
Regulatory Alignment. Mechanisms for gas cost recovery are designed to be fair and balanced
for 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:
•
•
•
the use of purchased gas adjustment (PGA) mechanisms approved by the OPUC and
WUTC (see Part II, Item 7., “Results of Operations—Regulation and Rates—Rate
Mechanisms,” below);
aligning customer and shareholder interests through incentive sharing mechanisms, such as
the PGA and asset optimization mechanisms; 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 pipelines to transport the gas to our distribution system and gains or
losses related to hedge contracts entered into in connection with the supply of gas to core customers.
While the rates for pipeline transportation and storage services are subject to federal regulation, the
purchase price of gas is not.
Supply cost. Natural gas commodity prices increased dramatically over the last six years due to
growing demand for natural gas (especially for power generation), surging alternative fuel prices, and
the impact of hurricane activity that affected oil and natural gas production in the Gulf of Mexico. We
are in a favorable position with respect to gas production because of the proximity of our service
territory to supply basins in British Columbia and the 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
stable until recently when two of the five major pipelines used by NW Natural filed with the FERC for
significant rate increases in 2006, which were implemented in 2007. Pipeline transportation rate
increases are generally recoverable through our state-approved PGA mechanisms.
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, by entering into natural
gas commodity-based financial hedge contracts, and by crediting gas costs with margin revenues
derived from off-system sales of commodity supplies and released transportation capacity in periods
when core utility customers do not fully utilize firm pipeline transportation capacity and gas supplies.
7
Managing the Cost of Gas
We manage natural gas commodity price risk through an active hedging program in which we
enter into either fixed price physical supply contracts or fixed price financial derivatives contracts. The
financial 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 this program, we enter into commodity
swaps, puts, calls or collars for the coming year and up to three years into the future. Gains or losses
from financial commodity hedge contracts are treated as reductions or increases to the cost of gas. The
intended effect of this program is to lock in prices for a majority of our gas supply portfolio for the
following gas contract year, including at least 50 percent of the expected heating season purchases,
based on the market prices and forecasted purchase requirements prevailing at the time the financial
agreements are entered into.
In addition to the volumes for which prices are locked in through financial hedges, we also use
gas storage as a physical hedge. We purchase and inject about 15 percent of our annual gas supply
requirements into storage during the summer when gas prices are historically lower. That gas is stored
for withdrawal during the winter months in five different storage facilities. We own and operate three
of these storage facilities located within our service territory, which eliminates the need for additional
upstream pipeline capacity and provides significant cost savings.
Source of Supply—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. To assure reliability, we base our plans on
being able to meet the supply needs on the coldest weather experienced over the last 20 years in our
service territory. We start with the coldest overall heating season and then modify it to include the
coldest 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 assume that all interruptible
customers will be curtailed on the design day. Our projected sources of delivery for design day firm
utility customer sendout total approximately 8.86 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 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. 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 planning
(IRP) process (see “Regulation and Rates—Integrated Resource Plan,” below).
8
The following table shows the sources of supply that are projected to be used to satisfy the design
day sendout for the 2007-2008 winter heating season:
Projected Sources of Supply for Design Day Sendout
Sources of Supply
Firm contracts
Off-system storage
Mist underground storage (utility only)
LNG storage
Recall agreements
Total
Therms
(in millions)
Percent
3.25
1.06
2.30
1.80
0.45
8.86
37
12
26
20
5
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 are sufficient to
satisfy the needs of existing customers and are positioned to grow, as needed, to meet requirements in
future years.
Core Utility Market Basic Supply
We purchase gas for our core utility customers from a variety of suppliers located in the
western United States and Canada. As shown above, about 65 to 70 percent of our supply comes from
Canada, with the balance coming primarily from the U.S. Rocky Mountain region. At January 1, 2008,
we had 23 firm contracts with 14 suppliers and remaining terms ranging from three months to eight
years, which provide for a maximum of 2.2 million therms of firm gas per day during the peak winter
heating season and 1.2 million therms per day during the remainder of the year. These contracts have a
variety of pricing structures and purchase obligations. During 2007, we purchased 809 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 a year)
Spot (one month or less)
Total
53%
11%
36%
100%
We regularly renew or replace our expiring long-term gas supply contracts with new
agreements from 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), three suppliers each provide between 11.1 percent and 12.5 percent of
our average daily contract volumes. Firm year-round supply contracts have remaining terms ranging
from one to eight years. All term gas supply contracts use price formulas tied to monthly index prices,
primarily at the NIT trading point in Alberta. 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 2007,
new short-term purchase agreements were entered into with six suppliers. These agreements have a
variety of pricing structures and provide for a total of up to 990,000 therms per day during the 2007-2008
9
heating season. We intend to enter into new purchase agreements in 2008 for equivalent volumes of gas
with our existing or other similar suppliers, as needed, to replace contracts that will expire during 2008.
We also buy gas on the spot market as needed to meet 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 gas from a non-affiliated producer in the Mist gas field in Oregon.
The production area is situated near our underground gas storage facility. The price for this gas is tied
to our weighted average cost of gas. Current production is approximately 10,000 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.
Core Utility Market Peaking Supply and Storage
We supplement our firm gas supplies with gas from storage facilities either owned or
contractually committed to us. Gas is generally purchased and stored during periods of low demand for
use 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
prices are historically lower.
Underground storage. We provide daily and seasonal peaking from our underground gas
storage facility in the Mist gas storage field. Including the latest expansions in 2007, this facility has a
maximum daily deliverability of 5.1 million therms and a total working gas capacity of about 16 Bcf.
In September 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. Also in 2004, a total of 400,000 therms per day of Mist storage capacity, which had been
available for the non-utility gas storage business, was recalled and committed to use for core utility
customers. This was the first instance of returning capacity that had been developed in advance of core
utility customers’ needs for interstate gas storage services under the regulatory agreement with the
OPUC. Under this agreement, storage capacity is recalled as needed and added to utility rate base, at
our original cost less accumulated depreciation, with a corresponding rate increase to customers to
reflect the cost of service. No additional recalls of Mist capacity were required in 2005, 2006 or 2007.
The core utility market now has 2.3 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, new storage capacity may be developed.
We also have contracts with Northwest Pipeline Corporation (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.
LNG. We own and operate two LNG storage facilities in our service territory that liquefy gas during
the summer months for storage until 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.
10
Recallable capacity. 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 450,000 therms per day of recallable capacity and supply. Two of these three contracts renew
from year to year, while the third will expire in 2010.
Transportation
Dependence on a 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 is bi-directional as 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 Rocky Mountain supply basins. The
need for pipeline transportation diversity has been underscored by past Northwest Pipeline ruptures
and the resulting federal order in 2003 that required Northwest Pipeline to replace its 26-inch mainline
from the Canadian border to our service territory. 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 evaluating a potential pipeline project 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 and owning this proposed pipeline. If
constructed, this pipeline would provide an alternate transportation path for gas purchases in Alberta
that currently move through the Northwest Pipeline system (See Part II, Item 7., “2008 Outlook—
Strategic Opportunities—Pipeline Diversity”).
Rates. Rates for interstate pipeline transportation are established by FERC for service under
long-term transportation agreements within the U.S. and by Canadian federal or provincial authorities
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 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 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 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 and no later than 2017, with a 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. A contract with Spectra Energy Corporation (formerly Westcoast Energy, Inc.) 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
11
Pipeline at the U.S./Canadian border. A contract with Terasen Gas 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 with
Terasen Gas 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.
Regulation and Rates
We provide local distribution gas utility service in Oregon and Washington and, accordingly,
we are subject to state regulation with respect to, among other matters, rates, systems of accounts and
issuance of securities by the OPUC and the WUTC. Local distribution service in Oregon represents
about 91 percent of the utility’s revenues, while Washington represents the remaining 9 percent (see
Part II, Item 8., Note 1).
We periodically file general rate case and rate tariff requests with the OPUC and WUTC to
change the rates we charge our customers. 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 the future, we may be subject to regulation in other states
resulting from our strategic investments. For further information, see Part II, Item 7., “Results of
Operations—Regulatory Matters,” below.
Integrated Resource Plan
The OPUC and WUTC have implemented integrated resource planning processes under which
utilities develop plans defining alternative growth scenarios and resource acquisition strategies. Our
most recent acknowledged integrated resource plans in Oregon and Washington were filed in 2005.
Elements of the plans included:
•
•
•
•
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.
Although the OPUC’s order acknowledging the integrated resource plan does not constitute
ratemaking approval of any specific resource acquisition or expenditure, the OPUC generally indicates
that it would give considerable weight in prudency reviews to utility actions that are consistent with
acknowledged plans. Elements of our current integrated resource plan demonstrate that the continued
development of the Mist underground gas storage facility is the least-cost option for serving customer
growth. We filed a draft IRP with the WUTC in the first quarter of 2007, and we expect to file a draft
IRP with the OPUC by the end of the first quarter of 2008.
Additions to Infrastructure
We expect a high level of capital expenditures for additions to infrastructure over the next five
years, reflecting projected customer growth, technology, distribution system replacement,
improvement and reinforcement projects and the development of additional gas storage facilities. In
2008, utility capital expenditures are estimated to be between $90 and $100 million, and business
development investments could amount to between $15 and $25 million. For the years 2008-2012,
12
capital expenditures for the utility are estimated at between $500 and $600 million, while business
development investments will depend largely on decisions about potential opportunities in storage and
pipeline development projects. Despite a slower annual growth rate than in past years, our growth rate
during 2007 continued to be above the national average for gas utilities.
Pipeline Safety
The Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (2006 Act) was
signed into law in December 2006. The 2006 Act mandates certain standards related to our distribution
lines, including the development of an integrity management program for those distribution pipelines.
Distribution pipeline safety rules required by the 2006 Act are expected to be final in 2009.
The Pipeline Safety Improvement Act of 2002 (2002 Act) and related regulations require gas
transmission pipeline operators to identify lines located in High Consequence Areas (HCAs) and
develop integrity management programs to periodically inspect the pipelines and make repairs or
replacements as necessary to ensure the ongoing safety of the pipelines. The legislation and related
pipeline safety regulations require us to complete inspection of 50 percent of the highest risk pipelines
located in our HCAs within the first five years, and the remaining covered pipelines within 10 years, of
the date of enactment. We are also required to re-inspect the covered pipelines every seven years from
the date of the previous inspection for the life of the pipelines. We continued to achieve our milestones,
completing the required inspection of the top 50 percent highest risk transmission pipelines in 2007.
We are currently on track to meet the next milestone to complete the inspection of all transmission
pipelines in HCAs by December 2012.
In 2005, we assumed responsibilities as operator of an approximately 60-mile pipeline that
transports gas from Northwest Pipeline to Coos County, Oregon. The pipeline is owned by Coos
County, and we have an agreement to operate the pipeline and related lateral pipelines that continues
yearly until terminated by either party. The pipeline safety requirements of the 2002 Act apply to us as
operator of that pipeline.
In 2001, we entered into a stipulation with the OPUC for an enhanced pipeline safety program
that includes an accelerated bare steel replacement program and a geo-hazard safety program. The bare
steel program accelerates the replacement of our bare steel piping over 20 years instead of 40 years and
allows us to receive rate treatment for costs associated with the program exceeding $3 million per year.
The geo-hazard component of the safety program expired on December 31, 2006. It included the
identification, assessment and remediation of risks to pipe infrastructure created by landslides,
washouts, earthquakes or similar occurrences, and allowed us to receive deferred rate treatment for
costs associated with the program. Although the regulatory authority for the geo-hazard safety program
expired, we received approval from the OPUC to defer the costs up to $2.5 million associated with a
specific remediation project, which was completed in 2007.
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 gas-to-gas competition from third-party sellers of natural gas commodity.
13
Competition among these forms of energy is based on price, reliability, efficiency and performance,
which can change from year-to-year based on market conditions, technology and legislative policy.
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, together with the price advantage of natural
gas compared with electricity in most areas and our operating convenience over fuel oil, provides the
potential for continuing growth from residential and commercial conversions. In 2007, 14,560 net
residential customers (after subtracting disconnected or terminated services) were added, primarily
from single- and multi-family new construction, but also due to the conversion of existing residential
housing from oil, electric or propane appliances to natural gas. The net increase of all new customers
added in 2007 was 15,428. This represents a growth rate of 2.4 percent, which is well above the
national average for local gas distribution companies as reported by the American Gas Association.
Industrial Markets
As a result of the deregulation and restructuring of the energy markets during the past two
decades, the natural gas industry, including producers, interstate pipelines and local gas distribution
companies, has undergone significant changes. Traditionally, local gas distribution companies sold a
“bundled” product that included both the natural gas commodity and delivery to the end-use
customer’s meter. However, beginning in the late 1980s, large industrial customers sought to achieve
savings by procuring their own supplies of natural gas from producers and contracting with pipelines
and local gas distribution companies for transportation of natural gas to their facilities. These changes
were intended to promote competition where it was economically beneficial to consumers.
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.
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 cost of providing transportation service. Generally, we are unaffected financially if
industrial customers transport customer-owned gas rather than purchasing gas directly from us, as long
as they remain on a tariff or contract with the same quality of service. This is because 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 different levels or qualities 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 interstate pipeline capacity to ship
customer-owned gas and the cost structure embedded in our industrial rates, are among the primary
factors that have caused some industrial customers to alternate between sales and transportation service
or between higher and lower qualities 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
14
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 some 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.
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 evolving 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 level. 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);
and an area adjacent to the Gasco and the Siltronic sites along a segment of 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). We do not
expect that the ultimate resolution of these matters will have a material adverse effect on our financial
condition or results of operations; however, if it is determined that both the insurance recovery and
future rate recovery of such costs are not probable, then the costs 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 Part II, Item 8, Note 12, to the accompanying Consolidated Financial
Statements for a further discussion of potential environmental responses and related costs.
15
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 (Kyoto Protocol),
proposed federal legislation and proposed or enacted state actions to develop statewide or regional
programs, each of which have imposed or would impose reductions in greenhouse gas emissions. The
outcome of federal and state climate change initiatives cannot be determined at this time, but these
initiatives could result in a variety of regulatory programs 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 taking steps to address future environmental 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, NW Natural’s President 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 (see
Part II, Item 7., “Regulation and Rates—Rate Mechanisms—Smart Energy Program”).
Employees
At December 31, 2007, our workforce consisted of 738 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.
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.W., 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 Web site (http://www.sec.gov) that contains reports, proxy statements
and other information filed electronically by us. In addition, we make available on our website
(http://www.nwnatural.com), free of charge, 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. Our Corporate Governance
16
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 June 1, 2007
that, as of that date, he was not aware of any violation by the company of 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, 2006, 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, 2007, 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, including
those set forth below and in other documents we file with the SEC.
Regulatory risk. The rates we charge customers for gas distribution services are established by
the OPUC and the WUTC, and the maximum rates for interstate gas storage services are approved by
FERC. The failure of these regulatory authorities to approve rates which provide for recovery of our
costs and an adequate return on invested capital may adversely impact our financial condition and
results of operations.
The rates charged to customers must be approved by the applicable regulatory commission. The
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. We expect to continue to make capital expenditures to expand
and improve our distribution and storage systems. The failure of any regulatory commission to approve
on a timely basis requested rate increases to recover increased costs or to allow an adequate return could
adversely impact our financial condition and results of operations. In addition, amounts required to be
refunded to customers in accordance with Oregon’s automatic regulatory adjustment for income taxes
paid could have a material adverse impact on our financial conditions and results of operations.
Gas price risk. Higher natural gas commodity prices and fluctuations in the price of gas may
adversely affect our earnings.
In recent years, natural gas commodity prices have been volatile primarily due to growing
demand, especially for power generation, and stagnant North American gas production. In Oregon and
in Washington, the utility has PGA tariffs which provide for annual revisions in rates resulting from
changes in the cost of purchased gas. 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 that 33 percent 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. Accordingly, higher gas costs than those assumed in setting rates can adversely
affect our results of operations.
The OPUC has begun a formal review of the PGA process which will cover portfolio
requirements, incentive sharing levels and filing requirements, among other items. The review is
17
expected to be completed in 2008. Implementation of any changes to the PGA mechanism is likely to
become effective with the 2008 PGA filing.
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.
Hedging risk. Our risk management policies and hedging activities cannot eliminate the risk of
commodity price movements and other financial market risks 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 risk through enforcement of established risk limits
and risk management procedures, including hedging activities, in accordance with our Financial
Derivatives Policy. These risk limits and risk management procedures may not always work as planned
and cannot entirely eliminate the risks associated with hedging. We also have credit exposure to
financial 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 the
policy specifies limits on the contract amount and duration based on each counterparty’s credit rating.
These practices are subject to regulatory review and, if found to be imprudent, could be disallowed,
which could adversely affect our financial condition and results of operations.
Customer growth risk. Our results of operations may be negatively affected if we are unable to
sustain customer growth rates.
Our earnings growth and results of operations have largely been dependent upon the sustained
growth of our residential and commercial customer base. If we are unable to sustain customer growth
rate levels at or above the national average, our results of operations may be negatively affected. A
number of factors could negatively impact our ability to sustain growth, such as a downturn in the
economy, reduced housing starts and competition.
Risk of competition. Our gas distribution business is subject to increased competition with
other energy sources.
To the extent that competition increases, our profit margins may be negatively affected. In the
residential market, we compete 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 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, then our ability to attract new customers could be significantly affected, which could
have a negative impact on our customer growth rate and results of operations.
Single transportation pipeline risk. We rely on a single pipeline for the transportation of gas to
our service territory.
18
We are largely dependent on a single, bi-directional pipeline for transportation of gas into our
service territory. 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 disruption of service.
Business development risk. The construction, startup and operation of our business
development projects may involve unanticipated changes or delays that could negatively impact our
financial condition and results of operations.
The startup, construction and operation of business development projects involve many risks,
including: the inability to obtain required governmental permits and approvals; startup and construction
delays; construction cost overruns; competition; 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. Such unanticipated events could negatively impact our results of
operations. These risks apply to our current business development activities, including Palomar
Pipeline and the Gill Ranch storage facility in California.
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 and financial
condition. Also, management expects that future legislation may impose carbon constraints to address
global climate change.
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. To the extent we are unable to recover these 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 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 a material adverse
effect on our results of operations, particularly if those costs are not fully recoverable from customers.
With respect to global climate change, there are a number of legislative and regulatory
proposals to address greenhouse gas emissions, which are in various phases of discussion or
implementation. The outcome of federal and state actions to address climate change could result in a
variety of regulatory programs 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.
19
Weather risk. Our results of operations may be negatively affected by warmer than average
weather.
A large portion of the utility’s margin is derived from sales to space heating residential and
commercial customers during each winter heating season. Current rates are based on an assumption of
average weather. In Oregon, the effects of warmer or colder weather on utility margin are reduced
through the operation of our weather normalization mechanism, and partially reduced by our
conservation tariff in months when weather normalization is not in effect. However, customers in
Oregon may elect to opt out of the weather normalization mechanism, and less than 10 percent of those
customers have opted out on an annualized basis. In addition, approximately 10 percent of our
residential and commercial customers are in Washington where we do not have a weather
normalization mechanism or conservation tariff. As a result, we are not fully protected against warmer
than average weather, 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 may result in increased conservation by customers, which can
decrease sales and adversely affect results of operations. The OPUC authorized our conservation tariff,
which is designed to recover lost margin due to changes in residential and commercial customers’
consumption patterns. The conservation tariff is intended to adjust for increases or decreases in
consumption attributable to annual changes in commodity costs or periodic changes in general rates
and for deviations between actual and expected usage. The conservation tariff expires in October 2012.
The failure of the OPUC to extend the conservation tariff in the future could adversely affect our
financial condition 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, such as
leaks, accidents, mechanical problems, fires, 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 recoverable through rates, which could adversely affect our
financial condition and results of operations.
Business continuity risk. We may be adversely impacted by extreme events to which we are not
able to promptly respond to and repair our system.
Extreme events (e.g. terrorism act or national disaster) that target or impact our natural gas
distribution, transmission and storage facilities could result in a disruption in our ability to meet
customer requirements. These events 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. A slow response to extreme events may have
an adverse affect on earnings as customers could be without gas for an extended period of time.
Economic risk. Changes in the economic outlook, including rates of inflation and capital
market conditions may have a negative impact on our financial condition and results of operations.
20
Our business relies on capital markets to finance our construction costs and other capital expense
requirements, and to refund maturing debt, that cannot by funded by operating cash flows. Changes in the
economy that impact our ability to access the capital markets at competitive rates may negatively impact
our ability to make strategic capital investments. Market disruptions and downgrades of our debt credit
ratings may increase our cost of borrowing or negatively impact our ability to access financial markets.
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.
Our gas distribution business is subject to a variety of workforce risks, including being able to
attract and retain qualified employees, being able to transfer the knowledge and expertise of an aging
workforce to new employees as older workers retire and being able to reach collective bargaining
agreements with the union that represents about 65 percent of our workers.
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 2. PROPERTIES
Our natural gas distribution system consists of approximately 13,700 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 1,400 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.
21
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
See Part II, Item 8., Note 12 to Consolidated Financial Statements, “Commitments and
Contingencies—Legal Proceedings.”
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, 2007.
22
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
2007
High
$46.34
52.85
49.37
50.89
Low
$39.79
44.05
40.98
44.28
2006
High
$36.57
37.04
40.08
43.69
Low
$32.83
33.30
35.81
38.53
The closing quotations for our common stock on December 31, 2007 and December 29, 2006
were $48.66 and $42.44, respectively.
(B) As of December 31, 2007, there were 7,863 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
2007
$0.355
0.355
0.355
0.375
$1.440
2006
$0.345
0.345
0.345
0.355
$1.390
The amount and timing of dividends payable on our common stock are within the sole
discretion of our Board of Directors. It is the intention of the Board of Directors to continue to pay cash
dividends on our common stock on a quarterly basis. However, the declaration and amount of future
dividends will be dependent upon our earnings, cash flows, financial condition and other factors.
23
(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, 2007:
ISSUER PURCHASES OF EQUITY SECURITIES
(a)
(b)
Total Number
of Shares
Purchased (1)
Average
Price Paid
per Share
(c)
Total Number of Shares
Purchased as Part of Publicly
Announced Plans or
Programs (2)
(d)
Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the Plans or
Programs (2)
1,126
19,984
1,736
22,846
$46.48
$49.54
$47.90
$49.27
1,905,528
132,300
61,100
25,600
2,124,528
$26,938,905
(6,138,707)
(2,843,169)
(1,224,381)
$16,732,648
Period
Balance forward
10/01/07-10/31/07
11/01/07-11/30/07
12/01/07-12/31/07
Total
(1) During the quarter ended December 31, 2007, 20,873 shares of our common stock were purchased
in the open market to meet the requirements of our Dividend Reinvestment and Direct Stock
Purchase Plan. In addition, 1,973 shares of our common stock were purchased in the open market
during the quarter under equity-based programs. During the three months ended December 31,
2007, no shares of our common stock were accepted as payment for stock option exercises
pursuant to our Restated Stock Option Plan.
(2) On May 25, 2000, we announced a program to repurchase up to 2 million shares, or up to $35
million in value, of NW Natural’s common stock through a repurchase program that has been
extended annually. The purchases are made in the open market or through privately negotiated
transactions. In April 2006, the Board increased the authorization from 2 million shares to
2.6 million shares and increased the dollar limit from $35 million to $85 million. In April 2007,
the Board extended the program through May 31, 2008 and increased the authorization from
2.6 million shares to 2.8 million shares and increased the dollar limit from $85 million to $100
million. During the three months ended December 31, 2007, 219,000 shares of our common stock
were purchased pursuant to this program. Since the program’s inception through December 31,
2007, we have repurchased 2,124,528 shares of common stock at a total cost of $83.3 million.
On September 28, 2007, we entered into a Stock Purchase Plan Engagement Agreement with our
broker that established a trading plan for our repurchase program that qualified for the safe harbors
provided by Rule 10b-18 and Rule 10b5-1 under the Exchange Act. That agreement expired on
November 9, 2007.
24
ITEM 6. SELECTED FINANCIAL DATA
Thousands, except per share amounts and
ratio of earnings to fixed charges
For the year ended December 31,
2007
2006
2005
2004
2003
Utility operating revenues:
Residential sales
Commercial sales
Industrial - firm sales
Industrial - interruptible sales
Unbilled revenues(1)
Total gas sales revenues
Transportation
Regulatory adjustment for income taxes paid(2)
Other
Total gross utility operating revenues
Cost of gas sold
Revenue taxes
Utility operating revenues
Non-utility operating revenues
$ 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
-
$ 328,346
176,336
33,578
23,655
14,474
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
576,389
17,968
-
7,627
601,984
323,128
14,650
264,206
9,210
Net operating revenues
$ 369,042
$ 340,176
$ 324,993
$ 291,495
$ 273,416
Net income
Redeemable preferred stock dividend requirements
Earnings applicable to common stock
Average common shares outstanding:
Basic
Diluted
Earnings per share of common stock:
Basic
Diluted
Dividends paid per share of common stock
$
$
$
$
$
74,497
-
74,497
26,821
26,995
2.78
2.76
1.44
$
$
$
$
$
63,415
-
63,415
27,540
27,657
2.30
2.29
1.39
$
$
$
$
$
58,149
-
58,149
27,564
27,621
2.11
2.11
1.32
$
$
$
$
$
50,572
-
50,572
27,016
27,283
1.87
1.86
1.30
$
$
$
$
$
45,983
294
45,689
25,741
26,061
1.77
1.76
1.27
Total assets - at end of period
$2,014,183
$1,956,856
$2,042,304
$1,732,195
$1,585,379
Long-term debt
$ 512,000
$ 517,000
$ 521,500
$ 484,027
$ 500,319
Ratio of earnings to fixed charges
3.92
3.40
3.32
3.02
2.84
(1) Unbilled revenues have been allocated by customer class for the years 2004 through 2007.
(2) Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation as described in Part II, Item 7.,
“Results of Operations - Regulatory Matters - Regulatory Adjustment for Income Taxes Paid,” and “Comparison of Gas Distribution
Operations - Regulatory Adjustment for Income Taxes Paid.”
Certain amounts from prior years have been reclassified to conform, for comparison purposes, with the
current financial statement presentation. These reclassifications had no impact on prior year
consolidated results of operations.
25
SELECTED FINANCIAL DATA (continued)
Thousands, except customer and gas cost per therm data
2007
2006
2005
2004
2003
For the year ended December 31,
Capitalization - at end of period
Common stock equity
Long-term debt
Total capitalization
Gas sales and transportation deliveries (therms):
Residential
Commercial
Industrial - firm
Industrial - interruptible
Unbilled therms1
Total gas sales
Transportation
$ 594,751
512,000
$ 599,545
517,000
$ 586,931
521,500
$ 568,517
484,027
$ 506,316
500,319
$1,106,751
$1,116,545
$1,108,431
$1,052,544
$1,006,635
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
343,534
226,257
55,314
47,994
12,099
685,198
414,554
Total volumes delivered
1,214,969
1,192,649
1,157,567
1,131,866
1,099,752
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)
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
510,336
56,504
362
98
179
567,479
4,374
3%
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
3,952
(7%)
673
4,004
46.99
(1) Unbilled therms have been allocated by customer class for the years 2004 through 2007.
26
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is management’s assessment of Northwest Natural Gas Company’s (NW
Natural) financial condition, including the principal factors that affect results of operations. The
discussion refers to our consolidated activities for the three years ended December 31, 2007.
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, which principally
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, including our wholly-
owned subsidiaries, NNG Financial Corporation (Financial Corporation) and Gill Ranch Storage, LLC
(Gill Ranch). In this report, the term “utility” is used to describe our regulated gas distribution
business, and the term “non-utility” is used to describe our gas storage business (gas storage) and our
other non-regulated investments and business activities (other segment), including investments in a
recently announced intrastate pipeline project in Oregon (Palomar Pipeline) (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 2007:
• Net income increased 17 percent to $74.5 million, and diluted earnings per share increased
21 percent to $2.76 per share;
• Net operating revenues from our utility increased 8 percent to $351.9 million;
• Net operating revenues from our gas storage business increased 33 percent to $17.0 million;
• Cash flow from operations increased 24 percent to $183.6 million, reflecting strong
earnings and deferred gas cost savings;
• Ranked best in the West and second-best nationally in overall residential customer
satisfaction among gas utilities according to a J.D. Power and Associates survey;
• Conservation tariff and weather normalization mechanisms were extended in Oregon
through October 2012;
• Smart Energy Program, a carbon-offset billing option for customers, was implemented as
the first program of its kind for a standalone gas company to address greenhouse gas
emissions;
• Announced plans to develop investments in a natural gas transmission pipeline in Oregon
and an underground gas storage facility in central California (see “Strategic Opportunities,”
below);
• Mist storage capacity was expanded by 1.8 Bcf to approximately 16 Bcf; and,
• Quarterly common stock dividend rate increased 6 percent to $0.375 per share in the fourth
quarter of 2007, making this the 52nd consecutive year of increasing dividends paid to
shareholders.
27
Our primary businesses consist of our regulated utility and gas storage. Factors critical to the
success of the utility business include: maintaining a safe and reliable distribution system; acquiring an
adequate supply of gas; providing distribution services at a competitive price; and being able to recover
the operating and capital costs of the utility in the rates charged to customers. The 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 segment include the ability to: develop additional storage capacity at competitive market
prices; plan for the replacement of capacity that is expected to be recalled by the utility to serve its core
customers in the future; and obtain timely and reasonable rate changes. Our gas storage businesses
charge rates approved by the Federal Energy Regulatory Commission (FERC). The Gill Ranch project
is expected to be subject to regulation by the California Public Utilities Commission (CPUC), if
completed.
2008 Outlook
In 2008, management expects to focus on the following four areas:
Core Business Improvement. We plan to incorporate new technology into our operations while
honing new processes established in the recent changes to our operating model. Our goal is to integrate
and to streamline operations and provide our employees with tools to become even more effective and
efficient.
Strategic Position. In our rapidly changing business environment, we will strive to continue
achieving shareholder value while balancing the interests of our customers and communities. In doing
so, we will continue to develop plans in response to potential climate change legislation as well as to
address regulatory, business development and workforce challenges and opportunities.
Business Development. We intend to advance our key natural gas infrastructure investments,
such as the Palomar Pipeline and Gill Ranch storage projects, while exploring new growth
opportunities. See “Strategic Opportunities,” below.
Organizational Effectiveness. As employees are our most highly valued resource, we intend to
continue to support our employees with well defined practices, training and technology to achieve our
goals.
Issues, Challenges and Performance Measures
Managing the business in a period of gas price volatility. Our gas acquisition strategy is
designed to secure sufficient supplies of natural gas to meet the needs of our utility’s core customers.
Equally important, however, is our strategy to hedge gas prices for a significant portion of our annual
purchase requirements based upon the market outlook and our core utility’s gas load forecast. We
believe we have sufficient supplies of natural gas under contract to meet the needs of our core
customers, but price increases could change our earnings outlook and our competitive advantage. If gas
prices increase, it could affect our ability to add residential and commercial customers and could result
in industrial customers shifting their businesses’ energy needs to alternative fuel sources. We continue
to develop new gas acquisition strategies to manage gas prices and to efficiently meet market demands.
Customer growth. Our growth is largely driven by new residential construction, and while we
expect to continue with a customer growth rate above the national average for local gas distribution
companies due to the growing market in the Pacific Northwest, we have experienced a slowdown in
28
new construction which is expected to continue through 2008. For the 12 months ended December 31,
2007, our annual growth rate was 2.4 percent, compared to 3.1 percent for the comparable period
ended December 31, 2006. A prolonged slowdown in residential new construction could adversely
impact our future results of operations.
Strategic Opportunities
Business Process Redesign. To address these economic and competitive challenges we will
continue to evaluate our business processes and costs in our new operating model and to improve those
processes where long-term efficiencies could be gained. We targeted a number of areas where we
could restructure to gain efficiencies, including more centralization and more standardized processes.
To date, we are on schedule to meet the target workforce reductions of 150 to 200 employees by late
2009. We are also currently completing the implementation of the first phase of a new integrated
information system, with the second phase of the new system installation expected to commence early
in 2008. These technology investments are expected to help facilitate additional business initiatives, as
well as help to improve overall operational efficiencies throughout NW Natural.
Pipeline Diversity. In September 2006, we announced that we were evaluating a possible equity
investment in a natural gas transmission pipeline that would connect TransCanada Gas Transmission
Northwest’s (GTN) interstate transmission line to our local gas distribution system (Palomar Pipeline).
The proposed pipeline is intended to diversify our gas delivery options, including the enhancement of
reliability for our customers by providing an alternate transportation path for, and an alternative gas
supply source to, gas purchases in Alberta and, including the possible delivery of supplies from a
liquefied natural gas (LNG) facility that is proposed on the Columbia River. In August 2007, we entered
into an agreement with GTN for the purpose of developing, designing, permitting, constructing and
owning the pipeline. During the planning and permitting phase we expect to contribute our 50 percent of
the estimated $30 million for permitting and planning, which is anticipated to occur during the 2007-2009
period. We believe there is sufficient interest from potential pipeline users to warrant proceeding with the
permitting phase of the project. We, along with GTN, will determine at a later date whether to proceed
with development of the project beyond the permitting phase. If constructed, we estimate the total cost
for the entire 220 mile pipeline to be between $600 million and $700 million. NorthernStar LLC,
developer of a proposed Bradwood Landing LNG terminal on the Columbia River, may elect to take
capacity on the Palomar Pipeline should the Bradwood Landing terminal and the Palomar Pipeline be
constructed.
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 Gill Ranch, a wholly owned subsidiary of NW Natural, to develop and operate
the facility. Gill Ranch will initially own 75 percent of this storage project and PG&E will own 25
percent. The new storage facility is expected to provide approximately 20 Bcf of underground gas
storage capacity, and will include 25 miles of transmission pipeline, when the initial phase is
completed. We estimate our share of the total cost for the initial phase of development to be between
$150 million and $160 million over the next three years, which represents 75 percent of the estimated
total project cost. We conducted an open season to gauge interest in the storage facility from October
2007 to December 2007, and the results indicated a strong level of interest in gas storage at Gill Ranch
from potential storage customers. We expect to file an application with the CPUC for a Certificate of
Public Convenience and Necessity in mid-2008 and, if granted, Gill Ranch will be subject to CPUC
regulation with respect, among other things, to rates, the issuance of securities, lien grants and sales of
property. We expect the initial phase of Gill Ranch to be in-service by late 2010.
29
Earnings and Dividends
Net income was $74.5 million, or $2.76 a diluted share, for the year ended December 31, 2007,
compared to $63.4 million, or $2.29 a diluted share, and $58.1 million, or $2.11 a share, for the years
ended December 31, 2006 and 2005, respectively. Returns on equity for these three years were 12.5
percent, 10.7 percent and 10.1 percent, respectively.
2007 compared to 2006:
Positive factors contributing to increased earnings were:
•
•
•
•
increased utility volumes and sales to residential and commercial customers primarily from
customer growth contributed $9.7 million to margin (see “Results of Operations—
Comparison of Gas Distribution Operations,” below);
increased margin of $6.0 million from a regulatory adjustment for income taxes paid;
increased margin from regulatory sharing of gas cost savings, up from $8.1 million in 2006
to $12.1 million in 2007, and from reversing temporary adjustments related to derivative
contracts that settled in 2007, reflecting gains of $2.9 million in 2007 compared to losses of
$2.9 million in 2006; and
increased margin of $4.2 million from gas storage operations, primarily due to an expansion
of firm storage capacity and higher revenue sharing from asset optimization.
Partially offsetting the above positive factors were:
•
•
•
increased depreciation expenses of $3.9 million, primarily related to increased utility plant
in service;
increased operations and maintenance expense of $5.9 million, partially due to higher
bonuses tied to improved performance results and an increase for certain strategic initiatives
including maintenance projects and training; and
increased income tax expense related to higher taxable income.
2006 compared to 2005:
Positive factors contributing to increased earnings were:
•
•
•
increased utility volumes and net operating revenues (margin) from sales to residential and
commercial customers due to 3.1 percent customer growth, plus extended coverage from
the weather normalization and conservation mechanisms in Oregon, partially offset by
weather that was 4 percent warmer than average and 2 percent warmer than 2005 (see
“Results of Operations—Comparison of Gas Distribution Operations,” below);
increased margin from regulatory sharing of gas cost savings, from $4.2 million in 2005 to
$8.1 million in 2006, partially offset by a $2.9 million temporary unrealized loss related to a
derivative contract that settled and reversed in 2007; and
increased gas storage margin over the prior year, primarily due to increased storage contract
volumes and increased optimization revenue from the independent energy marketing
company.
Partially offsetting the above positive factors were:
•
increased property tax and depreciation expenses related to increased utility plant in service,
which were partially covered by revenue increases approved in the 2006 Purchased Gas
Adjustment (PGA) filings in Oregon and Washington;
30
•
•
increased operations and maintenance expense related to higher bonuses tied to improved
performance results and to employee severance charges tied to business redesign initiatives,
partially offset by lower payroll and employee benefit costs; and
increased income tax expense related to higher taxable income.
Dividends paid on our common stock were $1.44 a share in 2007, compared to $1.39 a share in
2006 and $1.32 a share in 2005. The current indicated annual dividend rate is $1.50 per share.
Application of Critical Accounting Policies and Estimates
In preparing our financial statements using generally accepted accounting principles in the
United States of America (GAAP), management exercises judgment in the selection and application of
accounting principles, including making estimates and assumptions that affect reported amounts of
assets, liabilities, revenues, expenses and related disclosures in the financial statements. Management
considers our critical accounting policies to be those which are most important to the representation of
our financial condition and results of operations and which require management’s most difficult and
subjective or complex judgments, including accounting estimates that could result in materially
different amounts if we reported under different conditions or used different assumptions.
Our most critical estimates or judgments involve regulatory cost recovery, revenue recognition,
derivative instruments, pension assumptions, 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. Our critical accounting policies and estimates are
described below.
Within the context of our critical accounting policies and estimates, management is not
currently aware of any reasonably likely events or circumstances that would result in materially
different amounts being reported.
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 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.
31
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
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, 2007 and 2006 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 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, 2007 and 2006 were $78.0 million and $87.5 million, respectively. The decrease in
accrued unbilled revenues at year-end 2007 was primarily due to lower gas prices included in customer
rates. If the estimated percentage of unbilled volume at December 31, 2007 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 $3.0 million, $1.5 million and $0.9 million, respectively.
Utility revenues may also include the recognition of a regulatory adjustment for income taxes
paid (see “Results of Operations—Regulatory Matters—Regulatory Adjustment for Income Taxes
Paid,” below). 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 the tax year.
Non-utility revenues, derived primarily from our gas storage business segment, are recognized
upon delivery of the service to customers. Revenues from our optimization partner are recognized over
the life of the optimization contract for the guaranteed amount, or are recognized as they are earned for
amounts above the guaranteed value.
Accounting for Derivative Instruments and Hedging Activities
Our Financial Derivatives Policy and Gas Acquisition Policy set forth guidelines for using
financial derivative instruments to support prudent risk management strategies within designated
32
parameters. 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 qualify as
derivative instruments 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 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 made 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”). Our
estimate of fair value is determined from period-to-period based on an internal discounted cash flow
model for swap contracts and on a Black-Scholes model for option contracts. 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 at December 31, 2007 and 2006, 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,
with 67 percent of unrealized gains and losses recorded to a regulatory asset or liability account. The
remaining 33 percent is recognized in current income for contracts not qualifying for hedge accounting
or is recognized in Other Comprehensive Income for contracts qualifying for hedge accounting. An
interest rate swap qualifies for hedge accounting under SFAS No. 133. During the fourth quarter of
2006, we entered into a number of financial derivatives related to commodity purchases by the utility
after our PGA filing. The $2.9 million loss was reversed during 2007 in the cost of gas when the
derivative contract settled.
Derivative contracts are subjected to a hedge effectiveness test to determine the financial
statement treatment of each specific derivative. As of December 31, 2007, all of our derivatives were
effective economic hedges and either qualified or were expected to qualify for regulatory deferral, or
hedge accounting treatment. We utilize the hypothetical derivative method under SFAS No. 133 to
determine the hedge effectiveness of our interest rate swap and the dollar offset method under SFAS
No. 133 for all other derivative contracts. 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
2007
2006
2005
Net gain (loss) on commodity-price swaps—utility
Net loss on commodity-price options—utility
Subtotal on commodity—utility
Net gain on foreign currency forward purchases—utility
Total realized net gain (loss)
33
$(41,954) $(18,849) $90,205
(1,315)
(1,160)
(662)
(42,616)
662
(20,009)
355
88,890
532
$(41,954) $(19,654) $89,422
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. Unrealized gains and losses resulting from mark-to-market valuations are
generally not recognized in current income or other comprehensive income, but are recorded as
regulatory liabilities or regulatory assets, which are offset by a corresponding balance in non-trading
derivative assets or liabilities (see Note 11).
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 after December 31, 2006.
Instead, newly hired or rehired non-bargaining unit employees are provided an enhanced Retirement K
Savings Plan benefit. Benefits provided to bargaining unit employees under the Retirement Plan for
Bargaining Unit Employees are 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.
Effective December 31, 2006, the funded status of our pension plans was required to be
recognized in accordance with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension
and Other Postretirement Benefit Plans” (SFAS No. 158). SFAS No. 158 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 a regulatory asset or regulatory liability,
rather than include AOCI in common equity, for the funded status of those plans (see “Regulatory
Accounting”, above, and Note 1, “Industry Regulation”).
A number of factors are considered in developing pension assumptions, including an evaluation
of relevant discount rates, expected long-term investment returns, plan asset allocations, expected
changes in salaries, wages and retirement benefits, analyses of current market conditions and input
from actuaries and other consultants. For the December 31, 2007 measurement date, we:
•
updated the pension discount rate assumptions from a range of 6.00 percent to 6.05 percent
to a range of 6.75 percent to 6.87 percent. The new rate assumptions were determined for
34
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 or Aa3 or higher by
Moody’s Investors Service;
confirmed the expected rate of future compensation increases between 4.00 and 5.00
percent;
confirmed the expected long-term return on plan assets at 8.25 percent; and
reviewed and updated other key assumptions as needed.
•
•
•
Changes in valuation assumptions impact our projected benefit obligations. 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.
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. The actual annualized returns on
plan assets, net of management fees, for the past one-year, five-year and 10-year periods ended
December 31, 2007 were 8.98 percent, 14.17 percent and 8.92 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
2007 Pension Costs
Impact on Benefit
Obligations at
Dec. 31, 2007
(0.25%)
(0.25%)
$569
$560
$8,682
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 109 and Financial Accounting
Standards Board (FASB) Interpretation No. 48 (FIN 48), 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 109 and FIN 48 also require that deferred
tax assets be reduced by a valuation if it is more likely than not that some portion or all of the deferred
tax asset will not be realized. We adopted the provisions of FIN 48 on January 1, 2007. At the date of
adoption and as of December 31, 2007, we did not have a liability for unrecognized tax benefits as all
positions taken are considered highly certain. Our net long-term deferred tax liability totaled $203.1
million at December 31, 2007. This liability is estimated based on the expected future tax
consequences of items recognized in the financial statements. After application of the federal statutory
35
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, 2007, we did not
have a valuation allowance due to our expectation that all of these assets will be realized.
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, 2007 and 2006, we had regulatory assets representing
differences between book and tax basis related to pre-1981 property of $68.6 million and $67.1
million, respectively, and recorded an offsetting deferred tax liability for the same amounts (see Note
1, “Income Tax Expense”). We believe that it is reasonable to expect recovery of these regulatory
assets through future customer rates. However, future regulatory changes could require the write-off of
all or a portion of these regulatory assets should they no longer be probable of recovery in future 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 estimated that the total future expenditures for environmental investigation, monitoring and
remediation are $38.3 million as of December 31, 2007. 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.
36
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).
Results of Operations
Regulatory Matters
Regulation and Rates
We are subject to regulation with respect to, among other matters, rates, systems of accounts
and issuance of securities by the OPUC and the WUTC. In 2007, 93 percent of our utility gas
deliveries and 91 percent of our 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 pace of continued customer growth in the residential and commercial
markets 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
Our most recent general rate increase in Oregon authorized rates to customers based on a return
on shareholders’ equity (ROE) of 10.2 percent and was effective September 1, 2003. We retain all of
our earnings up to a threshold level equal to our authorized ROE of 10.2 percent plus 300 basis points,
subject to adjustment up or down each year based on movements in long-term interest rates. Our most
recent general rate case in Washington authorized a revenue increase of $3.5 million per year but did
not specifically authorize an ROE and was effective July 1, 2004. Our plans are to file a general rate
case in Washington in 2008.
The current maximum cost-based rates for our interstate gas storage services were approved by
FERC in 2005. These rates are designed to reflect updated costs related to development of the Mist gas
storage facility from 2001 through 2005. Pursuant to this approval, we were required to file either a
petition for rate approval or a cost and revenue study with FERC by January 18, 2008. We
requested and received an extension to enable us to file a cost and revenue study based on our actual
2007 results. We expect to file the study by March 31, 2008.
Oregon Rate Case Moratorium. 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, or
expansion of our automated meter reading program if an existing joint meter reading program with a
local electric utility ends. This agreement does not impact our ability to file annual rate adjustments to
reflect changes in gas purchase costs under our PGA mechanism and to collect, or refund, prior year’s
gas cost deferrals.
37
Rate Mechanisms
Purchased Gas Adjustment. Rate changes are applied each year under the PGA tariff
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 (see “Comparison of Gas Distribution Operations—Cost of Gas Sold,” below), 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. Under the current PGA mechanisms, we collect an amount for purchased gas costs based on
contract prices and market 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. As part of an incentive mechanism in Oregon, only 67
percent of the difference is 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
cost of gas sold. In Washington, the PGA deferral requires 100 percent of all prudently incurred gas
costs to be passed through in customer rates.
In October 2007, the OPUC and the WUTC approved rate decreases effective on November 1,
2007 under our PGA mechanism. The rate reduction lowered average monthly bills of Oregon
residential customers by 8.0 percent and those of Washington residential customers by 9.8 percent. The
PGA mechanism reflects the January 2007 rates approved by FERC for interstate pipeline suppliers.
Pursuant to the PGA tariffs, approved rate changes effective November 1, 2006 increased average
monthly bills of Oregon residential sales customers by 3.5 percent and those of Washington residential
sales customers by 2.6 percent. In 2005, the OPUC approved a PGA rate increase averaging 15.2
percent for Oregon residential sales customers, and the WUTC approved a rate increase averaging 12.0
percent for Washington residential sales customers, both effective October 1, 2005.
The OPUC is currently conducting a formal review of the PGA process used by natural gas
utilities in Oregon covering gas portfolio requirements, incentive sharing levels and filing
requirements, among other items. The review is expected to be completed in 2008. Implementation of
any changes to the PGA mechanism is likely to become effective with the 2008 PGA filing.
Conservation Tariff. In October 2002, the OPUC authorized the implementation of a
“conservation tariff,” which is a rate mechanism designed to adjust margin to compensate the utility 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 earnings and the
quantity of energy 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 utility
revenues.
The Oregon conservation tariff includes two components: (1) a price elasticity adjustment,
which adjusts rates annually for expected increases or decreases in 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
38
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 for current customer
growth. See Part II, Item 7., “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 has 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, decreasing rates when the weather is colder than average
and increasing rates when it is warmer than average. The mechanism is applied to our residential and
commercial customers’ bills between December 1 and May 15 for 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 accounts for about 10 percent of our utility revenues.
Excess Earnings Test. We are subject to an excess earnings test requirement in which we
retain all of our earnings up to a threshold level equal to our authorized ROE of 10.2 percent plus 300
basis points. Revenues equivalent to 33 percent of any earnings above the threshold are required to be
refunded to customers. The excess earnings threshold is subject to adjustment up or down each year
based on movements in long-term interest rates. In 2007 and 2006, the threshold after adjustment was
13.40 percent and 13.44 percent, respectively. No amounts were required to be refunded to customers
as a result of the 2006 or 2005 earnings test, and we do not expect that any amounts will be required to
be refunded to customers as a result of the 2007 earnings test, which will be reviewed by the OPUC
during the second quarter of 2008. The OPUC’s annual formal review process to test for excess
earnings ensures that we are allowed to pass through 100 percent of prudently incurred gas costs into
rates. In Washington, we are not subject to an annual excess earnings test, and 100 percent of all
prudently incurred gas costs are passed through into customer rates in the annual PGA.
Industrial Tariffs. In August 2006, the OPUC and WUTC approved tariff changes to the
service options for our major industrial accounts. The changes set out 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.
Pipeline Integrity Cost Recovery. In July 2004, the OPUC approved the accounting treatment
and full recovery for the cost of our 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 (see “Financial Condition—
Cash Flows—Investing Activities,” below). We classify our costs as either capital expenditures or
regulatory assets, accumulate the costs over each 12 months ending September 30, and recover the
39
costs, subject to audit, through rate changes effective with the annual PGA. The accounting and rate
treatment for these costs extends through September 30, 2008 and may be reviewed for potential
extension after that date. We do not have any special accounting or rate treatment for pipeline integrity
costs incurred in the state of Washington.
Smart Energy Program. Effective September 1, 2007, the OPUC approved our “Smart
Energy” program. Smart Energy allows residential and commercial customers to offset greenhouse
gases produced from their natural gas use. The Smart Energy rate is designed to neutralize the impact
of greenhouse gases, such as carbon dioxide and methane, by funding projects that prevent, reduce or
capture emissions released into the atmosphere. Offset funds collected from customers participating in
the program will be forwarded to The Climate Trust and these funds will specifically target the
reduction of methane emissions from farm operations.
Regulatory Adjustment for Income Taxes Paid
During 2005, the Oregon legislature passed legislation, effective January 1, 2006, intended to
ensure that utilities do not collect in rates more income taxes than they actually pay to taxing
authorities. The OPUC adopted permanent rules to implement this legislation in September 2006,
which were subsequently amended, with the revised rules approved in September 2007. The OPUC
rules require us to identify the amount of income taxes paid, as well as the amount of taxes authorized
to be collected in rates during the tax year. If amounts paid and amounts collected differ by more than
$100,000, the OPUC is required to direct the utility to implement a rate schedule with an automatic
adjustment clause to refund or surcharge for the difference. For more information regarding this
requirement, see “Comparison of Gas Distribution Operations—Regulatory Adjustment for Income
Taxes Paid,” below.
In January 2008, the Internal Revenue Service (IRS) ruled on our request for a Private Letter
Ruling on the issue of whether this state law complies with the provisions of federal tax law, including
the normalization requirements of the Internal Revenue Code. The IRS ruling indicated that, as
presented to them, the Oregon law does not violate the normalization requirements of federal tax law.
40
Comparison of Gas Distribution Operations
The following table summarizes the composition of gas utility volumes and revenues for the
years ended December 31, 2007, 2006 and 2005:
Total utility volumes sold and delivered
1,214,969
1,192,649
1,157,567
22,320
2007
2006
2005
Favorable/(Unfavorable)
2007
vs. 2006
2006
vs. 2005
398,960
249,659
52,340
161,790
89,128
263,092
382,665
242,683
66,971
150,153
112,736
237,441
371,538
233,987
74,880
135,807
149,106
192,249
16,295
6,976
(14,631)
11,637
(23,608)
25,651
$ 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
$ 471,502
250,287
64,507
4,087
100,740
6,668
—
2,862
900,653
563,772
21,633
$ 18,844
8,134
(12,419)
1,026
(18,231)
365
5,996
12,067
15,782
8,987
(161)
11,127
8,696
(7,909)
14,346
(36,370)
45,192
35,082
$ 64,966
40,379
2,479
814
(7,633)
1,231
—
(2,701)
99,535
(84,309)
(3,207)
$ 351,875
$ 327,267
$ 315,248
$ 24,608
$ 12,019
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
Other margin adjustments
$ 213,698
85,960
31,333
4,966
11,906
$ 204,951
83,334
32,383
4,333
2,610
$ 195,098
78,919
31,632
4,990
2,950
$ 8,747
2,626
(1,050)
633
9,296
20,252
(4,778)
3,138
5,996
$ 9,853
4,415
751
(657)
(340)
14,022
3,590
(5,593)
—
Margin before regulatory adjustments
Weather normalization mechanism
Decoupling mechanism
Regulatory adjustment for income taxes paid (1)
347,863
(2,496)
512
5,996
327,611
2,282
(2,626)
—
313,589
(1,308)
2,967
—
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)
$ 351,875
$ 327,267
$ 315,248
$ 24,608
$ 12,019
589,676
61,397
939
652,012
4,374
3%
575,116
60,523
945
636,584
4,089
(4%)
556,667
59,543
953
617,163
4,178
(2%)
14,560
874
(6)
15,428
18,449
980
(8)
19,421
(1) Regulatory adjustment for income taxes paid is the result of the implementation of the utility regulation as
described above under “Regulatory Matters—Regulatory Adjustment for Income Taxes Paid,” and described
below under “Regulatory Adjustment for Income Taxes Paid.”
(2) Amounts reported as margin for each category of customers is 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.
41
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 contributes to changes in margin based on changes in residential and commercial customer
consumption, and we have a weather normalization mechanism that adjusts customer bills up or down
contributing to changes in margin based on above- or below-average temperatures during the winter
heating season (see “Results of Operations—Regulatory Developments—Rate Mechanisms,” above).
Both mechanisms are designed to reduce the volatility of our utility earnings.
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 $11.4 million to margin in 2007, not
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 revenue
adjustments from regulatory deferrals and amortizations and miscellaneous fees. The weather
normalization and decoupling mechanisms decreased margin by a net $1.6 million in 2007 compared
to 2006, primarily reflecting colder weather, partially offset by an increase in decoupling that reflects
higher than expected consumption. Total utility volumes sold and delivered in 2007 were about the
same as last year. An increase in regulatory sharing 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).
Volume increases in 2007 were due mainly to residential and commercial customer growth,
which reflects a net increase of 15,428 customers during 2007, or an annual growth rate of 2.4 percent.
Our growth rate has slowed but remains well above the national average for local gas distribution
companies. Recent economic conditions have slowed the level of new construction in our service
territory.
Our weather normalization mechanism reduced margin 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 weather normalization mechanism is designed to balance our
margins when weather deviates from average.
The decoupling mechanism increased margin by $0.5 million in 2007, after adjusting for price
elasticity in the annual Oregon PGA filing, compared to a margin decrease of $2.6 million in 2006.
Decoupling is designed to adjust to our margin to reflect changes in customer usage due to customer
conservation efforts.
2006 compared to 2005:
Total utility margin increased $12.0 million or 4 percent in 2006 compared to 2005 with
residential and commercial customers contributing an additional $12.3 million to margin in 2006,
including the effect of the weather normalization and decoupling mechanisms. The $0.8 million
increase in margin from industrial customers in 2006 was offset by a decrease in revenue adjustments
from regulatory deferrals and amortizations and miscellaneous fees. The weather normalization and
decoupling mechanisms decreased margin by a net $2.0 million in 2006 compared to 2005, primarily
reflecting lower than expected consumption decline due to customer conservation efforts.
42
Our customer base grew in 2006, with a net increase of 19,421 customers. The growth rate for
2006 was 3.1 percent, compared to 3.4 percent in 2005. The slower growth rate in 2006 was primarily
due to a smaller increase in residential customers reflecting a modest slowdown in new construction.
In 2006, weather was 2 percent warmer than in 2005. The weather normalization mechanism
added $2.3 million to margin for the year ended December 31, 2006 based on weather that was 4
percent warmer than average, and reduced margin by $1.3 million in 2005 based on weather that was 2
percent warmer than average. Generally, we would have expected the weather normalization
mechanism in 2005 to recover lost margin when temperatures were warmer than average, but that year
we lost heating volumes and corresponding margin revenues in the latter part of May when
temperatures were significantly warmer than average because those volume and margin losses were not
entirely covered by the weather normalization mechanism, which ends on May 15 each year.
The decoupling mechanism decreased margin by $2.6 million in 2006, after adjusting for price
elasticity in the annual Oregon PGA filing, compared to a contribution of $3.0 million in 2005.
Residential and Commercial Sales
Residential and commercial sales markets are impacted by 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 discourage customers from conserving energy. In
Washington, where the remaining 10 percent of our customers are served, we do not have a weather
normalization or a conservation decoupling mechanism. As a result, these mechanisms do not fully
insulate the utility from earnings volatility due to weather and conservation. See the above tables under
“Comparison of Gas Distribution Operations” for the adjustments to utility margin revenues from the
weather normalization and decoupling mechanisms.
The primary factors that impact results of operations in the residential and commercial markets
are seasonal weather patterns, competition from other energy sources and economic conditions in our
service territory.
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).
43
2006 compared to 2005:
•
•
volumes sold were 3 percent higher, primarily reflecting 3.1 percent customer growth in the
residential and commercial sector and improved economic conditions, partially offset by 2
percent warmer weather;
operating revenues were 15 percent higher, primarily due to a 3 percent increase in volumes
and an 11 percent increase in the average rate per therm due to recent PGA rate increases,
effective October 1, 2005 and November 1, 2006; and
• margin was 5 percent higher, reflecting 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
The primary factors that impact results of operations in the industrial sales and transportation
markets are commodity costs, competition and economic conditions in our service territory.
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.
2006 compared to 2005:
•
•
volumes delivered to industrial customers increased 15.3 million therms, or 2.8 percent,
with the increase primarily in lower margin interruptible schedules;
operating revenue decreased $3.1 million, or 1.8 percent, due to customers transferring from
sales service to transportation service where cost of gas is not a component in operating
revenues; and
• margin increased 2 percent, reflecting increased volumes.
Several large industrial customers transferred from sales service back to transportation service
in 2006. High natural gas prices 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
Based upon the revised rules issued by the OPUC in September 2007, we filed our 2007 Tax
Report for the 2006 tax year on October 15, 2007. For the 2006 tax year, we estimated the utility was
entitled to recover $1.7 million through a surcharge to our Oregon utility customers based on taxes paid
44
that were greater than taxes collected, which was primarily driven by gains from gas cost savings from
the PGA incentive sharing mechanism in 2006. The increase in Oregon revenues for this surcharge is
expected to go into effect June 1, 2008 and would be recovered in a one-time adjustment to customers.
For the 2007 tax year, we estimate the utility will again be entitled to a surcharge for taxes paid in excess
of taxes collected in rates, largely driven by gains from gas cost savings from the PGA incentive sharing
mechanism in 2007. For 2007, we recognized an estimated surcharge of $4.3 million. The combined
2006 and 2007 surcharge estimate of $6.0 million was recognized in 2007 and is included in “Gross
operating revenues.” Deferred income tax expense of $2.4 million was also recognized in 2007 related to
the 2006 and 2007 estimated surcharges, resulting in a net contribution to earnings of $3.6 million (see
“Regulatory Matters—Regulatory Adjustment for Income Taxes Paid,” above).
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 $12.2 million in 2007, compared to $0.2
million in 2006 and $2.9 million in 2005.
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.
2006 compared to 2005:
Other revenues in 2006 were $2.7 million lower than in 2005 primarily due to a $5.6 million
decrease in deferrals under the decoupling mechanism (see “Results of Operations—Regulatory
Matters—Rate Mechanisms,” above) and a $1.5 million increase in amortization of the decoupling
deferrals from prior periods, partially offset by an increase of $1.3 million in interstate gas storage
credits to customers reflecting increased net income from storage operations, a decrease of $1.7 million
in amortization expense for the South Mist Pipeline Extension and a decrease of $1.0 million in the
deferral for the Oregon income tax kicker refund.
Cost of Gas Sold
Natural gas commodity prices had risen significantly in recent years, but the cost of gas
decreased slightly in 2007. The effects of higher commodity prices and price volatility on core utility
customers are mitigated, in part, through our use of underground storage facilities, fixed-price
commodity hedge contracts and short term sales of excess gas supply and transportation capacity to
off-system customers in periods when core utility customers do not require the full amount of contract
gas supplies or firm pipeline capacity.
The total cost of gas sold was $639.1 million in 2007, a decrease of $9.0 million or 1 percent
compared to 2006, and cost of gas sold in 2006 was $648.1 million, an increase of $84.3 million or
45
15 percent higher than 2005. The cost per therm of gas sold includes current gas purchases, gas drawn
from storage inventory, gains or losses from commodity hedges, margin from off-system gas sales,
pipeline demand charges, seasonal demand cost balancing adjustments, regulatory gas cost deferrals
and company gas use.
Under the PGA tariff in Oregon, our net income is affected within defined limits by changes in
purchased gas costs (see “Results of Operations—Regulatory Matters—Rate Mechanisms—Purchased
Gas Adjustment,” above). In each of the last three years, our actual gas costs were lower than the gas
costs embedded in rates, with the effect being that our share of the cost savings increased margin by
$12.1 million, $8.1 million and $4.2 million for 2007, 2006 and 2005, respectively.
We use natural gas derivatives, primarily fixed-price commodity swaps, under the terms of our
Financial Derivatives Policy, to help manage our exposure to floating price gas purchase contracts (see
“Application of Critical Accounting Policies and Estimates—Accounting for Derivative Instruments
and Hedging Activities,” above, and Note 11). We realized net losses of $42.0 million and $20.0
million from our financial hedges in 2007 and 2006, respectively, compared to a gain of $88.9 million
in 2005. Gains and losses from the financial hedging of utility gas purchases generally are included in
cost of gas, but generally do not impact net income because the hedges are factored into our PGA
deferrals and annual rate changes. To the extent that any utility gas hedge is entered into after the
annual PGA filing, then the gains and losses are subject to our PGA incentive sharing mechanism with
67 percent deferred and 33 percent recorded to current income.
Business Segments Other than Local Gas Distribution
Gas Storage
We earned $8.7 million in net income from our non-utility gas storage business segment in
2007, after regulatory sharing and income taxes, equivalent to 32 cents a share, compared to $6.0
million or 21 cents a share in 2006 and $4.6 million or 17 cents a share in 2005 (see Note 2). Earnings
from this business segment were higher in 2007 primarily because of increased revenues from
additional contract storage and higher margins from our contract with an independent energy
marketing company that optimizes the value of our utility assets.
In Oregon, we retain 80 percent of the pre-tax income from gas storage as well as from third
party optimization revenues when the costs of the capacity used have not been included in utility rates,
or 33 percent of the pre-tax income from such storage and optimization when the capacity costs have
been included in utility rates. The remaining 20 percent and 67 percent, respectively, are credited to a
deferred regulatory account for crediting to our core utility customers. We have a similar sharing
mechanism in Washington for pre-tax income derived from storage services and third party
optimization.
Other
The other business segment primarily consists of a wholly-owned subsidiary, Financial
Corporation, as well as various other non-utility investments, including an investment in an aircraft that
is leased to a U.S. airline, our equity investment in a proposed natural gas transmission pipeline project
(Palomar Pipeline), and our wholly-owned subsidiary, Gill Ranch (see Note 9). Our net investment
balance in Financial Corporation at December 31, 2007 and 2006 was $1.4 million and $2.6 million,
46
respectively. The decrease primarily reflects the sale in October 2007 of investments in alternative
energy projects for $2.1 million plus our portion of the investments’ retained cash, resulting in an
after-tax gain of $0.9 million. Our net investment balance in the aircraft lease at December 31, 2007
and 2006 was $3.2 million and $5.3 million, respectively, with the decrease primarily due to the receipt
in March 2007 of the final payment due under the terms of the original 20 year lease agreement. Our
equity investment balance in the proposed natural gas pipeline project with GTN was $6.0 million at
December 31, 2007 and a negligible amount at December 31, 2006 (see “Strategic Opportunities—
Pipeline Diversity,” above).
Net income from our other business segment was $0.8 million for each of 2007, 2006 and 2005.
In 2007, we recognized net income of $1.2 million from Financial Corporation, primarily related to the
sale of limited partnership interests in two wind power electric generation projects in California. These
sales generated an after-tax gain of $0.9 million. This was offset in part by the net loss we recognized
related to the Gill Ranch investment of $0.3 million.
Subsidiaries
Financial Corporation
Operating results in 2007 were net income of $1.2 million, compared to $0.2 million in 2006
and $0.3 million in 2005. The increase is primarily due to the gain from the sale of Financial
Corporation’s limited partnership interests in two wind power electric generation projects in California
in October 2007.
Gill Ranch
In September 2007, we announced a joint project with PG&E to develop a new underground
natural gas storage facility at Gill Ranch near Fresno, California. We formed Gill Ranch as a
subsidiary of NW Natural. See “Strategic Opportunities—Gas Storage Development,” above.
Operating Expenses
Operations and Maintenance
Operations and maintenance expenses increased by $5.9 million in 2007, or 5 percent,
compared to 2006 which in part reflects certain strategic initiatives which increased operations and
maintenance expense. These initiatives included additional training expenses ($1.2 million),
promotional and safety campaigns ($1.2 million) and maintenance projects ($1.9 million). Absent these
strategic initiatives, operations and maintenance would have increased 1 percent. Operations and
maintenance expense increased $1.3 million in 2006, or 1 percent, compared to 2005. The following
summarizes the major factors that contributed to changes in operations and maintenance expense:
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;
47
•
•
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.
2006 compared to 2005:
•
•
•
a $2.0 million increase in payroll expense, primarily due to bonuses related to improved
results on annual and long-term incentive plan performance goals;
a $1.1 million increase in severance expenses related to the 2006 severance incentive plan;
and
a $0.8 million increase in stock option expense due to the required adoption of SFAS
No. 123R related to stock-based compensation expense.
Partially offsetting the above increases were:
•
•
a $1.2 million decrease in system damages and damage claims written-off; and
a $2.3 million reduction in charges related to a settlement with a group of industrial
customers in 2005.
General Taxes
General taxes, which are principally comprised of property and payroll taxes, increased $0.9
million, or 4 percent, in 2007 compared to 2006, and increased $1.2 million, or 5 percent, in 2006
compared to 2005. The major factors that contributed to changes in general taxes are:
2007 compared to 2006:
•
•
•
a $0.4 million increase in property taxes related to a 3 percent increase in net utility plant;
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.
2006 compared to 2005:
•
•
•
a $0.7 million increase in property taxes;
a $0.5 million increase in regulatory fees based on higher revenue; and
a $0.1 million decrease in payroll taxes.
48
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
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
2007
2006
2005
$2,013,191
38,970
$1,925,837
37,661
$1,839,206
36,238
2,052,161
1,963,498
1,875,444
56,444
10,705
67,149
36,952
5,700
42,652
36,920
3,916
40,836
$2,119,310
$2,006,150
$1,916,280
$
$
67,410
933
68,343
$
$
63,552
883
64,435
$
$
60,935
710
61,645
3.4%
2.1%
3.4%
2.5%
3.4%
2.6%
Total depreciation and amortization expense increased by $3.9 million, or 6 percent, in 2007 and by
$2.8 million, or 5 percent, in 2006. 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). In 2006, we completed a
depreciation study on all company plant and property, which generally indicates that depreciation rates
overall would be reduced if we maintain the existing average service life depreciation method. We applied
for the adoption of new depreciation rates using the average service life method. However, if the OPUC or
WUTC were to require us to adopt a different depreciation method such as the equal life group method,
then depreciation rates could increase. Utility depreciation rates and methods are subject to review and
approval by the OPUC and WUTC, and new rates will not be placed into service until depreciation rate
proceedings are approved. We submitted the updated depreciation study for regulatory approval in 2007
and will implement the new rates upon approval. We do not anticipate that adoption of these new rates will
have a material impact on our financial condition or results of operations.
49
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
Other non-operating expenses
Net interest on deferred regulatory accounts
Gain on sale of equity investments
Earnings from equity investments of Financial Corporation
Total other income
2007
$ 1,939
537
(2,789)
84
1,544
130
2006
$2,609
363
(852)
(177)
-
191
2005
$ 1,856
403
(1,393)
282
-
57
$ 1,445
$2,134
$ 1,205
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 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 on 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.
Other income and expense–net improved by $0.9 million in 2006 over 2005. The increase was
primarily due to higher gains of $0.8 million from company-owned life insurance, reflecting higher
policy benefits realized during 2006, and a net decrease of $0.5 million in other non-operating
expenses, reflecting cost reduction initiatives. These positive changes were partially offset by a $0.5
million increase in net interest charges on deferred regulatory accounts, reflecting higher net credit
balances outstanding in these accounts.
Interest Charges—Net of Amounts Capitalized
Interest charges—net of amounts capitalized in 2007 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
in March 2007 and $9.5 million in May 2007. In 2006, interest charges—net of amounts capitalized
was $2.0 million, or 5 percent, higher than in 2005, reflecting higher interest rates on short-term debt
balances and slightly higher average balances of long-term debt outstanding during the period due to
the issuance of $50 million in June 2005 and $25 million in December 2006. The increase in an
allowance for funds used during construction (AFUDC) in 2006 reflects higher construction work in
progress balances. The average interest crediting rate for AFUDC, comprised of short-term and long-
term borrowing rates, as appropriate, was 5.4 percent in 2007, 4.7 percent in 2006 and 3.1 percent in
2005.
Income Tax Expense
The increase in income tax expense of $7.8 million or 22% in 2007, compared to 2006 was
primarily due to higher consolidated earnings and a slightly higher effective tax rate of 37.2% in 2007
compared to 36.4% in 2006. The increase in our effective tax rate was primarily a result of a lower
non-taxable gain on company-owned life insurance. We expect our effective tax rate in 2008 to remain
consistent with our 2007 rate. Income tax expense increased by $3.5 million in 2006, as compared to
total income tax expense of $32.7 million in 2005, and the effective tax rate increased 0.4 percent from
50
an effective tax rate of 36.0 percent in 2005. For more information on our income taxes, including a
reconciliation between the statutory federal income tax rate and the effective rate, see Note 1.
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
3, 5 and 6). 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
2007
2006
47.4% 48.1%
40.8% 41.5%
11.8% 10.4%
100.0% 100.0%
Achieving the target capital structure and maintaining sufficient liquidity are necessary to
maintain attractive credit ratings and have access to capital markets at reasonable costs.
Liquidity and Capital Resources
At December 31, 2007, we had $6.1 million in cash and cash equivalents compared to $5.8
million at December 31, 2006. Short-term liquidity is provided by cash from operations and from the
sale of commercial paper notes, which are supported by committed lines of credit. We have available a
committed bank facility totaling $250 million through May 31, 2012 (see “Credit Agreement,” below,
and Note 6). Short-term debt balances typically are reduced toward the end of the winter heating
season as a significant amount of our current assets, primarily accounts receivable and gas inventories,
are converted into cash.
Capital expenditures primarily relate to utility construction resulting from customer growth and
system improvements (see “Cash Flows—Investing Activities,” below). Certain contractual
commitments under capital leases, operating leases, gas supply purchase contracts and other contracts
require an adequate source of funding. These capital and contractual expenditures 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.
To provide long-term financing, we periodically issue and sell secured or unsecured debt,
preferred stock or common stock. In June 2005 and December 2006, we issued $50 million and $25
million of secured medium-term notes, respectively. At December 31, 2007, we had $85 million
available for future issuance of debt or equity securities under a universal shelf registration, which was
approved by the OPUC (see “Financing Activities,” below). On January 8, 2008, we filed a new
universal shelf registration for an unspecified amount of securities to replace the existing universal
shelf registration. Under new rules, NW Natural may designate the amount of securities to be
registered at the time of issuance.
51
Neither our Mortgage and Deed of Trust nor the Indenture under which other long-term debt
may be issued contain credit rating triggers or stock price provisions that require the acceleration of
debt repayment. Also, there are no rating triggers or stock price provisions contained in contracts or
other agreements with third parties, except for agreements with certain counterparties under our
Financial Derivatives Policy, which may require the affected party to provide substitute collateral such
as cash, guaranty or letters of credit if credit ratings are lowered to non-investment grade, or in some
cases if the mark-to-market value exceeds a certain threshold.
Based on the availability of short-term credit facilities and our expectation of being able to
issue long-term debt and equity securities, we believe there is sufficient liquidity to satisfy 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 first was
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
stock are within the sole discretion of our Board of Directors. It is the intention of the Board of
Directors to continue to pay cash dividends on common stock on a quarterly basis. However, the
declarations and amounts 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, 2007 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,
2008
$143,100
5,000
33,632
$
2009
-
-
33,417
$
2010
-
35,000
33,406
$
2011
-
10,000
30,858
2012
Thereafter
Total
$
-
40,000
28,536
$
-
427,000
313,056
$ 143,100
517,000
472,905
16,603
532
4,257
302,709
82,348
17,345
393
4,184
118,936
63,526
18,510
255
4,177
53,253
61,090
19,063
26
4,140
24,106
64,989
19,857
-
4,265
24,106
49,977
110,959
-
32,003
44,193
131,501
202,337
1,206
53,026
567,303
453,431
27,683
1,421
14
-
-
-
29,118
Total
$615,864
$239,222
$205,705
$153,182
$166,741
$1,058,712
$2,439,426
(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.
52
(2)
All gas purchase contracts use price formulas tied to monthly index prices. Commitment
amounts are based on index prices at December 31, 2007.
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 certain long-term debt have put options that, if exercised, would require repurchases
of up to $20 million principal amount in each of 2008 and 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
the long-term debt issues with put options ranges between 6.65 percent and 7.05 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
assignment of their firm gas supply 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.
In March 2004, our employees who are members of the Office and Professional Employees
International Union, Local No. 11, approved a labor agreement (Joint Accord) covering wages,
benefits and working conditions. This contract will expire on May 31, 2009.
Commercial Paper
Our primary source of short-term funds is from the sale of commercial paper notes. In addition
to issuing commercial paper to meet seasonal working capital requirements, including the financing of
gas inventories and accounts receivable, short-term debt may be used to temporarily fund capital
requirements. Commercial paper is periodically refinanced through the sale of long-term debt or equity
securities. Our commercial paper program is supported by committed lines of credit (see “Credit
Agreement,” below). We had $143.1 million in commercial paper notes outstanding at December 31,
2007, compared to $100.1 million at December 31, 2006.
Credit Agreement
In May 2007, we entered into a credit agreement for unsecured revolving loans totaling $250
million with a syndication of lenders, replacing the prior $200 million bilateral credit agreements
which were terminated. The new credit agreement is available and committed for a term of five years
expiring on May 31, 2012, which may be extended for additional one-year periods thereafter subject to
lender approval. The credit agreement allows us to request increases in the total commitment amount,
up to a maximum amount of $400 million. The credit agreement also permits the issuance of letters of
credit in an aggregate amount up to the applicable total borrowing commitment. The credit agreement
continues to be used primarily as back-up credit support for the notes payable issued under our
commercial paper program. Commercial paper borrowing provides the liquidity to meet our working
capital and interim financing requirements. Under the terms of the credit agreement, we pay upfront
fees, annual commitment fees and administrative agent fees, but we are not required to maintain
compensating bank balances. The interest rates on outstanding loans, if any, under the credit agreement
are based on our long-term unsecured debt ratings and on then-current market interest rates. All
53
principal and unpaid interest under the credit agreement is due and payable on May 31, 2012, subject
to extensions if any. There were no outstanding balances on this credit agreement at December 31,
2007 or on prior credit agreements at December 31, 2006.
The credit agreement requires that we maintain credit ratings with Standard & Poor’s (S&P)
and Moody’s Investors Service, Inc. (Moody’s) and notify the lenders of any change in our senior
unsecured debt ratings 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.
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, 2007. Our previous credit agreements required
us to maintain an indebtedness to total capitalization ratio of 65 percent or less, which we were in
compliance with at December 31, 2006.
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+
Stable
P-1
A2
A3
Positive
In July 2007, Moody’s revised our ratings outlook from “Stable” to “Positive.” Both of the
rating agencies have assigned us an investment grade rating. These credit ratings and ratings outlook
are dependent upon a number of factors, both qualitative and quantitative, and are subject to change at
any time. The disclosure of these credit ratings is not a recommendation to buy, sell or hold our
securities. Each rating should be evaluated independently of any other rating.
Redemptions of Long-Term Debt
We redeemed long-term debt during 2007, 2006 and 2005 as follows:
Thousands
Medium-Term Notes
6.34% Series B due 2005
6.38% Series B due 2005
6.45% Series B due 2005
6.05% Series B due 2006
6.31% Series B due 2007
6.80% Series B due 2007
Convertible Debentures
7.25% Series due 2012
Redeemed
in 2007
Redeemed
in 2006
Redeemed
in 2005
$
-
-
-
-
20,000
9,500
$
-
-
-
8,000
-
-
$5,000
5,000
5,000
-
-
-
-
-
528
54
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 2007, cash flow from net income and operating activity adjustments, excluding working capital
changes, increased by $23.0 million. Working capital changes in 2007 increased cash flow by $12.1
million.
In 2006, our cash flow from net income and operating activity adjustments, excluding working
capital changes, increased by $44.6 million, primarily due to a $31.0 million decrease in cash
contributions to our qualified defined benefit pension plans and a $18.2 million increase in cash
collections from deferred gas costs and improved operating results, partially offset by a decrease in
deferred income tax benefits reflecting the expiration of higher tax benefits realized in 2004 from
accelerated bonus depreciation. Working capital changes in 2006 increased cash flow by $24.9 million.
The overall change in cash flow from operating activities in 2007 compared to 2006 was an
increase of $35.1 million. The overall change in cash flow from operations in 2006 was an increase of
$69.5 million compared to 2005. The significant factors contributing to the cash flow changes between
years are as follows:
2007 compared to 2006:
•
•
•
•
•
•
•
•
•
an increase in net income added $11.1 million to cash flow;
an increase in cash of $11.2 million related to a smaller reduction in 2007 in deferred
income taxes compared to 2006;
the increase in regulatory liabilities in 2007 related to deferred gas costs increased cash flow
by $17.9 million, reflecting deferral activity between the two years with respect to
purchased gas cost savings and off-system gas sales under our PGA tariff;
a decrease in cash flow of $17.5 million due to change in deferred regulatory and other
costs;
an increase of $25.8 million due to a decrease in 2007 in accounts receivable and accrued
unbilled revenue at year end compared to an increase in 2006;
a decrease of $13.4 million in 2007 compared to 2006 resulting from income tax refunds
received during 2006;
an increase in accounts payable in 2007 compared to a decrease in 2006, increased cash
$27.5 million;
a decrease of $9.8 million in 2007 due to an increase in gas inventory in 2007 compared to a
decrease in 2006; and
a decrease of $16.6 million from a decrease in accrued taxes due to higher cash payments in
2007.
2006 compared to 2005:
•
•
an increase in net income added $5.3 million to cash flow;
a decrease in cash of $26.0 million related to a deferred income tax benefit in 2006
compared to a deferred income tax expense in 2005;
55
•
•
•
•
•
•
•
•
the change to regulatory liabilities in 2006 from regulatory receivables in 2005 related to
deferred gas costs increased cash flow by $18.2 million, reflecting deferral activity between
the two years with respect to purchased gas cost savings and off-system gas sales under our
PGA tariff;
cash increased by $31.0 million in 2006 compared to 2005 due to the 2005 cash
contributions to our qualified defined benefit pension plans;
an increase in cash in 2006 of $36.5 million due to a decrease in accounts receivable and
accrued unbilled revenue related to warmer weather around year end;
an increase of $27.7 million in cash resulting primarily from a decrease in gas inventory
costs in 2006 compared to 2005;
a decrease in income taxes receivable contributed $10.5 million to cash in 2006;
a reduction in accounts payable decreased cash $54.5 million in 2006 primarily due to lower
gas prices around year end;
a reduction in prepayments increased cash $6.4 million in 2006; and
an increase in deferred regulatory liabilities increased cash by $11.3 million in 2006.
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 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 $29.9 million in 2007, compared to $1.8 million in 2006, primarily related to
investments in Mist gas storage, Gill Ranch and Palomar Pipeline.
Cash requirements for investing activities in 2006 totaled $90.6 million, down slightly from
$92.0 million in 2005. Cash requirements for the acquisition and construction of utility plant totaled
$95.3 million, up from $89.3 million in 2005. The increase in cash requirements for utility construction
in 2006 primarily reflected $12.5 million of capital expenditures in 2006 for an automated meter
reading system, which was completed in 2007.
Investments in our pipeline integrity management program were $11.5 million in 2007,
compared to $11.0 million in 2006 and $6.1 million in 2005. These costs are estimated at
approximately $50 million to $100 million over a 10-year period through 2012. The costs are
accumulated over each 12 months ending September 30, and the capitalized costs, subject to audit, are
recovered through the annual PGA based on adjustments to rate base each year. The approved
regulatory accounting and rate treatment for these costs extends through September 30, 2008, and may
be reviewed for potential extension after that date.
During the five-year period 2008 through 2012, utility construction expenditures are estimated
at between $500 and $600 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.
56
Our utility and non-utility capital expenditures for 2008 are estimated to total between $90
million and $100 million. This estimate does not include costs of the potential Palomar Pipeline or Gill
Ranch projects, or other investments that may be driven by our business process redesign (see
“Strategic Opportunities,” above). In December 2003, the U.S. Department of Transportation’s Office
of Pipeline Safety (now the Pipeline Hazardous Materials Safety Administration) issued a rule that
specifies the detailed requirements for transmission pipeline integrity management plans as mandated
by the Pipeline Safety Act. See Part I., Item 1., “Pipeline Safety.” We continued to achieve our
milestones, completing the required inspection of the top 50 percent highest risk transmission pipelines
in 2007. We are currently on track to meet the next milestone to complete the inspection of all
transmission pipelines in HCAs by December 2012.
Financing Activities
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.
Cash used in financing activities in 2006 totaled $59.4 million, as compared to cash provided
by financing in 2005 of $14.8 million. Factors contributing to the $74.2 million net change were the net
change in short-term debt of $50.8 million, $25.0 million less of long-term debt issued during 2006 and
$3.6 million less equity financing in 2006, partially offset by $7.5 million less redemptions of long-
term debt in 2006 compared to 2005.
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 during the
second half of 2008 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.
In December 2006, we sold $25 million of 5.15% Series B, secured MTNs due 2016 and used
the proceeds to reduce short-term indebtedness and to fund utility construction.
In 2005, we sold $40 million of 4.70% Series B, secured MTNs due 2015 and $10 million of
5.25% Series B, secured MTNs due 2035, and used the proceeds to redeem long-term debt, to reduce
short-term indebtedness and to make investments in utility plant.
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 increased in 2007 to
2.8 million shares and $100 million and extended through May 2008. The purchases are made in the
open market or through privately negotiated transactions. Repurchases pursuant to the program in 2007
totaled 963,428 shares or $44.2 million; in 2006 totaled 395,500 shares or $16.0 million; and in 2005
totaled 410,200 shares, or $14.9 million. Since the program’s inception, we have repurchased an
aggregate 2,124,528 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 2007, we produced free cash flow of $27.5 million, compared to free cash flow of $19.7
million in 2006. In 2005 we had negative free cash flow of $49.3 million. Free cash flow is the amount
57
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)
2007
2006
2005
Cash provided by operating activities
Cash used in investing activities
Cash dividend payments on common stock
Free cash flow
$ 183,640
(117,479)
(38,613)
$148,566
(90,567)
(38,298)
$ 79,066
(92,008)
(36,376)
$ 27,548
$ 19,701
$(49,318)
The free cash flow information presented above is not intended to be a substitute for, nor is it
meant to be a better measure of, cash flow results prepared in accordance with GAAP. In addition, the
non-GAAP measure we provide may be calculated differently by other companies that present a
similar non-GAAP financial measure for free cash flow.
Pension Cost and Funding Status of Qualified Retirement Plans
We make contributions to our qualified defined benefit pension plans based on actuarial
assumptions and estimates, tax regulations and funding requirements under federal law. Generally, it is
our policy to contribute at least the minimum amount required by Internal Revenue Code regulations
and the Employee Retirement Income Security Act of 1974. It is also our intent to contribute additional
amounts sufficient on a sound actuarial basis to maintain funding targets and provide for the payment
of future benefits under the plans. Our qualified defined pension plans are currently funded at nearly
100 percent of the projected benefit obligation at December 31, 2007. For more information see
Note 7.
Ratios of Earnings to Fixed Charges
For the years ended December 31, 2007, 2006 and 2005, our ratios of earnings to fixed charges,
computed using the Securities and Exchange Commission method, were 3.92, 3.40 and 3.32,
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,
“Accounting for Contingencies,” (see “Application of Critical Accounting Policies and Estimates—
Contingencies,” above). At December 31, 2007, a cumulative $63.1 million in environmental costs was
recorded as a regulatory asset, consisting of $24.8 million of costs paid to-date, $35.1 million for
additional environmental accruals for costs expected to be paid in the future and accrued regulatory
interest of $3.2 million. If it is determined that both the insurance recovery and future customer rate
recovery of such costs is 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.
58
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, weather risk
and interest rate 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. Historically, we have taken physical delivery of at least the minimum
quantities specified in our natural gas supply contracts. These contracts are primarily index-based and
subject to annual re-pricing, a process that is intended to reflect anticipated market price trends during
the next year. Our PGA mechanisms in Oregon and Washington provide for the recovery from
customers of actual commodity costs, except that, for Oregon customers, we absorb 33 percent of the
higher cost of gas sold, or retain 33 percent of the lower cost, in either case as compared to the annual
PGA price built into customer rates.
Market risks related to potential adverse changes in commodity prices, interest rates, foreign
exchange rates or counterparty credit quality in relation to these financial and physical contracts are
discussed below.
Commodity Price Risk
Natural gas commodity prices are subject to fluctuations due to unpredictable factors including
weather, pipeline transportation congestion and other factors that affect short-term supply and demand.
Commodity-price swap, put and call option contracts (financial hedge contracts) are used to convert
certain natural gas supply contracts from floating prices to fixed prices. These financial hedge contracts
are generally included in our annual PGA filing, subject to a prudency review. At December 31, 2007
and 2006, notional amounts under these commodity swap, put and call option contracts totaled $287.6
million and $349.7 million, respectively. If the related financial derivative contracts had been settled on
December 31, 2007, a regulatory loss of $ 12.8 million would have been realized and deferred (see Note
11). The $12.8 million unrealized loss is an estimate of future cash flows that are expected to be paid as
follows: $10.5 million in 2008 and $2.3 million by October 31, 2009. The amount realized will change
based on market prices at the time contracts settle. We monitor the liquidity of our financial derivative
contracts and, based on the existing open interest in the contracts held, we believe existing contracts to be
liquid. All of our commodity financial hedge contracts settle by October 31, 2009.
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 hedge products, 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 is expected to occur in the latter part of 2008.
59
This swap is with an AA/Aaa 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).
Holders of certain long-term debt have put options that, if exercised, would accelerate
maturities by $20 million in each of 2008 and 2009 (see Note 5 and Note 11).
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 the purchases of natural gas from Canadian suppliers. At December 31, 2007 and
2006, notional amounts under foreign currency forward contracts totaled $6.1 million and $5.0 million,
respectively. As of December 31, 2007, no foreign currency forward contracts extended beyond
December 31, 2008. If all of the foreign currency forward contracts had been settled on December 31,
2007, a gain of $0.1 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. We evaluate and continuously 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, 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. Periodically we may have credit
exposure to financial derivative counterparties based on the estimated fair value of derivative contracts
outstanding. At December 31, 2007, in aggregate our financial derivative counterparties owed us $0.1
million while we owed our counterparties a net $14.1 million. Our Financial Derivatives Policy
requires counterparties to have a specified minimum credit rating at the time the derivative instrument
is entered into, and the policy sets forth limits on the contract amount and duration based on each
counterparty’s credit rating.
60
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 S&P or Moody’s rating, or a middle rating if the entity is split-rated more than
one rating level:
Thousands
AAA/Aaa
AA/Aa
A/A
BBB/Baa
Total
Financial Derivative Position by Credit Rating
Unrealized Fair Value Gain (Loss)
Dec. 31, 2007
Dec. 31, 2006
(309)
$
(13,941)
123
-
$(14,127)
-
$
(40,955)
-
-
$(40,955)
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 utilize various collateral management strategies to reduce
liquidity risk. The collateral provisions vary by counterparty but are not expected to result in any 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. During 2007, we neither called for nor posted collateral with any of
our derivative counterparties. Our derivative credit exposure is primarily with investment grade banks rated
AA-/Aa3 or higher. Contracts are diversified across counterparties to reduce credit and liquidity risk.
Credit exposure to customers. In the short term, market prices for natural gas have moderated
and resulted in some of our large industrial customers changing from sales services to transportation
service. Under sales service, the customer purchases both its gas commodity supply and transportation
service from us. Under transportation service, the customer purchases its commodity supplies from an
independent third party, while we provide the transportation service for delivery of that gas to the
customer’s premise. As a result of this migration from sales service to transportation service, our credit
exposure to large industrial customers is expected to moderate. We monitor and manage the credit
exposure of our industrial customers through credit policies and procedures, which are designed to
reduce credit risk. These policies and procedures include an ongoing review of credit risks, including
changes in the services provided to industrial customers as well as changes in market conditions and
customers’ credit quality. Changes in credit risk may require us to obtain additional assurance, such as
deposits, letters of credit, guarantees and prepayments, to reduce our credit exposure.
We also monitor and manage the credit exposure of our residential and commercial customers.
This credit risk is largely mitigated by the nature of our regulated business and reasonably short
collection terms, as well as by the consistent application of our credit policies and procedures.
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
61
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 “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, 2007, about 9 percent of our
Oregon customers had opted out. In addition to the Oregon customers opting out, our Washington
residential and commercial customers account for approximately 10 percent of our total customer base
and are not covered by weather normalization. The combination of Oregon and Washington customers
not covered by a weather normalization mechanism is less than 20 percent of all residential and
commercial customers.
Forward-Looking Statements
This report and other presentations made by us from time to time may contain forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended.
Forward-looking statements include statements concerning plans, objectives, goals, strategies, future
events or performance, and other statements that are other than statements of historical facts. Our
expectations, beliefs and projections are expressed in good faith and are believed to 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, 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 tax laws
and policies and 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;
application of the OPUC 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, pandemic events and other natural phenomena, including earthquakes
•
or other geohazard events;
unanticipated population growth or decline and changes in market demand caused by
changes in demographic or customer consumption patterns;
competition for retail and wholesale customers;
•
• market conditions and pricing of natural gas relative to other energy sources;
•
•
•
the creditworthiness of customers, suppliers and financial derivative counterparties;
our dependence on a single pipeline transportation provider for natural gas supply;
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 proposed natural gas pipeline project with GTN and the proposed Gill Ranch
storage facility;
unanticipated changes that may affect our liquidity or access to capital markets;
•
•
62
•
•
•
•
•
•
•
•
•
our ability to maintain effective internal controls over financial reporting in compliance
with Section 404 of the Sarbanes-Oxley Act of 2002;
unanticipated changes in interest or foreign currency exchange rates or in rates of inflation;
economic factors that could cause a severe downturn in certain key industries, thus affecting
demand for natural gas;
unanticipated changes in operating expenses and capital expenditures;
changes in estimates of potential liabilities relating to environmental contingencies;
unanticipated changes in future liabilities relating to employee benefit plans, including
changes in key assumptions;
capital market conditions, including their effect on financing costs, the fair value of pension
assets and on pension and other postretirement benefit costs;
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
legal and administrative proceedings and settlements.
All subsequent forward-looking statements, whether written or oral and whether made by or on
behalf of NW Natural, also are expressly qualified by these cautionary statements. Any forward-
looking statement speaks only as of the date on which such statement is made, and 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.
63
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, 2007,
2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Consolidated Balance Sheets at December 31, 2007 and 2006 . . . . . . . . . . . . . . . . . . . . . .
Page
65
66
68
69
Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the
Years Ended December 31, 2007, 2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
71
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007,
2006 and 2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
72
73
Quarterly Financial Information (unaudited) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
107
Supplementary Data for the Years Ended December 31, 2007, 2006 and 2005:
Financial Statement Schedule
Schedule II—Valuation and Qualifying Accounts and Reserves . . . . . . . . . . . . . . . . . . . .
108
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.
64
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 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, 2007. 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, 2007.
The effectiveness of internal control over financial reporting as of December 31, 2007 has been
audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated
in their report which appears in this annual report.
/s/ Mark S. Dodson
Mark S. Dodson
Chief Executive Officer
/s/ David H. Anderson
David H. Anderson
Senior Vice President and Chief Financial Officer
February 29, 2008
65
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, 2007 and 2006, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2007 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, 2007, 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 the 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 share based compensation in 2006. 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 the board of directors of the company; and
66
(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 29, 2008
67
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
Thousands, except per share amounts (year ended December 31)
2007
2006
2005
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
$1,033,193
639,150
25,001
$1,013,172
648,156
24,840
$910,486
563,860
21,633
369,042
340,176
324,993
120,488
25,288
68,343
214,119
154,923
1,445
37,811
118,557
44,060
114,560
24,419
64,435
113,216
23,185
61,645
203,414
198,046
136,762
126,947
2,134
39,247
99,649
36,234
1,205
37,283
90,869
32,720
$
74,497
$
63,415
$ 58,149
26,821
26,995
27,540
27,657
27,564
27,621
$
$
2.78
2.76
$
$
2.30
2.29
$
$
2.11
2.11
-------------------------------------------
See Notes to Consolidated Financial Statements.
68
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
2007
2006
$2,052,161
615,533
$1,963,498
574,093
1,436,628
1,389,405
67,149
7,904
59,245
42,652
6,916
35,736
1,495,873
1,425,141
6,107
69,442
78,004
(2,890)
17,598
2,903
71,079
8,865
122
25,569
5,767
82,070
87,548
(3,033)
31,509
5,109
68,576
9,552
-
21,695
276,799
308,793
175,938
324
54,070
11,179
241,511
164,771
1,448
47,985
8,718
222,922
$2,014,183
$1,956,856
----------------------------------------
See Notes to Consolidated Financial Statements.
69
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
2007
2006
$ 331,595
266,658
(3,502)
$ 371,127
230,774
(2,356)
594,751
512,000
599,545
517,000
1,106,751
1,116,545
143,100
5,000
119,731
13,259
2,827
61,326
14,829
29,794
389,866
206,340
213,764
41,619
3,758
52,085
517,566
-
100,100
29,500
113,579
21,230
2,924
11,919
38,772
21,455
339,479
210,084
202,982
52,690
11,031
24,045
500,832
-
$2,014,183
$1,956,856
-----------------------------------
See Notes to Consolidated Financial Statements.
70
NORTHWEST NATURAL GAS COMPANY
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND
COMPREHENSIVE INCOME
Thousands
Balance at Dec. 31, 2004
Net Income
Minimum pension liability
Common
Stock
and
Premium
Earnings
Invested in
the Business
Unearned
Stock
Compensation
Accumulated
Other
Comprehensive
Income (Loss)
Total
Shareholders’
Equity
Comprehensive
Income
$387,265
-
$183,932
58,149
$(862)
-
$(1,818)
-
$568,517
58,149
adjustment, net of $59 of tax
Restricted stock amortizations
Dividends paid on common stock
Tax benefits from employee stock
option plan
Issuance of common stock
Common stock repurchased
Convertible debentures
Common stock expense
-
-
-
-
-
(36,376)
220
7,266
(14,945)
3,999
-
-
-
-
-
(18)
-
212
-
-
-
-
-
-
(93)
-
-
-
-
-
-
-
Balance at Dec. 31, 2005
383,805
205,687
(650)
(1,911)
$58,149
(93)
$58,056
$63,415
(93)
212
(36,376)
220
7,266
(14,945)
3,999
(18)
586,931
63,415
(81)
(81)
298
(38,298)
317
555
-
2,773
(15,971)
(30)
599,545
74,497
$63,334
$74,497
(41)
(41)
-
(81)
(364)
-
-
-
-
-
-
-
-
(2,356)
-
(41)
(1,232)
(1,232)
(1,232)
127
127
-
-
-
-
-
-
127
285
(38,613)
536
2,094
2,180
(44,627)
$(3,502)
$594,751
$73,351
Net Income
Minimum pension liability
adjustment, net of $52 of tax
Recognition of 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
-
-
63,415
-
298
-
-
(38,298)
317
555
(650)
2,773
(15,971)
-
-
-
-
-
-
(30)
Balance at Dec. 31, 2006
371,127
230,774
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
-
-
-
74,497
-
-
-
285
-
-
-
(38,613)
536
2,094
2,180
(44,627)
-
-
-
-
Balance at Dec. 31, 2007
$331,595
$266,658
$
-
-
(364)
-
-
-
-
650
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-----------------------------------
See Notes to Consolidated Financial Statements.
71
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 earnings from equity investments
Deferred gas costs - net
Gain on sale of non-utility investments
Income from life insurance investments
Contributions to qualified defined benefit pension plans
Non-cash expenses related to qualified defined benefit pension plans
Deferred environmental expenditures
Deferred regulatory costs and other
Changes in working capital:
Accounts receivable and accrued unbilled revenue - net
Inventories of gas, materials and supplies
Income taxes receivable
Prepayments and other current assets
Accounts payable
Accrued interest and taxes
Other current and accrued liabilities
Cash provided by operating activities
Investing activities:
Investment in utility plant
Investment in non-utility property
Proceeds from sale of non-utility investments
Proceeds from life insurance
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 (used in) provided by 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
Supplemental disclosure of non-cash financing activities:
Conversions to common stock:
7-1/4 % Series of Convertible Debentures
2007
2006
2005
$ 74,497
$ 63,415
$ 58,149
68,343
(5,252)
(130)
38,665
(1,544)
(1,939)
-
4,387
(8,842)
(2,940)
22,029
(1,816)
(122)
(6,528)
5,841
(8,068)
7,059
183,640
(93,785)
(24,442)
2,628
881
(5,413)
2,652
(117,479)
2,180
(44,627)
-
(29,500)
43,000
(38,613)
1,739
(65,821)
340
5,767
6,107
$
$
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)
148,566
(95,307)
(1,773)
2,517
4,009
-
(13)
(90,567)
3,913
(15,971)
25,000
(8,000)
(26,600)
(38,298)
581
(59,375)
(1,376)
7,143
5,767
61,645
9,551
(57)
2,577
-
(1,873)
(31,000)
4,532
(9,132)
3,243
(40,262)
(19,684)
2,736
(3,439)
32,809
2,504
6,767
79,066
(89,259)
(6,842)
3,001
296
-
796
(92,008)
7,486
(14,945)
50,000
(15,528)
24,200
(36,376)
-
14,837
1,895
5,248
$ 7,143
$ 38,508
$ 56,215
$ 39,294
$ 31,270
$ 36,974
$ 28,479
$
-
$
-
$ 3,999
-----------------------------------
See Notes to Consolidated Financial Statements.
72
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, and other businesses which primarily consist of our wholly-
owned subsidiary businesses including NNG Financial Corporation (Financial Corporation) and
Gill Ranch Storage, LLC (Gill Ranch), and a joint venture in a natural gas transmission pipeline
(See Note 2).
In this report, the term “utility” is used to describe the regulated 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 (see Note 9).
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 business is the distribution of natural gas, which is regulated by the Oregon
Public Utility Commission (OPUC) and the Washington Utilities and Transportation
Commission (WUTC). Accounting records and practices of the regulated business conform to
the requirements and uniform system of accounts prescribed by these regulatory authorities in
accordance with SFAS No. 71. The utility business segment is authorized by the OPUC and the
WUTC 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 in general rate case or other deferral
proceedings, for example, our purchased gas adjustment (PGA) mechanism, to provide for
recovery of revenues or expenses from, or refunds to, utility customers in future periods,
including a return or a carrying charge.
73
At December 31, 2007 and 2006, the amounts deferred as regulatory assets and liabilities were
as follows:
Thousands
Regulatory assets:
Unrealized loss on non-trading derivatives1
Income tax asset
Pension and other postretirement benefit obligations2
Environmental costs - paid3
Environmental costs - accrued but not yet paid3
Other4
Total regulatory assets
Regulatory liabilities:
Gas costs payable5
Unrealized gain on non-trading derivatives1
Accrued asset removal costs
Other4
Total regulatory liabilities
Current
Non-Current
2007
2006
2007
2006
$14,788
-
1,912
-
-
898
$30,798
-
-
-
-
711
$
3,758
68,649
27,152
27,956
35,098
13,325
$
9,584
67,141
54,425
19,113
8,760
5,748
$17,598 $31,509
$175,938
$164,771
$46,153
2,903
-
12,270
$
737
-
-
11,182
$
6,290
324
204,886
2,264
$ 13,041
-
187,422
2,519
$61,326
$11,919
$213,764
$202,982
1
2
3
4
5
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 PGA mechanism.
Qualified pension plan and other postretirement costs 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 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 approved regulatory mechanisms.
The accounts being amortized typically earn a rate of return or carrying charge.
A majority of gas costs deferred 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, 2007 and 2006 are 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
Accounting for Uncertainty in Income Taxes. On January 1, 2007, we adopted Financial
Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), “Accounting for
Uncertainty in Income Taxes, an Interpretation of FASB Statement No. 109,” which provides
guidance for the recognition and measurement of a tax position taken or expected to be taken in
74
a tax return. As a result of the implementation of FIN 48, we recognized no change in our
recorded assets or liabilities for unrecognized income tax benefits. Based on our analysis of all
material tax positions taken, management believes the technical merits of these positions are
justified and expects that the full amount of the deductions taken and associated tax benefits
will be allowed.
FIN 48 requires the evaluation of a tax position as a two-step process. We must determine
whether it is more likely than not that a tax position will be sustained upon examination,
including the resolution of any related appeals or litigation processes, based on the technical
merits of the position. If the tax position meets the “more likely than not” recognition threshold,
then the tax benefit is measured and recorded at the largest amount that is greater than 50
percent likely of being realized upon effective settlement. The re-assessment of our tax
positions in accordance with FIN 48 did not result in any material change to our financial
condition, results of operations or cash flows.
FIN 48 prescribes that a company recognize the benefit of a tax position when it is effectively
settled. In May 2007, FASB Staff Position (FSP) FIN 48-1, “Definition of Settlement in FASB
Interpretation No. 48,” was issued to provide guidance on how to determine whether a tax
position is effectively settled for the purpose of recognizing previously unrecognized tax
benefits. The provisions of FSP FIN 48-1 did not change the conclusions reached during our
adoption of FIN 48.
We are subject to U.S. federal income taxes as well as several state and local income taxes. All
of our U.S. federal income tax matters audited by the Internal Revenue Service through the
2004 tax year were concluded during 2006 with no material adjustments. Also, substantially all
material state and local income tax matters are closed through the 2003 tax year. Based upon
our assessment in connection with the adoption of FIN 48, we do not believe there are any tax
positions taken that would not be fully sustained upon audit.
We have also assessed the classification of interest and penalties, if any, related to income tax
matters. Pursuant to the application of FIN 48, we have made an accounting policy election to
treat interest and penalties related to income tax matters, if any, as a component of income tax
expense rather than other operating expenses. See Note 8.
Accounting for Certain Hybrid Instruments. In February 2006, the FASB issued SFAS
No. 155, “Accounting for Certain Hybrid Instruments,” which amended SFAS No. 133,
“Accounting for Derivative Instruments and Hedging Activities,” and SFAS No. 140,
“Accounting for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities,” a replacement of FASB Statement No. 125. SFAS No. 155 allows financial
instruments that have embedded derivatives to be accounted for as a whole if the holder elects
to account for the whole instrument on a fair value basis. SFAS No. 155 is effective for all
financial instruments acquired or issued after January 1, 2007. The adoption and
implementation of SFAS No. 155 did not have an impact on our financial condition, results of
operations or cash flows.
Recent Accounting Pronouncements
Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, “Fair Value
Measurements,” which provides a common definition for the measurement of fair value for use
75
in applying GAAP and in preparing financial statement disclosures. Most of SFAS No. 157 is
effective as of the beginning of the first annual period after November 15, 2007, or January 1,
2008. However, implementation of the fair value measurement of liabilities applicable to us has
been delayed until the beginning of the first annual period after November 15, 2008. This
pronouncement replaces the definition of price used to determine fair value as the “price that
would be received to sell an asset or paid to transfer a liability in an orderly transaction.” To
increase consistency and comparability, it also establishes a hierarchy of inputs used to
calculate fair value, ranging from level one (observable) to level three inputs (unobservable).
New disclosures under SFAS No. 157 will primarily consist of:
• A description of the fair value measurements at the reporting date;
• A description of the inputs for fair value calculations;
• A description of the level of each input within the fair value hierarchy, segregated by input
level;
• A tabular reconciliation for all level three inputs illustrating the total gains and losses,
purchases or sales, and transfers into or out of level three;
• A tabular detail of the gains and losses for the period; and,
• A description of the valuation techniques used to measure fair value and a discussion of
changes in valuation techniques, if any.
Adoption of SFAS No. 157 will require us to identify the inputs for our fair value calculations
according to the fair value hierarchy, increase coordination with our external service providers
and provide more detailed disclosure. Based on our preliminary assessment, the adoption of
SFAS No. 157 is not expected to have a material effect on our financial condition, results of
operations or cash flow.
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 entities to choose to measure many financial instruments and certain other items at fair
value. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. Based on
our preliminary evaluation, the adoption and implementation of SFAS No. 159 is not expected
to have a material effect on our financial condition, results of operations or cash flow.
Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards. In
November 2006, the Emerging Issues Task Force (EITF) issued EITF 06-11, “Accounting for
Income Tax Benefits of Dividends on Share-Based Payment Awards,” which provides the
accounting requirements for the income tax benefit received on dividends that are 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.” EITF 06-11 is effective as of the
beginning of the first annual period starting after December 15, 2007.
EITF 06-11 will require us to adjust our current accounting policy on the recognition of the
income tax benefit received on dividends paid to employees. Based on our preliminary
evaluation, the adoption of EITF 06-11 is not expected to have a material impact on our
financial condition, results of operations or cash flow.
76
Plant and Property and Accrued Asset Removal Costs
Plant and property is stated at cost, including capitalized labor, materials and overhead (see
Note 9). The cost of constructing utility plant and gas storage assets includes an allowance for
funds used during construction (AFUDC), which represents the net financing cost during the
period the funds are used for construction purposes (see “Allowance for Funds Used During
Construction,” below).
Our provision for depreciation of utility property is computed under the straight-line, age-life
method in accordance with independent engineering studies and as approved by regulatory
authorities. The weighted average depreciation rate for utility plant in service was
approximately 3.4 percent for each of the years ended December 31, 2007, 2006 and 2005,
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 our most recent depreciation
study. 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 the 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. If
borrowings are less than the total costs of construction work in progress, then a composite rate
of interest on all debt, shown as a reduction to interest charges, and a return on equity funds,
shown as other income, is used to compute the AFUDC. While cash is not realized currently
from AFUDC, it is realized in future years through increased revenues from rate recovery
resulting from higher rate base and higher depreciation expense. Our composite AFUDC rates
were 5.4 percent in 2007, 4.7 percent in 2006 and 3.1 percent in 2005.
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, 2007 and 2006, book overdrafts of $4.9 million and $3.7 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 and weather. Accrued unbilled revenues are reversed the
77
following month when actual billings occur. Our accrued unbilled revenues at December 31,
2007 and 2006 were $78.0 million and $87.5 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 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 the tax year.
Non-utility revenues, derived primarily from gas storage services, are recognized upon delivery
of the service to customers. Revenues from optimization of excess storage and transportation
capacity include amounts that are recognized ratably over the life of the contract for guaranteed
amounts, or as earned for amounts above the guaranteed amount based on the terms of our
contract with the independent energy marketing company which optimizes the value of our
assets primarily through the use of commodity transactions and capacity release transactions.
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 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 past due accounts on payment plans, and historical trends of write-offs as a
percent of revenues. With respect to large individual customer receivables, a specific allowance
is established and added to the general allowance when amounts are identified as unlikely to be
partially or fully recovered. Inactive accounts are written-off against the allowance after they
are 120 days past due or when deemed to be uncollectible. Differences between our estimated
allowance and actual write-offs will occur based on changes in general economic conditions,
customer credit issues and the level of natural gas prices. Each quarter the allowance for the
uncollectible accounts is adjusted, if 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 full cost recovery in customer rates, subject to a prudency review, including any
differences between the actual purchase cost of gas injected into inventory and the embedded
cost of inventory in current rates. All gas that is injected into storage is priced into inventory at
the actual purchase cost based on a regulatory dispatch model for our gas 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 embedded in customer rates, which is established in our
annual PGA filing. Material and supplies inventories are stated at the lower of average cost or
net realizable value.
78
Derivatives
In accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities,” 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 PGA rate has
been set are subject to the PGA incentive sharing mechanism, whereby 67 percent of the
changes in fair value are deferred as regulatory assets or liabilities and the remaining 33 percent
is 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 (see Note
11).
Our Financial Derivatives Policy sets 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.
Revenue Taxes
We account for 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
79
purposes. We have recorded a deferred tax liability equivalent to $68.6 million and $67.1
million at December 31, 2007 and 2006, 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. Investment and energy tax credits generated by Financial
Corporation are amortized over a period of one to five years.
Other Income and Expense—Net
Other income and expense – net consists of interest income, gain on sale of investments,
investment income of Financial Corporation, investment expenses of our proposed pipeline
project and other miscellaneous income from merchandise sales, rents, leases and other items.
Thousands
Gains from company-owned life insurance
Interest income
Earnings from equity investments of Financial Corporation
Gain on sale from equity investments
Other non-operating expenses
Net interest on certain deferred regulatory accounts
Earnings Per Share
2007
2006
2005
$ 1,939
537
130
1,544
(2,789)
84
$2,609
363
191
-
(852)
(177)
$ 1,856
403
57
-
(1,393)
282
$ 1,445
$2,134 $ 1,205
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
Stock based compensation
Average common shares outstanding - diluted
Earnings per share of common stock - basic
Earnings per share of common stock - diluted
80
2007
2006
2005
$74,497
$63,415
$58,149
26,821
174
27,540
117
27,564
57
26,995
27,657
27,621
$
$
2.78
2.76
$
$
2.30
2.29
$
$
2.11
2.11
For the years ended December 31, 2007, 2006 and 2005, 442 shares,105,600 shares and 6,000
shares, respectively, represent the number of stock options which were excluded from the
calculation of diluted earnings per share because the effect was antidilutive.
Stock-Based Compensation
We periodically provide stock-based compensation to employees in the form of stock options
and other incentive awards. As required by SFAS No. 123R, “Share Based Compensation,” we
recognize the fair value of all share-based payments as compensation expense in the financial
statements. Prior to January 1, 2006, as permitted by SFAS No. 123, we applied APB Opinion
No. 25, “Accounting for Stock Issued to Employees,” to account for stock-based compensation.
Accordingly, prior to January 1, 2006, we did not recognize compensation expense for the fair
value of our stock option grants. We implemented SFAS 123R effective January1, 2006 by
applying the modified prospective transition method. The impact on net income of this new
standard, had it been adopted in 2005, is reflected in the pro forma amounts in Note 4.
2.
CONSOLIDATED SUBSIDIARY OPERATIONS AND SEGMENT INFORMATION:
At December 31, 2007, we had two direct wholly-owned subsidiaries, Financial Corporation
and Gill Ranch Storage, LLC.
Our core business segment is the local gas distribution segment, also referred to as the “utility,”
which involves the distribution and sale of natural gas. Another business segment, “gas storage,”
represents natural gas storage services provided to intrastate and interstate customers, and includes
asset optimization services under a contract with an independent energy marketing company. The
remaining business segment, “other,” primarily consists of wholly-owned subsidiaries, Financial
Corporation and Gill Ranch, as well as various other non-utility investments, including an
investment in a leveraged aircraft lease and our equity investment in a proposed natural gas pipeline
project with TransCanada Gas Transmission Northwest (GTN). See Note 9.
Gas Storage
The gas storage business segment is primarily made up of underground natural gas storage services
that we provide to large intra- and inter-state customers using our owned storage capacity at Mist
that has been developed in advance of core utility customers’ requirements. In Oregon, we retain 80
percent of the income before tax from these services and credit the remaining 20 percent to a
deferred regulatory account for sharing with core utility customers. For each of the years ended
December 31, 2007, 2006 and 2005, this business segment derived a majority of its revenues from
multi-year contracts with less than 10 customers. The largest of these customers is served under a
long-term contract.
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 the our assets primarily through the use of commodity transactions and transportation capacity
release transactions. In Oregon, we retain 80 percent of the pre-tax income 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 core utility rates. The remaining 20 percent and 67 percent, respectively, are
credited to a deferred regulatory account for distribution to core utility customers. We have a similar
sharing mechanism in Washington for revenue derived from storage and third party optimization.
81
Other
In October 2007, Financial Corporation sold its investments in two wind power electric
generating projects for $2.1 million, which resulted in an after-tax net gain on sale of
$0.9 million. In addition, in December 2007, one low-income housing project investment
reached the end of the contract period and our partnership interest was transferred pursuant to
the original terms of the agreement.
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. Our capacity on this pipeline is contracted to NW Natural’s
utility operations. Financial Corporation’s remaining assets totaled $1.4 million and $2.6
million at December 31, 2007 and 2006, respectively.
At December 31, 2006, we reclassified to current assets our net investment of $5.3 million in a
Boeing 737-300 airplane leased to Continental Airlines. The original lease term expired in
September 2007, and the aircraft lease was extended at the option of the lessee for 12 months.
We are currently in negotiations to sell the airplane and expect it to be sold during 2008.
Segment Information Summary
The following table presents summary financial information about the reportable segments for
2007, 2006 and 2005. Inter-segment transactions are insignificant.
Thousands
Utility
Gas Storage
Other
Total
2007
Net operating revenues
Depreciation and amortization
Income (loss) from operations
Income from financial investments
Net income
Total assets at Dec. 31, 2007
2006
Net operating revenues
Depreciation and amortization
Income from operations
Income from financial investments
Net income
Total assets at Dec. 31, 2006
2005
Net operating revenues
Depreciation and amortization
Income (loss) from operations
Income from financial investments
Net income
$16,999
933
14,953
-
8,742
59,427
$12,761
883
9,870
-
5,982
35,970
$ 9,609
710
8,158
-
4,557
$
168
-
(464)
1,674
817
13,912
$ 369,042
68,343
154,923
3,613
74,497
2,014,183
$
$
148
-
526
191
780
8,865
$ 340,176
64,435
136,762
2,800
63,415
1,956,856
136
-
(5)
57
833
$ 324,993
61,645
126,947
1,913
58,149
$ 351,875
67,410
140,434
1,939
64,938
1,940,844
$ 327,267
63,552
126,366
2,609
56,653
1,912,021
$ 315,248
60,935
118,794
1,856
52,759
82
3.
CAPITAL STOCK:
Common Stock
As of December 31, 2006 and 2007, we had 60,000,000 common shares authorized.
At December 31, 2007, we had reserved 223,033 shares of common stock for issuance under
the Employee Stock Purchase Plan, 666,537 shares under our Dividend Reinvestment and
Direct Stock Purchase Plan and 1,393,150 shares under our Restated Stock Option Plan (see
Note 4).
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, 2007
and 2006, our “common stock” and “premium on common stock” account balances are
reflected on the balance sheet as “common stock.”
Stock Repurchase Program
Our publicly announced stock repurchase program allows us to purchase up to 2.8 million
shares, or up to $100.0 million in total, of our common stock in the open market or through
privately negotiated transactions. We repurchased a total of 963,428, 395,500 and 410,200,
shares under this program in 2007, 2006, and 2005, respectively. In addition, during the first
half of 2007, we completed our voluntary oddlot share buyback program, which resulted in a
net repurchase of 10,188 shares.
Restated Stock Option Plan
There are 2,400,000 shares authorized for option grants under the Restated Stock Option Plan.
At December 31, 2007, options on 1,035,400 shares were available for grant and options on
357,750 shares were outstanding.
Convertible Debentures
In August 2005, we redeemed all of our outstanding Convertible Debentures, 7-1/4% Series
due 2012, at 100 percent of their principal amount plus accrued interest to the date of
redemption. During 2005, debentures with an aggregate principal amount of $4.0 million were
converted into shares of common stock on or prior to the redemption date at the rate of 50.25
shares for each $1,000 principal amount of debentures and $0.5 million of debentures were
redeemed.
83
Summary of Changes in Common Stock
The following table shows the changes in the number of shares of our common stock issued
and outstanding and the premium on common stock for the years 2007, 2006 and 2005:
Balance, Dec. 31, 2004
Sales to employees
Sales to stockholders
Exercise of stock options - net
Conversion of convertible debentures to common
Repurchase
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
4.
STOCK-BASED COMPENSATION:
Premium on
common
stock
(thousands)
$ 300,034
741
3,741
2,241
3,360
(13,646)
$ 296,471
-
285
(1,461)
(295,295)
$
-
n/a
n/a
n/a
-
Shares
27,546,720
30,896
113,925
97,068
200,887
(410,200)
27,579,296
31,397
68,548
(395,500)
-
27,283,741
21,373
75,850
(973,616)
26,407,348
$
We have the following stock-based compensation plans: the Long-Term Incentive Plan (LTIP);
the Restated Stock Option Plan (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 are purchased on the open
market.
At December 31, 2007, 299,721 shares of common stock were available for award under the
LTIP, assuming that outstanding performance based grants are awarded at the target level. The
LTIP stock awards are compensatory awards for which compensation expense is recognized
based on the market value of performance shares earned, or a pro rata amortization over the
vesting period for the outstanding restricted stock awards.
Performance-based Stock Awards. Since the LTIP’s inception in 2001 through
December 31, 2007, performance-based stock awards have been granted annually based on
three-year performance periods. At December 31, 2007, certain performance-based stock award
84
measures had been achieved for the 2005-07 award period. Accordingly, participants are
estimated to receive 66,666 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, 2006,
certain performance-based stock award measures had been achieved for the 2004-06 award
period and participants received 40,446 shares of common stock plus the applicable dividend
equivalent cash payment, resulting in $0.8 million in cash for taxes or deferral into the deferred
compensation plan. During 2007, we accrued and expensed $0.6 million related to the 2005-07
performance-based stock award, and on a cumulative basis we accrued a total $2.0 million
related to the 2005-07 performance period. In 2006, we accrued and expensed $0.9 million
related to the 2004-06 performance-based stock award, and on a cumulative basis we accrued a
total of $1.7 million related to the 2004-06 performance period.
At December 31, 2007, the aggregate number of performance-based shares granted and
outstanding at the threshold, target and maximum levels were as follows:
Year
Awarded
2006
2007
Performance
Period
2006-08
2007-09
Total
Performance Share Awards Outstanding
Threshold
7,536
7,980
15,516
Target
39,665
42,000
81,665
Maximum
79,330
84,000
163,330
The threshold level estimates future payout assuming the minimum award payable other than
no payout 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, 2007 and 2006 was $25.45 and $30.65,
respectively. The weighted-average per share grant date fair value of shares vested during the
year was $44.95 and granted during the year was $31.32. In 2007, under these LTIP grants we
accrued $2.7 million and expensed $2.3 million as compensation, while 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 5,167 restricted stock award
shares were vested at December 31, 2007. Compensation expense is recognized ratably over the
vesting period.
Restated Stock Option Plan. The Restated SOP authorizes an aggregate of 2,400,000 shares of
common stock for issuance as incentive or non-statutory stock options. These options 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 from the date of grant.
85
Option holders may exchange shares they have owned for at least six months, at the current
market price, to purchase shares at the option price. We use original issue shares upon exercise
of options under the plan. See Note 3.
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 six- to 12-month period. We use original issue shares upon
exercise of options under the plan. See Note 3.
In accordance with APB Opinion No. 25, no compensation expense was recognized for options
granted under the Restated SOP or shares issued under the ESPP during 2005 or earlier years. If
compensation expense for awards under these two plans had been determined based on fair
value at the grant dates using the method prescribed by SFAS No. 123R, net income and
earnings per share would have been reduced to the pro forma amounts shown below:
Pro Forma Effect of Stock-Based Options and ESPP:
Thousands, except per share amounts
Net income as reported
Stock-based compensation expense included in reported net income - net of related
Add:
tax effects
Deduct: Pro forma stock-based compensation expense determined under the fair value
based method - net of related tax effects
Pro forma earnings applicable to common stock
Basic earnings per share
As reported
Pro forma
Diluted earnings per share
As reported
Pro forma
2005
$58,149
613
(940)
$57,822
$
$
$
$
2.11
2.10
2.11
2.09
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:
2007
2006
2005
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
4.7%
6.2
4.5%
6.2
4.2%
7.0
17.2% 22.8% 24.6%
3.6%
4.0%
3.2%
n/a
3%
4%
$7.85
$6.29
$7.66
$27.87
$26.00
$33.38
The simplified formula for “plain vanilla” options was utilized 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
86
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.
Information regarding the Restated SOP’s activity for the three years ended December 31, 2007
is summarized as follows:
Price per Share
Weighted -
Average
Exercise Price
Intrinsic
Value
(In millions)
Balance outstanding, Dec. 31, 2004
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2005
Granted
Exercised
Forfeited
Balance outstanding, Dec. 31, 2006
Granted
Exercised
Forfeited
Option
Shares
Range
431,470
9,000
$20.25 - 32.02
34.95 - 38.30
(121,170) 20.25 - 31.34
(10,800) 27.60 - 31.34
20.25 - 38.30
308,500
97,800
34.29
(69,300) 20.25 - 31.34
(3,000) 31.34 - 34.29
20.25 - 38.30
44.48
334,000
100,600
(75,850) 20.25 - 34.95
(1,000)
44.48
$28.38
37.18
26.59
30.79
29.26
34.29
27.15
32.52
31.14
44.48
28.73
44.48
Balance outstanding, Dec. 31, 2007
357,750 $20.25 - 44.48
$35.36
Shares available for grant
Dec. 31, 2005
Shares available for grant
Dec. 31, 2006
Shares available for grant
Dec. 31, 2007
1,229,800
1,135,000
1,035,400
n/a
n/a
$1.2
n/a
n/a
n/a
0.8
n/a
n/a
n/a
1.4
n/a
$4.8
In the year ended December 31, 2007, cash of $2.7 million was received for option shares
exercised and a $0.5 million related tax benefit was realized. The total fair value of options that
vested was $0.2 million in 2007 and $0.4 million in both 2006 and 2005.
The following table summarizes additional information about stock options outstanding and
exercisable at December 31, 2007:
Outstanding
Exercisable
Weighted-
Average
Remaining
Life in Years
7.35
Stock
Options
357,750
Stock
Options
193,675
(In millions)
Aggregate
Intrinsic
Value
Weighted-
Average
Exercise
Price
Weighted-
Average
Remaining
Life in Years
$3.4
$31.15
6.2
Range of Exercise Prices
$20.25 - 44.48
87
In accordance with SFAS No. 123R, stock-based compensation expense is recognized within
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,
SOP and ESPP:
Thousands
Operations and maintenance expense
Stock-based compensation effect on income before taxes
Income taxes
Net stock-based compensation effect on net income
Amounts capitalized
2007
2006
$ 2,986
$2,304
2,986
(1,165)
2,304
(898)
$ 1,821
$1,406
$
479
$ 407
As of December 31, 2007, there was $0.6 million of unrecognized compensation cost related to
the unvested portion of outstanding stock option awards expected to be recognized over a
period extending through 2010.
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 our
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 latter 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. During 2006, 7,848 shares
vested under the plan and no forfeitures occurred. At December 31, 2007, 5,235 shares remain
unvested, all of which are scheduled to vest by December 31, 2008. The weighted-average
grant-date fair value of unvested shares at December 31, 2007 and 2006 was $30.60 and
$28.92, respectively.
Under a separate plan, prior to January 1, 2005 non-employee directors could elect to invest
their cash fees and retainers for board service in shares of common stock. Under a deferral plan
effective January 1, 2005, such fees and retainers are deferred to a cash account. Cash account
balances may be transferred to and invested in a stock account at the election of the director up
to four times per year.
88
5.
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 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.
The maturities on the long-term debt outstanding, for each of the 12-month periods through
December 31, 2012 amount to: $5 million in 2008; none in 2009; $35 million in 2010; $10
million in 2011; and $40 million in 2012. Holders of certain long-term debt have put options
that, if exercised, would accelerate the maturities by $20 million in both 2008 and 2009.
Thousands (December 31)
2007
2006
2005
Medium-Term Notes
First Mortgage Bonds:
6.05% Series B due 2006(1)
6.31 % Series B due 2007(2)
6.80 % Series B due 2007(3)
6.50% Series B due 2008
4.11% Series B due 2010
7.45% Series B due 2010
6.665% Series B due 2011
7.13% Series B due 2012
8.26% Series B due 2014
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
$
-
-
-
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
$
8,000
20,000
9,500
5,000
10,000
25,000
10,000
40,000
10,000
40,000
-
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
Less long-term debt due within one year
5,000
29,500
8,000
Total long-term debt
$512,000
$517,000
$521,500
517,000
546,500
529,500
(1) Redeemed at maturity in June 2006.
(2) Redeemed at maturity in March 2007.
(3) Redeemed at maturity in May 2007.
89
No long-term debt was issued during 2007. In 2006, we issued and sold $25 million of 5.15%
Series B secured Medium Term Notes (MTNs) due 2016. Proceeds from this sale were used, in
part, to repay short-term debt and fund our ongoing utility construction program.
In June 2005, we issued and sold $50 million of secured MTNs, consisting of $40 million of the
4.70% Series B secured MTNs due 2015 and $10 million of the 5.25% Series B secured MTNs
due 2035. Proceeds from these sales were used, in part, to redeem $15 million of maturing
MTNs in July 2005, and the balance was applied to our ongoing utility construction program
and the repayment of short-term debt.
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 a
committed credit facility (see below). At December 31, 2007 and 2006, the amounts and
average interest rates of commercial paper debt outstanding were $143.1 million and 4.4
percent and $100.1 million and 5.3 percent, respectively.
In May 2007, we entered into a credit agreement for unsecured revolving loans totaling $250
million, replacing the prior $200 million bilateral credit agreements which were terminated.
The new credit facility is available and committed for a term of five years expiring on May 31,
2012, which may be extended for additional one-year periods thereafter subject to lender
approval. The credit facility allows us to request increases in the total commitment amount, up
to a maximum amount of $400 million. The credit facility also permits the issuance of letters of
credit in an aggregate amount up to the applicable total borrowing commitment. The credit
facility continues to be used primarily as back-up credit support for the notes payable issued
under our commercial paper program. Commercial paper borrowing provides the liquidity to
meet our working capital and interim financing requirements. Under the terms of the credit
facility, we pay upfront fees, annual commitment fees and administrative agent fees, but we are
not required to maintain compensating bank balances. The interest rates on outstanding loans, if
any, under the credit agreement are based on our long-term unsecured debt ratings and on then-
current market interest rates. All principal and unpaid interest under the credit facility is due
and payable on May 31, 2012, subject to extensions if any. There were no outstanding balances
on this credit facility at December 31, 2007 or on prior credit facilities at December 31, 2006.
The credit agreement requires that we maintain credit ratings with Standard & Poor’s (S&P)
and Moody’s Investors Service, Inc. (Moody’s) and notify the lenders of any change in our
senior unsecured debt ratings by such rating agencies. A change in our debt ratings is not an
event of default, nor is the maintenance of a specific minimum level of debt rating a condition
of drawing upon the credit facility. However, interest rates on any loans outstanding under the
credit facility are tied to debt ratings, which would increase or decrease the cost of any loans
under the credit facility when ratings are changed.
The credit facility 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 to accelerate the maturity of all amounts
90
outstanding. We were in compliance with this covenant at December 31, 2007, with an
indebtedness to total capitalization ratio of 52.7 percent. Our previous credit agreements
required us to maintain an indebtedness to total capitalization ratio of 65 percent or less, which
we were in compliance with at December 31, 2006.
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 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 Retirement Plan for Non-Bargaining Unit Employees
and the Welfare Benefits Plan for Non-Bargaining Unit Employees were closed to anyone hired
or rehired after December 31, 2006. Instead, newly hired or rehired non-bargaining unit
employees will be 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, 2007, and a summary of the funded status and
amounts recognized in the consolidated balance sheets using measurement dates of
December 31, 2007, 2006 and 2005:
Thousands
Reconciliation of change in benefit obligation:
Obligation at January 1
Service cost
Interest cost
Expected benefits paid
Plan amendments
Change in assumptions
Net actuarial (gain) or loss
Obligation at December 31
Reconciliation of change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Benefits paid
Postretirement Benefits
Pension Benefits
2006
2007
2005
2007
Other Benefits
2006
2005
8,708
16,057
(15,924)
3,887
(23,916)
2,339
$269,410 $267,854 $222,948 $ 22,436 $ 20,398 $ 22,729
767
1,248
(1,173)
2,384
2,215
(7,772)
$260,561 $269,410 $267,854 $ 22,186 $ 22,436 $ 20,398
7,745
14,901
(13,183)
-
(9,208)
1,301
6,322
13,203
(12,866)
1,408
31,642
5,197
505
1,293
(1,299)
-
(645)
(104)
555
1,184
(1,015)
15
133
1,166
$236,518 $218,555 $186,787 $
30,088
1,058
(13,183)
19,658
1,166
(15,924)
12,558
32,076
(12,866)
- $
-
1,298
(1,298)
- $
-
1,015
(1,015)
-
-
1,173
(1,173)
Fair value of plan assets at December 31
$241,418 $236,518 $218,555 $
- $
- $
-
Funded status:
Funded status at December 31
Unrecognized transition obligation
Unrecognized prior service cost
Unrecognized net actuarial loss
$ (19,143) $ (32,892) $ (49,299) $(22,186) $(22,436) $(20,398)
2,880
2,243
988
-
6,492
69,766
-
8,212
20,995
-
5,512
45,862
2,058
1,866
1,514
2,469
2,063
2,288
Net amount recognized
$ 10,064 $ 18,482 $ 26,959 $(16,748) $(15,616) $(14,287)
91
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined
Benefit Pension and Other Postretirement Plans,” which required balance sheet recognition of
the overfunded or underfunded status of pension and other postretirement benefit plans. We
adopted SFAS No. 158 effective December 31, 2006. For pension plans, the liability is based
on the projected benefit obligation. 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 $1.9 million for the qualified plans, consisting of $1.4
million of prior service costs, transition obligations of $0.4 million, and negligible actuarial
gains, will be amortized from the regulatory asset account to net periodic benefit cost in 2008.
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 gains of $0.4 million and
negligible prior service costs for the non-qualified plans will be amortized from AOCI to net
periodic benefit cost.
Our qualified defined benefit pension plans had an aggregate projected benefit obligation of
$243.1 million, $255.5 million and $254.4 million at December 31, 2007, 2006 and 2005,
respectively, and the fair value of plan assets was $241.4 million, $236.5 million and $218.6
million, respectively. Changes in valuation assumptions impact our projected benefit
obligations. 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 projected benefit obligations at
December 31, 2006 decreased by $9.3 million, reflecting the increase in the discount rate
assumptions, and increased by $0.3 million, reflecting updates in retirement and withdrawal
rates for actual experience. 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 (Citigroup curve)
using high quality bonds (rated AA- or higher by Standard & Poor’s or Aa3 or higher by
Moody’s Investors Service). The Citigroup 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 Policy and Performance Objectives for the qualified pension plan assets held in
the Retirement Trust Fund were approved by the Company’s retirement committee, which is
composed of senior management employees. The policy sets forth the guidelines and objectives
92
governing the investment of plan assets. Plan assets are invested for total return with
appropriate consideration for liquidity and portfolio risk. All investments are expected to satisfy
the requirements of the rule of prudent investments as set forth under the Employee Retirement
Income Security Act of 1974. The approved asset classes are cash and short-term investments,
fixed income, common stock and convertible securities, absolute and real return strategies, real
estate and investments in our common stock. Plan assets may be invested in separately
managed accounts or in commingled or mutual funds. Re-balancing will take place periodically
as needed, or when significant cash flows occur, in order to maintain the allocation of assets
within the stated target ranges. Our expected long-term rate of return is based upon historical
index returns by asset class, adjusted by a factor based on our historical return experience and
active portfolio management by professional investment managers. The Retirement Trust Fund
is not currently invested in any NW Natural securities.
Our pension plan asset allocation at December 31, 2007 and 2006, 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,
2007
2006
18.1% 19.2%
13.1% 13.9%
24.9% 23.5%
13.3% 15.6%
8.9% 7.7%
16.3% 14.3%
5.4% 5.8%
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 $17.5
million, $13.9 million and $13.5 million at December 31, 2007, 2006 and 2005, 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 $22.2 million, $22.4 million and $20.4
million at December 31, 2007, 2006 and 2005, 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.
93
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,
2007, 2006 and 2005 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
2006
2007
2005
Other Postretirement
Benefits
2006
2007
2005
$
8,708 $
16,057
(18,490)
7,745 $
14,901
(17,611)
6,322 $
13,203
(14,449)
505 $
556 $
1,293
-
1,184
-
767
1,248
-
-
1,188
2,123
-
979
3,520
-
1,077
2,082
411
197
25
411
195
1
411
142
173
Net periodic benefit cost
$
9,586 $
9,534 $
8,235 $ 2,431 $ 2,347 $ 2,741
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
6.0%-6.05%
5.75%
4.0%-5.0% 4.0%-5.0% 4.0%-5.0%
8.25%
8.25%
8.25%
6.00% 5.91% 5.75% 6.00%
n/a
n/a
n/a
n/a
n/a
n/a
6.76%-6.87% 6.0%-6.05%
4.0%-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
The assumed annual increase in trend rates used in measuring other postretirement benefits as
of December 31, 2007 were 8 percent for medical and 11 percent for prescription drugs.
Medical costs were assumed to decrease gradually each year to a rate of 4.50 percent by 2013,
while prescription drug costs were assumed to decrease gradually each year to a rate of 4.50
percent by 2014.
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
$ 26
$ (23)
$277
$(250)
94
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, 2007 and 2006, and estimated
future payments:
Thousands
Employer Contributions by Plan Year
Pension Benefits
Other Benefits
2006
2007
2008 (estimated)
Benefit Payments
2005
2006
2007
Estimated Future Payments
2008
2009
2010
2011
2012
2013-2017
$
1,527
1,606
1,703
$ 12,866
13,183
15,924
$ 14,809
15,522
16,623
17,085
17,897
100,776
$ 1,015
1,298
1,794
$ 1,173
1,015
1,298
$ 1,794
1,823
1,887
1,978
1,960
10,183
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 $1.9 million in 2007, $1.8
million in 2006, and $1.7 million in 2005. 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 2007 and $0.5 million in both 2006 and 2005.
95
8.
INCOME TAXES:
A reconciliation between income taxes calculated at the statutory federal tax rate and the tax
provision 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
Federal income tax credits
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
Reversal of amounts provided in prior years
Total provision for income taxes
Federal statutory tax rate
Increase (decrease):
Current state income tax, net of federal tax benefit
Federal income tax credits
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
Reversal of amounts provided in prior years
Effective tax rate
The provision for income taxes consists of the following:
2007
$41,495
2006
$34,877
2005
$31,804
4,566
-
(881)
(704)
(679)
244
19
3,655
-
(994)
(704)
(913)
155
158
2,913
(210)
(956)
(704)
(650)
187
336
$44,060
$36,234
$32,720
35.0%
35.0%
35.0%
3.9%
0.0%
-0.7%
-0.6%
-0.6%
0.2%
0.0%
3.7%
0.0%
-1.0%
-0.7%
-0.9%
0.2%
0.1%
3.2%
-0.2%
-1.1%
-0.8%
-0.7%
0.2%
0.4%
37.2%
36.4%
36.0%
Thousands
Current tax expense
Deferred tax expense (benefit)
Deferred investment and energy tax credits
Total provision for income taxes
Total income taxes paid
2007
2006
2005
$ 48,850
(3,909)
(881)
$ 52,621
(15,393)
(994)
$ 23,034
10,642
(956)
$ 44,060
$ 36,234
$ 32,720
$56,215
$31,270
$28,479
96
The following table summarizes the total provision for income taxes for the regulated utility
and other non-regulated business segments for the three years ended December 31:
Thousands
Regulated utility:
Federal
Current
Deferred
Deferred investment and energy tax credits
State
Current
Deferred
Total charged to regulated utility
Non-regulated business segments:
Federal
Current
Deferred
Deferred investment and energy tax credits
State
Current
Deferred
2007
2006
2005
$36,805
(3,287)
(713)
$ 40,979
(12,472)
(756)
$17,848
8,691
(784)
32,805
27,751
25,755
6,782
(569)
6,213
7,490
(2,338)
5,152
1,649
2,855
4,504
39,018
32,903
30,259
4,281
61
(168)
4,174
982
(114)
868
3,806
(714)
(238)
2,854
3,581
(1,189)
(172)
2,220
346
131
477
(44)
285
241
Total charged to non-regulated business segments
5,042
3,331
2,461
Total provision for income taxes
$44,060
$ 36,234
$32,720
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 (assets)
Utility plant and equipment
Regulatory Adjustment for Income Taxes Paid
Utility other deferred tax differences
Non-regulated deferred tax differences
Deferred tax liabilities
Utility regulatory balances
Utility other deferred tax differences
Deferred tax assets
Deferred tax liabilities - net
Regulatory income tax assets
Change in employee post retirement benefit plan liability
Deferred income taxes
Deferred investment tax credits
Deferred income taxes and investment tax credits
97
2007
2006
$155,832
2,356
477
3,923
$150,648
-
-
3,893
162,588
154,541
(25,973)
-
(10,039)
(4,053)
(25,973)
(14,092)
136,615
68,649
(2,118)
203,146
3,194
140,449
67,141
(1,413)
206,177
3,907
$206,340
$210,084
We have determined that we are more likely than not to realize all recorded deferred tax assets
as of December 31, 2007.
The following is a reconciliation of the change in our deferred tax balance for the year ended
December 31:
Thousands
Deferred tax expense (benefit), 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
2007
$(3,909)
1,508
(705)
243
(881)
Change in deferred income tax accounts . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
$(3,744)
We calculate our deferred tax assets and liabilities under SFAS No. 109, which requires recording
deferred tax balances, at the currently enacted tax rate, on assets and liabilities that are reported
differently for income tax purposes than for financial reporting purposes. 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.
The Internal Revenue Service (IRS) completed its audit of our consolidated income tax returns
for the years 2002-2004 in the second quarter of 2006. The focus of the examination was the
$35.8 million net operating loss (NOL) generated in 2004 and carried back to 2002. This loss
was primarily due to the deductions claimed for a pension contribution and accelerated
depreciation. A federal refund of $8.3 million was received in October 2005. In conjunction
with recording the refund, we recorded additional federal and state income tax credits of $4.2
million. In addition to the NOL, the IRS examined income tax positions taken with respect to
various other ordinary business transactions. We reached agreement with the IRS for certain
income tax positions such that a notice of proposed adjustment was issued. As a result of this
agreement, we recorded an income tax benefit of $0.1 million in 2006.
9.
PROPERTY AND INVESTMENTS:
The following table sets forth the major classifications of our utility plant and accumulated
depreciation at December 31:
2007
2006
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
Accumulated depreciation
Utility plant-net
Weighted
Average
Depreciation
Rate
3.3%
2.6%
3.0%
8.8%
0.0%
3.4%
Weighted
Average
Depreciation
Rate
3.3%
2.6%
2.6%
8.6%
0.0%
3.4%
Amount
$1,657,466
110,721
92,946
68,088
12,850
1,942,071
21,427
1,963,498
(574,093)
$1,389,405
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
98
Accumulated depreciation does not include $204.9 million and $187.4 million at December 31,
2007 and 2006, respectively, which represent accrued asset removal costs 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
2006
Weighted
Average
Depreciation
Rate
2.5%
2007
Weighted
Average
Depreciation
Rate
2.1%
Amount
$54,083
4,881
58,964
8,185
67,149
(7,904)
$59,245
Amount
$34,652
4,820
39,472
3,180
42,652
(6,916)
$35,736
The following table summarizes our other long-term investments, including financial
investments in life insurance policies accounted for at fair value based on cash surrender values
and equity investments in certain partnerships and joint ventures accounted for under the equity
or cost methods, at December 31:
Thousands
Life insurance cash surrender value
Note receivable
Gas pipelines and other
Electric generation
Total other investments
2007
2006
$46,294
518
7,258
-
$45,234
526
1,369
856
$54,070
$47,985
Life Insurance Cash Surrender Value. We have invested in key person life insurance
contracts to provide an indirect funding vehicle for certain long-term employee benefit plan
liabilities.
Gas Pipelines. A wholly-owned subsidiary of Financial Corporation, KB Pipeline Company,
owns a 10 percent interest in an 18-mile interstate natural gas pipeline.
In 2007, we entered into an agreement with TransCanada’s Gas Transmission Northwest
(GTN) for the purpose of developing, designing, permitting, constructing and owning a pipeline
that would connect GTN’s interstate transmission line to our local gas distribution system to
serve markets in Oregon and the western United States (Palomar Pipeline). During 2007, we
incurred expenses totaling $6.0 million related to planning and permitting.
Electric Generation. In 2007, Financial Corporation sold its ownership interests in wind power
electric generation projects located in California (see Note 2).
99
FASB Interpretation No. 46(R), “Consolidation of Variable Interest Entities,” provides
guidance for determining whether consolidation is required for entities over which control is
achieved through means other than voting rights, known as “variable interest entities.” We
currently do not have any significant interests in variable interest entities for which we are the
primary beneficiary.
10
FAIR VALUE OF FINANCIAL INSTRUMENTS:
The estimated fair value of NW Natural’s financial instruments has been determined using
available market information and appropriate valuation methodologies. The following are
financial instruments whose carrying values are sensitive to market conditions:
Thousands
Dec. 31, 2007
Dec. 31, 2006
Carrying
Amount
Estimated
Fair Value*
Carrying
Amount
Estimated
Fair Value
Long-term debt including amount due within one year
$517,000
$557,916
$546,500
$595,564
* This estimate is calculated net of commission fees
Fair value of the long-term debt was estimated using market prices in effect on the valuation
date. Interest rates for debt with similar terms and remaining maturities were used to estimate
fair value for long-term debt issues.
11.
USE OF FINANCIAL DERIVATIVES:
We have entered into commodity swaps, an interest rate swap, 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 utilize derivative financial
instruments to manage commodity prices related to natural gas supply requirements and to
hedge interest rate risk related to our 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
the 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 67 percent of the changes in fair
value are deferred as regulatory assets or liabilities and the remaining 33 percent is recorded to
the income statement for contracts not qualifying for hedge accounting and to Other
Comprehensive Income for contracts qualifying for hedge accounting. Our interest rate swap
qualifies for hedge accounting under SFAS No. 133. During the fourth quarter of 2006, we
entered into a number of commodity-based financial derivatives after our PGA filing. The
unrealized mark-to-market losses on these hedges subject to sharing were $2.9 million, which
was recorded as a loss in 2006 and reversed in 2007.
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
100
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 derivative 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, 2007 was an unrealized gain of $0.1 million. This unrealized gain
is subject to regulatory deferral and, as such, was recorded as a derivative asset, which is offset
by recording a corresponding amount to a regulatory liability account.
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. We did not use
any derivative instruments to hedge interest rates in 2006 or 2005.
The unrealized mark-to-market value at December 31, 2007 for all derivative contracts
outstanding was a total loss of $15.4 million consisting of the following unrealized losses:
$10.7 million on commodity-based financial swap contracts, $2.1 million on commodity-based
financial option contracts, $1.4 million on commodity physical supply contracts and $1.3
million on an interest rate swap contract. These unrealized losses were offset in part by an
unrealized gain of $0.1 million on foreign exchange forward contracts.
At December 31, 2007 and 2006, the unrealized gains or losses from mark-to-market valuations
of our derivative instruments were primarily reported 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
Fair Value Gains (Losses )
Dec. 31, 2007
Dec. 31, 2006
Current Non-Current Current Non-Current
Natural gas commodity-based derivative instruments:
Natural gas commodity hedge contracts
Interest rate hedge contract
Foreign currency forward purchase contracts
$(12,099)
-
173
$(2,104)
(1,330)
-
$(33,528)
-
(135)
$(9,583)
-
-
Total
$(11,926)
$(3,434)
$(33,663)
$(9,583)
In 2007 and 2006, we realized net losses of $42.0 million and $20.0 million, respectively, from
the settlement of fixed-price financial swap contracts which were recorded as increases to the
cost of gas. Net realized gains from the settlement of such contracts in 2005 were $88.9 million
and were recorded as decreases to the cost of gas. Realized losses in 2007 were offset by lower
gas purchase costs from the underlying hedged 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. Any change in value of cash flow hedge contracts that is not included in regulatory
101
recovery is included in other comprehensive income. There were no realized gains or losses on
the interest rate swap during 2007.
As of December 31, 2007, all of the natural gas hedges mature by or are extendible to
October 31, 2009. The maturity date for our interest rate swap contract is September 30, 2018;
however, we expect to cash settle this contract concurrently with the issuance of long-term debt
in the second half of 2008.
12.
COMMITMENTS AND CONTINGENCIES:
Lease Commitments
We lease land, buildings and equipment under agreements that expire in various years through
2046. Rental expense under operating leases was $4.6 million, $4.4 million and $4.1 million for
the years ended December 31, 2007, 2006 and 2005, respectively. The table below reflects the
future minimum lease payments due under non-cancelable leases at December 31, 2007. Such
payments total $53.0 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
2008
2009
2010
2011
2012
Later
years
$4,257
532
$4,184
393
$4,177
255
$4,140
26
$4,265
-
$32,003
-
Minimum lease payments
$4,789
$4,577
$4,432
$4,166
$4,265
$32,003
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 gas purchase agreements. The aggregate amounts of these
agreements were as follows at December 31, 2007:
Thousands
2008
2009
2010
2011
2012
2013 through 2027
Total
Less: Amount representing interest
Total at present value
Gas
Purchase
Agreements
Pipeline
Capacity
Purchase
Agreements
Pipeline
Capacity
Release
Agreements
$302,709
118,936
53,253
24,106
24,106
44,193
567,303
27,538
$ 87,453
68,631
65,344
64,989
49,977
131,501
467,895
61,410
$ 5,105
5,105
4,254
-
-
-
14,464
567
$539,765
$406,485
$13,897
Our total payments of fixed charges under capacity purchase agreements in 2007, 2006 and
2005 were $90.1 million, $69.2 million and $83.1 million, respectively. Included in the
102
amounts were reductions for capacity release sales of $5.3 million for 2007 and $3.7 million for
both 2006 and 2005. 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 have 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
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. During 2007, we accrued an additional $19.3 million
103
for estimated liabilities based on updated information for the development of proposed studies
of in-water source control and completion of remedial actions. We have a net liability of $21.2
million at December 31, 2007 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 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
working with the ODEQ to develop a study of manufactured gas plant wastes on the uplands at
this site. During 2007, the estimated liability for this site increased by $1.8 million related to
future expenditures in connection with the study, which is at the low end of the range of
potential additional liability because no amount within the range is considered to be more likely
than another and the high end of the range cannot be estimated. The net liability at
December 31, 2007 for the Siltronic site is $1.5 million.
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 site and the Siltronic site. 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 2009. The EPA and the Lower Willamette
Group are conducting focused studies on approximately nine miles of the lower Willamette
River, including the segment previously studied by the EPA. During 2007, we received a
revised estimate and following a review of that estimate, we accrued an additional $13.6
million for additional expenditures related to RI/FS development and environmental
remediation and monitoring after the RI/FS work plan is completed. As of December 31, 2007,
we have a net liability of $13.8 million, 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 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, and legal fees and ongoing monitoring, was about $10.4 million. In
2007 we accrued $0.5 million for additional monitoring and reporting expense. To date, we
have paid $9.8 million on work related to the removal of the tar deposit. As of December 31,
2007, we have a net liability of $1.0 million, 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 be estimated.
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
104
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 has been 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. During 2007, we accrued $0.5 million for estimated liabilities related to the design
of an investigational plan for this site in cooperation with the ODEQ. We cannot estimate a
range of liability until studies are completed.
Front Street site. The Front Street site was the former location of a gas manufacturing plant
operated by our predecessor. 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 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. Until the results of that sampling are evaluated, a future
cost cannot be reasonably estimated.
Oregon Steel Mills site. See “Legal Proceedings,” below.
Accrued Liabilities relating to Environmental sites. Until the current year, we had not been
able to determine the timing of our environmental liabilities and therefore had classified no
liabilities as current prior to June 2007. The following table summarizes the accrued liabilities
relating to environmental sites at December 31, 2007 and 2006:
Thousands
Gasco site
Siltronic site
Portland Harbor site
Central Service Center site
Other sites
Total
Current Liabilities
Non-Current Liabilities
2007
2006
$
$
6,901
-
-
-
-
$
6,901
$
$
$
2007
14,342
1,540
14,821
529
167
2006
6,414
43
2,149
-
62
$
31,399
$
8,668
-
-
-
-
-
-
Regulatory and Insurance Recovery for Environmental Matters. In May 2003, the OPUC
approved our request for deferral of environmental costs associated with specific sites,
including the Gasco, Siltronic, Portland Harbor and Front Street sites. The authorization, which
was extended through January 2008 and expanded to include the Oregon Steel Mills site,
allows us to defer and seek recovery of unreimbursed environmental costs in a future general
rate case. Beginning in 2006, the OPUC authorized us to accrue interest on deferred 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.
An application for further extension of the regulatory approval to defer environmental costs and
accrued interest is pending. As of December 31, 2007, we have paid a cumulative total of $24.8
million relating to the named sites since the effective date of the deferral authorization.
On a cumulative basis, we have recognized a total of $67.8 million for environmental costs,
including legal, investigation, and monitoring and remediation costs. Of this total, $29.5 million
has been spent to-date and $38.3 million is reported as an outstanding liability. At
December 31, 2007, we had a regulatory asset of $63.1 million which includes $24.8 million of
total paid expenditures to date, $35.1 million for additional environmental accruals for costs
expected to be paid in the future and accrued interest of $3.2 million. We believe the recovery
105
of these costs is probable through the regulatory process. We intend to pursue recovery of these
environmental costs from 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 some portion 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 legislation 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.
We anticipate that our regulatory recovery of environmental cost deferrals will not be initiated
within the next 12 months because we will not have completed our insurance recovery efforts
during that time period. As such we have classified our regulatory assets for environmental cost
deferrals as non-current. The following table summarizes the regulatory assets and accrued
liabilities relating to environmental matters at December 31, 2007 and 2006:
Thousands
Gasco site
Siltronic site
Portland Harbor site
Central Service Center site
Other sites
Total
Legal Proceedings
Non-Current Regulatory Assets
2007
2006
$
$
$
29,042
2,227
30,869
545
371
63,054
$
10,336
477
16,769
-
291
27,873
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 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 Port’s 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. In March 2005, motions to
dismiss by ourselves and other third-party defendants were denied on the basis that the failure
of the Port to plead and prove that we were in violation of law was an affirmative defense that
may be asserted at trial, but did not provide a sufficient basis for dismissal of the Port’s claim.
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.
106
NORTHWEST NATURAL GAS COMPANY
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
Thousands, except per share amounts March 31
June 30
Sept. 30
Dec. 31
Total
Quarter ended
2007
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
2006
Operating revenues
Net operating revenues
Net income (loss)
Basic earnings (loss) per share
Diluted earnings (loss) per share
$394,091
139,008
48,075
1.77
1.76
$390,391
125,464
41,033
1.49
1.48
$183,249
64,118
2,617
0.10
0.10
$170,979
61,747
1,994
0.07
0.07
$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*
$114,914
41,341
(9,724)
(0.35)
(0.35)
$336,888
111,624
30,112
1.10
1.09
$1,013,172
340,176
63,415
2.30*
2.29*
*
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.
107
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)
2007
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
$3,033
$2,978
$0
$3,121
$2,890
2006
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
$3,067
$3,036
$0
$3,070
$3,033
2005
Reserves deducted in balance
sheet from assets to which they apply:
Allowance for uncollectible accounts
$2,434
$3,034
$0
$2,401
$3,067
108
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
As of December 31, 2007, the principal executive officer and principal financial officer of Northwest
Natural Gas Company (NW Natural) have evaluated 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). Based upon that evaluation, the principal executive officer and
principal financial officer of NW Natural have concluded that such disclosure controls and procedures are
effective to ensure that information required to be disclosed by us and included in our reports filed with
the Securities and Exchange Commission (Commission) under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the Commission’s rules and forms and are
also effective to ensure that information required to be disclosed by us and included in our reports filed
with or furnished to the Commission under the Exchange Act is accumulated and communicated to our
management 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 our most recent fiscal
quarter 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
(a) Entry into a Material Service Agreement
On February 8, 2008, we entered into a service agreement with Northwest Pipeline GP, for an
additional 120,000 therms per day of firm transportation capacity form the U.S. Rocky Mountain
region upon assignment of the capacity from March Point Cogeneration Company. The primary term
of the transportation service agreement will begin on January 1, 2017 and end on December 31, 2046.
This contract is included as Exhibit 10j.(9).
(b) Entry into Service Agreement Amendment
On February 12, 2008, we entered into a service agreement amendment with Northwest Pipeline GP to
extend the primary term of the previous agreement, dated June 29, 1990, to September 30, 2044. The
amendment also provides an additional 351,550 therms per day of firm transportation capacity from
the U.S. Rocky Mountain region.
This contract is included as Exhibit 10j.(7).
109
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 22, 2008 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 22, 2008 Annual Meeting of Shareholders is hereby
incorporated by reference.
Name
Dec. 31, 2007 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
Stephen P. Feltz
C. J. Rue
Richelle T. Luther
62
50
46
53
52
54
54
52
52
62
39
Chief Executive Officer (2007-
); President and Chief Executive
Officer (2003-2007).
President and Chief Operating Officer (2007 -
); 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 (2003-2004); Vice President of Investor Relations and
Shareholder Services, TXU Corp. (1997-2003).
Vice President and General Counsel (2005-
); Partner, Stoel Rives
LLP (1991- 2005).
Vice President, Human Resources (2000-
).
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);
Director, Strategic Development (2003); Director, Corporate and
Business Development (2001-2003).
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).
Treasurer and Controller (1999-
).
Secretary (1982-2007); Assistant Treasurer (1987-2007).
Assistant Secretary (2002-
).
Each executive officer serves successive annual terms; present terms end on May 22, 2008.
There are no family relationships among our executive officers.
NW Natural has adopted a Code of Ethics for all employees, including our chief executive
officer, chief financial officer and principal accounting officer, and a Financial Code of Ethics that
110
applies to senior financial employees, both of which are available on our website at
www.nwnatural.com.
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 22, 2008 Annual Meeting of Shareholders is hereby
incorporated by reference. Information related to Executive Officers as of December 31, 2007 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, 2007 (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))
87,998
357,750
23,213
6,967
74,580
27,024
n/a
577,532
n/a
$35.36
$40.95
299,721
1,035,400
199,820
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
1,534,941
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 22, 2008 Annual Meeting
of Shareholders is incorporated herein by reference.
1
Shares issued pursuant to the LTIP do not include an exercise price, but are payable by us when
the award criteria are satisfied. If the maximum awards were paid pursuant to the performance-
based awards outstanding at December 31, 2007, the number of shares shown in column
(a) would increase by 81,665 shares and the number of shares shown in column (c) would
decrease by 81,665 shares.
111
2
3
4
Prior to January 1, 2005, deferred amounts were credited, at the participants 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
ten years as elected by the participant in accordance with the terms of the DCP. 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 22, 2008 Annual Meeting of Shareholders is
hereby incorporated by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information captioned “2007 and 2006 Audit Firm Fees” in the Company’s definitive
Proxy Statement for the May 22, 2008 Annual Meeting of Shareholders is hereby incorporated by
reference.
112
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 115.
113
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
Date: February 29, 2008
NORTHWEST NATURAL GAS COMPANY
By:
/s/ Mark S. Dodson
Mark S. Dodson,
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
TITLE
/s/ Mark S. Dodson
Principal Executive Officer and Director
DATE
February 29, 2008
Mark S. Dodson, 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/ C. Scott Gibson
C. Scott Gibson
/s/ Tod R. Hamachek
Tod R. Hamachek
/s/ Randall C. Papé
Randall C. Papé
/s/ Jane L. Peverett
Jane L. Peverett
/s/ George J. Puentes
George J. Puentes
/s/ Richard G. Reiten
Richard G. Reiten
/s/ Kenneth Thrasher
Kenneth Thrasher
/s/ Russell F. Tromley
Russell F. Tromley
Principal Financial Officer
February 29, 2008
Principal Accounting Officer
February 29, 2008
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
Director
114
February 29, 2008
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
)
EXHIBIT INDEX
To
Annual Report on Form 10-K
For Fiscal Year Ended
December 31, 2007
Exhibit Number
Document
*3a.
*3b.
*4a.
*4d.
*4e.
*4f.
*4f.(1)
Restated Articles of Incorporation, as filed and effective May 31, 2006 and
amended May 31, 2006 (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).
115
*4i.
*4j.
*4k.
*4l.
*10j.
*10j.(1)
*10j.(2)
*10j.(3)
*10j.(5)
*10j.(6)
10j.(7)
10j.(8)
10j.(9)
12
Form of Credit Agreement between Northwest Natural Gas Company and
each of JPMorgan Chase Bank, N.A., and Bank of America, N.A., 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).
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. 1-15973).
Form of Secured Medium-Term Notes, Series B (incorporated herein by
reference to Exhibit 4.1 to Form 8-K dated October 4, 2004, File No. 1-
15973).
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).
Transportation Agreement, dated June 29, 1990, between the Company and
Northwest Pipeline GP (incorporated herein by reference to Exhibit 10j. to
Form 10-K for 1993, File No. 0-994).
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.
Service Agreement, dated February 8, 2008, between the Company and
Northwest Pipeline GP.
Agreement between the Company and March Point Cogeneration Company,
dated February 8, 2008.
Statement re computation of ratios of earnings to fixed charges.
116
23
31.1
31.2
32.1
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)
*10b.(2)
*10b.(3)
*10b.(4)
*10c.
*10c.(1)
10e.
10f.
10f.(1)
*10g.
*10i.
Executive Supplemental Retirement Income Plan (2007 Restatement).
Supplemental Executive Retirement Plan, effective September 1, 2004
restated December 20, 2007.
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 28, 2008.
Directors Deferred Compensation Plan, effective June 1, 1981, restated as of
February 28, 2008.
Deferred Compensation Plan for Directors and Executives effective January
1, 2005, restated February 28, 2008.
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).
117
*10k.
*10o.
*10o.-1
*10p.
*10p.-1
*10p.-2
*10p.-3
*10p.-4
*10v.
*10w.
*10w.(1)
10w.(2)
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 amended and restated executive change in control severance
agreement between the Company and each executive officer other than
Mark S. Dodson (incorporated herein by reference to Exhibit 10.2 to Form
8-K dated December 19, 2006, File No. 1-15973).
Amended and restated executive change in control severance agreement
dated December 14, 2006 between the Company and Mark S. Dodson
(incorporated herein by reference to Exhibit 10.3 to Form 8-K dated
December 19, 2006, File No. 1-15973).
Employment Agreement dated July 2, 1997, between the Company and an
executive officer (incorporated herein by reference to Exhibit 10(a) for
Form 10-Q for the quarter ended September 30, 1997, File No. 0-994).
Amendment dated December 18, 1997 to employment agreement dated July
2, 1997, between the Company and an executive officer (incorporated herein
by reference to Exhibit 10p.-1 to Form 10-K for 1997, File No. 0-994).
Amendment dated September 24, 1998 to employment agreement dated July
2, 1997, as previously amended, between the Company and an executive
officer (incorporated herein by reference to Exhibit 10(g) to Form 10-Q for
the quarter ended September 30, 1998, File No. 0-994).
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).
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.
118
*10x.
*10x.(1)
*10z.(1)
*10aa.
10bb.
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).
Summary of non-employee director compensation, effective January 1, 2007
(incorporated herein by reference to Form 8-K dated October 3, 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 as indicated
119
NORTHWEST NATURAL GAS COMPANY
Statement Re: Ratio of Earnings to Fixed Charges
Thousands, except per share amounts
(Unaudited)
EXHIBIT 12
Year Ended December 31,
2007
2006
2005
2004
2003
Fixed Charges, as defined:
Interest on Long-Term Debt . . . . . . . . . . . . . . . . .
Other Interest
. . . . . . . . . . . . . . . . . . . . . . . . . . . .
Amortization of Debt Discount and Expense . . . .
Interest Portion of Rentals . . . . . . . . . . . . . . . . . .
$ 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
$ 33,258
2,048
696
1,622
Total Fixed Charges, as defined . . . . . . . . . . . . . .
$ 40,644
$ 41,480
$ 39,160
$ 38,222
$ 37,624
Earnings, as defined:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Taxes on Income . . . . . . . . . . . . . . . . . . . . . . . . .
Fixed Charges, as above . . . . . . . . . . . . . . . . . . . .
$ 74,497
44,060
40,644
$ 63,415
36,234
41,480
$ 58,149
32,720
39,160
$ 50,572
26,531
38,222
$ 45,983
23,340
37,624
Total Earnings, as defined . . . . . . . . . . . . . . . . . .
$159,201
$141,129
$130,029
$115,325
$106,947
Ratio of Earnings to Fixed Charges . . . . . . . . . . . . . . .
3.92
3.40
3.32
3.02
2.84
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 29, 2008 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 29, 2008
CERTIFICATION
EXHIBIT 31.1
I, Mark S. Dodson, 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 29, 2008
/s/ Mark S. Dodson
Mark S. Dodson
Chief Executive Officer
CERTIFICATION
EXHIBIT 31.2
I, David H. Anderson, 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 29, 2008
/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, MARK S. DODSON, the 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, 2007 (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 29th day of February 2008.
/s/ Mark S. Dodson
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.
Corporate Profile
Utility Service Territory
NW Natural (NYSE: NWN) is a 149-year-old natural gas local distribution
and storage company headquartered in Portland, Oregon, with a customer
growth rate well above the national average. NW Natural serves more than
652,000 customers in Oregon and southwest Washington, including the
Portland-Vancouver metropolitan area, the Willamette Valley, the Oregon
coast and the Columbia River Gorge. In keeping with its steady growth,
the company has increased dividends paid to shareholders for 52 consecutive
years, a feat matched by few publicly traded companies. NW Natural purchases
natural gas for its core market from a variety of suppliers in the western United
States and Canada. The company operates gas storage facilities in its service
territory, contracts for additional gas storage outside its service territory, 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 natural gas transmission pipeline from
central Oregon to northwest Oregon providing enhanced gas deliverability and
reliability for the region.
Williams gas pipeline
NW Natural gas
transmission line
Kelso Beaver Pipeline
Coos County pipeline
LNG plant
Regional resource centers
Mist underground gas storage
Headquarters
2007
2006
percent
increase
(decrease )
Diluted Earnings Per Share (IN DOLLARS)
Financial 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
1,033,193
369,042
74,497
1,013,172
340,176
63,415
12.5
46.3
53.7
10.7
46.3
53.7
26,821
26,407
27,540
27,284
2.78
2.76
1.44
1.50
22.52
48.66
2.30
2.29
1.39
1.42
21.97
42.44
Gas sales and transportation deliveries (000 therms) 1,214,969
4,374
Degree days (25-year average, 4,265)
652,012
Customers at year-end
1,141
Employees at year-end
1,192,649
4,089
636,584
1,211
DIvIDENDS PAID ON COMMON STOCK (per share)
PAYMENT DATE
February 15
May 15
August 15
November 15
Total dividends paid
$ 0.355
0.355
0.355
0.375
$ 1.440
$ 0.345
0.345
0.345
0.355
$ 1.390
2
8
17
17
–
–
(3 )
(3 )
21
21
4
6
2
15
2
7
2
(6 )
$3.00
2.50
2.00
1.50
1.00
0.50
0
‘03
‘04
‘05
‘06
‘07
Diluted earnings per share were $2.76 in 2007, up
21 percent over 2006.
Dividends Paid Per Share (IN DOLLARS)
$1.47
1.42
1.37
1.32
1.27
1.22
‘03
‘04
‘05
‘06
‘07
Annual dividends paid per share in 2007 increased
for the 52nd consecutive year. The indicated
dividend rate at year-end was $1.50 per share.
We grew up here.
n w n a t u r a l . c o m
220 NW Second Avenue
Portland, Oregon 97209
nwnatural.com
NYSE: NWN
Growing responsibly.
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2007 ANNUAL REPORT